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As filed with the Securities and Exchange Commission on March 3, 2010
Registration No. 333-164492
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
PAA Natural Gas Storage, L.P.
(Exact Name of Registrant as Specified in Its Charter)
 
         
         
Delaware
  4922   27-1679071
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)
 
333 Clay Street, Suite 1500
Houston, Texas 77002
(713) 646-4100
(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)
 
Richard K. McGee
Tim Moore
333 Clay Street, Suite 1500
Houston, Texas 77002
(713) 646-4100
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)
 
Copies to:
 
     
David P. Oelman
D. Alan Beck, Jr.
Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2500
Houston, Texas 77002
(713) 758-2222
  Joshua Davidson
Gerald M. Spedale
Baker Botts L.L.P.
One Shell Plaza
910 Louisiana Street
Houston, Texas 77002
(713) 229-1234
 
Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.
 
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  o
 
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o
  Accelerated filer o   Non-accelerated filer þ
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 


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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.
 
SUBJECT TO COMPLETION DATED MARCH 3, 2010
 
PRELIMINARY PROSPECTUS
 
PAA Natural Gas Storage, L.P.
 
Common Units
Representing Limited Partner Interests
 
 
This is the initial public offering of our common units. We currently estimate that the initial public offering price will be between $      and $      per common unit. Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “PNG.”
 
 
Investing in our common units involves risks. Please read “Risk Factors” beginning on page 24. These risks include the following:
 
 
  •  We may not have sufficient cash following the establishment of reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common units and Series A subordinated units.
 
  •  Plains All American Pipeline, L.P., or PAA, owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including PAA, have conflicts of interest with us and limited fiduciary duties, and may favor their own interests to your detriment.
 
  •  Increased competition from other companies that provide natural gas storage services or services that can substitute for storage services could have a negative impact on the demand for our services, which could adversely affect our financial results.
 
  •  Our natural gas storage operations are subject to regulation by federal, state and local regulatory authorities; regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
 
  •  We may not be able to maintain or replace expiring storage contracts.
 
  •  We may not be able to achieve our current expansion plans at our Pine Prairie facility on economically viable terms.
 
  •  Holders of our common units have limited voting rights and are not entitled to elect the directors of our general partner.
 
  •  Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
 
  •  Upon the closing of the offering, investors in our common units will experience immediate and substantial dilution in pro forma net tangible book value of $      per common unit.
 
  •  You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
                         
            Proceeds to PAA
        Underwriting
  Natural Gas
    Price to Public   Discounts(1)   Storage, L.P.
 
Per Common Unit
  $           $           $        
Total
  $       $       $  
 
 
(1) Excludes expenses equal to     % of the gross proceeds of this offering, or approximately $     .
 
We have granted the underwriters a 30-day option to purchase up to an additional          common units from us on the same terms and conditions as set forth above if the underwriters sell more than           common units in this offering. If the underwriters exercise their option to purchase additional common units, we will sell such common units to the underwriters and redeem the same number of units from PAA.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
The underwriters expect to deliver the common units on or about          , 2010.
 
 
Barclays Capital UBS Investment Bank
 
          , 2010


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Map and pictures of facilities to come
 


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 EX-23.1
 
 
You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. We and the underwriters are offering to sell, and seeking offers to buy, our common units only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common units. Until          , 2010 (25 days after the date of this prospectus), all dealers that effect transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


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SUMMARY
 
This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully, including “Risk Factors” beginning on page 24 and the historical and pro forma financial statements and the notes to those financial statements. The information in this prospectus assumes (1) an initial public offering price of $      per common unit and (2) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. We include a glossary of some of the terms used in this prospectus as Appendix B.
 
References in this prospectus to “PAA Natural Gas Storage, L.P.,” “the Partnership,” “PNGS,” ”we,” “us,” “our” or similar terms when used in a historical context refer to the business of PAA Natural Gas Storage, LLC and its subsidiaries, which will be contributed to PAA Natural Gas Storage, L.P. in connection with this offering. When used in the present tense or prospectively, those terms refer to PAA Natural Gas Storage, L.P. and its subsidiaries. References in this prospectus to our “general partner” refer to PNGS GP LLC. Unless the context indicates otherwise, (i) all references to “Plains All American” or “PAA” refer to Plains All American Pipeline, L.P. (the ultimate parent company of our general partner) and its subsidiaries and affiliates other than PAA Natural Gas Storage, L.P. and our general partner and their respective subsidiaries, as of the closing date of this offering, (ii) all references to volumes of storage capacity are expressed in billions of cubic feet of natural gas, or Bcf, and are approximations that have been rounded to the nearest Bcf and (iii) all references to capacity mean working gas storage capacity.
 
PAA Natural Gas Storage, L.P.
 
Overview
 
We are a fee-based, growth-oriented Delaware limited partnership formed by Plains All American to own, operate and grow the natural gas storage business that PAA acquired in 2005. Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. We currently own and operate two natural gas storage facilities located in Louisiana and Michigan that have an aggregate working gas storage capacity of 40 Bcf and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. We also lease storage capacity and pipeline transportation capacity from third parties from time to time in order to increase our operational flexibility and enhance the services we offer our customers. As of December 31, 2009, we had 3 Bcf of storage capacity under lease from third parties and had secured the right to 379 MMcf per day of firm transportation service on various pipelines. Substantially all of our revenues are derived from the provision of firm storage services under multi-year, fee-based contracts.
 
Our business has expanded rapidly since its inception in 2005, primarily through organic growth initiatives. We have grown our storage capacity from 20 Bcf as of December 31, 2005 to 40 Bcf as of December 31, 2009. Our expansion plans include an additional 31 Bcf of working gas storage capacity, 28 Bcf of which we expect to place into service by mid-2012, including 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010. Our target is to increase our total capacity to 68 Bcf by mid-2012, representing a 70% increase in storage capacity from year-end 2009 levels. Through our current assets and proposed expansions, we believe we are well-positioned to benefit from the anticipated long-term growth in demand for natural gas storage capacity and services in North America.
 
Our Assets
 
We own 100% of the Pine Prairie facility, which is a recently constructed, high-deliverability salt-cavern natural gas storage complex located in Evangeline Parish, Louisiana, and 100% of the Bluewater facility, which is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in


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St. Clair County, Michigan. The following table contains certain information regarding our Pine Prairie and Bluewater storage facilities:
 
                                 
    Working Gas
    Peak Injection
    Peak Withdrawal
    Compression
 
Facility Name and Type
  Capacity (Bcf)     Rate (Bcf/d)     Rate (Bcf/d)     (Horsepower)  
 
Pine Prairie (salt-cavern)
                               
Existing facility
     14        1.2        2.4       32,000  
Planned expansion
    31 (1)     1.2 (2)     0.8 (2)     56,250 (3)
                                 
Subtotal:
    45       2.4       3.2       88,250  
                                 
Bluewater (depleted reservoir)
                               
Existing facility
    26       0.5       0.8       13,350  
Planned expansion
    2 (4)                  
                                 
Subtotal:
    28       0.5       0.8       13,350  
                                 
Total (both facilities):
    73       2.9       4.0       101,600  
                                 
 
 
(1) We expect to place 10 Bcf into service in the second quarter of 2010, 18 Bcf by mid-2012 and the final 3 Bcf will be added ratably through 2015.
 
(2) We expect to complete these expansions of peak injection and withdrawal capabilities by mid-2011.
 
(3) Of this aggregate expected increase in compression, 16,000 horsepower is on location with installation targeted for April 2010. With respect to the remaining compression capacity, we expect 23,000 horsepower to be in place by mid-2011 and an additional 17,250 horsepower to be in place by mid-2012.
 
(4) We expect to place this expansion in working gas capacity into service ratably over a 10-year period beginning in 2011 in connection with a planned liquids removal project.
 
Pine Prairie.  As a strategically located, high-deliverability storage facility, Pine Prairie has attracted a diverse group of customers, including utilities, pipelines, producers, power generators, marketers and liquefied natural gas (“LNG”) importers, whose storage needs include both traditional seasonal storage services and short-term storage services. Pine Prairie is strategically positioned relative to several major market hubs, including:
 
  •  the Henry Hub, which is the delivery point for NYMEX natural gas futures contracts and is located approximately 50 miles southeast of Pine Prairie;
 
  •  the Carthage Hub in east Texas, which is located approximately 150 miles northwest of Pine Prairie; and
 
  •  the Perryville Hub in north Louisiana, which is located approximately 130 miles north of Pine Prairie.
 
Pine Prairie’s pipeline header system, which includes an aggregate of 74 miles of 24-inch diameter pipe located within a 20-mile radius of Pine Prairie, is directly connected to eight large-diameter interstate pipelines through nine interconnects that service both conventional and unconventional natural gas production in Texas and Louisiana as well as Gulf of Mexico production and LNG imports. These interconnects also provide direct or indirect access to each of the market hubs described above and to other significant consumer and industrial markets.
 
Pine Prairie has a total current working gas storage capacity of 14 Bcf in two caverns, and planned expansions that will increase Pine Prairie’s total capacity to 42 Bcf by mid-2012 and 45 Bcf by mid-2015 (see table above). Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf. Taking these considerations into account and with certain infrastructure modifications, we currently estimate that Pine Prairie could support in excess of 15 salt caverns and an aggregate storage capacity of over 150 Bcf.


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Bluewater.  Bluewater is located in the State of Michigan, which contains more underground natural gas storage capacity than any other state in the U.S. according to data from the Energy Information Administration (“EIA”), and primarily services seasonal storage needs throughout the Midwestern and Northeastern portions of the U.S. and the Southeastern portion of Canada. Accordingly, Bluewater’s customers consist primarily of pipelines, utilities and marketers seeking seasonal storage services. Bluewater’s 30-mile, 20-inch diameter pipeline header system connects with three interstate and three intrastate natural gas pipelines that provide access to the major market hubs of Chicago, Illinois and Dawn, Ontario, which supply natural gas to eastern Ontario and the northeastern United States. These interconnects also provide access to natural gas utilities that serve local markets in Michigan and Ontario.
 
As indicated in the table above, Bluewater has total working gas storage capacity of approximately 26 Bcf in two depleted reservoirs and we expect to increase Bluewater’s working gas capacity by 2 Bcf ratably over a 10-year period beginning in 2011 as a result of a planned liquids removal project. Bluewater also leases third-party storage capacity and pipeline transportation capacity from time to time to increase its operational flexibility and enhance its service offerings. As of December 31, 2009, we had leased approximately 3 Bcf of additional capacity at third-party natural gas storage facilities as well as 329 MMcf per day of related pipeline transportation capacity.
 
Our Operations
 
We generate revenue almost exclusively through the provision of fee-based gas storage services to our customers. Our storage rates are regulated under Federal Energy Regulatory Commission, or FERC, rate-making policies, which currently permit our facilities to charge market-based rates for our services. For the year ended December 31, 2009, approximately 99% of our total revenue was derived from fee-based storage activities, with the remaining approximately 1% primarily attributable to the sale of liquid hydrocarbons incidentally produced in connection with the operation of our depleted reservoir storage facilities at Bluewater. Our revenues from fee-based gas storage services are derived from both “firm storage services” and “hub services.”
 
  •  Firm Storage Services.  Firm storage services include (i) storage services pursuant to which customers receive the assured or “firm” right to store gas in our facilities over a multi-year period and (ii) seasonal “park and loan” services pursuant to which customers receive the “firm” right to store gas in (park), or borrow gas from (loan), our facilities on a seasonal basis. Under our firm storage contracts, our customers are obligated to pay us fixed monthly capacity reservation fees, which are owed to us regardless of the actual storage capacity utilized. At Pine Prairie, our firm storage contracts typically have terms of 3 to 5 years, while at Bluewater terms generally range from 1 to 3 years. Under our firm storage contracts, we also typically collect a “cycling fee” based on the volume of natural gas nominated for injection and/or withdrawal and retain a small portion of natural gas nominated for injection as compensation for our fuel use. For the year ended December 31, 2009, approximately 92% of our total revenue was derived from firm storage services.
 
  •  Hub Services.  We also generate revenue from the provision of “hub services” at our facilities. Hub services include (i) “interruptible” storage services pursuant to which customers receive only limited assurances regarding the availability of capacity in our storage facilities and pay fees based on their actual utilization of our assets, (ii) non-seasonal “park and loan” services and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through our facilities from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from our facilities. For the year ended December 31, 2009, approximately 7% of our total revenue was derived from hub services.
 
We believe that the high percentage of our baseline cash flow derived from fixed-capacity reservation fees under multi-year contracts with a diverse portfolio of customers stabilizes our cash flow profile and substantially mitigates the risk to us of significant negative cash flow fluctuations caused by changing supply and demand conditions and other market factors. For additional information about our contracts, please read “Business — Contracts.”


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Our Business Strategy
 
Our principal business strategy is to capitalize on the anticipated long-term growth in demand for natural gas storage services in North America and increase the amount of cash distributions we make to our unitholders over time by owning and operating high-quality natural gas storage facilities and providing our current and future customers reliable, competitive and flexible natural gas storage and related services. Our plan for executing this strategy includes the following key components:
 
  •  Optimizing our existing natural gas storage facilities.  We are constantly seeking to optimize the performance and profitability of our existing natural gas storage facilities. Our primary commercial objective is to generate a significant portion of our revenues by committing a high percentage of our storage capacity under multi-year firm storage contracts at attractive rates. Effective as of April 1, 2010, approximately 93% of our owned and leased total working gas capacity will be committed under firm storage contracts with a weighted average remaining tenor of approximately 3.9 years at Pine Prairie and approximately 2.2 years at Bluewater. We also provide our customers with a variety of hub services that are designed to accommodate customer needs, maximize the utilization of our assets and optimize our earnings and cash flow.
 
  •  Organically expanding our existing natural gas storage facilities.  Our existing assets enable us to expand our storage capacity on what we believe to be attractive economic terms. Our current expansion plans include the addition of 31 Bcf of working gas storage capacity at our Pine Prairie facility, 28 Bcf of which we expect to place into service by mid-2012, including 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010. In addition, we are currently pursuing a liquids removal project to expand our storage capacity at our Bluewater facility by 2 Bcf ratably over a 10-year period beginning in 2011.
 
  •  Pursuing strategic and accretive acquisition or development projects.  We continually evaluate opportunities to acquire or develop new natural gas storage facilities in our existing and new markets. In general, we are seeking acquisition or development opportunities that will be accretive (or result in an increase in distributable cash flow on a per unit basis) and that will add natural gas storage assets or facilities that either complement our existing assets or strategically enhance our overall business by facilitating our entry into a desirable new market, diversifying our customer base or positioning us for future growth. Although there can be no assurances that viable acquisition or development opportunities will continue to be available to us or that we will ultimately be able to consummate any of the transactions currently being considered, we believe the combination of strong long-term fundamentals for natural gas demand and storage services coupled with the fragmented nature of the gas storage business should result in a variety of acquisition and/or development opportunities for us to consider. In addition, over time and working in conjunction with PAA, we intend to evaluate opportunities to acquire or develop other natural gas-related assets or businesses that complement our natural gas storage business and allow us to leverage our asset base and industry experience.
 
  •  Leasing storage capacity and transportation services from third parties to enhance operational flexibility.  In order to supplement our owned storage capacity, increase our operating flexibility, enhance the services that we are capable of offering to our customers and optimize the commercial performance of our assets, we periodically lease storage and/or transportation capacity from third parties. As of December 31, 2009, we had 3 Bcf of storage capacity under lease from third parties and had secured the right to 379 MMcf per day of firm transportation service on various pipelines.
 
  •  Utilizing a portion of our owned and leased storage capacity to enhance our commercial management activities.  Similar to the business model successfully employed by PAA, and without altering our basic commercial strategy of committing a high percentage of our storage capacity under multi-year firm storage contracts at attractive rates, we intend to establish a dedicated commercial marketing group that will capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. Consistent with PAA’s experience marketing crude oil and refined products, we anticipate that having a dedicated commercial marketing group that has a consistent presence in our markets will enhance our ability to


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  properly price our storage and hub service offerings and will increase our earnings by capitalizing on volatility and inefficiencies in the natural gas markets. We will conduct these commercial activities within pre-defined risk parameters, and our general policy will be (i) to purchase natural gas only in situations where we have a market for such gas, (ii) to utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that commodity price fluctuations will not have a material adverse impact on our cash flow and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.
 
Our Financial Strategy
 
Important factors to successfully grow our business will be our ability to maintain a competitive cost of capital and sufficient access to the capital markets. These factors will be significantly influenced by our ability to grow our distribution to unitholders, maintain a solid credit profile and ultimately achieve and maintain an investment-grade credit rating.
 
Targeted Credit Profile.  We have targeted a general credit profile that has the following attributes:
 
  •  a long-term debt-to-total capitalization ratio of 40% or less;
 
  •  an average long-term debt-to-Adjusted EBITDA multiple of approximately 3.5x (Adjusted EBITDA is earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring); and
 
  •  an average Adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.
 
When considered together with what we believe to be the relatively low risk profile of our business, we believe this credit profile is consistent with an investment grade credit rating. In combination with our intent to maintain a high percentage of storage capacity under multi-year contracts, this credit profile should also provide flexibility if storage markets become oversupplied and position us to take advantage of attractive acquisition opportunities.
 
In order for us to maintain our targeted credit profile, we generally intend to fund approximately 60% of the capital required for expansion and acquisition projects through a combination of equity capital and cash flow in excess of distributions. In connection with the closing of this offering, we expect to enter into a new $400 million revolving credit facility. We believe we will be able to fund up to the first $250 million of acquisitions or expansion projects primarily through borrowings under this credit facility or other sources and remain in compliance with our targeted credit profile.
 
Credit Rating.  We have not applied for a credit rating from any credit rating agency, nor to our knowledge has any such credit rating been assigned. If and when we seek a credit rating, our credit rating may be positively or negatively impacted by the leverage and credit rating of PAA. In addition, while we believe our targeted credit profile is consistent with an investment grade rating, we can provide no assurance in this regard. See “Risk Factors — The credit and risk profile of our general partner and its owner, PAA, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.”
 
As of March 1, 2010, the senior unsecured ratings of PAA with Standard & Poor’s Ratings Services and Moody’s Investors Service were BBB-, stable outlook, and Baa3, stable outlook, respectively.
 
Our Competitive Strengths
 
We believe that the following competitive strengths will position us to successfully execute our principal business strategy:
 
  •  Our natural gas storage assets are strategically located and operationally flexible.  Our Pine Prairie and Bluewater facilities are strategically positioned relative to several major market hubs and have


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  significant connectivity that enable them to serve a variety of major producing regions, LNG importers and the primary consumer and industrial markets in the Gulf Coast, Midwest, Northeast and Southeast regions of the U.S. as well as eastern Ontario, Canada. Collectively, our facilities have aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. Upon the completion of current expansion activities, these capabilities will increase to 2.9 Bcf per day of peak rate injection capability and 4.0 Bcf per day of peak rate withdrawal capability.
 
  •  Our business generates relatively stable and predictable cash flow.  Given the high percentage of our cash flow that is derived from fixed-capacity reservation fees under multi-year contracts with a diverse portfolio of customers, our baseline cash flow profile is relatively stable and predictable, which we believe significantly mitigates the risk to us of negative cash flow fluctuations caused by changing supply and demand conditions and other market factors. In addition, we do not take title to the natural gas that we store for our customers and, accordingly, are not exposed to commodity price fluctuations on the gas that is stored in our facilities by our customers. Except for the base gas we purchase and use in our facilities, which we consider to be a long-term asset, and volume and pricing variations related to small amounts of natural gas we are entitled to retain from our customers as compensation for our fuel costs, our current and planned business strategies are designed to minimize our exposure to fluctuations in the outright price of natural gas.
 
  •  Our Pine Prairie storage facility has the ability to be significantly expanded at competitive costs and with a relatively high degree of schedule certainty.  We own and/or lease 320 acres of land on the salt dome that underlies Pine Prairie. Our existing facilities and planned expansions through 2012 to five caverns will utilize only approximately 120 of these acres. Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf to over 150 Bcf. In addition, because our existing infrastructure at Pine Prairie has been specifically designed to facilitate future expansion, we expect it to both reduce our overall capital costs per additional Bcf of storage capacity and shorten the length and enhance the predictability of our development cycle.
 
  •  We have the evaluation, integration and engineering skill sets in-house that are necessary to successfully pursue acquisition and expansion opportunities.  We possess the in-house capabilities and expertise necessary to develop, construct, own, acquire and operate both depleted reservoir and salt-cavern storage capacity. We have been involved in substantially all aspects of the natural gas storage business since 2005 and our operational and management team has extensive energy industry and acquisition experience. In addition, from 1998 to 2009, PAA has (i) successfully acquired and integrated over $6 billion of acquisitions in over 50 separate transactions involving midstream energy assets, and (ii) executed over 100 organic growth and expansion projects with total capital expenditures of over $2.4 billion. We believe that the experience and skill sets of our collective management team provide us with a competitive advantage that enables us to appropriately identify, assess and evaluate the risks and opportunities that are likely to arise during the development and operational phases of potential gas storage acquisition and expansion opportunities.
 
  •  We have the financial flexibility to pursue acquisition and expansion opportunities.  At the closing of this offering, we expect to have approximately $200 million of borrowing capacity available to us under our revolving credit facility. We believe our borrowing capacity and our ability to access private and public debt and equity capital should provide us with the financial flexibility necessary to execute our growth and expansion strategy. Additionally, PAA may elect, but is not obligated, to provide us with financial support in connection with acquisitions or expansion capital projects in certain circumstances.
 
  •  Our general partner has an experienced executive management team with specialized knowledge of natural gas storage and markets and whose interests are aligned with those of our unitholders.  Our general partner has an executive management team that has extensive experience managing, operating, building, acquiring and integrating energy assets, including natural gas storage assets and other midstream energy assets. On average, the members of our general partner’s executive management team have in


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excess of 20 years of energy industry experience. In addition, our general partner’s executive management team includes a President and three Vice Presidents who are exclusively dedicated to and focused on the operation, management, development and expansion of our natural gas storage business. Through their indirect and direct interests in us, our general partner and PAA, our general partner’s executive management team has a significant, vested interest in our continued success.
 
We believe these competitive strengths will aid our efforts to expand our presence in the natural gas storage sector.
 
Our Relationship with Plains All American Pipeline, L.P.
 
We believe one of our strengths is our relationship with Plains All American Pipeline, L.P., the fourth largest publicly traded master limited partnership as measured by industry data regarding equity market capitalization, which was approximately $7.5 billion as of February 26, 2010. Plains All American’s common units trade on the New York Stock Exchange, or NYSE, under the ticker symbol “PAA.” In addition to its participation in the natural gas storage business through our partnership, PAA is engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas-related petroleum products.
 
PAA and its predecessors have been active participants in the hydrocarbon storage industry since the early 1990s. PAA has a long history of successfully expanding its energy infrastructure businesses through a combination of organic growth projects and complementary acquisitions. Since its initial public offering in 1998, PAA has grown its asset base from approximately $600 million to over $12 billion and increased the annualized distribution on its limited partner units by over 100%, from $1.80 per unit as of PAA’s initial public offering to $3.71 per unit for the distribution paid in February 2010.
 
Our partnership will own all of the natural gas storage business and assets formerly owned by PAA and PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business. Upon completion of this offering, as the ultimate owner of our 2.0% general partner interest, all of our incentive distribution rights and an approximate     % limited partner interest in us (including common units, Series A subordinated units and Series B subordinated units), PAA will have a significant economic stake in us and a commensurate incentive to promote and support the successful execution of our growth plan and strategy.
 
We will also enter into an omnibus agreement with PAA and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them. Please read “Certain Relationships and Related Transactions — Agreements Governing the Transactions — Omnibus Agreement.”
 
We believe PAA’s significant presence in the energy sector, its successful track record of growth and its significant investment in, and sponsorship and support of, us will enhance our ability to grow our business. While we believe this relationship with PAA is a significant positive attribute, it may also be a source of conflicts. For example, PAA is not restricted in its ability to compete with us. Please read “Conflicts of Interest and Fiduciary Duties.”
 
Risk Factors
 
An investment in our common units involves risks. The following list of risk factors is not exhaustive. Please read “Risk Factors” carefully for a more thorough description of these and other risks.
 
Risks Related to Our Business
 
  •  We may not have sufficient cash following the establishment of reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common units and Series A subordinated units.
 
  •  On a pro forma basis, we would not have had sufficient available cash from distributable cash flow to pay the full minimum quarterly distribution on our common units or any distributions on our Series A subordinated units for the year ended December 31, 2009.


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  •  The amount of cash we have available for distribution to holders of our common units and Series A subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
 
  •  The assumptions underlying our minimum estimated available cash from distributable cash flow included in “Our Cash Distribution Policy and Restrictions on Distributions” involve inherent and significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.
 
  •  Increased competition from other companies that provide natural gas storage services or services that can substitute for storage services could have a negative impact on the demand for our services, which could adversely affect our financial results.
 
  •  Our natural gas storage operations are subject to regulation by federal, state and local regulatory authorities; regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
 
  •  We may not be able to maintain or replace expiring storage contracts.
 
  •  We may not be able to achieve our current expansion plans at our Pine Prairie facility on economically viable terms.
 
Risks Inherent in an Investment in Us
 
  •  Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
  •  Cost reimbursements due to PAA’s general partner and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to you. The amount and timing of such reimbursements will be determined by PAA’s general partner.
 
  •  Holders of our common units have limited voting rights and are not entitled to elect the directors of our general partner.
 
  •  Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
 
  •  Upon the closing of the offering, investors in our common units will experience immediate and substantial dilution in pro forma net tangible book value of $      per common unit.
 
Risks Related to Conflicts of Interest
 
  •  PAA owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. PAA and our general partner have conflicts of interest and may favor PAA’s interests to your detriment.
 
  •  PAA may engage in competition with us.
 
  •  Our partnership agreement defines and modifies the duties of our general partner and restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner.
 
Tax Risks to Common Unitholders
 
  •  Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.


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  •  The tax treatment of (i) publicly traded partnerships or (ii) an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
  •  You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
Formation Transactions and Partnership Structure
 
At or prior to the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:
 
  •  PAA will contribute to us 98.0% of the equity interests in the entities that own its gas storage business, in exchange for           common units,          Series A subordinated units, and           Series B subordinated units, representing an aggregate     % limited partner interest in us;
 
  •  PNGS GP LLC, our general partner and a subsidiary of PAA, will contribute to us 2.0% of the equity interests in the entities that own PAA’s gas storage business, in exchange for a 2.0% general partner interest in us as well as all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $      per quarter;
 
  •  we will issue           common units to the public, representing a     % limited partner interest in us;
 
  •  we will receive net proceeds of approximately $      million from the issuance and sale of           common units at an assumed initial offering price of $      per common unit and we will use the proceeds from this offering as described in “Use of Proceeds;”
 
  •  we expect to enter into a new $400 million credit facility and use the credit facility to repay approximately $200 million of intercompany indebtedness owed to PAA; and
 
  •  we will also enter into an omnibus agreement with PAA and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by PAA’s general partner to us of certain general and administrative services and employees, our agreement to reimburse PAA’s general partner for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Plains All American,” “PAA” and related marks, and other matters. Please read “Certain Relationships and Related Transactions — Agreements Governing the Transactions — Omnibus Agreement.”


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Ownership of PAA Natural Gas Storage, L.P.
 
The diagram below illustrates our organization and ownership based on total units outstanding after giving effect to the offering and the related formation transactions and assumes that the underwriters’ option to purchase additional common units is not exercised.
 
         
Public Common Units
      %
Common Units owned by PAA
      %
Series A Subordinated Units owned by PAA
      %
Series B Subordinated Units owned by PAA
      %(1)
General Partner Interest
    2.0 %
         
Total
    100.0 %
         
 
(FLOW CHART)
 
 
(1) The Series B subordinated units will not be entitled to participate in our quarterly distributions unless and until they convert into Series A subordinated units or common units. The Series B subordinated units are, however, entitled to vote on matters submitted to a vote to our unitholders.


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Management of PAA Natural Gas Storage, L.P.
 
PNGS GP LLC, our general partner, has sole responsibility for conducting our business and for managing our operations. The board of directors and officers of our general partner will make decisions on our behalf. PAA is the sole member of our general partner and will have the right to elect all seven members to the board of directors of our general partner, with at least three of these directors meeting the independence standards established by the New York Stock Exchange. One of such independent directors will be appointed prior to the effectiveness of the registration statement of which this prospectus forms a part. In addition, some of the executive officers and directors of PAA also serve as executive officers and directors of our general partner. For more information about the directors and executive officers of our general partner, please read “Management — Directors and Executive Officers of Our General Partner.”
 
Pursuant to our partnership agreement as well as the omnibus agreement that we will enter into concurrently with the closing of this offering, PAA and our general partner will be entitled to reimbursement for all direct and indirect expenses that they incur on our behalf. In addition, PAA and our general partner will have substantial discretion in incurring third-party expenses on our behalf. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.”
 
As is common with publicly traded partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries.
 
Principal Executive Offices and Internet Address
 
Our principal executive offices are located at 333 Clay St., Suite 1500, Houston, Texas 77002, and our telephone number is (713) 646-4100. Our website will be located at                 and will be activated in connection with the closing of this offering. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.
 
Summary of Conflicts of Interest and Fiduciary Duties
 
General.  Our general partner has a legal duty to manage us in a manner beneficial to holders of our common and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its owner, PAA. Certain of the officers and directors of our general partner are also officers of PAA. As a result, conflicts of interest will arise in the future between us and holders of our common and subordinated units, on the one hand, and PAA and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units and Series A subordinated units, which in turn has an effect on whether our general partner receives incentive cash distributions. In addition, our general partner has the discretion to take actions which may hasten the conversion of Series B subordinated units into Series A subordinated units or common units or Series A subordinated units into common units.
 
Partnership Agreement Modifications to Fiduciary Duties.  Our partnership agreement limits the liability of, and defines the duties owed by, our general partner to holders of our common and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common and subordinated units for actions that might otherwise be challenged under state law standards as a breach of our general partner’s fiduciary duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.


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PAA May Engage in Competition With Us.  While PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business, PAA and its affiliates are not limited in their ability to compete with us.
 
For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”


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The Offering
 
         
     
Common units offered to the public
            common units.
     
              common units if the underwriters exercise their option to purchase additional common units.
     
Units outstanding after this offering
            common units,1          Series A subordinated units and          Series B subordinated units for a total of     limited partner units. The Series B subordinated units will not be entitled to participate in our quarterly distributions, but will convert into Series A subordinated units on a one-for-one basis upon the satisfaction of certain operational and financial conditions, which include achievement of expansion activities and increases in our distribution level. If at the time the operational and financial conditions are satisfied, the subordination period has already ended, the Series B subordinated units will instead convert directly into common units on a one-for-one basis. In addition, our general partner will own a 2.0% general partner interest in us. For additional information regarding our Series B subordinated units, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period — Series B Subordinated Units.”
     
Use of proceeds
  We intend to use the net proceeds of approximately $     , after deducting underwriting discounts, but before paying offering expenses, together with borrowings under our credit facility, to repay intercompany indebtedness owed to PAA in the amount of approximately $     .
         
         
    If the underwriters’ option to purchase     additional common units is exercised in full, we will use the net proceeds to redeem from PAA a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts. Please read “Use of Proceeds.”
 
 
1 Excludes common units subject to issuance under our Long-Term Incentive Plan. Please read “Management — Our Long-Term Incentive Plan.”


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Cash distributions
  Upon completion of this offering, our general partner will establish a minimum quarterly distribution of $     per common unit and Series A subordinated unit ($     per common unit and Series A subordinated unit on an annualized basis) to the extent we have sufficient cash after establishment of reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A and in the glossary included in this prospectus as Appendix B. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions On Distributions.” We will adjust the minimum quarterly distribution payable for the period from the completion of this offering through June 30, 2010, based on the actual length of that period.
     
    Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:
         
      first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $     , plus any arrearages from prior quarters; and
         
      second, 98.0% to the holders of Series A subordinated units and 2.0% to our general partner, until each Series A subordinated unit has received the minimum quarterly distribution of $     .
         
         
    If cash distributions to our unitholders exceed $     per common unit and Series A subordinated unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”
         
         
    The amount of pro forma available cash from distributable cash flow generated during the year ended December 31, 2009 would have been sufficient to allow us to pay only     % of the minimum quarterly distribution ($     per unit per quarter, or $     on an annualized basis) on our common units for such period and would not have been sufficient to pay any distributions on our Series A subordinated units for such period. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

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    We believe that, based on the Statement of Minimum Estimated Available Cash from Distributable Cash Flow included under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient distributable cash flow to pay the minimum quarterly distribution of $     per unit on all common units and Series A subordinated units and the corresponding distributions on our general partner’s 2.0% interest for the four quarters ending June 30, 2011. This should be read in conjunction with “Risk Factors” and “Our Cash Distribution Policy and Restrictions on Distributions.”
     
Series A subordinated units
  PAA will initially own all of our Series A subordinated units. The principal difference between our common units and Series A subordinated units is that in any quarter during the subordination period, holders of the Series A subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Series A subordinated units will not accrue arrearages.
     
Conversion of Series A subordinated units  
The subordination period will end on the first business day after we have earned and paid from distributable cash flow at least (i) $     (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and Series A subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four quarter periods ending on or after June 30, 2013 from distributable cash flow or (ii) $     per quarter (150.0% of the minimum quarterly distribution, which is $     on an annualized basis) on each outstanding common unit and Series A subordinated unit and the corresponding distributions on our general partner’s 2.0% interest and the related distributions on the incentive distribution rights for each of four consecutive quarters ending on or after June 30, 2011.
     
    Distributable cash flow is defined as net income adjusted for (i) any gain or loss from the sale of assets not in the ordinary course of business, (ii) any gain or loss as a result of a change in accounting principles, (iii) any non-cash gains or items of income and any non-cash losses or expenses, including mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities, (iv) any acquisition-related expenses associated with (a) successful acquisitions or (b) all other acquisitions until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence and (v) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received; plus depreciation, depletion and amortization expense; and less maintenance capital expenditures.
     
    In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

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    When the subordination period ends, all Series A subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.
     
Series B subordinated units
  PAA will initially own all of the Series B subordinated units. The Series B subordinated units will not be entitled to participate in our quarterly distributions until they convert into Series A subordinated units or common units.
     
    The Series B subordinated units are designed to compensate PAA for prior capital expenditures made by it to expand the working gas storage capacity at Pine Prairie and the future financial contribution expected to result from such investment. As of the closing of this offering, we expect to have approximately 24 Bcf of aggregate working gas storage capacity at Pine Prairie, including approximately 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010.
     
Conversion of Series B subordinated units  
The Series B subordinated units will convert into Series A subordinated units upon satisfaction of the following operational and financial conditions:
         
                Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 29.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $     per unit (representing an annualized distribution of $     per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $     per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters);
         
                Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 35.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $     per unit (representing an annualized distribution of $     per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $     per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters); and

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                Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 41.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $     per unit (representing an annualized distribution of $     per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $     per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters).
     
    Our general partner will determine whether the in-service operational tests set forth above have been satisfied. To the extent that the above operational and financial tests are satisfied, the Series B subordinated units will convert into Series A subordinated units and participate in the quarterly distribution payable to Series A subordinated units.
     
    Any Series B subordinated units that remain outstanding as of December 31, 2018 will automatically be cancelled.
     
    Following conversion of any Series B subordinated units into Series A subordinated units, such converted Series B subordinated units will further convert into common units (together with any other outstanding Series A subordinated units) to the extent that the tests for conversion of the Series A subordinated units are satisfied. In determining whether such conversion tests have been satisfied, the Series B subordinated units that have converted into Series A subordinated units will be treated as Series A subordinated units from and after the date of their conversion into Series A subordinated units.
     
    If at the time the above operational and financial tests are satisfied, the subordination period has already ended and all outstanding Series A subordinated units have converted into common units, the Series B subordinated units will instead convert directly into common units on a one-for-one basis and participate in the quarterly distribution payable to common units.
     
    For additional information regarding our Series B subordinated units, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period — Series B Subordinated Units.”

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General partner’s right to reset the target distribution levels  
Our general partner has the right, at any time when there are no Series A subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and each target distribution level will be reset to the correspondingly higher amount that causes such reset target distribution level to exceed the reset minimum quarterly distribution by the same percentage that such distribution level exceeds the then-current minimum quarterly distribution.
     
    If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and a general partner interest necessary to maintain its general partner interest in us immediately prior to the reset election. The number of common units to be issued to our general partner will equal the number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”
     
Issuance of additional units
  We have the ability to issue an unlimited number of units without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
     
Limited voting rights
  Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, voting together as a single class, including any units owned by our general partner and its affiliates, including PAA. Upon consummation of this offering, PAA will own an aggregate of approximately     % of our outstanding units. This will give PAA the ability to prevent the involuntary removal of our general partner. Please read “The Partnership Agreement — Voting Rights.”
     
Limited call right
  If at any time our general partner and its affiliates own more than 80.0% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price that is not less than the then-current market price of the common units.

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Estimated ratio of taxable income to distributions
 
We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2012, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $     per unit, we estimate that your average allocable federal taxable income per year will be no more than $     per unit. Please read “Material Income Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”
     
Material income tax consequences
  For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Income Tax Consequences.”
     
Exchange listing
  We intend to apply to list our common units on the New York Stock Exchange under the symbol “PNG.”

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Summary Historical Financial and Operating Data
 
The summary historical financial and operating data below was derived from our audited consolidated balance sheets as of December 31, 2009 and 2008 and the audited consolidated statements of operations, changes in members’ capital and cash flows for the periods of September 3, 2009 to December 31, 2009, January 1, 2009 to September 2, 2009, and the years ended December 31, 2008 and 2007 included elsewhere in this prospectus. The summary historical financial and operating data below for the year ended December 31, 2007 and 2006 was derived from our audited consolidated balance sheets as of December 31, 2007 and 2006 and the consolidated statements of operations, changes in members’ capital and cash flows for the year ended December 31, 2006 not included in this prospectus.
 
On September 3, 2009, PAA became our sole owner by acquiring Vulcan Capital’s 50% interest in us (the “PAA Ownership Transaction”) in exchange for $220 million, including contingent cash consideration of $40 million. At the time of the transaction, the entity had approximately $450 million of outstanding project finance debt. Although we continued as the same legal entity after the transaction, pursuant to applicable accounting principles, all of our assets and liabilities were adjusted to fair value as a result of this transaction. This change in value resulted in a new cost basis for accounting (fair value push down accounting). Accordingly, the selected financial and operating data presented below are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the PAA Ownership Transaction. The Predecessor and Successor periods have been separated by a vertical line to highlight the fact that the financial and operating information for such periods was prepared under two different cost bases of accounting.
 
The summary pro forma statement of operations data for the year ended December 31, 2009 and the summary pro forma balance sheet data as of December 31, 2009 are derived from our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus. The pro forma adjustments have been prepared as if the PAA Ownership Transaction, this offering and the anticipated borrowings under our credit facility had taken place on December 31, 2009 in the case of the pro forma balance sheet, and on January 1, 2009 in the case of the pro forma statement of operations data. A more complete explanation of the pro forma data can be found in our unaudited pro forma condensed combined financial statements.
 
The summary historical financial and operating data should be read in conjunction with the Consolidated Financial Statements, including the notes thereto, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                                                   
    Predecessor       Successor     Pro Forma  
                      January 1,
      September 3,
       
                      2009
      2009
       
    Year Ended
    Year Ended
    Year Ended
    through
      through
    Year Ended
 
    December 31,
    December 31,
    December 31,
    September 2,
      December 31,
    December 31,
 
    2006     2007     2008     2009       2009     2009  
    ($ in thousands except for /Mcf numbers)  
Statement of operations data:
                                                 
Total revenues
  $ 30,831     $ 36,945     $ 49,177     $ 46,929       $ 25,251     $ 72,180  
                                                   
Storage related costs
    100       3,847       8,934       8,792         7,003       15,795  
Operating costs (except those shown below)
    3,658       3,947       4,059       4,820         3,257       8,077  
Fuel expense
    613       1,140       2,320       1,816         578       2,394  
General and administrative expenses
    3,402       3,755       3,874       3,562         4,083       8,897  
Depreciation, depletion and amortization
    3,986       4,520       6,245       8,054         3,578       11,442  
                                                   
Total costs and expenses
    11,759       17,209       25,432       27,044         18,499       46,605  
                                                   
                                                   
Operating income
    19,072       19,736       23,745       19,885         6,752       25,575  
Interest expense
    (8,389 )     (7,108 )     (4,941 )     (4,352 )       (4,262 )     (759 )
Interest income and other income (expense), net
    2,030       5,378       1,669       458         (2 )     456  
Income tax expense
                (887 )     (473 )             (473 )
                                                   
Net income
  $ 12,713     $ 18,006     $ 19,586     $ 15,518       $ 2,488     $ 24,799  
                                                   
                                                   


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    Predecessor       Successor     Pro Forma  
                      January 1,
      September 3,
       
                      2009
      2009
       
    Year Ended
    Year Ended
    Year Ended
    through
      through
    Year Ended
 
    December 31,
    December 31,
    December 31,
    September 2,
      December 31,
    December 31,
 
    2006     2007     2008     2009       2009     2009  
    ($ in thousands except for /Mcf numbers)  
Balance sheet data (at end of period):
                                                 
Total assets
  $ 518,092     $ 674,765     $ 811,436               $ 900,407     $ 900,407  
Long-term debt(1)
    227,300       352,713       415,263                 450,523          
Total debt(1)
    227,300       355,163       417,713                 450,523          
Members’/partners’ capital
    264,109       294,717       363,229                 432,744          
Other financial data:
                                                 
Adjusted EBITDA(2)
  $ 27,395     $ 29,663     $ 31,001     $ 28,701       $ 12,165 (3)   $ 39,614  
Distributable cash flow(2)
  $ 19,006     $ 22,156     $ 25,577     $ 23,965       $ 7,200     $ 37,768  
Maintenance capital expenditures
  $     $     $ 377     $ 384       $ 320     $ 704  
Net cash provided by (used in) operating activities
  $ 13,973     $ 22,343     $ 21,818     $ 22,603       $ 15,265          
Net cash provided by (used in) investing activities
  $ (206,612 )   $ (177,280 )   $ (118,890 )   $ (58,561 )     $ (9,656 )        
Net cash provided by (used in) financing activities
  $ 158,771     $ 145,743     $ 122,344     $ 23,636       $ (22,813 )        
Operating data:
                                                 
Average monthly working capacity (Bcf)(4)(5)
    24       26       28       40         43       41  
Average monthly Firm Storage Services revenue/Mcf
  $ 0.09     $ 0.10     $ 0.13     $ 0.13       $ 0.14     $ 0.14  
Average monthly Hub Services revenue/Mcf
  $ 0.01     $ 0.02     $ 0.01     $ 0.02       $ 0.01     $ 0.01  
Adjusted EBITDA/Mcf
  $ 1.14     $ 1.14     $ 1.11     $ 0.72       $ 0.28     $ 1.00  
 
 
(1) At December 31, 2009, the long-term debt and total debt balances consist of an intercompany note payable to PAA.
 
(2) Adjusted EBITDA and distributable cash flow are defined in “— Non-GAAP and Segment Financial Measures” below.
 
(3) The successor period includes total expenses of approximately $1 million associated with increased personnel costs, including added staffing, and accelerated audit and other costs related to our increased acquisition activities and our efforts to become a publicly traded entity as well as increased overhead allocations from PAA.
 
(4) Calculated as the sum of the capacity at the end of each month divided by the number of months in the period.
 
(5) Includes up to 3 Bcf of storage capacity under lease from third parties.


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Non-GAAP and Segment Financial Measures
 
Adjusted EBITDA and distributable cash flow are supplemental financial measures that are used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
 
We define Adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring.
 
Adjusted EBITDA may be used to assess:
 
  •  our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
 
  •  the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and
 
  •  the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
 
We define distributable cash flow as net income adjusted for (i) any gain or loss from the sale of assets not in the ordinary course of business, (ii) any gain or loss as a result of a change in accounting principles, (iii) any non-cash gains or items of income and any non-cash losses or expenses, including mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities, (iv) any acquisition-related expenses associated with (a) successful acquisitions or (b) all other acquisitions until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence and (v) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received; plus depreciation, depletion and amortization expense; and less maintenance capital expenditures.
 
Distributable cash flow may be used to assess our ability to generate sufficient cash flow to make distributions of the minimum quarterly distribution on all of our outstanding units as well as to satisfy the tests necessary for the conversion of our Series B subordinated units into Series A subordinated units or common units and the conversion of our Series A subordinated units into common units. However, distributable cash flow does not reflect actual cash on hand that is available for distribution to our unitholders.
 
For a discussion of the limitations on our cash distributions and our general partner’s ability to change our cash distribution policy, please read “Our Cash Distribution Policy and Restrictions on Distributions — General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”
 
The GAAP measure most directly comparable to Adjusted EBITDA and distributable cash flow is net income. The supplemental measures of Adjusted EBITDA and distributable cash flow should not be considered as alternatives to GAAP net income. These measures have important limitations as an analytical tool because they exclude some but not all items that affect net income. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for net income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
 
Management compensates for the limitations of Adjusted EBITDA and distributable cash flow as analytical tools by reviewing the comparable GAAP measure, understanding the differences between such measures and net income, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.


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The following table presents a reconciliation of each of these supplemental financial measures of Adjusted EBITDA and distributable cash flow to the GAAP financial measure of net income on a historical and pro forma basis.
 
                                                                     
      Predecessor       Successor     Pro Forma  
      August 18,
                              January 1
      September 3
       
      through
      Year Ended
      Year Ended
      Year Ended
      through
      through
    Year Ended
 
      December 31,
      December 31,
      December 31,
      December 31,
      September 2,
      December 31,
    December 31,
 
      2005       2006       2007       2008       2009       2009     2009  
      ($ in thousands)  
Adjusted EBITDA reconciliation
                                                                   
Net income
    $ 1,696       $ 12,713       $ 18,006       $ 19,586       $ 15,518       $ 2,488     $ 24,799  
Income tax expense
                              887         473               473  
Interest expense, net of amounts capitalized
      1,684         8,389         7,108         4,941         4,352         4,262       759  
Depreciation, depletion and amortization
      1,223         3,986         4,520         6,245         8,054         3,578       11,442  
Selected items impacting EBITDA
                                                                   
Equity compensation expense
              515         553         (110 )       304         1,467       1,771  
Mark-to-market of open derivative positions
              1,792         (524 )       (548 )               370       370  
                                                                     
Adjusted EBITDA
    $ 4,603       $ 27,395       $ 29,663       $ 31,001       $ 28,701       $ 12,165     $ 39,614  
                                                                     
Distributable cash flow reconciliation
                                                                   
Net income
    $ 1,696       $ 12,713       $ 18,006       $ 19,586       $ 15,518       $ 2,488     $ 24,799  
Depreciation, depletion and amortization
      1,223         3,986         4,520         6,245         8,054         3,578       11,442  
Income tax expense
                              887         473               473  
Maintenance capital expenditures
                              (377 )       (384 )       (320 )     (704 )
Other non-cash items:
                                                                   
Non-cash equity compensation expense
              515         154         (216 )       304         1,084       1,388  
Mark-to-market of open derivative positions
              1,792         (524 )       (548 )               370       370  
                                                                     
Distributable cash flow
    $ 2,919       $ 19,006       $ 22,156       $ 25,577       $ 23,965       $ 7,200     $ 37,768  
                                                                     


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RISK FACTORS
 
Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
 
If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.
 
Risks Related to Our Business
 
We may not have sufficient cash following the establishment of reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common units and Series A subordinated units.
 
In order to pay the minimum quarterly distribution of $      per common unit and Series A subordinated unit per quarter, or $      per common unit and Series A subordinated unit per year, we will require available cash of approximately $      million per quarter, or $      million per year, based on the number of common units and Series A subordinated units to be outstanding immediately after completion of this offering, regardless of whether or not the underwriters exercise their option to purchase additional common units. We may not have sufficient available cash from distributable cash flow each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
  •  the rates we charge for storage services and the amount of natural gas storage services our customers purchase from us;
 
  •  the overall balance between the supply of and demand for natural gas, on a seasonal and long-term basis, which impacts the level of demand for the natural gas storage services we provide and the rates we are able to charge for such services;
 
  •  regulatory action affecting the rates we can charge for the services we provide, the demand for natural gas, the supply of natural gas, how we contract for services, our existing contracts, our operating and capital costs and our operating flexibility;
 
  •  the creditworthiness of our customers;
 
  •  the level of competition from other providers of natural gas storage services;
 
  •  the level of our operating and maintenance and general and administrative costs; and
 
  •  prevailing economic conditions.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
  •  the level of capital expenditures we make;
 
  •  the cost of acquisitions;
 
  •  our debt service requirements and other liabilities;
 
  •  fluctuations in our working capital needs;
 
  •  our ability to borrow funds and access capital markets;
 
  •  restrictions contained in debt agreements to which we are a party; and
 
  •  the amount of cash reserves established by our general partner.


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For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”
 
On a pro forma basis, we would not have had sufficient available cash from distributable cash flow to pay the full minimum quarterly distribution on our common units or any distributions on our Series A subordinated units for the year ended December 31, 2009.
 
The amount of available cash from distributable cash flow we need to pay the minimum quarterly distribution for four quarters on all of our common units and Series A subordinated units outstanding immediately after this offering is approximately $     . The amount of our pro forma available cash from distributable cash flow generated during the year ended December 31, 2009 would have been sufficient to allow us to pay only     % of the minimum quarterly distribution on our common units during this period and would not have been sufficient to pay any distributions on our Series A subordinated units during this period. For a calculation of our ability to make distributions to unitholders based on our pro forma results for the year ended December 31, 2009 and for the twelve months ending June 30, 2011, please read, “Our Cash Distribution Policy and Restrictions on Distributions.”
 
The amount of cash we have available for distribution to holders of our common units and Series A subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
 
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
 
The assumptions underlying our minimum estimated available cash from distributable cash flow included in “Our Cash Distribution Policy and Restrictions on Distributions” involve inherent and significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.
 
Our estimate of available cash from distributable cash flow set forth in “Our Cash Distribution Policy and Restrictions on Distributions” has been prepared by management, and we have not received an opinion or report on it from our or any other independent registered public accounting firm. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or Series A subordinated units, in which event the market price of our common units may decline materially. For further discussion on our ability to pay our minimum quarterly distribution, please read “Our Cash Distribution Policy and Restrictions on Distributions.”
 
Increased competition from other companies that provide natural gas storage services or services that can substitute for storage services could have a negative impact on the demand for our services, which could adversely affect our financial results.
 
We compete primarily with other providers of natural gas storage services who own or operate salt-dome, depleted reservoir and/or converted aquifer gas storage facilities. Such competitors include independent storage developers and operators, local distribution companies, utilities, interstate and intrastate gas transmission companies with storage facilities connected to their pipelines and midstream energy companies. FERC has adopted policies that favor the development of new storage projects and there are numerous projects, including expansions of existing facilities and greenfield construction projects, at various stages of development in the markets where Pine Prairie and Bluewater operate. According to FERC data, since 2000, permits have been issued by the FERC for new interstate gas storage facilities or expansions in the Gulf Coast (excluding intrastate facilities and FERC pre-filings for additional storage capacity) representing aggregate additional working gas capacity of approximately 576 Bcf. These projects, if developed and placed into service, may


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compete with our storage operations. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, flexibility and reliability of service.
 
We also compete with certain pipelines, marketers and LNG facilities that provide services that can substitute for certain of the storage services we offer. In addition, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage services.
 
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business. This could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas storage in our markets, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
 
Our natural gas storage operations are subject to regulation by federal, state and local regulatory authorities; regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
 
Our natural gas storage operations are subject to federal, state and local laws and regulations administered by a number of authorities. Because we store natural gas that is transported in interstate commerce, our natural gas storage facilities are subject to comprehensive regulation by the FERC under the Natural Gas Act of 1938, or NGA. Federal regulation under the NGA extends to such matters as:
 
  •  rates, operating terms and conditions of service;
 
  •  the form of tariffs governing service;
 
  •  the types of services we may offer to our customers;
 
  •  the certification and construction of new, or the expansion of existing, facilities;
 
  •  the acquisition, extension, disposition or abandonment of facilities;
 
  •  contracts for service between storage providers and their customers;
 
  •  creditworthiness and credit support requirements;
 
  •  the maintenance of accounts and records;
 
  •  relationships among affiliated companies involved in certain aspects of the natural gas business;
 
  •  the initiation and discontinuation of services; and
 
  •  various other matters.
 
The NGA requires that tariff rates for our interstate gas storage facilities be “just and reasonable.” In addition, under the NGA and applicable FERC regulations, we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to rates or terms and conditions of service.
 
The rates and terms and conditions for interstate services provided by our Pine Prairie and Bluewater facilities are set forth in FERC-approved tariffs, which currently permit both Pine Prairie and Bluewater to charge market-based rates. Market-based rate authority allows Pine Prairie and Bluewater to negotiate rates with individual customers based on market demand. This right to charge market-based rates may be challenged by a party filing a complaint with FERC. Our market-based rate authorization may also be re-examined if we add substantial new storage capacity through expansion or acquisition and as a result obtain market power. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing storage services.
 
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPAct 2005,


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FERC has civil penalty authority under the NGA to impose penalties for certain violations of up to $1,000,000 per day for each violation. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct 2005. Please read “Business — Regulation.”
 
Finally, new rules, regulations or laws may be passed or implemented that impose additional costs, burdens or restrictions on us. We cannot give any assurance regarding the likelihood of such future rules, regulations or laws or the effect they could have on our business, financial condition, results of operations or ability to make distributions to you.
 
Pine Prairie’s and Bluewater’s authorizations to charge “market-based rates” are subject to the continued existence of certain conditions related to these facilities’ competitive position in their respective markets and, if those conditions change, the right to charge “market-based rates” could be terminated.
 
The rates Pine Prairie and Bluewater charge for storage services are regulated by FERC pursuant to its “market-based rate” policy, which allows regulated entities to charge rates different from, and in some cases, less than, those which would be permitted under traditional cost-of-service regulation. Pine Prairie’s and Bluewater’s authorization to charge “market-based rates” is based on determinations by FERC that neither Pine Prairie nor Bluewater have “market power” in their respective markets. The determination that storage facilities lack market power is subject to review and revision by FERC if there is a change in circumstances that could affect the ability of additional storage or interconnected pipeline facilities at Pine Prairie or Bluewater to exercise market power. Among the sorts of changes in circumstances that could raise market power concerns would be an expansion of Pine Prairie’s or Bluewater’s capacity, acquisitions, or other changes in market dynamics. If the FERC were to conclude that Pine Prairie or Bluewater may have acquired and cannot mitigate market power, their rates could become subject to cost-of-service regulation.
 
If Pine Prairie or Bluewater’s rates become subject to cost-of-service regulation, the maximum rates that may be charged for storage services would be established through FERC’s ratemaking process, and Pine Prairie or Bluewater would no longer be able to charge a rate demanded by the market. Generally, cost-of-service based rates for interstate natural gas services are based on the cost of providing service including recovery of, and a reasonable return on, the entity’s actual prudent historical cost investment for providing jurisdictional service. Key determinants in the ratemaking process are costs of providing service, allowed rate of return, and billing determinants, which are based upon storage volumes and contractual capacity commitment assumptions. Rate design and the allocation of costs underlying cost-of-service based rates must also be approved by FERC as part of each rate case. The resolution of these key determinants, particularly the allowed rate of return and billing determinants that would underlie the cost-of-service based rates through the FERC’s ratemaking process, could adversely impact Pine Prairie or Bluewater’s profitability, and have adverse consequences on our cash flow and our ability to make distributions. Additionally, changes in generally applicable FERC ratemaking policies could also affect Bluewater and Pine Prairie.
 
Certain risks are amplified by the current economic environment.
 
During 2007, the U.S. and many key countries began to exhibit signs of economic weakness, which continued throughout 2008 and 2009, and into 2010. This weakness had a severe adverse impact on the global financial system, stressing a number of large financial institutions to the point of failure, merger or requiring government assistance and resulting in a severe reduction in available capital. Capital constraints coupled with significant energy price volatility have produced pervasive liquidity issues for many companies. Such events have created pronounced uncertainty in the economic outlook, and have amplified the potential impact and likelihood of the occurrence of certain risks inherent in our business. Such amplified risks include:
 
  •  increased cost of capital and increased difficulties accessing capital to fund expansion and acquisition activities as well as routine operating requirements;
 
  •  the inability or unwillingness of lenders to honor their contractual commitments;
 
  •  the failure of customers to timely or fully pay amounts due to us;
 
  •  the failure of suppliers to pay third parties under obligations for which we have potential contingent liabilities;


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  •  the potential for adverse actions by rating agencies;
 
  •  potentially adverse changes in tax laws;
 
  •  the failure of counterparties to fulfill their delivery or purchase obligations; and
 
  •  business failures by vendors, suppliers or customers.
 
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our business.
 
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline.
 
In addition to volatility and seasonality, an extended period of high gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated expansion activities. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business and financial results.
 
We may not be able to maintain or replace expiring storage contracts.
 
Our primary exposure to market risk occurs at the time our existing storage contracts expire and are subject to renegotiation and renewal. Effective as of April 1, 2010, the weighted average remaining tenor of our existing portfolio of firm storage contracts will be approximately 3.9 years at Pine Prairie and approximately 2.2 years at Bluewater. For the year ended December 31, 2009, Iberdrola Renewables, Inc. and Guardian Pipeline, LLC accounted for approximately 17% and 13% of our revenues, respectively. The extension or replacement of existing contracts, including our contracts with Iberdrola Renewables, Inc. and Guardian Pipeline, LLC, depends on a number of factors beyond our control, including:
 
  •  the level of existing and new competition to provide storage services to our markets;
 
  •  the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
 
  •  the extent to which the customers in our markets are willing to contract on a long-term basis; and
 
  •  the effects of federal, state or local regulations on the contracting practices of our customers.
 
Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
 
Our storage business depends on third-party pipelines connected to our storage facilities, and we could be negatively impacted by circumstances beyond our control that temporarily or permanently interrupt the operation of such pipelines.
 
We depend on the continued operation of third-party pipelines and other facilities that provide delivery options to and from our storage facilities. For example, at our Pine Prairie facility, we have nine separate interconnect points with eight different interstate pipelines, and at our Bluewater facility, we are connected to three interstate and three intrastate natural gas pipelines. Because we do not own the pipelines that are interconnected to our facilities, their continued operation is not within our control. If any of the pipelines to which we are connected were to become unavailable for current or future withdrawals or injections of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and satisfy our customers needs could be compromised, thereby potentially reducing our revenues. Any temporary or permanent interruption at any key pipeline or other interconnect point with our gas storage


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facilities that caused a material reduction in the volume of storage services provided by us could have a material adverse effect on our business, financial condition, results of operation and ability to make distributions.
 
In addition, the rates charged by pipelines interconnected with our storage facilities for transportation to and from our facilities affects the utilization and value of the storage services we provide. Significant changes in the rates charged by these pipelines or their competitors could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
 
We may not be able to achieve our current expansion plans at our Pine Prairie facility on economically viable terms.
 
Our current expansion plans include the addition of 31 Bcf of working gas storage capacity at our Pine Prairie facility, 28 Bcf of which we expect to place into service by mid-2012, including 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010. In connection with these expansion efforts, we may encounter difficulties in the drilling required to access subsurface storage caverns, the drilling of raw water wells or salt water disposal wells and the completion of the wells. These risks include the following:
 
  •  unexpected operational events;
 
  •  adverse weather conditions;
 
  •  facility or equipment malfunctions or breakdowns;
 
  •  unusual or unexpected geological formations;
 
  •  drill bit or drill pipe difficulties;
 
  •  collapses of wellbore, casing or other tubulars or other loss of drilling hole;
 
  •  unexpected problems associated with filling the caverns with base gas and conducting pressure and mechanical integrity tests;
 
  •  unexpected problems associated with leaching the caverns, filtration of extracted water and offsite disposal of water; and
 
  •  risks associated with subcontractors’ services, supplies, cost escalation and personnel.
 
Specifically, the creation of a salt-cavern storage facility requires sourcing, injecting, withdrawing and disposing of significant volume of water. For example, to create 10 Bcf of working capacity, a salt cavern requires approximately 73 million barrels of raw water supply and an equivalent volume of salt water disposal. Additionally, the rate of access to raw water and the rate of disposal of salt water have a direct impact on the time it takes to create a salt cavern. Any physical or regulatory restriction imposed on our current operations with respect to accessing raw water or disposing of salt water would have an adverse impact on our ability to timely and fully expand our facility at Pine Prairie. During the initial construction of Pine Prairie, we encountered challenges related to many of the factors listed above and specifically with respect to the ability to efficiently dispose of salt water, all of which resulted in substantial delays and the incurrence of significant costs in excess of our original estimates. There can be no assurance that we will not encounter similar situations in the future or that our ability to access raw water or dispose of salt water will not be adversely impacted in the future. Additionally, the occurrence of uninsured or under-insured losses, delays or operating cost overruns associated with these drilling efforts could have a negative impact on our operations and financial results.
 
We may not be able to increase the capacity of our Pine Prairie facility beyond our current expansion plans.
 
While we have both the property rights and operational capacity necessary to expand our Pine Prairie facility beyond the currently permitted capacity of 48 Bcf to a potential of over 150 Bcf of total working gas storage capacity, we may not be able to secure the financing or permits necessary to pursue such expansion and the necessary infrastructure modifications that would be needed to accommodate such expansion. Additionally, such expansion will be subject to market demand, the successful execution of any expansion projects and the availability of sufficient third-party interstate and intrastate pipelines receipt and deliverability capacity to accommodate the increased capacity. Any combination of these factors may prevent us from expanding our Pine Prairie facility beyond its current permitted capacity.


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We are exposed to the credit risk of our customers in the ordinary course of our business.
 
As a normal part of our business we extend credit to our customers. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. While we have established credit policies that include assessing the creditworthiness of our customers as permitted by Pine Prairie’s and Bluewater’s tariffs and requiring appropriate terms or credit support from them based on the results of such assessments, there can be no assurance that we have adequately assessed the creditworthiness of our existing or future customers or that there will not be unanticipated deterioration in their creditworthiness. Resulting nonpayment and/or nonperformance by our customers could have a material adverse effect on our business, financial condition, results of operation and ability to make distributions.
 
Additionally, in instances where we loan natural gas to third parties, the magnitude of our credit risk is significantly increased, as the failure of the third party to return the loaned volumes would result in losses equal to the full value of the loaned natural gas rather than, in the case of firm storage or hub services contracts, losses equal to fees on volumes nominated for injection or withdrawal.
 
For various operating and commercial reasons, we may not be able to perform all of our obligations under our contracts, which could lead to increased costs and negatively impact our financial results.
 
Various operational and commercial factors could result in an inability on our part to satisfy our contractual commitments and obligations. For example, in connection with our provision of firm storage services and hub services to our customers, we enter into contracts that obligate us to honor our customers’ requests to inject gas into our storage facilities, withdraw gas from our facilities and wheel gas through our facilities, in each case subject to volume, timing and other limitations set forth in such contracts. The following factors could adversely impact our ability to perform our obligations under these contracts:
 
  •  a failure on the part of our storage facilities to perform as we expect them to, whether due to malfunction of equipment or facilities or realization of other operational risks;
 
  •  the operating pressure of our storage facilities:
 
  •  the operating pressure of our depleted reservoir storage facilities is driven primarily by the total volume of working and base gas contained in the reservoir, which depends primarily on the amount of base gas purchased by us and injected into the facility, the amount of base gas we may have loaned to third parties and the aggregate injection or withdrawal demands of our customers; and
 
  •  the operating pressure of our salt-cavern storage facilities is directly affected by the volume and temperature of natural gas within each facility. The total volume of gas in our salt caverns is driven by the same factors mentioned above for our depleted reservoirs. The temperature of the natural gas stored in a salt cavern is driven by a number of factors, including the ambient subsurface temperature for such cavern (i.e., the static subsurface temperature to which the stored gas will naturally return over time) and the rate of injection or withdrawal of gas from such cavern (due to the fact that sustained periods of high rates of withdrawal reduce the temperature of the remaining gas and sustained periods of high rates of injection have the opposite effect). Higher than normal temperatures generally equate with higher than normal pressures and require more space to store the same volume of gas and remain in compliance with maximum pressure limitations imposed by prudent operating practices or regulations. Lower than normal temperatures generally equate with lower than normal pressures and require more base gas to meet contractual withdrawal obligations and remain in compliance with minimum pressure limitations imposed by prudent operating practices or regulations;
 
  •  a variety of commercial decisions we make from time to time in connection with the management and operation of our storage facilities. Examples include, without limitation, decisions with respect to matters such as (i) the aggregate amount of commitments we are willing to make with respect to wheeling, injection, and withdrawal services, which could exceed our capabilities at any given time for various reasons, (ii) the timing of scheduled and unplanned maintenance or repairs, which can impact equipment availability and capacity, (iii) the schedule for and rate at which we conduct leaching


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  activities at our Pine Prairie facility in connection with the creation of new salt caverns or the expansion of existing caverns, which can impact the amount of storage capacity we have available to satisfy our customers’ requests, (iv) the timing and aggregate volume of any base gas park and/or loan transactions we consummate, which can directly affect the operating pressure of our storage facilities and (v) the amount of compression capacity and other gas handling equipment that we install at our facilities to support gas wheeling, injection and withdrawal activities; and
 
  •  adverse operating conditions due to hurricanes, extreme weather events or conditions, and operational problems or issues with third party pipelines, storage or production facilities.
 
Although we manage and monitor all of these various factors in connection with the ongoing operation of our natural gas storage facilities with the goal of performing all of our contractual commitments and obligations and optimizing our revenue, one or more of the above factors may adversely impact our ability to satisfy our injection, withdrawal or wheeling obligations under our storage contracts. In such event, we may be liable to our customers for losses or damages they suffer and/or we may need to incur costs or expenses in order to permit us to satisfy our obligations and avoid a breach or increase our costs in doing so.
 
For example, if Pine Prairie experiences sustained periods of high injections as it approaches full capacity and the resulting cavern temperature and pressure would otherwise exceed the maximum operating pressure, we may be required to loan a portion of our base gas to third parties in order to create the space we need to permit us to honor our customers’ injection requests. In connection with any such base gas loans, we will be required to pay fees that could be significant. Conversely, if Pine Prairie experiences sustained periods of high withdrawals as customers withdraw their inventory and an abnormally low cavern temperature results in a significant reduction in pressure, we may be required to borrow gas from a third party and inject it into our facility or inject raw water into our facility, in each case in order to maintain our minimum operating pressure or create the operating pressure needed to satisfy our customers’ withdrawal requests. In such a circumstance we would have to (i) pay fees to a third party to borrow additional gas or (ii) incur operating costs associated with raw water injection, removal and disposal and opportunity costs associated with the temporary loss of usable storage capacity displaced by the injected water.
 
Our marketing activities could result in financial losses.
 
Without altering our basic commercial strategy of committing a high percentage of our storage capacity under multi-year firm storage contracts at attractive rates, we intend to establish a dedicated commercial marketing group that will capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. Through these transactions, we will seek to maintain a position that is substantially balanced between purchases on the one hand and sales or future delivery obligations on the other hand. Our general policy will be (i) to purchase natural gas only in situations where we have a market for such gas, (ii) to utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that commodity price fluctuations will not have a material adverse impact on our cash flow and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes. While we intend to conduct these transactions within these pre-defined risk parameters, these policies will not eliminate all risks. For example, any event that disrupts our anticipated physical supply of or market for natural gas could expose us to significant costs or expenses in order to enable us to satisfy our obligations to store or deliver contracted natural gas volumes.
 
We are subject to environmental laws and regulations that may expose us to significant costs and liabilities.
 
Our natural gas storage operations are subject to stringent and complex federal, state and local environmental laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities, increases in operating expenses or curtailment of certain operations to limit or prevent releases of materials from our


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facilities, the incurrence of capital expenditures associated with the installation of pollution control equipment, and the imposition of substantial liabilities for pollution resulting from our operations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the costs of any remediation of environmental contamination that may become necessary, and these costs could be material. For example, the adoption and implementation of any climate change legislation or regulations imposing reporting obligations with respect to, or limiting emissions of, “greenhouse gases” could result in increased operating costs and adversely affect demand for natural gas.
 
Numerous governmental authorities, such as the U.S. Environmental Protection Agency and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. In addition, joint and several liability or strict liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover all or any of these costs through insurance or other means, which may have a material adverse effect on our business, financial condition, results of operation and ability to make distributions. Please read “Business — Environmental Matters” for more information.
 
If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.
 
A principal focus of our strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends on our ability to complete expansion projects and make acquisitions that result in an increase in cash generated from operations on a per unit basis (i.e., are accretive). We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:
 
  •  we are unable to identify attractive expansion projects or acquisition candidates that satisfy our economic and other criteria, or we are outbid for such opportunities by our competitors;
 
  •  we are unable to raise financing for such expansion projects or acquisitions on economically acceptable terms;
 
  •  we are unable to secure adequate customer commitments to use the facilities to be expanded or acquired; or
 
  •  we are unable to obtain governmental approvals or other rights, licenses or consents needed to complete such expansion projects or acquisitions.
 
Acquisitions or expansion projects that we complete may not perform as anticipated and could result in a reduction of our distributable cash flow on a per unit basis.
 
Even if we complete expansion projects or acquisitions that we believe will be accretive, such projects or acquisitions may nevertheless reduce our available cash from distributable cash flow on a per unit basis due to the following factors:
 
  •  mistaken assumptions about storage capacity, deliverability, base gas needs, geological integrity, revenues, synergies, costs (including operating and general and administrative, capital, debt and equity costs), customer demand, growth potential, assumed liabilities and other factors;
 
  •  an inability to complete expansion projects on schedule and within applicable budgets due to various factors, including cost overruns, schedule delays, and the inability to obtain necessary permits or approvals;


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  •  the failure to receive cash flows from an expansion project or newly acquired asset due to delays in the commencement of operations for any reason;
 
  •  unforeseen operational issues or the realization of liabilities that were not known to us at the time the acquisition or expansion project was completed;
 
  •  the inability to attract new customers or retain acquired customers to the extent assumed in connection with the expansion or acquisition project;
 
  •  the failure to successfully integrate expansion projects or acquired assets or businesses into our operations and/or the loss of key employees; or
 
  •  the impact of regulatory, environmental, political and legal uncertainties that are beyond our control.
 
If we consummate any future expansion projects or acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources. If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per common unit and Series A subordinated unit, our ability to make distributions may be reduced.
 
We could lose the benefits of the Pine Prairie tax abatement.
 
In May 2006, we entered into an arrangement with the Industrial Development Board No. 1 of the Parish of Evangeline, State of Louisiana, Inc. (the “Industrial Development Board”), pursuant to which we sold a portion of the Pine Prairie facility located in the parish to the Industrial Development Board and entered into a 15-year agreement, which commenced in January of 2008, to lease back such portion of the facility. Pursuant to this arrangement and in exchange for certain payments in lieu of taxes, we are not subject to ad valorem property tax in Evangeline Parish except for ad valorem tax on inventory. As of December 31, 2009, the present value of the tax abatement was approximately $23 million. We classify the present value of the tax abatement as an intangible asset, so if we were to lose the tax abatement due to a successful legal challenge of the arrangement, our violation of the terms of the lease, or for any other reason, it would be a charge to our earnings and could have an adverse impact on our results of operations and ability to make distributions. See “Business — Title to Properties and Rights-of-Way.”
 
Our natural gas storage facilities are new and have limited operating history. The facilities may not be able to deliver as anticipated, which could prevent us from meeting our contractual obligations and cause us to incur significant costs.
 
Although we believe that our operating gas storage facilities at Bluewater and Pine Prairie have been designed to meet our contractual obligations with respect to wheeling, injection, withdrawal and gas specifications, the facilities are new and have a limited operating history. If we fail to wheel, inject or withdraw natural gas at contracted rates, or cannot deliver natural gas consistent with contractual quality specifications, we could incur significant costs to satisfy our contractual obligations. These costs could have an adverse impact on our business, financial condition, results of operations and ability to make distributions.
 
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.
 
Our operations are subject to all of the risks and hazards inherent in the natural gas storage business, including:
 
  •  reduction of our available storage capacity at our salt caverns over time due to (i) unexpected increases in the temperature of our caverns, which reduces capacity as a result of the expansion of the stored natural gas, (ii) the long-term effect of pressure differentials between the caverns and the surrounding salt formations (known as “salt creep”) or (iii) problems with the structural integrity of our salt caverns;
 
  •  subsidence of the geological structures where we store natural gas;


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  •  risks and hazards inherent in drilling operations associated with the development of new caverns and/or the drilling of raw water wells or salt water disposal wells;
 
  •  problems maintaining the wellbores and related equipment and facilities that form a part of the infrastructure that is critical to the operation of our storage facilities;
 
  •  impacts to our operations due to the unavailability of raw water for any reason or the inability to dispose of salt water through our salt water disposal wells for any reason;
 
  •  damage to our storage facilities, related equipment and connecting pipelines and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
 
  •  inadvertent damage from third parties, including construction, farm and utility equipment;
 
  •  leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
 
  •  collapse of storage caverns;
 
  •  operator error;
 
  •  environmental pollution or other environmental issues, including drinking water contamination, associated with our raw water or water disposal wells or our water treatment facilities;
 
  •  damage associated with equipment or material failures, pipeline or vessel ruptures or corrosion, explosions, fires and other incidents; and
 
  •  other hazards that could result in personal injury and loss of life, pollution and suspension of operations.
 
These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. In addition, we are not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.
 
In addition, we share insurance coverage with PAA, for which we reimburse PAA’s general partner pursuant to the terms of the omnibus agreement. To the extent PAA experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.
 
If leakage or migration of natural gas or other hydrocarbons occurs from any of our storage facilities, our operations and financial results could be adversely affected.
 
Our operations are subject to the risk that natural gas or other hydrocarbons could leak or migrate from our storage facilities, causing a loss of volumes stored in the storage facilities. This risk could cause substantial losses due to our inability to deliver the stored volumes back to our customers. Furthermore, we may not be able to obtain insurance to protect against this risk and we may not be able to maintain insurance of the type and amount we desire at reasonable rates to insure against this risk.


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Restrictions in our anticipated credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our units.
 
We expect to have a credit facility available to us concurrent with the closing of the offering. Our credit facility is likely to restrict our ability to, among other things:
 
  •  incur additional debt;
 
  •  make distributions on or redeem or repurchase units;
 
  •  make certain investments and acquisitions;
 
  •  incur or permit certain liens to exist;
 
  •  enter into certain types of transactions with affiliates;
 
  •  merge, consolidate or amalgamate with another company; and
 
  •  transfer or otherwise dispose of assets.
 
Furthermore, our credit facility may contain covenants requiring us to maintain certain financial ratios.
 
The provisions of our credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit facility could result in an event of default which could enable our lenders, subject to the terms and conditions of the anticipated credit facility, to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.
 
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
 
Our future level of debt could have important consequences to us, including the following:
 
  •  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
 
  •  our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
 
  •  we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
 
  •  our flexibility in responding to changing business and economic conditions may be limited.
 
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
 
For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”


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We are considered a subsidiary of PAA under its debt instruments and, as such, we may be directly or indirectly subject to and impacted by certain restrictions in PAA’s existing and future credit facilities and indentures. These restrictions may limit our access to credit, prevent us from engaging in beneficial activities, and in certain circumstances, require us to guarantee PAA’s indebtedness.
 
Although we are not contractually bound by and are not liable for PAA’s debt under its debt instruments, we are subject to and indirectly affected by certain prohibitions and limitations contained therein. Such restrictions may prevent us from obtaining the most advantageous financing terms or from engaging in certain transactions that might otherwise be considered beneficial. For example (by reference to the most restrictive of any applicable covenant):
 
  •  We will be restricted from entering into any future sale/leaseback transactions.
 
  •  PAA is subject to a limit of 10% of PAA’s consolidated net tangible assets with respect to the amount of debt that can be secured by liens on facilities owned by its subsidiaries, including us. We cannot control the incurrence of secured debt by PAA’s other subsidiaries.
 
  •  We cannot give intercompany guaranties of debt for borrowed money for the benefit of PAA or any subsidiary of PAA (including any of our subsidiaries) unless we agree to guarantee PAA’s outstanding debt. The same restriction would apply to a guaranty of our debt by one of our subsidiaries.
 
Although we believe that the restrictions in PAA’s debt instruments will not have a material impact on our operations or access to credit, no assurance can be given to that effect, and PAA’s ability to comply with any restrictions in PAA’s debt instruments may be affected by events beyond our control.
 
Any debt instruments that PAA enters into in the future, including any amendments to its existing credit facilities, may include additional or more restrictive limitations on our ability to conduct our business. These additional restrictions could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities. In addition, PAA has the ability to prevent us from taking actions that would cause PAA to violate any covenants in its credit facilities or indentures, or otherwise to be in default under any of its debt instruments. In deciding whether to prevent us from taking any such action, PAA will have no fiduciary duty to us or our unitholders.
 
The credit and risk profile of our general partner and its owner, PAA, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
 
The credit and business risk profiles of our general partner and PAA may be factors considered in credit evaluations of us. This is because our general partner, which is owned by PAA, controls our business activities, including our cash distribution policy and expansion strategy. Any adverse change in the financial condition of PAA, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, may adversely affect our credit ratings and risk profile.
 
If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or PAA, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of PAA and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.
 
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.
 
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by


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the level of our cash distributions and our implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.
 
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
 
Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2011. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
 
Risks Inherent in an Investment in Us
 
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
 
In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.


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Cost reimbursements due to PAA’s general partner and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to you. The amount and timing of such reimbursements will be determined by PAA’s general partner.
 
Prior to making distributions on our common units, we will reimburse PAA’s general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by PAA, its general partner or our general partner in managing and operating us. These operating expense reimbursements and the reimbursement of incremental general and administrative expenses we will incur as a result of becoming a publicly traded partnership are not capped. In addition, PAA and our general partner will have substantial discretion in incurring third-party expenses on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursements to PAA’s general partner and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.
 
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
 
Our general partner has the right, at any time when there are no Series A subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and each target distribution level will be reset to the correspondingly higher amount that causes such reset target distribution level to exceed the reset minimum quarterly distribution by the same percentage that such distribution level exceeds the then-current minimum quarterly distribution.
 
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and will retain its then-current general partner interest. The number of common units to be issued to our general partner will equal the number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Target Distribution Levels.”
 
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on


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account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
 
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states in which we do business or may do business in from time to time in the future. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
 
  •  we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.
 
For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”
 
Holders of our common units have limited voting rights and are not entitled to elect the directors of our general partner.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect the directors of our general partner. The board of directors of our general partner will be chosen by PAA. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
 
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
 
The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove our general partner. Following the closing of this offering, PAA will own an aggregate of approximately     % of our outstanding units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining Series A subordinated units and Series B subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our then-existing common units by prematurely eliminating their distribution and liquidation preference over our Series A subordinated units and Series B subordinated units, which would otherwise have continued until we had met certain distribution, performance and operational tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most


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likely result in the termination of the subordination period and conversion of all Series A subordinated units and Series B subordinated units to common units.
 
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
 
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of PAA to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner may then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
 
Upon closing of the offering, investors in our common units will experience immediate and substantial dilution in pro forma net tangible book value of $      per common unit.
 
The estimated initial public offering price of $      per common unit exceeds our pro forma net tangible book value of $      per common unit. Based on the estimated initial public offering price of $      per common unit, you will incur immediate and substantial dilution of $      per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”
 
We may issue additional units without your approval, which would dilute your existing ownership interests.
 
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •  our existing unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be Series A subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
  •  the ratio of taxable income to distributions may increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
 
PAA may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
 
After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, PAA will hold          common units,           Series A subordinated units and          Series B subordinated units. All of the Series A subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain


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circumstances. The Series B subordinated units are also eligible for conversion into common units if certain operational and financial conditions are satisfied and the end of the subordination period has occurred. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. A sale or transfer, including certain deemed transfers, by PAA of all or portions of its interests in us may cause our partnership to terminate for federal income tax purposes. For a discussion of the impact this could have on common unitholders, please read “Tax Risks to Common Unitholders — The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.”
 
There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.
 
Prior to this offering, there has been no public market for our common units. After this offering, there will be only           publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
 
The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:
 
  •  our quarterly or annual earnings or those of other companies in our industry;
 
  •  the loss of a large customer;
 
  •  announcements by us or our competitors of significant contracts or acquisitions;
 
  •  changes in accounting standards, policies, guidance, interpretations or principles;
 
  •  general economic conditions;
 
  •  the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;
 
  •  future sales of our common units; and
 
  •  other factors described in these “Risk Factors.”
 
We will incur increased costs as a result of being a publicly traded partnership.
 
We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain


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qualified persons to serve on its board of directors or as executive officers. We have included $2.6 million of estimated incremental costs per year associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
 
Risks Related to Conflicts of Interest
 
PAA owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. PAA and our general partner have conflicts of interest and may favor PAA’s interests to your detriment.
 
Following this offering, PAA will own and control our general partner, as well as appoint all of the officers and directors of our general partner, some of whom will also be officers of PAA’s general partner. Although our general partner has a legal duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a legal duty to manage our general partner in a manner that is beneficial to its owner, PAA. Conflicts of interest may arise between PAA and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of PAA over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
 
  •  neither our partnership agreement nor any other agreement requires PAA to pursue a business strategy that favors us. Directors and officers of PAA’s general partner have legal duties to make these decisions in the best interests of the owners of PAA, which may be contrary to our interests;
 
  •  while PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business, PAA and its affiliates are not limited in their ability to compete with us;
 
  •  our general partner is allowed to take into account the interests of parties other than us, such as PAA, in resolving conflicts of interest;
 
  •  certain of the officers of our general partner will also devote significant time to the business of PAA and will be compensated by PAA’s general partner accordingly;
 
  •  our partnership agreement limits the liability of and defines the duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might otherwise constitute breaches of fiduciary duty under default state law standards;
 
  •  our partnership agreement contains provisions designed to facilitate PAA’s ability to provide us with financial support while reducing concerns regarding conflicts of interest by defining certain potential financing transactions between PAA and us as fair to our unitholders;
 
  •  except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
 
  •  our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of cash reserves. Each of these determinations can affect the amount of cash that is distributed to our unitholders and to our general partner, the ability of the Series A subordinated units to convert to common units and the achievement of the financial conditions necessary for the Series B subordinated units to convert to Series A subordinated units or common units;
 
  •  our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces distributable cash flow. These determinations can affect the amount of cash that is distributed to our unitholders and to our general partner, the ability of the Series A subordinated units to convert to common units and the Series B subordinated units to convert to Series A subordinated units or common units;


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  •  our general partner will determine the amount and timing of the planned expansions of our Pine Prairie facility, and as a result, the achievement of the operational conditions necessary for the Series B subordinated units to convert to Series A subordinated units or common units, as applicable;
 
  •  our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the Series A subordinated units, to make incentive distributions or to make distributions to achieve the financial conditions necessary for the Series B subordinated units to convert to Series A subordinated units for the Series A subordinated units to convert to common units;
 
  •  our partnership agreement permits us to distribute up to $40 million from capital sources without treating such distribution as a distribution from capital;
 
  •  our general partner determines which costs incurred by it are reimbursable by us;
 
  •  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
  •  our general partner intends to limit its liability regarding our contractual and other obligations;
 
  •  our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units;
 
  •  our general partner controls the enforcement of the obligations that it and its affiliates owe to us;
 
  •  our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
 
  •  our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
Please read “Conflicts of Interest and Fiduciary Duties.”
 
PAA may engage in competition with us.
 
Although PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business, PAA and its affiliates are not limited in their ability to compete with us.
 
Our partnership agreement defines and modifies the duties of our general partner and restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner.
 
Our partnership agreement contains provisions that define the standard of care that our general partner must exercise and restrict the remedies available to unitholders for actions taken by our general partner in accordance with that standard of care, including in circumstances that might otherwise be challenged under state law standards. For example, our partnership agreement:
 
  •  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples of decisions that our general partner may make in its individual capacity include:
 
  (a)  how to allocate corporate opportunities among us and our general partner’s affiliates;
 
  (b)  whether to exercise its limited call right;
 
  (c)  how to exercise its voting rights with respect to the units it owns;


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  (d)  whether to exercise its registration rights;
 
  (e)  whether to elect to reset target distribution levels; and
 
  (f)  whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
 
  •  provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
 
  •  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it subjectively believed that the decision was in, or not opposed to, the best interests of our partnership;
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal;
 
  •  generally provides that any resolution or course of action adopted by our general partner and its affiliates in respect of a conflict of interest will be permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement or any duty stated or implied by law or equity if the resolution or course of action in respect of such conflict of interest is:
 
(a) approved by the conflicts committee of our general partner after due inquiry, based on a subjective belief that the course of action or determination that is the subject of such approval is fair and reasonable to us;
 
(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
 
(c) determined by our general partner (after due inquiry) to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
(d) determined by our general partner (after due inquiry) to be fair and reasonable to us, taking into account the totality of the circumstances and relationships involved, including other matters that may be favorable or advantageous to us; and
 
  •  provides that, to the fullest extent permitted by law, in connection with any action or inaction of, or determination made by, our general partner’s board of directors or its conflicts committee with respect to any matter relating to us, it shall be presumed that our general partner’s board of directors or its conflicts committee acted in a manner that satisfied the contractual standards set forth in our partnership agreement, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or our partnership challenging any such action or inaction of, or determination made by, our general partner, the person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption.
 
By purchasing a common unit, a common unitholder agrees to become bound by the provisions of the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Duties of our General Partner.”


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Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
 
Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, PAA will own approximately     % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the Series A subordinated units), PAA will own approximately     % of our outstanding common units. Upon the satisfaction of certain operational and financial conditions and the end of the subordination period having occurred, assuming no additional issuances of common units (other than upon the conversion of the Series A subordinated units and the ultimate conversion of the Series B subordinated units to common units), PAA will own approximately     % of our outstanding common units For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”
 
Tax Risks to Common Unitholders
 
In addition to reading the following risk factors, you should read “Material Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or the IRS, on this or any other tax matter affecting us.
 
Despite the fact that we are classified as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax


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would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Specifically, we will be subject to an entity-level tax on any portion of our income that is generated in Texas in the prior year. Imposition of any such additional taxes on us will reduce the cash available for distribution to our unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, our target distribution amounts will be adjusted to reflect the impact of that law on us.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
The tax treatment of (i) publicly traded partnerships or (ii) an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present U.S. federal income tax treatment of (i) publicly traded partnerships, including us, or (ii) an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. Although the considered legislation would not appear to have affected our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
 
You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, PAA will own more than 50% of the total interests in our capital and profits interests. Therefore, a transfer by PAA of all or a portion of its interests in us, including a deemed transfer as a result of a termination of PAA’s partnership for federal income tax purposes, could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year


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other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material Income Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.
 
Tax gain or loss on the disposition of our common units could be more or less than expected.
 
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Income Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.
 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
 
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
 
The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please


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read “Material Income Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopt.
 
We will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
 
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
 
Because there is no tax concept of loaning a partnership interest, a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.


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You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
 
In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and conduct business in the states of Louisiana and Michigan. Each of these states currently imposes a personal income tax and also impose income taxes on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.


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USE OF PROCEEDS
 
We expect to receive net proceeds of approximately $      million, after deducting underwriting discounts and commissions but before paying offering expenses, from the issuance and sale of           common units offered by this prospectus. We expect to use these net proceeds, together with borrowings under our new credit facility, to repay intercompany indebtedness owed to PAA in the amount of approximately $     . PAA expects to use all or a portion of these proceeds to repay amounts outstanding under its credit facilities and for general partnership purposes.
 
As of December 31, 2009, we had approximately $451 million of intercompany indebtedness outstanding to PAA with a fixed interest rate of 6.5% incurred to refinance project debt and for capital expenditures.
 
Our estimates assume an initial public offering price of $      per common unit and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, to increase or decrease by $      million. If the proceeds increase due to a higher initial public offering price, we will use the additional proceeds to repay any remaining amounts under the intercompany indebtedness owed to PAA and for general partnership purposes. If the proceeds decrease due to a lower initial public offering price, we will decrease the amount of our repayment of the intercompany indebtedness owed to PAA.
 
The proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem from PAA a number of common units corresponding to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts.
 
Affiliates of Barclays Capital Inc. and UBS Securities LLC are lenders under PAA’s credit facilities and will receive their proportionate share of any repayment by PAA of its credit facilities in connection with this transaction.


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CAPITALIZATION
 
The following table shows:
 
  •  our historical capitalization as of December 31, 2009; and
 
  •  our as adjusted capitalization as of December 31, 2009, reflecting this offering of           common units at an assumed initial public offering price of $     , the other formation transactions described under “Summary — Formation Transactions and Partnership Structure” and the application of the net proceeds from this offering as described under “Use of Proceeds.”
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                 
    As of December 31, 2009  
    Historical     As Adjusted  
    (in thousands)  
 
Cash and cash equivalents
  $ 3,124     $          
Revolving credit facility
             
Note payable to PAA
    450,523          
                 
Total debt
    450,523          
Members’ equity
    432,744          
                 
Total capitalization
  $ 883,267     $  
                 


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DILUTION
 
Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per common unit after the offering. On a pro forma basis as of December 31, 2009, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $      million, or $      per common unit. Net tangible book value excludes $47 million of net goodwill and intangible assets. Purchasers of common units in this offering will experience immediate and substantial dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:
 
                 
Assumed initial public offering price per common unit
          $        
Net tangible book value per common unit before the offering(1)
               
Increase in net tangible book value per common unit attributable to purchasers in the offering
                   
                 
Less: Pro forma net tangible book value per common unit after the offering(2)
               
                 
Immediate dilution in net tangible book value per common unit to purchasers in the offering(3)
          $    
                 
 
 
(1) Determined by dividing the number of units (           common units,           Series A subordinated units,           Series B subordinated units and the corresponding value for the 2.0% general partner interest to be issued to our general partner and its affiliates, including PAA, for the contribution of assets and liabilities to us) into the net tangible book value of the contributed assets and liabilities.
 
(2) Determined by dividing the total number of units to be outstanding after the offering (           common units,           Series A subordinated units,           Series B subordinated units and the corresponding value for the 2.0% general partner interest) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.
 
(3) If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $      and $     , respectively. Because the proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem an equal number of common units from PAA, any exercise of the underwriters’ option to purchase additional common units will not have a dilutive effect.
 
The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:
 
                                 
    Units Acquired     Total Consideration  
    Number     Percent     Amount     Percent  
                (in thousands)        
 
General partner and affiliates(1)(2)(3)
                      %   $                   %
Purchasers in the offering
            %   $         %
                                 
Total
            100.0 %   $         100.0 %
                                 
 
 
(1) The units acquired by our general partner and its affiliates, including PAA, consist of          common units,          Series A subordinated units and          Series B subordinated units. Our general partner also owns a 2.0% general partner interest in us.
 
(2) The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of          , 2010, equals parent net investment, which was $      million and is not affected by this offering.
 
(3) Assumes the underwriters’ option to purchase additional common units is not exercised.


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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
 
You should read the following discussion of our cash distribution policy in conjunction with “— Assumptions and Considerations” below, which includes the factors and assumptions upon which we base our cash distribution policy. In addition, please read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical operating results, you should refer to our historical consolidated financial statements, and the notes thereto, included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy.  Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects a fundamental judgment that our unitholders generally will be better served by our distributing rather than retaining our available cash. Basically, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.
 
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.  There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to distribute available cash as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:
 
  •  Our cash distribution policy may be subject to restrictions on distributions under our new credit facility or other debt agreements entered into in the future. We expect that our new credit facility will contain material financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions under our credit facility, we may be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Credit Facility.”
 
  •  Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be made in good faith, our general partner must subjectively believe that the determination is in, or not opposed to, the best interests of our partnership.
 
  •  Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions contained therein that require us to make cash distributions, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by PAA), voting as a single class after the subordination period has ended. At the closing of this offering, PAA will own our general partner and an aggregate of approximately     % of our total outstanding units.
 
  •  Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
 
  •  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.


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  •  We may lack sufficient cash to pay distributions to our unitholders due to revenue shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expense, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar for dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash.”
 
  •  If and to the extent our distributable cash flow materially declines, we may elect to reduce our quarterly distribution in order to service or repay our debt or fund expansion capital expenditures.
 
  •  Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.
 
Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital.  Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to access such external sources to finance our growth, our cash distribution policy could significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
Our Minimum Quarterly Distribution
 
Upon completion of this offering, the board of directors of our general partner will establish an initial minimum quarterly distribution of $      per common unit and Series A subordinated unit per complete quarter, or $      per common unit and Series A subordinated unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending June 30, 2010. This equates to an aggregate cash distribution of $      million per quarter, or $      million per year, based on the number of common units, Series A subordinated units and the 2.0% general partner interest to be outstanding immediately after the completion of this offering. Our ability to make cash distributions at the minimum quarterly distribution rate pursuant to this policy will be subject to the factors described above under the caption “— General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”
 
If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and we will use the net proceeds from the sale of these additional common units to redeem from PAA a number of common units equal to those issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses, but after underwriting discounts. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all common units and Series A subordinated units.
 
As of the date of this offering, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.


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The table below sets forth the assumed number of outstanding common units and Series A subordinated units upon the closing of this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the aggregate distribution amounts payable on such units and the 2.0% general partner interest during the year following the closing of this offering at our minimum quarterly distribution rate of $      per common unit and Series A subordinated unit per quarter ($      per common unit and Series A subordinated unit on an annualized basis).
 
                                         
    Minimum Quarterly Distributions              
    Number of Units     One Quarter     Annualized              
 
Publicly held common units
              $           $                        
Common units held by PAA
                                       
Series A subordinated units held by PAA
                                       
2.0% general partner interest
                                       
                                         
Total
          $       $                  
                                         
 
We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 10th day prior to such payment date. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through June 30, 2010 based on the actual length of the period.
 
Series A Subordinated Units
 
PAA will initially own all of our Series A subordinated units. The principal difference between our common units and Series A subordinated units is that in any quarter during the subordination period, holders of the Series A subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Series A subordinated units will not accrue arrearages.
 
The subordination period for the Series A subordinated units generally will end if we have earned and paid from distributable cash flow at least $      on each outstanding common unit and Series A subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. If we have earned and paid from distributable cash flow at least $     per quarter (150.0% of the minimum quarterly distribution, which is $      on an annualized basis) on each outstanding common unit and Series A subordinated unit and the corresponding distribution on our general partner’s 2.0% interest and the related distributions on the incentive distribution rights for each of four consecutive quarters ending on or after June 30, 2011, the subordination period will terminate automatically and all of the Series A subordinated units will convert into an equal number of common units. When the subordination period ends, all of the Series A subordinated units will convert into an equal number of common units. Please read the “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
To the extent we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of Series A subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
Series B Subordinated Units
 
The Series B subordinated units that will be outstanding upon the consummation of this offering are not entitled to cash distributions unless and until they convert to Series A subordinated units or common units. The Series B subordinated units are designed to compensate PAA for prior capital expenditures made by it to


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expand the working gas storage capacity at Pine Prairie and the future financial contribution expected to result from such investment. We currently do not expect any of the Series B subordinated units to convert to Series A subordinated units or common units before June 30, 2011. As a result, we would not expect any Series B subordinated units to receive any distributions for the twelve-month period ending June 30, 2011. We may, however, make acquisitions or take other actions that could cause Series B subordinated units to convert to Series A subordinated units during this period. In order for Series B Subordinated units to convert to Series A subordinated units, the following financial and operating conditions must be satisfied:
 
  •            Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 29.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $      per unit (representing an annualized distribution of $      per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $      per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters);
 
  •            Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 35.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $      per unit (representing an annualized distribution of $      per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $      per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters); and
 
  •            Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 41.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $      per unit (representing an annualized distribution of $      per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $      per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters).
 
Our general partner will determine whether the in-service operational tests set forth above have been satisfied. To the extent that the above operational and financial tests are satisfied, the Series B subordinated units will convert into Series A subordinated units and participate in the quarterly distribution payable to Series A subordinated units.
 
Following conversion of any Series B subordinated units into Series A subordinated units, such converted Series B subordinated units will further convert into common units (together with any other outstanding Series A subordinated units) to the extent that the tests for conversion of the Series A subordinated units are satisfied. In determining whether such conversion tests have been satisfied, the Series B subordinated units that have converted into Series A subordinated units will be treated as Series A subordinated units from and after the date of their conversion into Series A subordinated units.
 
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $      per common unit and Series A subordinated unit each quarter for the twelve months ending June 30, 2011. In those sections, we present the following two tables:
 
  •  “Unaudited Pro Forma Available Cash from Distributable Cash Flow,” in which we present the amount of available cash we would have had from distributable cash flow on a pro forma basis for our year ended December 31, 2009, as adjusted to give pro forma effect to the offering and the formation transactions as if the offering and such transactions had occurred on January 1, 2009; and


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  •  “Statement of Minimum Estimated Available Cash from Distributable Cash Flow,” in which we demonstrate our anticipated ability to generate the minimum estimated available cash from distributable cash flow necessary for us to pay the minimum quarterly distribution on all common units and Series A subordinated units for the twelve months ending June 30, 2011.
 
We define distributable cash flow as net income adjusted for (i) any gain or loss from the sale of assets not in the ordinary course of business, (ii) any gain or loss as a result of a change in accounting principles, (iii) any non-cash gains or items of income and any non-cash losses or expenses, including mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities; (iv) any acquisition-related expenses associated with (a) successful acquisitions or (b) all other acquisitions until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence and (v) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received; plus depreciation, depletion and amortization expense; and less maintenance capital expenditures.
 
Unaudited Pro Forma Available Cash from Distributable Cash Flow for the Year Ended December 31, 2009
 
If we had completed the transactions contemplated in this prospectus on January 1, 2009, pro forma available cash from distributable cash flow generated for the year ended December 31, 2009 would have been approximately $36.6 million and would have enabled us to make a distribution of $     (     % of the minimum quarterly distribution) on the common units and no distribution on the Series A subordinated units. These distributions are significantly less than the amounts that would have been required to pay the minimum quarterly distribution of $      per common unit and Series A subordinated unit per quarter ($      per common unit and Series A subordinated unit on an annualized basis).
 
Unaudited pro forma available cash from distributable cash flow also includes incremental general and administrative expenses we will incur as a result of being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, Sarbanes-Oxley compliance, New York Stock Exchange listing, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. We expect our incremental general and administrative expenses associated with being a publicly traded limited partnership to total approximately $2.6 million per year. Such incremental general and administrative expenses are not reflected in our historical financial statements.
 
The following table illustrates, on a pro forma basis, for the year ended December 31, 2009, the amount of our available cash from distributable cash flow, assuming that this offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.
 
We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash from distributable cash flow only as a general indication of the amount of available cash from distributable cash flow that we might have generated had we been formed in earlier periods.


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PAA Natural Gas Storage, L.P.
 
Unaudited Pro Forma Available Cash from Distributable Cash Flow
 
         
    Year Ended
 
    December 31, 2009  
    (in millions, except
 
    per unit data)  
 
Net income(1)
  $ 18.0  
Add:
       
Interest expense, net of capitalized interest(1)(2)
    8.6  
Income tax expense(1)(2)(3)
    0.5  
Depreciation, depletion and amortization(1)(2)
    11.6  
Equity compensation expense(2)(4)
    1.8  
Mark-to-market on open derivative positions(1)(2)
    0.4  
         
Adjusted EBITDA(5)
  $ 40.9  
         
Adjusted for:
       
Incremental general and administrative expense of being a public company(6)
    (2.6 )
Pro forma cash interest expense(7)
    (0.8 )
Cash paid for equity compensation
    (0.4 )
Acquisition related cost
    0.2  
Maintenance capital expenditures(8)
    (0.7 )
         
Pro forma available cash from distributable cash flow
  $ 36.6  
         
Pro forma cash distributions
       
Distributions on publicly held common units(9)
  $    
Distributions on common units held by PAA(9)
       
Distributions on Series A subordinated units held by PAA(9)
       
Distributions on 2.0% general partner interest held by PAA(9)
       
Total distributions
       
         
Excess/(Shortfall)
  $  
         
Percent of minimum quarterly distributions payable to common unitholders
       
Percent of minimum quarterly distributions payable to Series A subordinated unitholders
       
 
 
(1) The unaudited pro forma financial information for the year ended December 31, 2009 is provided for informational purposes and reflects net income derived by combining our Predecessor and Successor historical financial results for the year ended December 31, 2009.
 
(2) Reflects adjustments necessary to reconcile net income to Adjusted EBITDA.
 
(3) Reflects primarily Michigan state income tax.
 
(4) Represents expense associated with grants under PAA’s long-term incentive plans to employees that are dedicated to our operations.
 
(5) We define Adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring. Because Adjusted EBITDA excludes some, but not all, items that affect net income and may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA has important limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Please see “Summary — Non-GAAP and Segment Financial Measures.”


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(6) Reflects an adjustment to our Adjusted EBITDA for an estimated incremental cash expense associated with being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, Sarbanes-Oxley compliance, New York Stock Exchange listing, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs and director compensation.
 
(7) In connection with the closing of this offering, we expect to enter into a new $400 million credit agreement under which we expect to incur approximately $200 million of borrowings. The pro forma cash interest expense is based on $200 million of historical borrowings at an assumed rate based on a forecast of LIBOR rates during the period plus the margin expected under our new credit facility, net of capitalized interest, with the remainder of historical borrowings financed with equity proceeds from this offering.
 
(8) Maintenance capital expenditures are expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production, and/or functionality of our existing assets. Examples of maintenance capital expenditures include capital expenditures associated with maintaining the storage capacity of our facilities as well as ongoing maintenance or replacement costs for the various injection, withdrawal and related equipment costs associated with those facilities, to replace expected reductions in our storage, injection or withdrawal capacities (which we refer to as operating capacity).
 
(9) The table below sets forth the assumed number of outstanding common units and Series A subordinated units upon the closing of this offering and the estimated per common unit and Series A subordinated unit and aggregate distribution amounts payable on our common units and Series A subordinated units, as well as the aggregate distribution amount payable on the 2.0% general partner interest for four quarters at our initial distribution rate of $      per common unit per quarter ($      per common unit on an annualized basis).
 
                         
    Number of
    Distributions for Four Quarters  
    Units     Per Unit     Aggregate  
 
Pro forma distributions on publicly-held common units
                               
Pro forma distributions on common units held by PAA
                       
Pro forma distributions on Series A subordinated units held by PAA
                       
Pro forma distributions on 2.0% general partner interest
                       
                         
Total
                       
                         
 
The Series B subordinated units that will be outstanding upon the consummation of this offering are not entitled to cash distributions unless and until they convert to Series A subordinated units or common units. Please read “ — Series B Subordinated Units” above.
 
Minimum Estimated Available Cash from Distributable Cash Flow for the Twelve Months Ending June 30, 2011
 
In order to fund distributions to our unitholders at our initial minimum quarterly distribution of $      per common unit and Series A subordinated unit for the twelve months ending June 30, 2011, our minimum estimated available cash from distributable cash flow for the twelve months ending June 30, 2011 must be at least $      million. This minimum estimated available cash from distributable cash flow should not be viewed as management’s projection of the actual amount of available cash from distributable cash flow that we will generate during the twelve month period ending June 30, 2011. We believe that we will be able to generate this minimum estimated available cash from distributable cash flow based on the assumptions discussed in “— Assumptions and Considerations” below.
 
We can give you no assurance, however, that we will generate the minimum estimated available cash from distributable cash flow. There will likely be differences between our minimum estimated available cash from distributable cash flow and our actual results and those differences could be material. If we fail to


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generate the minimum estimated available cash from distributable cash flow, we may not be able to pay the minimum quarterly distribution on our common units.
 
We define distributable cash flow as net income adjusted for (i) any gain or loss from the sale of assets not in the ordinary course of business, (ii) any gain or loss as a result of a change in accounting principles, (iii) any non-cash gains or items of income and any non-cash losses or expenses, including mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities (iv) any acquisition-related expenses associated with (a) successful acquisitions or (b) all other acquisitions until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence and (v) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received; plus depreciation, depletion and amortization expense; and less maintenance capital expenditures.
 
Management has prepared the minimum estimated available cash from distributable cash flow and related assumptions set forth below to substantiate our belief that we will have sufficient available cash from distributable cash flow to pay the minimum quarterly distribution to all our common unitholders and Series A unitholders for the twelve months ending June 30, 2011. This forecast is a forward-looking statement and should be read together with the historical financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum estimated available cash from distributable cash flow necessary for us to pay the minimum quarterly distribution to all common unitholders and Series A subordinated unitholders for the twelve months ending June 30, 2011. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.
 
The prospective financial information included in this registration statement has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report included in this registration statement relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.
 
When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those which would enable us to generate the minimum estimated available cash from distributable cash flow.
 
We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.


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PAA Natural Gas Storage, L.P.
Unaudited Minimum Estimated Available Cash from Distributable Cash Flow
 
         
    Twelve Months Ending
 
    June 30, 2011  
    (in millions, except
 
    per unit data)  
 
Firm storage services
  $ 107.9  
Hub services
    16.4  
Other
    2.2  
         
Total revenue
    126.4  
Storage related costs
    16.7  
Operating costs (except those shown below)
    9.2  
Fuel expense
    14.5  
General and administrative expenses
    13.1  
Depreciation, depletion and amortization
    12.6  
         
Total costs and expenses
    66.1  
Operating income
    60.3  
Interest expense, net of capitalized interest
    4.4  
Income tax expense(1)
     
         
Net income
  $ 55.9  
Add:
       
Depreciation, depletion and amortization
    12.6  
Interest expense, net of capitalized interest
    4.4  
Equity compensation expense(2)
    1.3  
Income tax expense(1)
     
Adjusted EBITDA(3)
    74.3  
Less:
       
Equity compensation expense — cash(2)
    0.3  
Interest expense, net of capitalized interest
    4.4  
Maintenance capital expenditures
    0.4  
Expansion capital expenditures
    80.0  
Income tax expense — cash(1)
     
Add:
       
Borrowings to fund expansion capital expenditures
    80.0  
Acquisition costs(4)
     
Estimated distributable cash flow
    69.1  
Less:
       
Cash reserves
    6.6  
         
Minimum estimated available cash from distributable cash flow
  $ 62.5  
         
Per unit minimum annual distribution
       
         
Annual distributions to:
       
Publicly held common units
       
Common units held by PAA
       
Series A subordinated units held by PAA
       
2.0% general partner interest held by PAA
       
         
         
Total minimum annual cash distributions
       
         
Interest coverage ratio(5)
    16.9x  
Leverage ratio(5)
    3.8x  
 
 
(1) Michigan state income tax is an apportionment tax and, based on the size of our operations at Pine Prairie, such amounts are expected to be immaterial in the forecast period.
 
(2) Reflects our estimate of expense associated with grants under our and PAA’s long-term incentive plans.


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(3) We define Adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring. Because Adjusted EBITDA excludes some, but not all, items that affect net income and may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA has important limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Please see “Summary — Summary Historical Financial and Operating Data — Non-GAAP and Segment Financial Measures.”
 
(4) Pursuant to our definition of distributable cash flow, we will exclude the impact of costs associated with an acquisition until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence.
 
(5) We expect that our credit agreement will contain certain customary covenants limiting our ability to (i) make distributions of available cash to unitholders if any default or event of default (as defined in the credit agreement) exists, (ii) incur additional indebtedness, (iii) grant liens or enter into certain restricted contracts, (iv) engage in transactions with affiliates, (v) make any material change to the nature of our business, (vi) make a disposition of assets or (vii) enter into a merger, consolidate, liquidate, wind up or dissolve.
 
In addition, we expect that our credit agreement will contain financial covenants requiring us to maintain:
 
  •  A minimum consolidated interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest charges, in each case as such term will be defined in our credit agreement) of not less than 3.0 to 1.0, determined as of the last day of each quarter for the four-quarter period ending on the date of determination; and
 
  •  A maximum consolidated leverage ratio (the ratio of our consolidated funded indebtedness to our consolidated EBITDA, in each case as such term will be defined in our credit agreement) of not more than 4.75 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than 5.5 to 1.0).
 
If an event of default exists under the credit agreement, we expect that the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. The credit agreement is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation.
 
Assumptions and Considerations
 
We believe our minimum estimated available cash from distributable cash flow for the twelve months ending June 30, 2011 will not be less than $      million. This amount of estimated minimum available cash from distributable cash flow is approximately $      million, or  %, more than the unaudited pro forma available cash from distributable cash flow for the year ended December 31, 2009. The December 31, 2009 financial information used in the pro forma table is derived by combining the Predecessor period ended September 2, 2009 with the Successor period ended December 31, 2009 from our historical financial statements. This significant increase in available cash from distributable cash flow is primarily attributable to in service dates for additional storage capacity at Pine Prairie as described in detail below. Our estimates do not assume any incremental revenue, expenses or related start-up costs associated with our expected establishment of a commercial marketing group or any acquisitions we might pursue. We believe that the


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estimates, assumptions and considerations incorporated into the minimum estimated available cash from distributable cash flow are reasonable, and include the following:
 
Operating Revenue
 
  •  We estimate that we will generate $126 million in revenues for the twelve months ending June 30, 2011, as follows:
 
  •  Revenues from Firm Storage.  We estimate that approximately 85%, or approximately $108 million, of our total revenue will be generated from firm storage services. This compares to approximately 92%, or approximately $67 million, of our total revenues that were generated from firm storage revenues during the 12 month period ended December 31, 2009. Furthermore, we have assumed that:
 
  (i)  Approximately 73% of our total revenue will be generated from firm storage services provided under contracts in existence as of January 22, 2010, which cover 46.5 Bcf of our approximate 50 Bcf of total owned and leased working gas capacity as of April 1, 2010, including the 10 Bcf of additional capacity we expect to place into service during the second quarter of 2010; and
 
  (ii)  Approximately 12% of our total revenue will be generated from firm storage services provided under contracts entered into after January 22, 2010 that will cover (a) the remaining 3.5 Bcf of our approximate 50 Bcf of working gas capacity as of April 1, 2010, (b) the 8 Bcf of additional working gas capacity we expect to place into service during the second quarter of 2011 and (c) renewals of existing firm storage contracts covering approximately 11 Bcf of working gas capacity at our Bluewater facility, the terms of which expire on March 31, 2011. With respect to such contracts to be entered into after January 22, 2010, we have assumed we will earn storage rates on such capacity that are consistent with our rates for new contracts entered into over the last 18 months.
 
  •  Revenues from Hub Services.  We estimate that approximately 13%, or approximately $16 million, of our total revenues will be generated from hub services, which includes non-seasonal parks and loans, wheeling and balancing services and interruptible storage services. This compares to approximately 7%, or approximately $5 million, of revenues from hub services generated during the twelve-month period ended December 31, 2009. Our estimate with respect to the level of hub services revenues for the forecast period incorporates assumptions with respect to increased natural gas flows and related hub service opportunities at Pine Prairie associated with (i) an approximate 115% increase relative to our weighted average storage capacity during 2009, (ii) increased flexibility provided both by an approximate 50% increase in compression capacity and an approximate 115% increase in base gas relative to the 2009 period and (iii) a continuation of volatility related to market conditions and weather consistent with those experienced over the last five years.
 
  •  Other Revenues.  We estimate that approximately 2%, or approximately $2.2 million, of our total revenues will be generated from the sale of crude oil and other liquid hydrocarbons produced in conjunction with the operation of our Bluewater facility. This compares to approximately 1%, or approximately $0.9 million, of other revenues generated during the twelve-month period ended December 31, 2009. Fuel related revenue for both firm and hub services is based on an average natural gas price of $6.18 per mcf, which approximates the average price quoted on NYMEX in late January 2010 for the twelve months ended June 30, 2011. No gains or losses were assumed with respect to the sale of excess fuel collections.
 
  •  Incremental storage capacity additions related to our ongoing expansion at Pine Prairie constitute the primary driver for the approximate $54 million increase in estimated firm storage and hub services revenues, as:
 
  •  our second cavern began generating revenue on April 1, 2009, and thus revenue associated with the added 9 Bcf of incremental storage capacity is only included for nine months of the twelve-month period ended December 31, 2009;


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  •  our third cavern is expected to begin generating revenue by April 1, 2010 and be placed into full service during the second quarter of 2010, providing an expected 10 Bcf of incremental storage capacity for the entire twelve-month period ending June 30, 2011; and
 
  •  our fourth cavern is expected to begin generating revenue on April 1, 2011 and be placed into full service during the second quarter of 2011, providing an expected 8 Bcf of incremental storage capacity for the final three months of the twelve-month period ending June 30, 2011.
 
As a result of these expansions, our weighted average working gas capacity at Pine Prairie will increase from approximately 12 Bcf for the twelve-month period ended December 31, 2009 to approximately 26 Bcf for the twelve-month period ending June 30, 2011.
 
Our Expenses
 
  •  We estimate that operating, fuel and leased storage costs and transportation expenses will be $40.3 million for the twelve months ending June 30, 2011, as compared to $26.3 million for the year ended December 31, 2009. This increase is generally attributable to costs associated with the incremental storage capacity related to the ongoing expansion at our Pine Prairie facility. We do not expect our operating expenses to increase proportionately with our capacity additions, both because these additions do not require significant additions of operating employees and because the revenues associated with the additions have the benefit of the tax exemption we have obtained at Pine Prairie. See “Business — Title to Properties and Rights-of-way.”
 
  •  We estimate that our total general and administrative expense will be $13.1 million for the twelve months ended June 30, 2011, as compared to $7.6 million for the year ended December 31, 2009. This projected increase includes additional personnel and related costs associated with our preparation to become a publicly traded limited partnership, an increased level of acquisition activity and approximately $2.6 million of incremental external costs we expect to begin incurring upon becoming a publicly traded limited partnership. These general and administrative expenses include corporate general and administrative expense to be allocated from PAA. Such general and administrative expense reflects twelve months of increased allocations from PAA consistent with historical allocations subsequent to the PAA Ownership Transaction.
 
  •  We have not included any amounts related to the Michigan state income tax applicable to our operations in the twelve months ending June 30, 2011. This tax is an apportionment tax and, because of the size of our operations at Pine Prairie, is expected to be immaterial in the forecast period.
 
Our Capital Expenditures
 
  •  We estimate that our maintenance capital expenditures will be approximately $0.4 million for the twelve months ending June 30, 2011, as compared to $0.7 million for the year ended December 31, 2009. Our maintenance capital expenditures are not significant in the forecast period because our storage facilities and related equipment are relatively new. We would expect maintenance capital expenditures to increase periodically as we undertake scheduled maintenance on our caverns and related equipment. While these periodic costs may increase our maintenance capital expenditures from time to time, we do not expect these increases to materially impact our operating results or distributable cash flow.
 
  •  We estimate that our expansion capital expenditures, which include the purchase of base gas and capitalized interest, will be approximately $80 million for the twelve months ending June 30, 2011, as compared to $90 million for the year ended December 31, 2009. The substantial majority of this capital is attributable to the capacity additions at our Pine Prairie facility.
 
Our Financing
 
  •  We estimate that at the closing of this offering we will borrow $200 million in revolving debt under our new $400 million credit facility. We estimate that the borrowings will bear interest at a weighted average rate of 4%. This rate is based on a forecast of LIBOR rates during the period plus the margin expected under our new credit facility. In addition, we have assumed that we will fund our


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  expansion capital expenditures for the twelve months ended June 30, 2011 by borrowing an additional $80 million under our new credit facility.
 
  •  Our aggregate interest expense is forecast to be $      million, net of $     million in capitalized interest.
 
Our Regulatory, Industry and Economic Factors
 
  •  Our estimate incorporates assumptions that (i) there will not be any new federal, state or local regulations or any new interpretations of existing regulations, that would materially impact our or our customers’ operations, and (ii) there will not be any major adverse economic changes in the portions of the energy industry in which we operate, or in general economic conditions, that would be materially adverse to our business during the twelve months ending June 30, 2011.


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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS
 
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.
 
Distributions of Available Cash
 
General.  Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2010, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through June 30, 2010.
 
Definition of Available Cash.  Available cash, for any quarter, consists of all cash on hand at the end of that quarter:
 
  •  less, the amount of cash reserves established by our general partner to:
 
  •  provide for the proper conduct of our business;
 
  •  comply with applicable law, any of our debt instruments or other agreements; or
 
  •  provide funds for distributions to our unitholders for any one or more of the next four quarters;
 
  •  plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from borrowings, including working capital borrowings, made after the end of the quarter.
 
Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners. In addition, all such borrowings are required to be reduced to a relatively small amount within twelve months of incurrence for an economically meaningful period of time from sources other than working capital borrowings.
 
Intent to Distribute the Minimum Quarterly Distribution.  We intend to distribute to the holders of common units and Series A subordinated units on a quarterly basis at least the minimum quarterly distribution of $      per unit, or $      per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
 
General Partner Interest and Incentive Distribution Rights.  Initially, our general partner will be entitled to 2.0% of all quarterly distributions that we make after inception and prior to our liquidation. The general partner interest will be represented by a 2.0% general partner interest. The 2.0% general partner interest is not deemed outstanding for purposes of voting and such interest represents a non-voting general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner’s initial 2.0% interest in our distributions may be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.
 
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from distributable cash flow in excess of $      per common unit and Series A subordinated unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on limited partner units that it owns.


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Distributable Cash Flow and Capital Surplus
 
General.  All cash distributed to unitholders will be characterized as either “distributable cash flow” or “capital surplus.” Our partnership agreement requires that we distribute available cash from distributable cash flow differently than available cash from capital surplus.
 
Distributable Cash Flow.  Distributable cash flow consists of:
 
  •  net income; plus
 
  •  depreciation, depletion and amortization expense; less
 
  •  maintenance capital expenditures.
 
For purposes of this definition, net income does not include or will be adjusted for:
 
  •  any gain or loss from the sale of assets not in the ordinary course of business;
 
  •  any gain or loss as a result of a change in accounting principles;
 
  •  any non-cash gains or items of income and any non-cash losses or expenses, including mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities;
 
  •  any acquisition-related expenses associated with (i) successful acquisitions or (ii) all other acquisitions until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence; and
 
  •  earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received.
 
As described above, distributable cash flow does not reflect actual cash on hand that is available for distribution to our unitholders. Our definition of distributable cash flow is generally designed and intended to adjust net income (as determined in accordance with generally accepted accounting principles) for items that do not impact the level of cash we have available for distribution to our unitholders but may be required to be reflected in net income by applicable accounting rules and regulations.
 
Characterization of Cash Distributions.  Our partnership agreement requires that we treat all available cash distributed as coming from distributable cash flow until the sum of all available cash distributed since the closing of this offering equals the distributable cash flow as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of distributable cash flow, regardless of its source, as capital surplus. However, our partnership agreement includes a provision that will enable us, if we choose, to distribute up to $40 million of cash we receive in the future from sources other than distributable cash flow, such as asset sales, issuances of securities and borrowings, without being required to classify such distribution as a distribution from capital surplus under our partnership agreement. We do not anticipate that we will make any distributions from capital surplus.
 
Maintenance Capital Expenditures
 
For purposes of determining distributable cash flow, maintenance capital expenditures are expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production, and/or functionality of our existing assets. Examples of maintenance capital expenditures include capital expenditures associated with maintaining the storage capacity of our facilities as well as ongoing maintenance or replacement costs for the various injection, withdrawal and related equipment associated with those facilities, and capital expenditures to replace expected reductions in our storage, injection or withdrawal capacities (which we refer to as operating capacity).


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Subordination Period
 
General.  Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from distributable cash flow each quarter in an amount equal to $      per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from distributable cash flow may be made on the Series A subordinated units. These Series A subordinated units are deemed “subordinated” because for a period of time, referred to as the subordination period, the Series A subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the Series A subordinated units. The practical effect of the Series A subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The Series B subordinated units will not be entitled to receive any distributions until they are converted to either Series A subordinated units or common units, at which time they will be treated as other Series A subordinated units or common units, as applicable, are treated.
 
Series A Subordinated Units and Subordination Period.  PAA will initially own all of our Series A subordinated units. The subordination period will extend until the first business day of any quarter beginning after June 30, 2013, that each of the following tests are met:
 
  •  distributions of available cash from distributable cash flow on each of the outstanding common units, Series A subordinated units and the general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the distributable cash flow generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and Series A subordinated units and the general partner interest during those periods on a fully diluted basis; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
 
Early Termination of Subordination Period.  Notwithstanding the foregoing, the subordination period will automatically terminate and all of the Series A subordinated units will convert into common units on a one-for-one basis on the first business day of any quarter beginning after June 30, 2011 that each of the following occurs:
 
  •  distributions of available cash from distributable cash flow equaled or exceeded $      per quarter (150.0% of the minimum quarterly distribution, which is $      on an annualized basis) on each outstanding common unit and Series A subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each calendar quarter in the immediately preceding four-quarter period;
 
  •  the distributable cash flow generated during each calendar quarter in the immediately preceding four-quarter period equaled or exceeded the sum of $     (150.0% of the minimum quarterly distribution) on each of the outstanding common units and Series A subordinated units and the corresponding distribution on our general partner’s 2.0% interest during that period on a fully diluted basis and the related distributions on the incentive distribution rights; and
 
  •  there are no arrearages in payment of the minimum quarterly distributions on the common units.
 
Expiration of the Subordination Period.  When the subordination period ends, each outstanding Series A subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. Any Series B subordinated units that become eligible for conversion after the end of the subordination period will convert to common units an a one-for-one basis and will then participate pro rata with the other common units in distributions of available cash. In addition, if the


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unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:
 
  •  the subordination period will end and each Series A subordinated unit will immediately convert into one common unit;
 
  •  each Series B subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
 
Series B Subordinated Units.  PAA will initially own all of the Series B subordinated units. The Series B subordinated units will not be entitled to participate in our quarterly distributions until they convert into Series A subordinated units or common units.
 
The Series B subordinated units are designed to compensate PAA for prior capital expenditures made by it to expand the working gas storage capacity at Pine Prairie and the future financial contribution expected to result from such investment. As of the closing of this offering, we expect to have approximately 24 Bcf of working gas storage capacity at Pine Prairie, including approximately 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010. The Series B subordinated units will convert into Series A subordinated units upon satisfaction of the following operational and financial conditions:
 
  •        Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 29.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $      per unit (representing an annualized distribution of $      per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $      per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters);
 
  •        Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 35.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $      per unit (representing an annualized distribution of $      per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $      per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters); and
 
  •        Series B subordinated units will convert into Series A subordinated units on a one-for-one basis if (a) the aggregate amount of working gas storage capacity at Pine Prairie that has been placed into service totals at least 41.6 Bcf, (b) we generate distributable cash flow for two consecutive quarters sufficient to pay a quarterly distribution of at least $      per unit (representing an annualized distribution of $      per unit) on all outstanding common units, Series A subordinated units and such Series B subordinated units and (c) we make a quarterly distribution of at least $      per quarter for two consecutive quarters on all outstanding common units and Series A subordinated units (including such Series B subordinated units in the case of the second of such consecutive quarters).
 
Our general partner will determine whether the in-service operational tests set forth above have been satisfied. To the extent that the above operational and financial tests are satisfied, the Series B subordinated units will convert into Series A subordinated units and participate in the quarterly distribution payable to Series A subordinated units.


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Any Series B subordinated units that remain outstanding as of December 31, 2018 will automatically be cancelled.
 
Following conversion of any Series B subordinated units into Series A subordinated units, such converted Series B subordinated units will further convert into common units (together with any other outstanding Series A subordinated units) to the extent that the tests for conversion of the Series A subordinated units are satisfied. In determining whether such conversion tests have been satisfied, the Series B subordinated units that have converted into Series A subordinated units will be treated as Series A subordinated units from and after the date of their conversion into Series A subordinated units.
 
If at the time the above financial tests are satisfied, the subordination period has already ended and all outstanding Series A subordinated units have converted into common units, the Series B subordinated units will instead convert directly into common units on a one-for-one basis and participate in the quarterly distribution payable to common units.
 
Distributions of Available Cash from Distributable Cash Flow During the Subordination Period
 
Our partnership agreement requires that we make distributions of available cash from distributable cash flow for any quarter during the subordination period in the following manner:
 
  •  first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
  •  second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
 
  •  third, 98.0% to the Series A subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each Series A subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
Distributions of Available Cash From Distributable Cash Flow After the Subordination Period
 
Our partnership agreement requires that we make distributions of available cash from distributable cash flow for any quarter after the subordination period in the following manner:
 
  •  first, 98.0% to all common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
General Partner Interest and Incentive Distribution Rights
 
Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is


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entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.
 
Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from distributable cash flow after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.
 
The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.
 
If for any quarter:
 
  •  we have distributed available cash from distributable cash flow to the common unitholders and Series A subordinated unitholders in an amount equal to the minimum quarterly distribution; and
 
  •  we have distributed available cash from distributable cash flow on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
 
then, our partnership agreement requires that we distribute any additional available cash from distributable cash flow for that quarter among the unitholders and the general partner in the following manner:
 
  •  first, 85.0% to all common unitholders and Series A subordinated unitholders, pro rata, and 15.0% to our general partner, until each such unitholder receives a total of $      per unit for that quarter (the “first target distribution”);
 
  •  second, 75.0% to all common unitholders and Series A subordinated unitholders, pro rata, and 25.0% to our general partner, until each such unitholder receives a total of $      per unit for that quarter (the “second target distribution”); and
 
  •  thereafter, 50.0% to all common unitholders and Series A subordinated unitholders, pro rata, and 50.0% to our general partner.
 
Percentage Allocations of Available Cash From Distributable Cash Flow
 
The following table illustrates the percentage allocations of available cash from distributable cash flow between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from distributable cash flow we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Common Unit and Series A Subordinated Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest, assume our general partner has contributed any additional capital to maintain its


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2.0% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.
 
                                 
    Total Quarterly Distribution
    Marginal Percentage
       
    per Common Unit and
    Interest in Distributions        
    Series A Subordinated Unit     Unitholders     General Partner        
 
Minimum Quarterly Distribution
  $             98.0 %     2.0 %        
First Target Distribution
  above $      up to $            85.0 %     15.0 %        
Second Target Distribution
  above $      up to $            75.0 %     25.0 %        
Thereafter
  above $             50.0 %     50.0 %        
 
General Partner’s Right to Reset Incentive Distribution Levels
 
Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount, and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount, and the target distribution levels upon which the incentive distributions payable to our general partner are based, may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no Series A subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. Our general partner will have the right to reset the minimum quarterly distribution whether or not any Series B subordinated units remain outstanding. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per common unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.
 
In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period. In addition, our general partner will be issued a general partner interest necessary to maintain our general partner’s interest in us immediately prior to the reset election.
 
The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.
 
Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly


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distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from distributable cash flow for each quarter thereafter as follows:
 
  •  first, 98.0% to all common unitholders, pro rata, and 2.0% to our general partner, until each such unitholder receives an amount per unit equal to the reset minimum quarterly distribution for that quarter;
 
  •  second, 85.0% to all common unitholders, pro rata, and 15.0% to our general partner, until each such unitholder receives an amount per unit equal to 110.0% of the reset minimum quarterly distribution for the quarter;
 
  •  third, 75.0% to all common unitholders, pro rata, and 25.0% to our general partner, until each such unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and
 
  •  thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to our general partner.
 
The following table illustrates the percentage allocation of available cash from distributable cash flow between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $     .
 
                         
                    Quarterly Distribution per
    Quarterly Distribution
  Marginal Percentage Interest
    Common Unit
    per Common Unit
  in Distribution     Following
    Prior to Reset   Unitholders     General Partner     Hypothetical Reset
 
Minimum Quarterly Distribution
  $          98.0 %     2.0 %   $(1)
First Target Distribution
  above $     up to $          85.0 %     15.0 %   above $     (1) up to $(2)
Second Target Distribution
  above $     up to $          75.0 %     25.0 %   above $     (2) up to $(3)
Thereafter
  above $          50.0 %     50.0 %   above $     (3)
 
 
(1) This amount is equal to the hypothetical reset minimum quarterly distribution.
 
(2) This amount is 110.0% of the hypothetical reset minimum quarterly distribution.
 
(3) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.
 
The following table illustrates the total amount of available cash from distributable cash flow that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be           common units outstanding, our general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit would be $     for the two quarters prior to the reset.
 
                                                     
              Cash Distributions to
       
              General Partner Prior to Reset        
        Cash Distributions
          2.0%
                   
    Quarterly Distribution
  to Common
          General
    Incentive
             
    per Common Unit
  Unitholders Prior
    Common
    Partner
    Distribution
          Total
 
    Prior to Reset   to Reset     Units     Interest     Rights     Total     Distributions  
 
Minimum Quarterly Distribution
  $        $       $                       $           $        
First Target Distribution
  above $     up to $                                              
Second Target Distribution
  above $     up to $                                                   
Thereafter
  above $                                                   
                                                     
        $           $                     $       $  
                                                     


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The following table illustrates the total amount of available cash from distributable cash flow that would be distributed to the unitholders and our general partner, including in respect of IDRs, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $     . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its IDRs for the two quarters prior to the reset as shown in the table above, or $     , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $     .
 
                                                     
              Cash distributions to general partner at reset        
        Cash Distributions
          2.0%
                   
    Quarterly Distribution
  to Common
          General
    Incentive
             
    per Common Unit
  Unitholders at
    Common
    Partner
    Distribution
          Total
 
    at Reset   Reset     Units     Interest     Rights     Total     Distributions  
 
Minimum Quarterly Distribution
  $        $       $       $       $     $       $    
First Target Distribution
  above $     up to $                                         
Second Target Distribution
  above $     up to $                                         
Thereafter
  above $                                         
                                                     
        $       $       $       $     $       $  
                                                     
 
Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement. Neither the existence of the reset right nor the exercise thereof will preclude our general partner from unilaterally foregoing the payment of all or a portion of the IDRs otherwise payable, whether temporarily or permanently.
 
Distributions From Capital Surplus
 
How Distributions from Capital Surplus Will Be Made.  Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:
 
  •  first, 98.0% to all common unitholders and Series A subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;
 
  •  second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
 
  •  thereafter, we will make all distributions of available cash from capital surplus as if they were from distributable cash flow.
 
The preceding paragraph assumes that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
Our partnership agreement includes a provision that will enable us, if we choose, to distribute up to $40 million of cash we receive in the future from sources other than distributable cash flow, such as asset sales, issuances of securities and borrowings, without being required to classify such distribution as a distribution from capital surplus under our partnership agreement. We do not anticipate that we will make any distributions from capital surplus.
 
Effect of a Distribution from Capital Surplus.  Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital.


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The initial public offering price less any distributions of capital surplus per common unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions, for the Series A subordinated units to convert into common units and the Series B subordinated units to convert into Series A subordinated units or common units. However, any distribution of capital surplus cannot be applied to the payment of the minimum quarterly distribution or any arrearages unless and until the unrecovered initial unit price is reduced to zero.
 
Once we distribute capital surplus on a unit issued in this offering in an aggregate amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from distributable cash flow, with 50.0% being paid to the holders of units and 50.0% to our general partner. The percentage interest shown for our general partner include its 2.0% general partner interest and assume our general partner has maintained its 2.0% general partner interest and our general partner has not transferred the incentive distribution rights.
 
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
 
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:
 
  •  the minimum quarterly distribution;
 
  •  the target distribution levels;
 
  •  the unrecovered initial unit price; and
 
  •  the number of Series A subordinated units and Series B subordinated units.
 
For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each Series A subordinated unit and Series B subordinated unit would convert into two Series A subordinated units and two Series B subordinated units, respectively. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.
 
In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.
 
Distributions of Cash Upon Liquidation
 
General.  If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.


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The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.
 
Although the Series B subordinated units will not be entitled to quarterly distributions, the Series B subordinated units would participate in distributions upon liquidation in accordance with their capital account balances. After conversion of the Series B subordinated units, special allocations of income, gain, loss, deduction, unrealized gain, and unrealized loss among the partners will be utilized to create economic uniformity among the units into which the Series B subordinated units convert.
 
Manner of Adjustments for Gain.  The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:
 
  •  first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
 
  •  second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;
 
  •  third, 98.0% to the Series A subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each Series A subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
 
  •  fourth, 85.0% to all common unitholders and Series A subordinated unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from distributable cash flow in excess of the minimum quarterly distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;
 
  •  fifth, 75.0% to all common unitholders and Series A subordinated unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from distributable cash flow in excess of the first target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence; and
 
  •  thereafter, 50.0% to all common unitholders and Series A subordinated unitholders, pro rata, and 50.0% to our general partner.
 
The percentage interests set forth above for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.


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We may make special allocations of gain among the partners in a manner to create economic uniformity among the units, including among the units into which the Series A subordinated units and Series B subordinated units convert, and among the common units issued in connection with a reset of the incentive distribution levels and the common units held by public unitholders.
 
Manner of Adjustments for Losses.  If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and the unitholders in the following manner:
 
  •  first, 98.0% to holders of Series A subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the Series A subordinated unitholders have been reduced to zero;
 
  •  second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and
 
  •  thereafter, 100.0% to our general partner.
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and Series A subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
 
We may make special allocations of loss among the partners in a manner to create economic uniformity among the units, including among the units into which the Series A subordinated units and Series B subordinated units convert, and among the common units issued in connection with a reset of the incentive distribution levels and the common units held by public unitholders.
 
Adjustments to Capital Accounts.  Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and Series A subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.


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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
 
The selected financial and operating data below was derived from our audited consolidated balance sheets as of December 31, 2009 and 2008, and the audited consolidated statements of operations, changes in members’ capital and cash flows for the periods of September 3, 2009 to December 31, 2009, January 1, 2009 to September 2, 2009, and the years ended December 31, 2008 and 2007 included elsewhere in this prospectus. The selected historical financial and operating data below for the years ended December 31, 2007, 2006 and 2005 was derived from our audited consolidated balance sheet as of December 31, 2007, 2006 and 2005 and the consolidated statements of operations, changes in members’ capital and cash flows for the years ended December 31, 2006 and 2005 not included in this prospectus.
 
On September 3, 2009, PAA became our sole owner by acquiring Vulcan Capital’s 50% interest in us (the “PAA Ownership Transaction”) in exchange for $220 million, including contingent cash consideration of $40 million. At the time of the transaction, the entity had approximately $450 million of outstanding project finance debt. Although we continued as the same legal entity after the transaction, pursuant to applicable accounting principles, all of our assets and liabilities were adjusted to fair value as a result of this transaction. This change in value resulted in a new cost basis for accounting (fair value push down accounting). Accordingly, the selected financial and operating data presented below are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the PAA Ownership Transaction. The Predecessor and Successor periods have been separated by a vertical line to highlight the fact that the financial and operating information for such periods was prepared under two different cost bases of accounting.
 
The summary pro forma statement of operations data for the year ended December 31, 2009 and the summary pro forma balance sheet data as of December 31, 2009 are derived from our unaudited pro forma condensed combined financial statements included elsewhere in this prospectus. The pro forma adjustments have been prepared as if the PAA Ownership Transaction, this offering and the anticipated borrowings under our credit facility had taken place on December 31, 2009 in the case of the pro forma balance sheet, and on January 1, 2009 in the case of the pro forma statement of operations data. A more complete explanation of the pro forma data can be found in our unaudited pro forma condensed combined financial statements.
 
The selected historical financial and operating data should be read in conjunction with the Consolidated Financial Statements, including the notes thereto, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 


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      Predecessor       Successor     Pro Forma  
      August 18,
                              January 1,
      September 3,
       
      2005
                              2009
      2009
       
      through
      Year Ended
      Year Ended
      Year Ended
      through
      through
    Year Ended
 
      December 31,
      December 31,
      December 31,
      December 31,
      September 2,
      December 31,
    December 31,
 
      2005(1)       2006       2007       2008       2009       2009     2009  
      ($ in thousands except for /Mcf numbers)  
Statement of operations data:
                                                                   
Total revenues
    $ 6,580       $ 30,831       $ 36,945       $ 49,177       $ 46,929       $ 25,251     $ 72,180  
                                                                     
Storage related costs
              100         3,847         8,934         8,792         7,003       15,795  
Operating costs (except those shown below)
      1,180         3,658         3,947         4,059         4,820         3,257       8,077  
Fuel expense
      411         613         1,140         2,320         1,816         578       2,394  
General and administrative expenses
      866         3,402         3,755         3,874         3,562         4,083       8,897  
Depreciation, depletion and amortization
      1,223         3,986         4,520         6,245         8,054         3,578       11,442  
                                                                     
Total costs and expenses
      3,680         11,759         17,209         25,432         27,044         18,499       46,605  
                                                                     
                                                                     
Operating income
      2,900         19,072         19,736         23,745         19,885         6,752       25,575  
Interest expense
      (1,684 )       (8,389 )       (7,108 )       (4,941 )       (4,352 )       (4,262 )     (759 )
Interest income and other income (expense), net
      480         2,030         5,378         1,669         458         (2 )     456  
Income tax expense
                              (887 )       (473 )             (473 )
                                                                     
Net income
    $ 1,696       $ 12,713       $ 18,006       $ 19,586       $ 15,518       $ 2,488     $ 24,799  
                                                                     
Balance sheet data (at end of period):
                                                                   
Total assets
    $ 332,002       $ 518,092       $ 674,765       $ 811,436                 $ 900,407     $ 900,407  
Long-term debt(2)
      85,500         227,300         352,713         415,263                   450,523          
Total debt(2)
      85,500         227,300         355,163         417,713                   450,523          
Members’/partners’ capital
      226,696         264,109         294,717         363,229                   432,744          
Other financial data:
                                                                   
Adjusted EBITDA(3)
    $ 4,603       $ 27,395       $ 29,663       $ 31,001       $ 28,701       $ 12,165 (4)   $ 39,614  
Distributable cash flow(3)
    $ 2,919       $ 19,006       $ 22,156       $ 25,577       $ 23,965       $ 7,200     $ 37,768  
Maintenance capital expenditures
    $       $       $       $ 377       $ 384       $ 320     $ 704  
Net cash provided by (used in) operating activities
    $ 5,351       $ 13,973       $ 22,343       $ 21,818       $ 22,603       $ 15,265          
Net cash provided by (used in) investing activities
    $ (264,189 )     $ (206,612 )     $ (177,280 )     $ (118,890 )     $ (58,561 )     $ (9,656 )        
Net cash provided by (used in) financing activities
    $ 309,278       $ 158,771       $ 145,743       $ 122,344       $ 23,636       $ (22,813 )        
Operating data:
                                                                   
Average monthly working capacity (Bcf)(5)(6)
      20         24         26         28         40         43       41  
Average monthly Firm Storage Services revenue/Mcf
    $ 0.08       $ 0.09       $ 0.10       $ 0.13       $ 0.13       $ 0.14     $ 0.14  
Average monthly Hub Services revenue/Mcf
    $ 0.01       $ 0.01       $ 0.02       $ 0.01       $ 0.02       $ 0.01     $ 0.01  
Adjusted EBITDA/Mcf
    $ 0.23       $ 1.14       $ 1.14       $ 1.11       $ 0.72       $ 0.28     $ 1.00  
 
 
(1) Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. In September 2005, we entered the gas storage business through the acquisition of the Bluewater facility in the start-up phase and certain land and development rights of Pine Prairie in the

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permitting phase. The assets we acquired constituted only a small portion of the seller’s total assets and detailed, segregated financial information regarding these assets for the eight months ended August 31, 2005 was not maintained and cannot be provided without unreasonable effort and expense. Due to the significant growth and development of our business since September 2005, the age of this information and its limited comparability to more current period information, we believe that the omission of financial information for this eight month period of 2005 is immaterial and unnecessary with respect to an understanding of our financial results and condition or any related trends or business prospects.
 
(2) At December 31, 2009, the long-term debt and total debt balances consist of an intercompany note payable to PAA.
 
(3) Adjusted EBITDA and distributable cash flow are defined in “Summary — Summary Historical Financial and Operating Data — Non-GAAP and Segment Financial Measures.” Distributable cash flow does not reflect actual cash on hand that is available for distribution to our unitholders. For a discussion of the limitations on our cash distributions and our general partner’s ability to change our cash distribution policy, please read “Our Cash Distribution Policy and Restrictions on Distributions — General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”
 
(4) The successor period includes total expenses of approximately $1 million associated with increased personnel costs, including added staffing, and accelerated audit and other costs related to our increased acquisition activities and our efforts to become a publicly traded entity as well as increased overhead allocations from PAA.
 
(5) Includes up to 3 Bcf of storage capacity under lease from third parties.
 
(6) Calculated as the sum of the capacity at the end of each month divided by the number of months in the period.


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MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
You should read the following discussion of financial condition and results of operations in conjunction with our historical consolidated financial statements included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the following discussion. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding certain risks inherent in our business.
 
Overview
 
We are a fee-based, growth-oriented Delaware limited partnership formed by Plains All American in January 2010 to own, operate and grow the natural gas storage business that PAA acquired in 2005 and has continuously operated since that time. Concurrent with the closing of this offering, PAA will contribute the equity interest in the entities that own its natural gas storage business to us. Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. We currently own and operate two natural gas storage facilities located in Louisiana and Michigan that have an aggregate working gas storage capacity of 40 Bcf and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively.
 
Our operating assets include the Pine Prairie facility, which is a recently constructed, high-deliverability salt-cavern natural gas storage complex located in Evangeline Parish, Louisiana, and the Bluewater facility, which is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. Pine Prairie has a total current working gas storage capacity of 14 Bcf in two salt caverns, and Bluewater has total working gas storage capacity of approximately 26 Bcf in two depleted reservoirs.
 
Activities Impacting Our Historical and Anticipated Growth
 
Our gas storage facilities have been expanded, are undergoing current expansion or present additional organic growth opportunities for future expansion. These ongoing expansion activities have affected operating and financial results since 2005 and are expected to affect our future results. We have budgeted approximately $260 million for all of our planned organic growth capital expenditures through 2012, $95 million of which we plan to spend in 2010, $85 million of which we plan to spend in 2011 and $80 million of which we plan to spend in 2012. A description of our historical and planned expansion activities is set forth below.
 
  •  Pine Prairie.  Since we acquired the development rights and assets of Pine Prairie in 2005, we have developed and placed into service two salt caverns with an aggregate working gas storage capacity of 14 Bcf. Our first storage cavern (5 Bcf) went into service in October 2008 and the second storage cavern (9 Bcf) went into service in March 2009. Our current expansion plans include the addition of 31 Bcf of working gas storage capacity at our Pine Prairie facility, 28 Bcf of which we expect to place into service by mid-2012, including 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010. We have received all applicable federal, state and local approvals required to construct these expansions (including FERC and Louisiana Department of Natural Resources) and, when complete, we expect to have five salt caverns in service and 45 Bcf of working gas storage capacity at Pine Prairie. We have also constructed a pipeline header system, which includes an aggregate of 74 miles of 24-inch diameter pipe located within a 20-mile radius of Pine Prairie, that connects directly to eight large-diameter interstate pipelines through nine interconnects that service both conventional and unconventional natural gas production in Texas and Louisiana, including production from existing and emerging shale plays, as well as Gulf of Mexico production and LNG imports. In connection with our current plan to expand Pine Prairie to five caverns, we are in the process of adding approximately 56,250 horsepower of compression to supplement the approximately 32,000 horsepower already in place. Pine Prairie also has a solution mining facility (used to create salt-dome storage caverns) that is capable of leaching at an aggregate rate of up to 8,000 gallons of water per minute. Our total estimated capital cost for all of our existing


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  facilities at Pine Prairie and the planned expansions to take our working gas storage capacity to 45 Bcf is expected to be approximately $735 million, excluding capitalized interest, approximately $504 million of which had been spent as of December 31, 2009. Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf. Taking these considerations into account, with certain infrastructure modifications, we currently estimate that Pine Prairie could support in excess of 15 salt caverns and an aggregate storage capacity of over 150 Bcf.
 
  •  Bluewater.  We acquired the Bluewater facility in 2005 at the same time we acquired the development rights and assets of Pine Prairie. At the time we acquired Bluewater, it had an aggregate working gas storage capacity of 20 Bcf. Since the acquisition, we have completed various expansion activities that enabled us to raise the maximum operating pressure of the Bluewater facility, which in turn increased the total storage capacity of the initial Bluewater facility to 23 Bcf. During 2006, we acquired the nearby Kimball depleted reservoir storage facility and integrated it with our extensive pipeline header system at Bluewater, which provided an additional 3 Bcf of storage capacity and enhanced our operating flexibility. During the second quarter of 2010, we intend to commence drilling of an additional well within the main portion of the larger reservoir, which we believe will create additional natural gas storage capacity by allowing removal of liquids from the reservoir that could not be produced from existing well bores. Any liquid hydrocarbons recovered will be sold to generate additional revenue, and any water produced will be removed from the reservoir. The project also involves re-configuring our compression to optimize our existing injection and deliverability capacity. We expect the total cost of the project to be approximately $9 million, including incremental base gas requirements. Although we can give no assurance that the project will be successful, we currently estimate that the project will increase the Bluewater facility’s total storage capacity by approximately 2 Bcf ratably over a 10-year period beginning in 2011.
 
Factors That Impact Our Business
 
We believe that the high percentage of our earnings derived from fixed-capacity reservation fees under multi-year contracts with a diverse portfolio of customers stabilizes our baseline cash flow profile, and substantially mitigates the risk to us of significant negative cash flow fluctuations caused by changing supply and demand conditions and other market factors. We do not take title to the natural gas that we store for our customers, but we are entitled to retain a small portion of the natural gas scheduled for injection by our customers to compensate us for the natural gas we use as fuel to run our facilities. Except for (i) the base gas we purchase and use in our facilities and which we consider a long-term asset, and (ii) volume and pricing variations related to fuel retained from our customers, our current and planned business strategies are designed to minimize our exposure to fluctuations in the outright price of natural gas.
 
We believe key factors that influence our business are (i) the long-term demand for natural gas in our markets and the overall balance in our markets between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis, which factors determine the amount of volatility in natural gas prices and drive the month to month differentials in the forward curve for natural gas prices, (ii) the needs of our customers and the competitiveness of our service offerings with respect to price, reliability and flexibility, and (iii) government regulation of natural gas storage systems. These key factors, discussed in more detail below, play an important role in how we evaluate our operations and implement our long-term strategies.
 
Natural Gas Supply and Demand Dynamics
 
To effectively manage our business, we monitor our market areas for both short-term and long-term changes in natural gas supply and demand and the relative adequacy of existing and planned pipeline and storage infrastructure to meet these changing needs. In general, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent and severe imbalances between the


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supply of and demand for natural gas, whether caused by supply or demand fluctuations, should increase volatility, inter-month differentials in gas prices and the need for and value of storage services. Our storage services allow our customers to manage volatility in natural gas supply and demand, as well as price, throughout our markets. As changes in natural gas supply and demand dynamics take place, we will attempt to adjust our service offerings in terms of price, term, operating flexibility and other factors to meet the needs of our customers, in each case subject to any regulatory constraints or limitations provided in our FERC-approved tariffs.
 
Customers and Competition
 
We store natural gas and provide other storage services for a broad mix of customers, including LDCs, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. Our Pine Prairie and Bluewater facilities are located in two different markets. Bluewater is located in the Midwestern U.S. and its function and value is generally related to supply and demand imbalances resulting from seasonal factors. Pine Prairie is a multi-turn, high-performance facility located in the Gulf Coast that provides seasonal-related services as well as a variety of other services. Collectively, these facilities are strategically positioned relative to several major market hubs and have significant connectivity that enable them to serve a variety of major producing regions, LNG importers and the primary consumer and industrial markets in the Gulf Coast, Midwest, Northeast and Southeast regions of the U.S. as well as eastern Ontario, Canada.
 
In general, the mix of services we provide to our customers varies depending on market conditions, expectations for future market conditions and the overall competitiveness of our service offerings. The storage markets in which we operate are very competitive and we compete with other storage operators on the basis of rates, terms of service, types of service, supply and market access, and flexibility and reliability of service. We continuously monitor the evolving needs of our customers, current and forecasted market conditions and the competitiveness of our service offerings in order to maintain the proper balance between optimizing near-term earnings and cash flow and positioning the business for sustainable long-term growth.
 
Regulation
 
Government regulation of natural gas storage can have a significant impact on our business. The rates and terms and conditions for the interstate storage services provided by our Pine Prairie and Bluewater facilities are set forth in FERC-approved tariffs, which currently permit both Pine Prairie and Bluewater to charge market-based rates. Market-based rate authority allows Pine Prairie and Bluewater to negotiate rates with individual customers based on market demand. The right to charge market-based rates may be challenged by a party filing a complaint with the FERC or by the FERC on its own initiative. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing storage services. Other federal and state regulation can impact our operations, cost structure and profitability, which could in turn impact our financial performance and our ability to make distributions to our unitholders. As a result, we closely monitor regulatory developments affecting our business. For more information, see “Business — Regulation.”
 
How We Evaluate Our Operations
 
We evaluate our business performance on the basis of the following key measures:
 
  •  revenues derived from both firm storage services and hub services;
 
  •  our operating and general and administrative expenses;
 
  •  our Adjusted EBITDA; and
 
  •  our distributable cash flow.
 
We do not utilize depreciation, depletion and amortization expense in our key measures, because we focus our performance management on cash flow generation and our assets have long useful lives.


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In our period to period comparisons of our revenues and expenses set forth below, we analyze the following revenue and expenses components:
 
Revenues
 
Firm storage reservation fees.  Firm storage services include (i) storage services pursuant to which customers receive the assured or “firm” right to store gas in our facilities over a multi-year period and (ii) seasonal “park and loan” services pursuant to which customers receive the “firm” right to store gas in (park), or borrow gas from (loan), our facilities on a seasonal basis. Under our firm storage contracts, our customers are obligated to pay us fixed monthly capacity reservation fees, which are owed to us regardless of the actual storage capacity utilized. At Pine Prairie, our firm storage contracts typically have terms of 3 to 5 years, while at Bluewater terms generally range from 1 to 3 years.
 
Firm storage cycling fees and fuel-in-kind.  We also typically collect a “cycling fee” based on the volume of natural gas nominated for injection and/or withdrawal and retain a small portion of natural gas nominated for injection as compensation for our fuel use.
 
Hub services.  We collect fees from (i) “interruptible” storage services pursuant to which customers receive only limited assurances regarding the availability of capacity in our storage facilities and pay fees based on their actual utilization of our assets, (ii) non-seasonal “park and loan” services and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through our facilities from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from our facilities. We may also retain a small portion of natural gas nominated for injection as compensation for our fuel use.
 
Other revenues.  We also generate revenues through the sale of crude oil and liquids produced in conjunction with the operation of our Bluewater facility, net of royalties and taxes. Additionally, we periodically sell any fuel-in-kind volumes in excess of actual volumes needed as fuel for our facilities and reflect any gain or loss on such sales in other revenues.
 
Expenses
 
Storage related costs.  These consist of fees incurred to lease third-party storage and pipeline capacity and costs associated with certain loan services.
 
Fuel expense.  Natural gas constitutes the primary fuel for our compressors, which are used to inject natural gas into our storage facilities and to boost the pressures for certain pipeline deliveries or transfers. Fuel-related expenses may fluctuate materially from period to period due to variations in both the volume and value of natural gas consumed in our operations, with volumes being driven primarily by the volumes of natural gas injected into or wheeled through our facilities. We measure our fuel consumption using meters located at our central facilities. We charge fuel expense for the estimated volume consumed based on the weighted average price of fuel collected.
 
General and Administrative Expense.  Excluding fuel-related expenses, our operating and general and administrative expenses typically do not materially vary based on the amount of natural gas we store. The timing of certain expenditures during a year generally fluctuate with customers’ demands, which change depending on market conditions and whether we are in the injection or withdrawal season for natural gas. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. Fluctuations in operating costs may occur due to the timing of planned maintenance activities as well as fluctuations in the level of project development and acquisition activity during a given period of time. Regulatory compliance can also impact our maintenance requirements and affect the timing and amount of our costs and expenditures.


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Adjusted EBITDA and Distributable Cash Flow
 
Adjusted EBITDA and distributable cash flow are supplemental financial measures that are used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
 
We define Adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring.
 
Adjusted EBITDA may be used to assess:
 
  •  our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
 
  •  the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and
 
  •  the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
 
We define distributable cash flow as net income adjusted for (i) any gain or loss from the sale of assets not in the ordinary course of business, (ii) any gain or loss as a result of a change in accounting principles, (iii) any non-cash gains or items of income and any non-cash losses or expenses, including mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities, (iv) any acquisition-related expenses associated with (a) successful acquisitions or (b) all other acquisitions until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence and (v) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received; plus depreciation, depletion and amortization expense; and less maintenance capital expenditures.
 
Distributable cash flow may be used to assess our ability to generate sufficient cash flow to make distributions of the minimum quarterly distribution on all of our outstanding units as well as to satisfy the tests necessary for the conversion of our Series B subordinated units into Series A subordinated units or common units and the conversion of our Series A subordinated units into common units.
 
The GAAP measure most directly comparable to Adjusted EBITDA and distributable cash flow is net income. The supplemental measures of Adjusted EBITDA and distributable cash flow should not be considered as alternatives to GAAP net income. These measures have important limitations as an analytical tool because they exclude some but not all items that affect net income. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for net income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. For a reconciliation of these measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Summary — Summary Historical Financial and Operating Data — Non-GAAP and Segment Financial Measures.”
 
Management compensates for the limitations of Adjusted EBITDA and distributable cash flow as analytical tools by reviewing the comparable GAAP measure, understanding the differences between such measures and net income, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.
 
Results of Operations
 
PAA Ownership Transaction and Basis of Presentation
 
On September 3, 2009, PAA became our sole owner by acquiring Vulcan Capital’s 50% interest in us (“PAA Ownership Transaction”) in exchange for $220 million, including contingent cash consideration of $40 million, which we expect to be paid, and the obligation to pay 100% of our outstanding project finance debt of approximately $450 million. Although we continued as the same legal entity after the transaction, pursuant to


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applicable accounting principles, all of our assets and liabilities were adjusted to fair value as a result of the transaction. This change in value resulted in a new cost basis for accounting (fair value push down accounting). Accordingly, the accompanying consolidated financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the PAA Ownership Transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of our consolidated financial statements to highlight the fact that the financial information for such periods has been prepared under two different historical-cost bases of accounting. We have prepared our discussion of the results of operations by comparing the results of operations of the Predecessor for the years ended December 31, 2007 and 2008 to the Predecessor period of January 1, 2009 to September 2, 2009. A comparative discussion of the results of operations of the Successor period of September 3, 2009 to December 31, 2009 has not been provided due to the lack of a comparable 2008 operating period for Predecessor; however, we have prepared a brief discussion of the factors that materially affected our operating results in the Successor period. We have provided a comparative discussion of the pro forma results of operations of the year ended December 31, 2009 (prepared as if the PAA Ownership Transaction, this offering and the anticipated borrowing under our credit facility had taken place on January 1, 2009) to the year ended December 31, 2008. The following table includes our operating results for these periods (dollar amounts in thousands, except per Mcf amounts).
 
                                                 
      Predecessor       Successor     Pro Forma  
                      January 1,
      September 3,
       
                      2009
      2009
       
      Year Ended
      through
      through
    Year Ended
 
      December 31,       September 2,
      December 31,
    December 31,
 
      2007       2008       2009       2009     2009  
Revenues
                                               
Firm storage services
                                               
Reservation fees
    $ 28,542       $ 37,674       $ 39,616       $ 22,919     $ 62,535  
Cycling fees and fuel-in-kind
      2,815         5,197         3,033         1,053       4,086  
Hub Services
      4,802         1,417         2,988         1,637       4,625  
Other
      786         4,889         1,292         (358 )     934  
                                                 
Total revenue
      36,945         49,177         46,929         25,251       72,180  
Storage related costs
      (3,847 )       (8,934 )       (8,792 )       (7,003 )     (15,795 )
Operating costs (except those shown below)
      (3,947 )       (4,059 )       (4,820 )       (3,257 )     (8,077 )
Fuel expense
      (1,140 )       (2,320 )       (1,816 )       (578 )     (2,394 )
General and administrative expenses
      (3,755 )       (3,874 )       (3,562 )       (4,083 )     (8,897 )
Interest income and other income (expense), net
      5,378         1,669         458         (2 )     456  
Equity compensation expense
      553         (110 )       304         1,467       1,771  
Mark-to-market of open derivative positions
      (524 )       (548 )               370       370  
                                                 
Adjusted EBITDA
      29,663         31,001         28,701         12,165       39,614  
                                                 
Reconciliation to net income
                                               
Depreciation, depletion and amortization
      (4,520 )       (6,245 )       (8,054 )       (3,578 )     (11,442 )
Interest expense(1)
      (7,108 )       (4,941 )       (4,352 )       (4,262 )     (759 )
Income tax expense
              (887 )       (473 )             (473 )
Equity compensation expense
      (553 )       110         (304 )       (1,467 )     (1,771 )
Mark-to-market of open derivative positions
      524         548                 (370 )     (370 )
                                                 
Net income
    $ 18,006       $ 19,586       $ 15,518       $ 2,488     $ 24,799  
                                                 
Operating Data:
                                               
Average monthly working capacity (Bcf)
      26         28         40         43       41  
Average monthly Firm Storage Services revenue/Mcf
    $ 0.10       $ 0.13       $ 0.13       $ 0.14     $ 0.14  
Average monthly Hub Services revenue/Mcf
    $ 0.02       $ 0.01       $ 0.02       $ 0.01     $ 0.01  
Adjusted EBITDA/Mcf
    $ 1.14       $ 1.11       $ 0.72       $ 0.28     $ 1.00  


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(1) Interest expense is net of capitalized interest of $18.6 million, $19.0 million, $10.2 million, $5.4 million and $7.5 million for the periods presented, respectively.
 
Pro forma period of 2009 and 2008
 
The following discussion and analysis compares the pro forma results of operations for the year ended December 31, 2009 to our predecessor’s historical results of operations for the year ended December 31, 2008. As the pro forma results of operations are not necessarily indicative of operating results had the transactions occurred January 1, 2009, this discussion is not a substitute for management’s discussion and analysis on a historical basis.
 
Revenues, Volumes and Storage Related Costs.  As noted in the table above, our total revenue and storage related costs increased for the year ended December 31, 2009 on a pro forma basis (“2009 pro forma period”) as compared to the year ended December 31, 2008 (the “2008 period”). This increase primarily resulted from our second Pine Prairie facility cavern being placed into operation in April 2009. Significant additional variances related to these periods are discussed below:
 
  •  Firm storage reservation fees — Firm storage reservation fee revenues increased for the 2009 pro forma period as compared to the 2008 period, primarily due to an additional 8 Bcf of capacity being placed into service at Pine Prairie during 2009, along with a full year of operations for our initial 6 Bcf of capacity at Pine Prairie. Our Pine Prairie facility generated approximately $19.4 million of incremental firm storage services revenues during the 2009 pro forma period. Revenues from firm storage reservation fees were also positively impacted by loan transactions and third-party transportation activities together with increases in storage leased from third parties for the 2009 pro forma period when compared to the 2008 period. See “— Storage related costs” below.
 
  •  Firm storage cycling fees and fuel-in-kind  — Firm storage cycling fees and fuel-in-kind revenues decreased in the 2009 pro forma period as compared to the 2008 period primarily due to a decrease in the period over period average natural gas price of approximately 53% in the 2009 pro forma period, which was partially offset by increased volumes collected primarily due to an additional 8 Bcf of capacity being placed into service at our Pine Prairie facility.
 
  •  Hub services — Hub services increased approximately $3.2 million in the 2009 pro forma period as compared to the 2008 period. This increase was primarily related to increased wheeling and balancing services through the utilization of transportation capacity during the 2009 pro forma period. See “— Storage related costs” below.
 
  •  Other — Other revenue for each of the periods was comprised primarily of crude oil sales. The decrease in the 2009 pro forma period as compared to the 2008 period was primarily related to lower average prices realized in the 2009 pro forma period. Additionally, other revenue during the 2008 period reflects a realized gain of approximately $1.1 million on a natural gas storage related futures derivative position. Other revenue for the 2009 pro forma period includes an unrealized loss of approximately $0.4 million on a natural gas storage related futures derivative position.
 
  •  Storage related costs — We increased the amount of storage and transportation capacity leased from third parties in the 2009 pro forma period compared to the 2008 period. In addition, we experienced higher costs as a result of increased loan transactions in the 2009 pro forma period compared to the 2008 period.
 
Other Costs and Expenses.  The significant variances are discussed further below:
 
  •  Operating costs — Field operating costs increased in the 2009 pro forma period compared to the 2008 period. This increase is primarily related to our continued expansion of the Pine Prairie facility and related growth in personnel costs.
 
  •  Fuel expense — Fuel expense was relatively flat in the 2009 pro forma period compared to the 2008 period as an increase in volumes used was largely offset by a decrease in the average price of natural gas.


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  •  General and administrative expenses — General and administrative expenses increased in the 2009 pro forma period compared to the 2008 period. This increase was driven by increased costs primarily related to the continued expansion of our business and growth in personnel costs, including an increase in costs allocated to us from PAA as a result of PAA personnel devoting additional time and effort to our operations.
 
  •  Depreciation, depletion and amortization — Depreciation, depletion and amortization expense increased in the 2009 pro forma period compared to the 2008 period. This increase was driven primarily by an increased amount of depreciable assets resulting from our internal growth projects (including our second Pine Prairie facility cavern) along with an increase in the basis of property and equipment as a result of fair value adjustments recorded in connection with the PAA Ownership Transaction. These increases were partially offset by adjustments to the estimated useful lives of our property and equipment in conjunction with the PAA Ownership Transaction which lengthened the estimated useful lives of most of our more significant components of property and equipment. Depreciation, depletion and amortization expense includes amortization of debt issue costs and intangibles of $1.8 million and $1.4 million in the 2009 pro forma period and 2008 period, respectively.
 
  •  Interest expense — Interest expense decreased in the 2009 pro forma period as compared to the 2008 period. This decrease was principally due to the reduction in our debt balance as a result of the use of the net offering proceeds to pay down $      of our intercompany note payable to PAA and the decrease in interest rate associated with the $200 million of credit facility borrowings which were used to pay down our note payable to PAA. The pro forma interest rate on borrowings under our new credit facility is 3.5%, which is based on an assumed rate based on a forecast of LIBOR rates during the period plus the margin expected under the new credit facility, whereas the interest rate on the intercompany note payable to PAA is 6.5%. The impact of this interest rate differential was offset by higher average debt balances and a decrease in capitalized interest in the 2009 pro forma period as compared to the 2008 period. The amount of interest capitalized decreased from approximately $19 million for the 2008 period to approximately $7.5 million for the 2009 pro forma period. The decrease resulted from lower levels of capitalized interest expense as a result of the commencement of operations on caverns one and two of our Pine Prairie facility.
 
  •  Income tax expense — Income tax expense consists of the Michigan state income tax, which was effective January 1, 2008. This tax is an apportionment tax and the commencement of operations at our Pine Prairie facility effectively diluted the activity apportioned to Michigan. Our activity apportionable to Michigan was further diluted when we became a consolidated subsidiary of PAA, which under Michigan tax law resulted in our being required to report for tax purposes on a consolidated basis with PAA. Such factors resulted in a decrease in income tax expense in the 2009 pro forma period when compared to the 2008 period.
 
  •  Interest Income and Other Income (Expense), Net — Interest income and other income (expense), net is comprised primarily of interest income and decreased for the 2009 pro forma period compared to the 2008 period primarily due to a decrease in our average cash balances. The year over year decreases in interest income was also impacted by lower average interest rates for the 2009 pro forma period as compared to the 2008 period.
 
Successor Period of 2009
 
Because the PAA Ownership Transaction did not impact our operations, there were no significant changes in the underlying trends affecting our results of operations. The following discussion compares our operating results between the period beginning January 1, 2009 and ending September 2, 2009 (the “2009 Predecessor Period”) and the period beginning September 3, 2009 and ending December 31, 2009 (the “2009 Successor period”), as well as discusses certain factors that materially affected our operating results in the 2009 Successor period.
 
Revenues, volumes and storage related costs.  During the 2009 Successor period, our average monthly working capacity was approximately 43 Bcf, which was an increase over the 40 Bcf average


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monthly working capacity for the 2009 Predecessor period. This increase was primarily as a result of the commencement of operations of our second cavern at the Pine Prairie facility in April 2009. The increased storage capacity resulted in higher average monthly revenue and storage and transportation related costs. In addition, our average monthly revenues increased as we expanded our services through loans and increased third-party storage and transportation related activities. These increased activities also resulted in higher costs during the 2009 Successor period.
 
Operating costs and general and administrative expenses.  Average monthly field operating costs and general and administrative costs increased during the 2009 Successor period. The increase is primarily related to the continued expansion of our business and growth in personnel costs, including staff additions as we prepared for becoming a publicly traded entity and increased acquisition evaluation activity, a portion of which is reflected in increased allocations from PAA subsequent to the PAA Ownership Transaction.
 
Depreciation, depletion and amortization.  Average monthly depreciation, depletion and amortization expense was impacted in the 2009 Successor period by (i) the change in the cost basis of our property and equipment resulting from the fair value push down accounting and additional assets being placed into service, offset by (ii) an increase in the estimate of the useful lives of our facilities and related property and equipment resulting from the valuation assessment conducted in coordination with the fair value push down accounting adjustments. (see Note 2 to our Consolidated Financial Statements). On an annual basis, depreciation decreased approximately $2.7 million as a result of the change in the depreciable lives. This was partially offset by an increase in annual depreciation of approximately $2.3 million resulting from the increase in the fair values as a result of the PAA Ownership Transaction.
 
Interest expense.  In conjunction with the PAA Ownership Transaction, we entered into an intercompany note payable to PAA and used the proceeds therefrom to repay outstanding project finance debt and terminate our outstanding credit facilities. See “— Liquidity and Capital Resources.” Our average debt outstanding under the note payable, primarily associated with financing the construction of our Pine Prairie facility, increased during the 2009 Successor period to an average of approximately $442 million. In addition, we capitalized interest of approximately $5.4 million, which is a lower percentage of overall interest than we have capitalized in prior periods, due to lower balances of construction in progress as we have commenced operations of our first two caverns at our Pine Prairie facility. The increased average debt balances, higher average interest rate and lower capitalized interest resulted in an increase in average monthly interest expense during the 2009 Successor period.
 
Income tax expense.  Income tax expense consists of the Michigan state income tax, which was effective January 1, 2008. This tax is an apportionment tax and the consolidation of our operations by PAA effectively diluted the activity apportioned to Michigan resulting in a significant decrease in income tax expense for the 2009 Successor period.
 
Interest income and other income (expense), net.  Interest income and other income (expense), net has historically been comprised primarily of interest income related to our cash balances, which were required to be maintained under the terms of our Pine Prairie revolving credit facility. Following the termination of the credit facilities, we no longer carry significant cash balances and do not expect a material amount of interest income.
 
Predecessor Periods of 2009, 2008 and 2007
 
Revenues, Volumes and Storage Related Costs.  As noted in the table above, our total revenue and storage related costs decreased for the 2009 Predecessor period compared to the 2008 period. The primary reason for the decreases is that the 2009 Predecessor period was approximately eight months and is being compared to a twelve-month period. This was partially offset in both cases by the second Pine Prairie facility cavern being placed into operation in April 2009. Total revenue and related storage and transportation costs


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for the 2008 period increased as compared to the year ended December 31, 2007 (the “2007 period”). Significant additional variances related to these periods are discussed below:
 
  •  Firm storage reservation fees — Firm storage reservation fee revenues increased for the 2009 Predecessor period as compared to the 2008 period, primarily due to the second Pine Prairie facility cavern being placed into operation, resulting in approximately $10.8 million in incremental revenues generated by our Pine Prairie facility for the 2009 Predecessor period. This more than offset the decrease in firm storage reservation fees caused by the shorter 2009 Predecessor period. Firm storage revenues increased for the 2008 period as compared to the 2007 period as we sold additional firm storage capacity and entered into fewer seasonal parks, which allowed us to capture the market premium that our customers were placing on firm storage services. This increase in firm storage reservation fees was partially offset by decreases in our hub services as discussed below. Firm storage reservation fees were also positively impacted by the commencement of operations at our first cavern at our Pine Prairie facility, which contributed approximately $1.4 million of additional revenue during the 2008 period. Revenues from firm storage reservation fees were also positively impacted by loan and third-party transportation activities together with increases in storage leased from third parties for both the 2009 Predecessor period and the 2008 period. See “— Storage related costs” below.
 
  •  Firm storage cycling fees and fuel-in-kind — Firm storage cycling fees and fuel-in-kind revenues decreased in the 2009 Predecessor period as compared to the 2008 period primarily due to a decrease in the period over period average natural gas price of approximately 56% in the 2009 Predecessor period as well as the shorter 2009 Predecessor period, which was partially offset by increased volumes collected primarily due to the second Pine Prairie facility cavern being placed into operation. These revenues increased in the 2008 period as compared to the 2007 period primarily due to an increase in the period over period average natural gas prices of approximately 25%, combined with an increase in volumes collected.
 
  •  Hub services — Hub services increased approximately $1.6 million in the 2009 Predecessor period as compared to the 2008 period. This increase was primarily related to an increased amount of wheeling and balancing services through the utilization of transportation capacity during the 2009 Predecessor period. See “— Storage related costs” below. These increases offset the impact caused by the shorter 2009 Predecessor period as compared to the 2008 period. Hub services decreased approximately $3.4 million in the 2008 period as compared to the 2007 period. The decrease was primarily due to an increase in the amount of firm storage capacity that we sold resulting in less capacity available for non seasonal parks. See “— Firm storage reservation fees” above.
 
  •  Other — Other revenue for each of the periods was comprised primarily of crude oil sales. The decrease in the 2009 Predecessor period as compared to the 2008 period was primarily related to lower average prices realized in the 2009 Predecessor period. The increase in the 2008 period over the 2007 period was primarily related to higher average prices and increased volumes sold. In addition, the 2008 period includes a financial derivative gain of approximately $1.1 million from natural gas storage related futures position.
 
  •  Storage related costs — We increased the amount of storage and transportation capacity leased from third parties in both the 2009 Predecessor period and the 2008 period as compared to the applicable prior period. In addition, we experienced higher costs as a result of increased loan transactions in each period. The increased costs were partially offset by the shorter 2009 Predecessor period.
 
Other Costs and Expenses.  The significant variances are discussed further below:
 
  •  Operating costs — Field operating costs increased in the 2009 Predecessor period and 2008 period as compared to the applicable prior periods. The increases in these periods are primarily related to our continued expansion of the Pine Prairie facility and related growth in personnel costs. The increase in costs in the 2009 Predecessor period was partially offset by the shorter 2009 Predecessor period.
 
  •  Fuel expense — Fuel expense was relatively flat in the 2009 Predecessor period as compared to the 2008 period as an increase in volumes used was offset by a decrease in the average price of natural gas.


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  Fuel expense increased in the 2008 period as compared to the 2007 period as both volumes and the average price of natural gas increased.
 
  •  General and administrative expenses — General and administrative expenses decreased in the 2009 Predecessor period as compared to the 2008 period primarily as a result of the shorter 2009 Predecessor period. That decrease was partially offset by increased costs primarily related to the continued expansion of our business and growth in personnel costs. General and administrative expenses were relatively flat for the 2008 period as compared to the 2007 period.
 
  •  Depreciation, depletion and amortization — Depreciation, depletion and amortization expense increased in both the 2009 Predecessor period and 2008 period as compared to the applicable prior periods. The respective increases related primarily to an increased amount of depreciable assets stemming from our internal growth projects. Depreciation, depletion and amortization expense includes amortization of debt issue costs and intangibles of $2.2 million, $1.4 million and $0.9 million in the 2009 Predecessor period, 2008 period and 2007 period, respectively.
 
  •  Interest expense — Interest expense decreased in the 2009 Predecessor period as compared to the 2008 period primarily because of the shorter 2009 Predecessor period, but also because of lower average interest rates. That decrease was partially offset by a higher average debt balance for the 2009 Predecessor period and a lower percentage of capitalized interest. The amount of interest capitalized decreased from approximately $19 million for the 2008 period to approximately $10 million for the 2009 Predecessor period. The decrease resulted from lower levels of capitalized interest expense as a result of the commencement of operations on caverns one and two of our Pine Prairie facility. Interest expense decreased for the 2008 period from the 2007 period primarily due to lower average interest rates and slightly higher capitalized interest compared to approximately $18.6 million for the 2007 period. The decrease was partially offset by increased average debt balances during the 2008 period.
 
  •  Income tax expense — Income tax expense consists of the Michigan state income tax, which was effective January 1, 2008. This tax is an apportionment tax and the commencement of operations at our Pine Prairie facility effectively diluted the activity apportioned to Michigan resulting in a decrease in expense for the 2009 Predecessor period as compared to the 2008 period. Because this tax was not effective until January 1, 2008, we recognized no such tax expense in the 2007 period.
 
  •  Interest Income and Other Income (Expense), Net — Interest income and other income (expense), net is comprised primarily of interest income and decreased for the 2009 Predecessor period and 2008 period as compared to the applicable prior periods primarily due to a decrease in our average cash balances. The year over year decreases in interest income were also impacted by lower average interest rates for the 2009 Predecessor period and 2008 period as compared to the applicable prior periods.
 
Future Trends and Outlook
 
We expect our business to continue to be affected by the key trends described below. We base our expectations on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results will vary, and may vary materially, from our expected results.
 
Benefits from Organic Growth Projects.  We expect that our results from operations for the year ending December 31, 2010 and thereafter will benefit from increased revenues associated with our ongoing expansion projects. At our Pine Prairie facility, we are nearing completion of a third storage cavern that we expect will have 10 Bcf of working gas capacity that we expect to place into service during the second quarter of 2010. In addition, as part of our current development plan, our expansion plans include an additional 21 Bcf of working gas storage capacity, 18 Bcf of which we expect to place into service by mid-2012. We have received regulatory approval for these expansions, and when completed as designed, we will have five salt caverns in service and 45 Bcf of working gas storage capacity at Pine Prairie. At Bluewater, we are pursuing a liquids removal project that is targeted to increase Bluewater’s total storage capacity by approximately 2 Bcf ratably over a 10-year period beginning in 2011.


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Growing Natural Gas Demand.  Publications by the EIA and other industry sources forecast continued growth of long-term demand for natural gas, as well as a continuation of the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors. The various factors supporting these forecasts include (i) expectations of continued growth in the U.S. gross domestic product, which exerts a significant influence on long-term growth in natural gas demand, (ii) an increased likelihood that regulatory and legislative initiatives regarding U.S. carbon policy will drive greater demand for cleaner burning fuels like natural gas, (iii) increasing acceptance of the view that fossil fuels will continue to provide the vast majority of total energy used in the U.S. for the foreseeable future and that natural gas is a clean and abundant domestic fuel source, and (iv) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source.
 
Natural Gas Supply.  For the foreseeable future we believe there will be ample supplies of natural gas from a combination of domestic production, pipeline imports and waterborne imports of LNG. We also believe, however, that it is difficult to predict the extent to which domestic production from unconventional shale resources and LNG imports will increase or decrease, and that this “source of supply uncertainty” adds an element of volatility to natural gas markets that will drive greater demand for storage services, especially from well-positioned facilities that can provide customers with access to both LNG imports and shale production.
 
Market Volatility.  Our business can be positively or negatively affected by the widening or narrowing of seasonal spreads, extended periods of significant or little volatility and economic expansions or downturns.
 
Barriers to Entry.  Although competition within the storage industry is robust, significant barriers to entry exist in the natural gas storage business. These barriers include significant costs and execution risk, a lengthy permitting and development cycle, financing challenges, shortage of personnel with the requisite expertise and the finite number of storage sites suitable for development.
 
Supply of Storage Capacity.  An important factor in determining the value of storage and therefore the rates we are able to charge for new contracts or contract renewals is whether a surplus or shortfall of storage capacity exists relative to the overall demand for storage services in a given market area. In general, on a relative basis, storage values will be lower in markets that are oversupplied with storage than in markets where storage capacity is in short supply. The extent to which markets are oversupplied or undersupplied will fluctuate in response to significant variations in natural gas supply and demand. We believe that the current market for storage capacity is undersupplied. However, future market conditions will be determined both by the future demand for storage as well as the net amount of storage capacity added in future years.
 
Commercial Management Activities.  Similar to the business model successfully employed by PAA, and without altering our basic commercial strategy of committing a high percentage of our storage capacity under multi-year firm storage contracts at attractive rates, we intend to establish a dedicated commercial marketing group that will capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. Consistent with PAA’s experience marketing crude oil and refined products, we anticipate that having a dedicated commercial marketing group that has a consistent presence in our markets will enhance our ability to properly price our storage and hub service offerings and will increase our cash flow by capitalizing on volatility and inefficiencies in the natural gas markets. We will conduct these commercial activities within pre-defined risk parameters, and our general policy will be (i) to purchase natural gas only in situations where we have a market for such gas, (ii) to utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that commodity price fluctuations will not have a material adverse impact on our cash flow and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.
 
Maintenance Capital Expenditures.  Maintenance capital expenditures reduce our distributable cash flow and consist of expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production, and/or functionality of our existing assets. Examples of maintenance


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capital expenditures include capital expenditures associated with maintaining the storage capacity of our facilities as well as ongoing maintenance or replacement costs for the various injection, withdrawal and related equipment associated with those facilities. Our maintenance capital expenditures are not significant because our storage facilities and related equipment are relatively new. We would expect maintenance capital expenditures to increase periodically as we undertake scheduled maintenance on our caverns and related equipment. Although these periodic costs may increase our maintenance capital expenditures from time to time, we do not expect these increases to materially impact our operating results or distributable cash flow.
 
Operating Costs and Inflation.  High levels of natural gas exploration, development and production activities across the U.S. can result in increased competition for personnel and equipment. This can cause an increase in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We will attempt to recover any increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.
 
Increased Costs as a Result of Being a Public Entity.  As a result of being a publicly traded limited partnership, we will incur incremental general and administrative expenses that are not reflected in our historical financial statements. These costs include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, Sarbanes-Oxley compliance, New York Stock Exchange listing, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. We expect our incremental general and administrative expenses associated with being a publicly traded limited partnership to total approximately $2.6 million per year.
 
Ongoing Acquisition Activities.  Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase of natural gas storage assets. Such acquisition efforts involve our participation in processes that have been made public, involve a number of potential buyers and are commonly referred to as “auction” processes, as well as situations where we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations.
 
In connection with our acquisition activities, we routinely incur evaluation and due diligence costs, which are expensed as incurred. In addition to the in-house costs of our personnel and ancillary overhead expenditures allocated to us by our general partner for time devoted to evaluating acquisition opportunities (which can be substantial), we also budget approximately $250,000 per year associated with third party evaluation or due diligence costs for transactions that are assumed not to be consummated.
 
Working with PAA, we are currently involved in discussions and, in certain cases, negotiations, with a number of potential sellers regarding the purchase of natural gas storage assets. Certain of these discussions are more advanced than others, but past experience has demonstrated that any of these discussions and negotiations could advance or terminate in a short period of time. Because of the current increased level of activity, however third party expenses may exceed our typical budgeted levels in the near term. Additionally, certain of the opportunities under evaluation are of a size that would likely involve PAA’s assistance with respect to financing or jointly purchasing such assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Potential PAA Financial Support.” We can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us. See “Risk Factors — If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.”
 
Liquidity and Capital Resources
 
Overview.  Our ability to finance our operations, including funding capital expenditures, making acquisitions, making cash distributions and satisfying any indebtedness obligations, will depend on our ability to generate cash in the future. Our ability to generate cash remains subject to a number of factors, some of which


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extend beyond our control. See “Risk Factors” for further discussion regarding such risks that may affect our liquidity and capital resources.
 
Prior to September 3, 2009, our activities were conducted in a joint venture arrangement. Accordingly, cash flow from operations, borrowings under our credit facilities and contributions from equity owners were historically our primary sources of liquidity. On September 3, 2009, PAA became our sole owner by acquiring Vulcan’s 50% interest in us. In conjunction with that transaction, we entered into a note payable to PAA for approximately $421 million. The proceeds of the note payable were used to repay amounts borrowed under our credit facilities and related interest rate swaps. The credit facilities were terminated following their repayment. The note payable accrues interest at a rate of 6.5%. The proceeds of this offering, as well as anticipated borrowings under our expected credit facility, will be utilized to reduce the amount outstanding under this note payable to approximately $     million.
 
Currently, our sources of liquidity include cash generated from operations and funding from PAA. Subsequent to this offering, we expect our sources of liquidity to include:
 
  •  cash generated from operations;
 
  •  borrowings under a newly established credit facility with a group of banks;
 
  •  issuances of additional partnership units; and
 
  •  debt offerings.
 
We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements, and quarterly cash distributions to unitholders.
 
To maintain our targeted credit profile, we generally intend to fund approximately 60% of the capital required for expansion projects with equity and cash flow in excess of distributions. In connection with the closing of this offering, we expect to enter into a new $400 million revolving credit facility. We believe we will be able to fund up to the first $250 million of acquisitions or expansion projects primarily through borrowings under this credit facility or through other sources and remain in compliance with our targeted credit profile.
 
For a discussion of the impact that the price of natural gas might have on our operations and liquidity and capital resources, please read “— Quantitative and Qualitative Disclosures About Market Risk.”
 
Working Capital.  Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven primarily by changes in accounts receivable and accounts payable. These changes are primarily affected by factors such as credit extended to, and the timing of collections from, our customers and our level of spending for maintenance and expansion activity. We had a working capital balance of approximately $29 million as of December 31, 2008. As of December 31, 2009, we had a working capital deficit of approximately $4 million, primarily as a result of PAA’s election to fund our capital requirements through the intercompany note with PAA following the PAA Ownership Transaction.
 
Historical cash flow information.  The following table reflects cash flows for the applicable periods (in thousands):
 
                                   
    Predecessor       Successor  
                January 1,
      September 3,
 
                2009 through
      2009 through
 
    Year Ended December 31,     September 2,
      December 31,
 
    2007     2008     2009       2009  
Net cash provided by (used in):
                                 
Operating activities
  $ 22,343     $ 21,818     $ 22,603       $ 15,265  
Investing activities
  $ (177,280 )   $ (118,890 )   $ (58,561 )     $ (9,656 )
Financing activities
  $ 145,743     $ 122,344     $ 23,636       $ (22,813 )


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Operating Activities.  The primary drivers of cash flow from our operations are (i) the collection of amounts related to the storage of natural gas, and (ii) the payment of amounts related to expenses, principally storage and transportation related costs, field operating costs and general and administrative expenses. Cash flow from operations increased for the 2009 Predecessor period as compared to the 2008 period primarily due to increased storage activity resulting from the commencement of activities at our Pine Prairie facility in late 2008 and early 2009. These increases were offset by the shorter time period in the 2009 Predecessor period. In addition, 2008 operating activities were negatively affected by approximately $3.2 million for a payment made to the Industrial Development Board No. 1 of the Parish of Evangeline, State of Louisiana, Inc. with respect to a tax abatement for our Pine Prairie facility (see Note 8 to our Consolidated Financial Statements for further discussion). Operating cash flows for the 2008 period decreased from the prior year primarily as a result of the payment to the Parish, which was partially offset by increased storage activity in the 2008 period as compared to the prior year.
 
Investing and Financing Activities.  Our investing activities for each of the periods listed above primarily relate to the continued expansion of our Pine Prairie facility and the acquisition of the related base gas required to operate the facility. See “— Activities Impacting Our Historical and Anticipated Growth” above. To fund these expenditures we made borrowings under our previous credit facilities and term loan agreements and received capital contributions from our equity owners.
 
Distributions to our unitholders and general partner.  Our partnership agreement requires us to distribute all of our available cash quarterly. Generally, our available cash is our cash on hand at the end of the quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from borrowings, including working capital borrowings, made after the end of the quarter. We anticipate paying a minimum quarterly distribution of $      per common unit and Series A subordinated unit per complete quarter, which equates to $      million per quarter, or $      million per year, based on the number of common units, Series A subordinated units and the general partner interest expected to be outstanding immediately after completion of this offering. We do not have a legal obligation to pay this distribution unless and until a quarterly distribution is declared. See “Our Cash Distribution Policy and Restrictions On Distributions” for further information.
 
Capital Requirements.  Our expansion plans include an additional 31 Bcf of working gas storage capacity at our Pine Prairie facility, of which 10 Bcf is substantially complete and expected to be in service during the second quarter of 2010. At Bluewater, we are pursuing a liquids removal project targeted to increase Bluewater’s total storage capacity by approximately 2 Bcf ratably over a 10-year period beginning in 2011. We currently forecast capital expenditures for 2010 of approximately $95 million, primarily related to the Pine Prairie expansion and purchases of related base gas required to operate the facility. We expect to fund our capital expenditures with cash generated from operations and borrowings under our credit facility.
 
New Credit Facility.  In connection with the closing of this offering, we expect to enter into a new $400 million revolving credit facility, with an expected maturity date 3 years from the closing of this offering. The credit facility will be available to fund working capital and our expansion projects, make acquisitions and for general partnership purposes. We expect that we will incur approximately $200 million of borrowings under our credit facility at the closing of this offering. As a result, we expect to have approximately $200 million of remaining capacity immediately after the closing, subject to compliance with any applicable covenants under such facility. We also expect to have an accordion feature that would allow us to increase the available borrowings under the facility by up to $200 million, subject to our lenders agreeing to satisfy the increased commitment amounts under our new facility.
 
This new credit facility is likely to restrict our ability to, among other things:
 
  •  make distributions of available cash to unitholders if any default or event of default (as defined in the credit agreement) exists;
 
  •  incur additional indebtedness;
 
  •  grant liens or make certain negative pledges;


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  •  engage in transactions with affiliates;
 
  •  make any material change to the nature of our business;
 
  •  make a disposition of assets; or
 
  •  enter into a merger, consolidate, liquidate, wind up or dissolve.
 
Furthermore, our credit facility may contain covenants requiring us to maintain certain financial ratios.
 
Restrictions due to PAA’s indebtedness.  Although we are not contractually bound by and are not liable for PAA’s debt under its debt instruments, we are subject to and indirectly affected by certain prohibitions and limitations contained therein. These restrictions may prevent us from obtaining the most advantageous financing terms or from engaging in certain transactions that might otherwise be considered beneficial. See “Risk Factors — We are considered a subsidiary of PAA under its debt instruments and, as such, we may be directly or indirectly subject to and impacted by certain restrictions in PAA’s existing and future credit facilities and indentures. These restrictions may limit our access to credit, prevent us from engaging in beneficial activities, and in certain circumstances, require us to guarantee PAA’s indebtedness.” Although we believe that the restrictions in PAA’s debt instruments will not have a material impact on our operations or access to credit, no assurance can be given to that effect, and PAA’s ability to comply with any restrictions in PAA’s debt instruments may be affected by events beyond our control.
 
Potential PAA Financial Support
 
PAA may elect, but is not obligated, to provide financial support to us under certain circumstances, such as in connection with an acquisition or expansion capital project. Our partnership agreement contains provisions designed to facilitate this process and reduce concerns regarding conflicts of interest by describing certain transactions which, by definition, will be deemed fair to our unitholders. For example, our partnership agreement contains provisions designed to facilitate PAA’s ability to provide us with financial support while reducing concerns regarding conflicts of interest by defining certain potential financing transactions between PAA and us as fair to our unitholders. In that regard, the following forms of potential PAA financial support will be deemed fair to our unitholders, and will not constitute a breach of any duty by our general partner, if consummated on terms not less favorable than those described below:
 
  •  We may issue common units to PAA at a price per common unit of no less than 95% of the trailing 20-day average closing price per common unit; provided, however, we may redeem any such common units (assuming PAA’s agreement) at a price per common unit no greater than 95% of the trailing 20-day average closing price per common unit.
 
  •  We may borrow funds from PAA on terms that include a tenor of no more than three years and a fixed rate of interest that is no more than (i) 100 basis points higher than the fixed rate of interest incurred by PAA on any senior notes or other financial instruments issued by PAA to fund such loan to us or (ii) in the event no such notes or other financial instruments have been issued by PAA to fund such loan to us, 100 basis points higher than the weighted average of PAA’s outstanding senior note issues.
 
We have no obligation to seek financing from PAA on the terms described above or to accept such financing if offered to us. In addition, PAA will have no obligation to provide financial support under these or any other circumstances. We would anticipate that PAA would provide such support to us only if permitted under the relevant provisions of its debt instruments at the time. The existence of these provisions will not preclude other forms of financial support from PAA, including financial support on significantly less favorable terms under circumstances in which such support appears to be in our best interests.
 
Potential Impact of Recent Economic and Financial Market Trends.  During 2008 and the first portion of 2009, worldwide financial markets were extremely volatile, the economy weakened considerably and there was widespread uncertainty regarding the health and stability of our banking system and financial markets. Early in 2009, capital markets access was very limited. As a result of substantial government intervention, the absence of another widespread calamity and the passage of time, panic subsided, and financial markets


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stabilized, successively becoming more and more favorable for capital formation over the remainder of 2009 and through the first few months of 2010.
 
In connection with the closing of this offering, we expect to enter into a new $400 million revolving credit facility. We believe the borrowings available to us under this committed facility in combination with cash flow in excess of our distributions will enable us to fund our existing expansion activities for the next several years, while maintaining credit metrics consistent with our targeted credit profile. Funding of additional expansion activities or acquisitions will require us to access additional capital resources, which we intend to fund with approximately 60% equity capital and 40% debt capital. Although we believe that the equity and debt markets are currently available to us on reasonable terms, there can be no assurance that future market conditions will permit us to access capital to fund future acquisition and expansion activities.
 
We will not be unaffected by challenging economic and capital markets conditions or fluctuations in the price of natural gas; however, our business strategy and financial strategy are designed to help us manage through a volatile environment. In general, our assets and our business model benefit from volatility in the price of natural gas, whether natural gas prices are high or low relative to historical averages. Although an extended period of high gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated expansion activities, such conditions would also result in higher competitive entry barriers and higher demand for contract renewals on our existing storage and planned storage. An extended period of low natural gas prices could adversely impact storage values for a time. Such conditions have typically been self correcting, as positive demand response typically results, increasing natural gas consumption and accentuating seasonal imbalances and the demand for storage. A low gas price environment also typically increases competitive entry barriers and reduces our cost of incremental base gas and storage construction costs.
 
We anticipate our future working capital needs will increase modestly in connection with our expansion into commercial optimization activities. Revenues generated from these activities will be influenced by natural gas prices, which have been volatile and unpredictable in the past. While we expect this volatility to continue in the future, we consider our exposure to commodity price risk not to be material based on the amount of revenues associated with these activities compared to our overall revenues and the fact that the balance of our revenues is fee-based.
 
See “Business — Our Financial Strategy” for a description of our financial strategy and “Risk Factors — Risks Related to Our Business.”
 
Off-balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.
 
Contingencies
 
For a discussion of contingencies that may impact us, see Note 8 to our Consolidated Financial Statements.
 
Commitments
 
Contractual Obligations.  In the ordinary course of doing business we lease storage and transportation capacity from third parties. We also incur debt and interest payments. The following table includes our best


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estimate of the amount and timing of the payments due under our contractual obligations as of December 31, 2009 (in thousands):
 
                                                         
    Total     2010     2011     2012     2013     2014     Thereafter  
 
Long-term debt and interest payments(1)
  $ 651,415     $     $     $     $     $ 651,415     $  
Leases — storage, transportation, other
    51,118       16,103       11,822       10,522       6,228       4,448       1,995  
Purchase obligations
    41,718       23,512       1,556       1,800       1,800       1,800       11,250  
Other long-term liabilities
    1,097             808       145       137       4       3  
                                                         
Total
  $ 745,348     $ 39,615     $ 14,186     $ 12,467     $ 8,165     $ 657,667     $ 13,248  
                                                         
 
 
(1) Includes intercompany loan of $451 million and interest of 6.5% for 5 years entered into in connection with the PAA Ownership Transaction. The loan is represented by a demand note payable to PAA. PAA has issued a waiver stating that it will not demand payment during the year ended December 31, 2010, and PAA has indicated that it will not request repayment prior to December 31, 2013. In connection with the closing of this offering, we expect to repay $      million of this indebtedness.
 
Upon the consummation of this offering, we expect to incur long-term debt under our new credit facility of $200 million, which will be used, together with the net proceeds of this offering, to repay intercompany indebtedness owed to PAA. We expect the interest rate under our new credit facility to be approximately          % . Additionally, in connection with the closing of this offering, we will enter into an omnibus agreement with PAA pursuant to which, among other things, PAA’s general partner will provide to us certain general and administrative services and employees. Pursuant to the omnibus agreement, we will be obligated to reimburse PAA’s general partner for all reasonable costs and expenses incurred by it in connection with the performance of these services and for PAA’s provision of employees.
 
Quantitative and Qualitative Disclosures About Market Risk
 
From time to time, we may use derivative instruments to (i) manage our exposure to interest rates or natural gas prices associated with future base gas purchases and (ii) economically hedge the intrinsic value of our natural gas storage facilities.
 
Commodity Price Risk
 
Natural Gas.  We do not take title to the natural gas that we store for our customers and, accordingly, are not exposed to commodity price fluctuations on the gas that is stored in our facilities by our customers. Except for the base gas we purchase and use in our facilities, which we consider to be a long-term asset, and volume and pricing variations related to small volumes of fuel-in-kind natural gas that we are entitled to retain from our customers as compensation for our fuel costs, our current business model is designed to minimize our exposure to fluctuations in the outright price of natural gas. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas should not materially impact our operations.
 
With respect to base gas, we typically use derivative instruments to hedge all or some portion of our anticipated base gas purchases. In addition, we periodically sell any fuel-in-kind volumes in excess of actual volumes needed for our facilities, and we may also purchase fuel in excess of our fuel-in-kind volumes to the extent such volumes are needed to operate our facilities.
 
Our derivatives at December 31, 2009 represented a net liability of $0.4 million; a 10% decrease in natural gas prices would result in an incremental liability of $0.3 million.
 
Oil.  We generate a relatively small amount of revenue through the sale of crude oil and liquids incrementally produced from our Bluewater facility and, accordingly, are exposed to commodity price fluctuations on the volumes of crude oil and liquids produced and sold from our Bluewater facility. Given the


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fact that crude oil sales generate a relatively small amount of our revenue and that the volumes produced are difficult to predict, we do not typically attempt to hedge the value of such sales.
 
Commercial Activities.  We intend to establish a dedicated commercial marketing group that will capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. We will conduct these commercial activities within pre-defined risk parameters, and our general policy will be (i) to purchase natural gas only in situations where we have a market for such gas, (ii) utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that price fluctuations will not have a material adverse impact on our cash flow, and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.
 
Revenues generated from these activities will be subject to the pricing of hydrocarbons, which has been volatile and unpredictable in the past. While we expect this volatility to continue in the future, we consider our exposure to commodity price risk not to be material based on the amount of revenues associated with these activities compared to our overall revenues and the fact that the balance of our revenues is fee-based.
 
Interest Rate Risk
 
Interest rates in recent years have been low compared to rates over the last 50 years. If interest rates were to rise, our financing costs would increase accordingly. Although increased borrowing costs could limit our ability to raise funds in the capital markets, we expect our competitors would be similarly affected.
 
Prior to the PAA Ownership Transaction, amounts outstanding under our credit facilities accrued interest at floating rates, which were hedged with interest rate swaps. In conjunction with the PAA Ownership Transaction, we entered into a note payable to PAA for approximately $421 million. The proceeds of the note payable were used to repay amounts borrowed under our then-existing credit facilities and related interest rate swaps. The note payable to PAA accrues interest at a fixed rate of 6.5%. At the closing of this offering, we will incur approximately $200 million of borrowings under a new credit facility, which will bear interest at floating rates. We intend to enter into interest rate swaps to fix the interest rate of borrowings under the new credit facility. If we fail to do so, to the extent the interest rate on borrowings under our new credit facility increases or decreases by 1%, interest on amounts outstanding will increase or decrease, respectively, by approximately $2 million.
 
Critical Accounting Policies and Estimates
 
Critical Accounting Policies
 
We have adopted various accounting policies to prepare our consolidated financial statements in accordance with GAAP. These critical accounting policies are discussed in Note 2 to our Consolidated Financial Statements.
 
Critical Accounting Estimates
 
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. The critical accounting estimates that we have identified are discussed below.
 
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets.  In accordance with FASB guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimated provision will be recognized. This provision will be adjusted as if the


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amount was recognized when the combination occurred if material. We also expense the transaction costs as incurred in connection with each acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Intangible assets with finite lives are amortized over their estimated useful lives as determined by management. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment.
 
Impairment testing entails estimating future net cash flows relating to the asset, based on management’s estimate of market conditions including pricing, demand, competition, operating costs and other factors. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, and industry expertise involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third-party assessments. Uncertainties associated with these estimates include assumptions regarding natural gas supply and demand, volatility and pricing of natural gas, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. We perform our goodwill impairment test annually (as of June 30) and when events or changes in circumstances indicate that the carrying value may not be recoverable.
 
We did not have any goodwill impairments in 2009, 2008 or 2007. See Note 2 to our Consolidated Financial Statements for a discussion of goodwill.
 
Property, Plant and Equipment and Depreciation Expense.  We compute depreciation using the straight-line method based on estimated useful lives. We periodically evaluate the estimated useful lives of our property, plant and equipment and revised our estimates in September 2009. Please read Note 2 to our Consolidated Financial Statements.
 
We also evaluate our property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property, plant and equipment a critical accounting estimate. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to:
 
  •  whether there is an indication of impairment;
 
  •  the grouping of assets;
 
  •  the intention of “holding” versus “selling” an asset;
 
  •  the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
 
  •  if an impairment exists, the fair value of the asset or asset group.
 
No impairments have been recorded since our inception.
 
Accruals and Contingent Liabilities.  We record accruals or liabilities including, but not limited to, insurance claims, asset retirement obligations, taxes and potential legal claims. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Such accruals may include estimates and are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory requirements for operating gas storage facilities, costs of medical care associated with worker’s compensation and employee health insurance claims, and the possibility of legal claims. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. Presently, there are no material accruals in these areas. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
 
Equity Compensation Plan Accruals.  We accrue compensation expense for outstanding equity awards granted under a Long-Term Incentive Plan (collectively, our “equity compensation plans”). Under generally


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accepted accounting principles, we are required to estimate the fair value of our outstanding equity awards and recognize that fair value as compensation expense over the service period. For equity awards that contain a performance condition, the fair value of the equity award is recognized as compensation expense only if the attainment of the performance condition is considered probable.
 
For equity compensation awards prior to this offering, the total compensation expense initially allocated to us by PAA over the service period is determined by multiplying PAA’s unit price by the number of equity awards that are expected to vest, plus our share of associated employment taxes. Uncertainties associated with these accruals include the actual unit price at time of vesting, whether or not a performance condition will be attained and the continued employment of personnel with outstanding equity awards.
 
We anticipate that, in connection with the closing of this offering, the board of directors of our general partner will grant awards to our key employees and our outside directors pursuant to the Long-Term Incentive Plan. Certain of our key employees hold grants under PAA’s Long-Term Incentive Plan. It is our intent to replace such grants with grants of equivalent value under our Long-Term Incentive Plan.
 
We recognized total compensation expense of approximately $1.5 million, $0.3 million, $(0.1) million and $0.6 million in the 2009 Successor period, 2009 Predecessor period, and the years ended December 31, 2008 and 2007, respectively, related to equity awards granted under the various equity compensation plans, which are allocated to us by PAA. We cannot provide assurance that the actual fair value of our equity compensation awards will not vary significantly from estimated amounts. See Note 6 to our Consolidated Financial Statements.
 
Mark-to-Market Accrual.  In situations where we are required to mark-to-market derivatives pursuant to FASB guidance, the estimates of gains or losses at a particular period end do not reflect the end results of particular transactions, and will most likely not reflect the actual gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models utilize market-observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
 
Recent Accounting Pronouncements
 
For a discussion of recent accounting pronouncements that will impact us, see Note 2 to our Consolidated Financial Statements.


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NATURAL GAS STORAGE INDUSTRY
 
Introduction
 
Natural gas storage facilities represent a critical component of the North American natural gas transmission and distribution system. These facilities provide an essential reliability cushion against unexpected disruptions in supply, transportation or markets and allow for the warehousing of gas to meet expected seasonal, monthly and daily variability in demand. The diagram below illustrates the position and function of natural gas storage within the natural gas market chain.
 
(Natural Gas Storage)
 
We believe that changes in natural gas markets over the last 25 years have contributed to a growing demand for natural gas storage services provided by independent storage operators like us, particularly with respect to strategically-located, high-performance facilities. Factors contributing to this growing market include (a) a major shift in the manner in which natural gas sales, transportation and storage are regulated; (b) changes in the manner of sale of natural gas, including the development of a futures market and a cash spot market; (c) changes in the composition of natural gas consumption and political and environmental pressures that appear to directionally support increased consumption of natural gas; and (d) the dynamic and evolving profile of various sources of natural gas supply. The overview below provides additional information regarding the current and potential demand for storage as well as the various types of natural gas storage facilities, the services they provide and other related information.
 
Overview
 
Historical Context.  The current market environment for natural gas storage has evolved significantly since the 1970s as the market for natural gas has become less regulated. During this time period, various developments have contributed to the emergence of an open and less regulated market for natural gas sales and natural gas storage, including:
 
  •  interstate pipelines and intrastate utilities were required to “unbundle” their merchant, transportation and storage services, allowing storage services to be provided by non-pipeline service providers at “market-based rates” (as opposed to traditional cost-of-service based rates);
 
  •  “take-or-pay” contracts were eliminated through a combination of regulation and litigation. Under take-or-pay arrangements, purchasers would pay for a minimum quantity of natural gas during a contract year even if the actual amount of gas received by the purchaser was less than the stated


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  minimum. These contracts permitted purchasers to effectively dictate sellers’ production schedules, directing the producers as to when to turn on or turn off their contracted wells. Excess production capacity of sellers represented significant “in situ” natural gas storage capacity and deliverability that was utilized by purchasers to meet seasonal or other peak demand requirements. The elimination of these contractual arrangements afforded sellers the ability to produce natural gas on a year-round basis and contract directly with end-users;
 
  •  a spot market for natural gas developed and the NYMEX introduced the natural gas futures contract in April 1990; and
 
  •  primarily as a result of continuous production and direct competition among gas sellers, natural gas prices fell and consumption increased. According to the EIA, natural gas consumption increased an average of 1% annually from 1990 to 2008.
 
Over this same time period, the purpose and use of natural gas storage has evolved, expanding from a service that was used almost exclusively by local distribution companies and pipelines to balance seasonal or other demand variations, as well as to balance system loads and facilitate pipeline movements, into a service that is used by a wider variety of customers. These expanded services developed for multiple commercial purposes, including:
 
  •  to ensure fuel availability for peak loads by gas-fired power generation;
 
  •  to reduce the impact of supply interruptions in the Gulf of Mexico resulting from hurricanes and other severe weather;
 
  •  to accommodate increased balancing requirements associated with erratic and rapidly declining initial production profiles of new wells in developing shale resource plays or wells that needed to produce continuously without regard to current market demand or price in order to optimize recovery;
 
  •  to contribute to the commercial optimization activities of natural gas suppliers and consumers or financial arbitrage and risk management activities of commodity traders and other market participants;
 
  •  to facilitate storage and distribution of intermittent LNG cargoes; and
 
  •  to manage the variability of solar and wind power generation by providing a back-up fuel source to support gas-fired power generating facilities.
 
As a result of the increased consumption of natural gas over the last two decades, the changes in domestic production capacity and the increased demand for natural gas storage services from a wide variety of market participants, natural gas storage currently plays a critical role in maintaining the reliability and availability of gas supplies in North America.
 
Storage Services.  Storage operators compete for customers based on geographical location, which determines connectivity to pipelines and proximity to supply sources and end-users, as well as operating reliability and flexibility, price, available capacity and service offerings. Services provided by storage operators typically include “firm storage services” and “hub services.”
 
  •  Firm Storage Services.  Customers pay a fixed monthly capacity reservation fee in exchange for an assured or “firm” right to store, inject or withdraw specified volumes for specified periods of time. Capacity reservation fees are payable without regard to the amount of storage capacity actually utilized. Firm storage customers also typically pay “cycling fees” based on the volume of natural gas nominated for injection and/or withdrawal on any given day.
 
  •  Hub Services.  Hub services include (i) “interruptible” storage services pursuant to which customers receive only limited assurances regarding the future availability of capacity in a storage facility and pay fees based on their actual utilization of storage capacity and services, (ii) “park and loan” services, pursuant to which customers pay fees for the right to store gas in (park), or borrow gas from (loan), a storage facility and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through a storage facility from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from, a storage facility.


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From the storage operator’s perspective, having a diverse customer group that requires a variety of storage services is important to maximizing asset utilization and capturing incremental revenue opportunities while minimizing costs.
 
Types of Storage Facilities.  Natural gas is typically stored underground in depleted reservoirs, aquifers or salt caverns. In any non-salt cavern underground storage facility, there is a certain amount of natural gas that may never be extracted, referred to as physically unrecoverable, or permanent, natural gas. In addition to this permanent gas, underground storage facilities contain what is known as base gas, or cushion gas. This is the volume of gas that is injected into a storage facility to maintain adequate pressure and deliverability rates, especially throughout the withdrawal season. In general, working gas is the volume of natural gas in a storage facility at a given point in time that exceeds the amount of base gas and, if applicable, physically unrecoverable gas. Assuming adequate operating pressures, working gas is the amount of gas that can be extracted during the normal operation of the facility. References to the capacity of a storage facility typically refer to its working gas capacity.
 
We estimate that depleted natural gas or oil reservoirs comprise approximately 85% of total working gas storage capacity in the United States. Depleted reservoir facilities are prevalent in the producing regions of the United States, primarily the Northeast, Midwest, Gulf Coast and West Coast regions. Aquifer storage facilities are primarily located in the Midwest. Most salt-cavern storage facilities have been developed in salt-dome formations located along the Gulf Coast, with more limited development in bedded salt formations located in Northeastern, Midwestern and Southwestern states. We estimate that natural aquifers and salt caverns comprise approximately 9% and 6%, respectively, of total working gas storage capacity in the United States.
 
The key distinguishing operational characteristics of any given storage facility, aside from its overall capacity, are its peak injection and withdrawal rates, which dictate the number of times during a given year that a facility is capable of being “turned” or “cycled” (i.e., completely filled with injections of working gas and then completely emptied by withdrawals) and its connectivity to different pipelines and/or markets. Higher peak injection and withdrawal rates and access to multiple markets provide storage users with greater commercial and operational flexibility and, accordingly, command higher storage rates. Salt caverns are voided underground spaces and natural gas can be freely injected into and withdrawn from such caverns with the aid of compression. Conversely, depleted reservoirs and aquifers store natural gas within pore spaces in rock formations and the ability of natural gas to move into and out of the facility is limited by the permeability of the applicable formations, even with the aid of compression. As a result, salt caverns generally have significantly higher peak injection and withdrawal rates, and can be cycled more times per year, than depleted reservoirs and aquifers.
 
Other important characteristics of storage facilities include the overall cost of developing the facility, including base gas requirements and geological risk.
 
  •  Cost to Develop.  The primary categories of cost associated with the development of natural gas storage facilities are (i) real and personal property acquisition costs, (ii) equipment purchase costs, (iii) costs associated with construction, and (iv) the cost of acquiring base gas, which is required to maintain operating pressures and allow for working gas withdrawals. With respect to construction and other non-base gas costs, depleted reservoir facilities are usually the least expensive to develop as portions of existing pipeline and facility infrastructure related to prior production operations can often be used in connection with the development and operation of a depleted reservoir facility, reducing up-front infrastructure costs. In terms of base gas costs, which represent an additional up-front investment cost for a storage facility operator, according to a 2004 FERC report on underground natural gas storage, salt caverns typically require the lowest levels of base gas at approximately 20 to 30% of total gas capacity. By comparison, depleted reservoirs typically require approximately 50% base gas and aquifers may require up to 80% base gas.
 
  •  Geological Risks.  A critical attribute of any underground gas storage facility is the integrity of the geological structure in which the natural gas is stored. The geology of depleted reservoirs is typically well understood and the risk of gas leaks is relatively low given their prior natural use for storing hydrocarbons. The risk of gas leaks from salt caverns is also relatively low given that the walls of a properly constructed salt cavern provide a non-porous seal that reduces the likelihood of gas leaks.


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  Aquifers typically have a higher level of geological risk because they have not previously been used to store hydrocarbons.
 
Barriers to Entry.  Although competition within the storage industry is robust, there are significant barriers to entering the natural gas storage business. These barriers include:
 
  •  Costs and Execution Risk.  The costs of developing and constructing an underground storage facility are significant and highly variable, depending on drilling costs, subsurface issues, raw water availability, brine disposal arrangements, compression requirements, costs of establishing interconnects and other factors. In addition, the creation of all three types of storage facilities involves significant execution risk with respect to drilling and completing wells and related sub-surface activities.
 
  •  Time Commitment.  The length of time required to permit and develop a new project and place it into service can be long and unpredictable, generally ranging from two to four years or more, depending on the type of facility, location, permitting issues, subsurface issues and other factors.
 
  •  Financing.  The magnitude and uncertainty of capital costs, length of the permitting and development cycle and scheduling uncertainties associated with gas storage development present significant project financing challenges. In recent years, the tightening of credit markets has led to a reduction in the amount of capital available for natural gas storage projects.
 
  •  Finite Number of Sites.  Finding and developing new gas storage facilities, or acquiring existing facilities, is extremely competitive given that there are a finite number of sites that possess the requisite characteristics in terms of proximity to pipelines and load centers, operational flexibility, geological characteristics and overall risk/return profile.
 
  •  Required Expertise.  Specialized expertise is required to identify market areas that require or will support additional storage capacity. In addition, acquiring, developing and operating natural gas storage facilities involves identifying, assessing and managing significant geological and other risks that require specialized industry knowledge and experience, including in the areas of reservoir engineering and geology, cavern or reservoir development and construction, and gas compression, handling, treating and transportation. Because there is significant market demand for this combination of skill sets and individuals with such skills sets are in short supply, finding and retaining management and operational personnel is highly competitive.
 
Drivers of Demand for Storage.  The long-term demand for storage services in the United States is driven primarily by the long-term demand for natural gas and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis. In general, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations, should increase the need for and value of storage services.
 
Natural Gas Demand.  According to the EIA, as shown in the chart below, during the period from 1998 through 2008, natural gas consumption increased by 4.1% overall from an average of approximately 60.9 Bcf per day in 1998 to an average of approximately 63.4 Bcf per day in 2008. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation and commercial/residential sectors, where consumption grew by approximately 45.2% and 6.2%, respectively. The growth in these sectors was partially offset by an approximate 20.5% decline in gas consumption in the less seasonal industrial sector.
 


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(CHART)
Percentage Change In Consumption 1998-2008:
 
         
Residential & Commercial
    6.2 %
Industrial
    −20.5 %
Electric Power
    45.2 %
Total Consumption
    4.1 %
 
Source: derived from EIA data
 
Despite the increased use of natural-gas fired generation during the summer cooling months and the recent trend of warmer winters, the seasonality of natural gas consumption has remained strong. According to EIA data, during the last decade, consumption during the winter months averaged approximately 40% more than consumption during the summer months. This seasonal trend is reflected in the chart below, which shows annual U.S. natural gas consumption by sector for the period January 2004 to July 2009.
 
Annual U.S. Natural Gas Consumption by Sector
 
(CHART)
 
Note: Supply includes lower 48 state production, net pipeline imports and LNG imports.
 
 
Source: Derived from EIA data Updated February 5, 2010


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Looking forward, publications by the EIA and other industry sources forecast that long-term demand for natural gas will continue to grow and that the historical trend of growth in natural gas demand from seasonal and weather-sensitive consumption sectors will also continue. Among the various factors that we believe support these forecasts are (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand, (ii) an increased likelihood that regulatory and legislative initiatives regarding U.S. carbon policy will drive greater demand for cleaner burning fuels like natural gas, (iii) increasing acceptance of the view that fossil fuels will continue to provide the vast majority of total energy used in the U.S. for the foreseeable future and that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the U.S. by reducing its dependence on imported petroleum, and (iv) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source.
 
Natural Gas Supply.  The extent to which natural gas supplies are available on a seasonal or shorter-term basis to meet the demand for natural gas consumption directly impacts the demand for storage; however, storage capacity is required in both an oversupplied and an undersupplied natural gas market. In market conditions where there is insufficient domestic production and import supply to meet demand, natural gas must be withdrawn from storage to balance the market. Conversely, in market conditions where there is excess domestic production and import supply relative to demand, natural gas must be injected into storage to balance the market or domestic production and imports must be reduced.
 
For the foreseeable future, we believe there will be ample supplies of natural gas from a combination of domestic production, pipeline imports and waterborne imports of LNG. We also believe, however, that it is difficult to predict the extent to which domestic production from unconventional shale resources and LNG imports will increase or decrease and that this “source of supply uncertainty” adds an element of volatility to natural gas markets that will drive greater demand for storage services, especially from well-positioned, high-performance facilities that can provide customers with access to both LNG imports and shale production.
 
  •  Near-Term Domestic Production Growth.  For the majority of the last decade, domestic production has been relatively flat and has failed to keep pace with domestic consumption. Over the past few years, however, domestic production has been growing, primarily due to increases in production from developing shale resource plays. According to EIA data, during the two-year period from January 1, 2007 through December 31, 2008 domestic production of natural gas increased by an average of approximately 5% per annum and estimates of proved natural gas reserves increased by an average of approximately 7.6% per annum, in each case largely due to continued development of shale resources. Beginning in 2007, leasing and development activities increased in a number of new shale resource plays, which in 2009 caused the EIA to significantly increase its outlook for domestic natural gas production. Notably, the typical production profile for shale production is short lived with initial high levels of production and steep declines thereafter. For this reason, and because producing gas from shale formations is generally more complex and expensive than conventional onshore production, it is difficult to predict future shale resource production levels with certainty.
 
  •  LNG Supplies.  In addition to the emergence of domestic shale plays as a significant supply source, over the past several years, the U.S. has developed significant infrastructure for the import of LNG. In recent years, U.S. and Canadian LNG imports have averaged an aggregate of approximately 1 to 3 Bcf per day, while the total LNG import capacity of U.S. and Canadian infrastructure is approximately 16 Bcf per day. In addition, total worldwide liquefaction capacity for LNG has been increasing over the last several years and additional U.S. and Canadian capacity is scheduled to come online over the next few years.
 
  •  Supply Variability and Uncertainty.  We believe this “source of supply” uncertainty and potential variability related to both domestic production and LNG imports will continue for the foreseeable future, and will contribute to the volatility of natural gas markets and support continued demand for storage capacity, especially high-deliverability storage that provides customers with greater flexibility to access both domestic production from shale resources and LNG imports.


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Supply of Storage Capacity.  An important factor in determining the value of storage is whether there is a surplus or shortfall of storage capacity relative to the overall demand for storage services in a given market area. In general, on a relative basis, storage values will be lower in markets that are oversupplied with storage than in markets where storage capacity is in short supply. The extent to which markets are oversupplied or undersupplied will fluctuate in response to significant variations in natural gas supply and demand.
 
The EIA reports two measures of aggregate peak storage capacity for the U.S.: working gas design capacity and demonstrated non-coincidental peak storage capacity. Working gas design capacity is a measure based on the design capabilities of all U.S. storage facilities whereas demonstrated peak capacity is based on the non-coincidental peak storage volumes for each of these facilities over the last five years (i.e., the sum of maximum volumes stored at each facility at any time within the five-year period). According to the EIA, the aggregate peak working gas capacity of the U.S. underground natural gas storage market is approximately 4.3 Tcf using the design capacity methodology and 3.9 Tcf using the non-coincidental peak storage methodology. A comparison of actual peak storage inventory levels to working gas design capacity and demonstrated non-coincidental peak storage capacity since 2005 suggests that since 2005, peak storage utilization as a percentage of peak storage capacity has increased using both EIA measures of aggregate peak storage capacity. Utilization has increased from 82% to 89% using the working gas design capacity measure and from 91% to 99% using the demonstrated non-coincidental peak storage capacity measure. While both measures have merits, we believe the non-coincidental peak storage measure is a better directional indicator of true useable storage capacity due to the fact that working gas design capacity is based on “design” parameters and does not take into account operational, logistical and other practical constraints. The graph below illustrates the relationship between actual peak storage inventory levels and non-coincidental peak storage levels between 2005 and 2009 based on EIA data, and also reflects the 3.84 Tcf record level of working gas stored in underground storage facilities on November 27, 2009.
 
U.S. Working Gas Capacity (Non-Coincidental Peak
Levels and Design Capacity) vs. Peak Storage Inventory Levels (2005-2009)
 
(CHART)
 
 
Source: derived from EIA data
 
Although the above chart suggests that storage is high and the current market for storage capacity may be approaching an undersupplied state, future market conditions will be determined both by the future demand for storage as well as the net amount of storage capacity that is added in future years. From a storage operator’s perspective, an “over-build” of storage capacity would reduce storage values by putting downward pressure on the rates that storage providers are able to charge for new contracts on uncontracted capacity and


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renewal contracts with existing customers whose contracts are approaching expiration. Conversely, a continuation of an undersupplied storage market would imply higher values and rates for new contracts and renewals of expiring contracts.
 
Following the FERC’s change in policies and practices with respect to natural gas storage in the late 1990s and early 2000s, there has been a significant increase in the number of permits requested and issued for new storage facilities. For example, according to FERC data, since 2000, permits have been issued by the FERC for new interstate gas storage facilities or expansions in the Gulf Coast (excluding intrastate facilities and FERC pre-filings for additional storage capacity) representing aggregate additional working gas capacity of approximately 576 Bcf. However, through January 2010, based on our review of publicly available FERC filings and other publicly available data, we estimate that only approximately 153 Bcf, or 27%, of such permitted capacity has been placed in service, which leaves approximately 423 Bcf of permitted Gulf Coast capacity that has not yet been placed in service.
 
While it is difficult to predict when, and how much of, such “permitted but not yet in service” capacity will ultimately be placed in service, based on our review of publicly available FERC filings and other publicly available data, a significant number of these Gulf Coast projects have experienced delays and some of them have been abandoned. These delays and abandonments are due to a variety of factors, including geological issues, permitting delays, financing issues, landowner and public relations issues, construction issues and operating challenges.
 
We believe that these types of challenges will continue to affect storage capacity development in the U.S. and will result in a number of new projects being placed in service later than initially forecast or at lesser volumes of working capacity than the backlog of permitted projects indicates. As a result, we believe there will continue to be market demand for the services we provide.


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BUSINESS
 
Overview
 
We are a fee-based, growth-oriented Delaware limited partnership formed by Plains All American to own, operate and grow the natural gas storage business that PAA acquired in 2005 and has continuously operated since that time. Our business consists of the acquisition, development, operation and commercial management of natural gas storage facilities. We currently own and operate two natural gas storage facilities located in Louisiana and Michigan that have an aggregate working gas storage capacity of 40 Bcf and an aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. We also lease storage capacity and pipeline transportation capacity from third parties from time to time in order to increase our operational flexibility and enhance the services we offer our customers. As of December 31, 2009, we had 3 Bcf of storage capacity under lease from third parties and had secured the right to 379 MMcf per day of firm transportation service on various pipelines. Substantially all of our revenues are derived from the provision of firm storage services under multi-year, fee-based contracts.
 
Our business has expanded rapidly since its inception in 2005, primarily through organic growth initiatives. We have grown our storage capacity from 20 Bcf as of December 31, 2005 to 40 Bcf as of December 31, 2009, and we expect this growth to continue at a rapid pace as we complete our planned expansions over the next several years. Our expansion plans include an additional 31 Bcf of working gas storage capacity, 28 Bcf of which we expect to place into service by mid-2012, including 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010. Our target is to increase our total capacity to 68 Bcf by mid-2012, representing a 70% increase in storage capacity from year-end 2009 levels. Through our current assets and proposed expansions, we believe we are well-positioned to benefit from the anticipated long-term growth in demand for natural gas storage capacity and services in North America.
 
Our Assets
 
We own 100% of the Pine Prairie facility, which is a recently constructed, high-deliverability salt-cavern natural gas storage complex located in Evangeline Parish, Louisiana, and 100% of the Bluewater facility, which is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. The following table contains certain information regarding our Pine Prairie and Bluewater storage facilities:
 
                                 
    Working Gas
    Peak Injection
    Peak Withdrawal
    Compression
 
Facility Name and Type
  Capacity (Bcf)     Rate (Bcf/d)     Rate (Bcf/d)     (Horsepower)  
 
Pine Prairie (salt-cavern)
                               
Existing facility
    14       1.2       2.4       32,000  
Planned expansion
    31 (1)     1.2 (2)     0.8 (2)     56,250 (3)
                                 
Subtotal:
    45       2.4       3.2       88,250  
                                 
Bluewater (depleted reservoir)
                               
Existing facility
    26       0.5       0.8       13,350  
Planned expansion
    2 (4)                  
                                 
Subtotal:
    28       0.5       0.8       13,350  
                                 
Total (both facilities)
    73       2.9       4.0       101,600  
                                 
 
 
(1) We expect to place 10 Bcf into service in the second quarter of 2010, 18 Bcf by mid-2012 and the final 3 Bcf will be added ratably through 2016.
 
(2) We expect to complete these expansions of peak injection and withdrawal capabilities by mid-2011.


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(3) Of this aggregate expected increase in compression, 16,000 horsepower is on location with installation targeted for April 2010. With respect to the remaining compression capacity, we expect 23,000 horsepower to be in place by mid-2011, and an additional 17,250 horsepower to be in place by mid-2012.
 
(4) We expect to place this expansion in working gas capacity into service ratably over a 10-year period beginning in 2011 in connection with a planned liquids removal project.
 
Pine Prairie.  As a strategically-located, high-deliverability storage facility, Pine Prairie has attracted a diverse group of customers, including utilities, pipelines, producers, power generators, marketers and LNG importers, whose storage needs include both traditional seasonal storage services and short-term storage services. Pine Prairie is strategically positioned relative to several major market hubs, including:
 
  •  the Henry Hub, which is the delivery point for NYMEX natural gas futures contracts and is located approximately 50 miles southeast of Pine Prairie;
 
  •  the Carthage Hub in east Texas, which is located approximately 150 miles northwest of Pine Prairie; and
 
  •  the Perryville Hub in north Louisiana, which is located approximately 130 miles north of Pine Prairie.
 
Pine Prairie’s pipeline header system, which includes an aggregate of 74 miles of 24-inch diameter pipe located within a 20-mile radius of Pine Prairie, is directly connected to eight large-diameter interstate pipelines through nine interconnects that service both conventional and unconventional natural gas production in Texas and Louisiana, including production from existing and emerging shale plays, as well as Gulf of Mexico production and LNG imports. These interconnects also provide direct or indirect access to each of the market hubs described above and to consumer and industrial markets in the Gulf Coast, Midwest, Northeast and Southeast regions of the United States. This interconnectivity, combined with existing compression capacity and approximately 50 MMcf per day of leased third-party pipeline transportation capacity as of December 31, 2009, gives Pine Prairie the operational flexibility to receive from and deliver to multiple pipelines simultaneously.
 
Pine Prairie has a total current working gas storage capacity of 14 Bcf in two caverns, and planned expansions that will increase Pine Prairie’s total capacity to 42 Bcf by mid-2012 and 45 Bcf by mid-2015 (see table above). Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf. Taking these considerations into account and with certain infrastructure modifications, we currently estimate that Pine Prairie could support in excess of 15 salt caverns and an aggregate storage capacity of over 150 Bcf.
 
Bluewater.  Bluewater is located in the State of Michigan, which contains more underground natural gas storage capacity than any other state in the U.S. according to EIA data, and primarily services seasonal storage needs throughout the Midwestern and Northeastern portions of the U.S. and the Southeastern portion of Canada. Accordingly, Bluewater’s customers consist primarily of pipelines, utilities and marketers seeking seasonal storage services. Bluewater’s 30-mile, 20-inch diameter pipeline header system is supported by 13,350 horsepower of compression and connects with three interstate and three intrastate natural gas pipelines that provide access to the major market hubs of Chicago, Illinois and Dawn, Ontario, which supply natural gas to eastern Ontario and the northeastern United States. These interconnects also provide access to natural gas utilities that serve local markets in Michigan and Ontario.
 
As indicated in the table above, Bluewater has total working gas storage capacity of approximately 26 Bcf in two depleted reservoirs and we expect to increase Bluewater’s working gas capacity by 2 Bcf ratably over a 10-year period beginning in 2011 as a result of a planned liquids removal project. Bluewater also leases third-party storage capacity and pipeline transportation capacity from time to time to increase its operational flexibility and enhance its service offerings. As of December 31, 2009, we had leased approximately 3 Bcf of additional capacity at third-party natural gas storage facilities as well as 329 MMcf per day of related pipeline transportation capacity.


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Our Operations
 
We provide natural gas storage services to a broad mix of customers, including local gas distribution companies, or LDCs, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. Our storage rates are regulated under Federal Energy Regulatory Commission, or FERC, rate-making policies, which currently permit our facilities to charge market-based rates for our services.
 
We generate revenue almost exclusively through the provision of fee-based gas storage services to our customers. For the year ended December 31, 2009, approximately 99% of our total revenue was derived from fee-based storage activities, with the remaining approximately 1% primarily attributable to the sale of liquid hydrocarbons incidentally produced in connection with the operation of our depleted reservoir storage facilities at Bluewater as well as other fuel and derivative related net gains and losses. Our revenues from fee-based gas storage services are derived from both “firm storage services” and “hub services.”
 
  •  Firm Storage Services.  Firm storage services include (i) storage services pursuant to which customers receive the assured or “firm” right to store gas in our facilities over a multi-year period and (ii) seasonal “park and loan” services pursuant to which customers receive the “firm” right to store gas in (park), or borrow gas from (loan), our facilities on a seasonal basis. Under our firm storage contracts, our customers are obligated to pay us fixed monthly capacity reservation fees, which are owed to us regardless of the actual storage capacity utilized. At Pine Prairie, our firm storage contracts typically have terms of 3 to 5 years, while at Bluewater terms generally range from 1 to 3 years. Effective as of April 1, 2010, the weighted average remaining tenor of our existing portfolio of firm storage contracts will be approximately 3.9 years at Pine Prairie and approximately 2.2 years at Bluewater. Under our firm storage contracts, we also typically collect a “cycling fee” based on the volume of natural gas nominated for injection and/or withdrawal and retain a small portion of natural gas nominated for injection as compensation for our fuel use. For the year ended December 31, 2009, approximately 92% of our total revenue was derived from firm storage services.
 
  •  Hub Services.  We also generate revenue from the provision of “hub services” at our facilities. Hub services include (i) “interruptible” storage services pursuant to which customers receive only limited assurances regarding the availability of capacity in our storage facilities and pay fees based on their actual utilization of our assets, (ii) non-seasonal “park and loan” services and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through our facilities from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from, our facilities. For the year ended December 31, 2009, approximately 7% of our total revenue was derived from hub services.
 
We believe that the high percentage of our baseline cash flow derived from fixed-capacity reservation fees under multi-year contracts with a diverse portfolio of customers stabilizes our cash flow profile and substantially mitigates the risk to us of significant negative cash flow fluctuations caused by changing supply and demand conditions and other market factors. For additional information about our contracts, please read “Business — Contracts.”
 
Our Business Strategy
 
Our principal business strategy is to capitalize on the anticipated long-term growth in demand for natural gas storage services in North America by owning and operating high-quality natural gas storage facilities and providing our current and future customers reliable, competitive and flexible natural gas storage and related services. In executing this strategy, we intend to expand the scope and scale of our business, grow our earnings and cash flow and increase the amount of cash distributions we make to our unitholders over time. Our plan for executing this strategy includes the following key components:
 
  •  Optimizing our existing natural gas storage facilities.  We are constantly seeking to optimize the performance and profitability of our existing natural gas storage facilities. Our primary commercial objective is to generate a significant portion of our revenues by committing a high percentage of our


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  storage capacity under multi-year firm storage contracts at attractive rates. Effective as of April 1, 2010, approximately 93% of our owned and leased total working gas capacity, which includes the 10 Bcf of additional capacity expected to be placed into service during the second quarter of 2010, was committed under our existing portfolio of firm storage contracts with a weighted average remaining tenor of approximately 3.9 years at Pine Prairie and approximately 2.2 years at Bluewater. We also provide our customers with a variety of hub services that are designed to accommodate customer needs, maximize the utilization of our assets and optimize our earnings and cash flow. For example:
 
  •  If firm storage customers are not utilizing all of their firm capacity, we can offer such capacity to other customers on a short-term, interruptible basis, earning fees to the extent our capacity is actually utilized.
 
  •  We offer various “hub services,” pursuant to which we earn fees for (i) allowing customers to “park” their gas in our facilities on a short-term basis, (ii) loaning gas to customers for relatively short periods of time and (iii) providing wheeling and balancing services to customers through the use of our header system.
 
Operationally, we seek to optimize our profitability by executing various initiatives that increase our efficiency, reliability and flexibility. For example:
 
  •  Daily we manage the gas flows through our facilities to reduce our overall costs and optimize our use of compression. This is accomplished by aggregating and offsetting customer nominations to reduce required physical flows, scheduling our wheeling services to take advantage of pressure differentials across our system and sequencing our gas movements to increase the efficiency of compressor usage.
 
  •  In 2009 we installed back-up generators that enable us to run our gas handling facility and pipeline interconnects at Pine Prairie in the event of a power interruption.
 
  •  Subject to receipt of applicable approvals, our planned expansion to five caverns at Pine Prairie will include electric compression, which will diversify our existing portfolio of natural-gas fired compression and provide us with the flexibility to run more efficiently.
 
  •  Organically expanding our existing natural gas storage facilities.  Our existing assets enable us to expand our storage capacity on what we believe to be attractive economic terms. Our current expansion plans include the addition of 31 Bcf of working gas storage capacity at our Pine Prairie facility, 28 Bcf of which we expect to place into service by mid-2012, including 10 Bcf of new capacity that is substantially complete and that we currently expect to place into service during the second quarter of 2010. We have received all applicable federal, state and local approvals required to construct these expansions (including FERC and Louisiana Department of Natural Resources) and, when complete, we will have five salt caverns in service and 45 Bcf of working gas storage capacity at Pine Prairie. Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf. Taking these considerations into account and with certain infrastructure modifications, we currently estimate that Pine Prairie could support in excess of 15 salt caverns and an aggregate storage capacity of over 150 Bcf. In addition, we are currently pursuing a liquids removal project to expand our storage capacity at our Bluewater facility by 2 Bcf ratably over a 10-year period beginning in 2011.
 
  •  Pursuing strategic and accretive acquisition or development projects.  We continually evaluate opportunities to acquire or develop new natural gas storage facilities in our existing and new markets. In general, we are seeking acquisition or development opportunities that will be accretive (or result in an increase in distributable cash flow on a per unit basis) and that will add natural gas storage assets or facilities that either complement our existing assets or strategically enhance our overall business by facilitating our entry into a desirable new market, diversifying our customer base or positioning us for future growth. Working with PAA, we are currently involved in discussions and, in certain cases negotiations, with a number of potential sellers regarding the purchase of natural gas storage assets. Although there can be no assurances that viable acquisition or development opportunities will continue


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  to be available to us or that we will ultimately be able to consummate any of the transactions currently being considered, we believe the combination of strong long-term fundamentals for natural gas demand and storage services coupled with the fragmented nature of the gas storage business should result in a variety of acquisition and/or development opportunities for us to consider. In addition, over time and working in conjunction with PAA, we intend to evaluate opportunities to acquire or develop other natural gas-related assets or businesses that complement our natural gas storage business and allow us to leverage our asset base and industry experience.
 
  •  Leasing storage capacity and transportation services from third parties to enhance operational flexibility.  In order to supplement our owned storage capacity, increase our operating flexibility, enhance the services that we are capable of offering to our customers and optimize the commercial performance of our assets, we periodically lease storage and/or transportation capacity from third parties. As of December 31, 2009, we had 3 Bcf of storage capacity under lease from third parties and had secured the right to 379 MMcf per day of firm transportation service on various pipelines.
 
  •  Utilizing a portion of our owned and leased storage capacity to enhance our commercial management activities.  Similar to the business model successfully employed by PAA, and without altering our basic commercial strategy of committing a high percentage of our storage capacity under multi-year firm storage contracts at attractive rates, we intend to establish a dedicated commercial marketing group that will capture short-term market opportunities by utilizing a portion of our owned or leased storage capacity for our own account and engaging in related commercial marketing activities. Consistent with PAA’s experience marketing crude oil and refined products, we anticipate that having a dedicated commercial marketing group that has a consistent presence in our markets will enhance our ability to properly price our storage and hub service offerings and will increase our earnings by capitalizing on volatility and inefficiencies in the natural gas markets. We will conduct these commercial activities within pre-defined risk parameters, and our general policy will be (i) to purchase natural gas only in situations where we have a market for such gas, (ii) to utilize physical natural gas inventory and financial derivatives to manage and optimize seasonal and spread risks inherent in our operations and commercial management activities and to structure our transactions so that commodity price fluctuations will not have a material adverse impact on our cash flow and (iii) not to acquire or hold natural gas, futures contracts or other derivative products for the purpose of speculating on outright commodity price changes.
 
Our Financial Strategy
 
Important factors to successfully grow our business will be our ability to maintain a competitive cost of capital and sufficient access to the capital markets. These factors will be significantly influenced by our ability to grow our distribution to unitholders, maintain a solid credit profile and ultimately achieve and maintain an investment-grade credit rating.
 
Targeted Credit Profile.  We have targeted a general credit profile that has the following attributes:
 
  •  a long-term debt-to-total capitalization ratio of 40% or less;
 
  •  an average long-term debt-to-Adjusted EBITDA multiple of approximately 3.5x (Adjusted EBITDA is earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring); and
 
  •  an average Adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.
 
When considered together with what we believe to be the relatively low risk profile of our business, we believe this credit profile is consistent with an investment grade credit rating. In combination with our intent to maintain a high percentage of storage capacity under multi-year contracts, this credit profile should also provide flexibility if storage markets become oversupplied and position us to take advantage of attractive acquisition opportunities.


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In order for us to maintain our targeted credit profile, we generally intend to fund approximately 60% of the capital required for expansion and acquisition projects through a combination of equity capital and cash flow in excess of distributions. In connection with the closing of this offering, we expect to enter into a new $400 million revolving credit facility. We believe we will be able to fund up to the first $250 million of acquisitions or expansion projects primarily through borrowings under this credit facility or other sources and remain in compliance with our targeted credit profile.
 
From time to time, we may be outside the parameters of our targeted credit profile due to timing issues related to the initial funding of certain capital expenditures or acquisitions with debt or delays in realizing increases in Adjusted EBITDA, synergies or other benefits from expansion and/or acquisition projects.
 
Credit Rating.  We have not applied for a credit rating from any credit rating agency, nor to our knowledge has any such credit rating been assigned. Additionally, we do not currently intend to apply for a credit rating until such time as we expect to access the public debt capital markets. If and when we seek a credit rating, our credit rating may be positively or negatively impacted by the leverage and credit rating of PAA. In addition, while we believe our targeted credit profile is consistent with an investment grade rating, we can provide no assurance in this regard. See “Risk Factors — The credit and risk profile of our general partner and its owner, PAA, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.”
 
As of March 1, 2010, the senior unsecured ratings of PAA with Standard & Poor’s Ratings Services and Moody’s Investors Service were BBB-, stable outlook, and Baa3, stable outlook, respectively.
 
Our Competitive Strengths
 
We believe that the following competitive strengths will position us to successfully execute our principal business strategy:
 
  •  Our natural gas storage assets are strategically located and operationally flexible.  Our Pine Prairie facility is strategically positioned relative to several major market hubs, including the Henry Hub, the Carthage Hub, and the Perryville Hub and is located approximately 80 miles inland from the Gulf Coast shoreline, a feature that minimizes Pine Prairie’s exposure to operational disruptions from hurricanes or other severe weather affecting the Gulf of Mexico region. Pine Prairie’s pipeline header system, which includes an aggregate of 74 miles of 24-inch diameter pipe located within a 20-mile radius of Pine Prairie, is directly connected to eight large-diameter interstate pipelines through nine interconnects that enable it to serve a variety of major producing regions, LNG importers and the primary consumer and industrial markets in the Gulf Coast, Midwest, Northeast and Southeast. This interconnectivity, combined with existing compression capacity and approximately 50 MMcf per day of leased third-party pipeline transportation capacity as of December 31, 2009, gives Pine Prairie the operational flexibility to receive from and deliver to multiple pipelines simultaneously.
 
Pine Prairie’s operational flexibility enables it to partially fill or deplete, or “cycle,” its storage caverns multiple times per year. This allows Pine Prairie to offer a premium service of “cycling” or “turning” contracted storage volume up to twelve times per year, providing Pine Prairie customers with additional operating and financial flexibility. The significant operational flexibility of the Pine Prairie facility also creates more opportunities for us to provide our customers with hub services, such as interruptible storage, park and loan, balancing and wheeling services.
 
Our Bluewater natural gas storage complex is strategically positioned to access the major market hubs of Chicago, Illinois and Dawn, Ontario, which supply natural gas to eastern Ontario and the northeastern United States. Bluewater’s 30-mile pipeline header system connects the facility to three interstate and three intrastate natural gas pipelines and provide access to natural gas utilities that serve local markets in Michigan and Ontario.
 
Collectively, our facilities have aggregate peak injection and withdrawal capacity of 1.7 Bcf per day and 3.2 Bcf per day, respectively. Upon the completion of current expansion activities, these


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capabilities will increase to 2.9 Bcf per day of peak rate injection capability and 4.0 Bcf per day of peak rate withdrawal capability.
 
  •  Our business generates relatively stable and predictable cash flow.  Given the high percentage of our cash flow that is derived from fixed-capacity reservation fees under multi-year contracts with a diverse portfolio of customers, our baseline cash flow profile is relatively stable and predictable, which we believe significantly mitigates the risk to us of negative cash flow fluctuations caused by changing supply and demand conditions and other market factors. For the twelve-month period that ended on December 31, 2009, approximately 92% of our total revenue was derived from the provision of firm storage services, and effective as of April 1, 2010, the weighted average remaining life of our existing portfolio of firm storage contracts will be approximately 3.9 years at our Pine Prairie facility and approximately 2.2 years at our Bluewater facility. In addition, we do not take title to the natural gas that we store for our customers and, accordingly, are not exposed to commodity price fluctuations on the gas that is stored in our facilities by our customers. Except for the base gas we purchase and use in our facilities, which we consider to be a long-term asset, and volume and pricing variations related to small amounts of natural gas we are entitled to retain from our customers as compensation for our fuel costs, our current and planned business strategies are designed to minimize our exposure to fluctuations in the outright price of natural gas.
 
  •  Our Pine Prairie storage facility has the ability to be significantly expanded at competitive costs and with a relatively high degree of schedule certainty.  We own and/or lease 320 acres of land on the salt dome that underlies Pine Prairie. Our existing facilities and planned expansions through 2012 to five caverns will utilize only approximately 120 of these acres. Subject to market demand, project execution, sufficient pipeline capacity, available financing and receipt of future permits, we have the property rights and operational capacity to expand our Pine Prairie facility significantly beyond our current permitted capacity of 48 Bcf. Taking these considerations into account and with certain infrastructure modifications, we currently estimate that Pine Prairie could support in excess of 15 salt caverns and an aggregate storage capacity of over 150 Bcf. In addition, because our existing infrastructure at Pine Prairie has been specifically designed to facilitate future expansion, we expect it to both reduce our overall capital costs per additional Bcf of storage capacity and shorten the length and enhance the predictability of our development cycle. Some of the specific aspects of our Pine Prairie facility that will facilitate incremental expansion are as follows:
 
  •  Pine Prairie has been specifically designed solely for natural gas storage development, and we have customized the design and layout of the caverns so that (i) there is ample spacing between caverns and (ii) the caverns are optimally shaped for natural gas storage.
 
  •  Pine Prairie has a solution mining facility (used to create salt-dome storage caverns) that is capable of leaching at an aggregate rate of 8,000 gallons of water per minute, a rate that we believe to be significantly higher than the rates at many competing facilities. This solution mining facility and supporting infrastructure provide us with the capability to simultaneously conduct leaching operations on new caverns, remove water from a recently completed cavern (called “dewatering”) and/or conduct fill/dewater operations on existing caverns (a process used to expand the capacity of an existing cavern through incremental leaching), subject to a maximum fluid handling capacity of 8,000 gallons per minute. For approximately six months during 2009, all three of these activities were conducted simultaneously on three cavern wells, achieving water handling rates of approximately 7,500 gallons per minute for extended periods of time.
 
  •  The pipeline header system, pipeline interconnects and gas treating facilities at Pine Prairie are complete and have been designed to accommodate larger-scale future expansion. The pipeline header system, which includes an aggregate of 74 miles of 24-inch diameter pipe located within a 20-mile radius of Pine Prairie, can move volumes of gas through our facility at peak rates that comfortably exceed both our current peak gas storage withdrawal rate of 2.4 Bcf per day and our withdrawal rate of 3.2 Bcf per day after our planned expansions are completed.


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We believe these features of our Pine Prairie facility, together with the significant hands-on experience that has been gained by our personnel while developing the first three caverns at Pine Prairie, provide us with the capability to (i) develop expansion capacity at costs that are competitive with or superior to expansion costs at other Gulf Coast facilities and substantially lower than greenfield development projects and (ii) place new caverns in service for existing and potential customers quickly and with a high degree of certainty regarding the projected in service dates.
 
  •  We have the evaluation, integration and engineering skill sets in-house that are necessary to successfully pursue acquisition and expansion opportunities.  We possess the in-house capabilities and expertise necessary to develop, construct, own, acquire and operate both depleted reservoir and salt-cavern storage capacity. We have been involved in substantially all aspects of the natural gas storage business since 2005 and our operational and management team has extensive energy industry and acquisition experience. In addition, from 1998 to 2009, PAA has (i) successfully acquired and integrated over $6 billion of acquisitions in over 50 separate transactions involving midstream energy assets, and (ii) executed over 100 organic growth and expansion projects with total capital expenditures of over $2.4 billion. We believe that the experience and skill sets of our collective management team provide us with a competitive advantage that enables us to appropriately identify, assess and evaluate the risks and opportunities that are likely to arise during the development and operational phases of potential gas storage acquisition and expansion opportunities.
 
  •  We have the financial flexibility to pursue acquisition and expansion opportunities.  At the closing of this offering, we expect to have approximately $200 million of borrowing capacity available to us under our revolving credit facility. We believe our borrowing capacity and our ability to access private and public debt and equity capital should provide us with the financial flexibility necessary to execute our growth and expansion strategy. Additionally, PAA may elect, but is not obligated, to provide us with financial support in connection with acquisitions or expansion capital projects in certain circumstances.
 
  •  Our general partner has an experienced executive management team with specialized knowledge of natural gas storage and markets and whose interests are aligned with those of our unitholders.  Our general partner has an executive management team that has extensive experience managing, operating, building, acquiring and integrating energy assets, including natural gas storage assets and other midstream energy assets. On average, the members of our general partner’s executive management team have in excess of 20 years of energy industry experience. In addition, our general partner’s executive management team includes a President and three Vice Presidents who are exclusively dedicated to and focused on the operation, management, development and expansion of our natural gas storage business. Through their indirect and direct interests in us, our general partner and PAA, our general partner’s executive management team has a significant, vested interest in our continued success. We believe the experience of our general partner’s executive management team and the experience and market presence of PAA, combined with our relationships with participants across the natural gas supply chain, provide us with extensive operational and commercial understanding of the physical North American natural gas market.
 
We believe these competitive strengths will aid our efforts to expand our presence in the natural gas storage sector.
 
Our Relationship with Plains All American Pipeline, L.P.
 
We believe one of our strengths is our relationship with Plains All American Pipeline, L.P., the fourth largest publicly traded master limited partnership as measured by industry data regarding equity market capitalization, which was approximately $7.5 billion as of February 26, 2010. Plains All American’s common units trade on the New York Stock Exchange, or NYSE, under the ticker symbol “PAA.” In addition to its participation in the natural gas storage business through our partnership, PAA is engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas-related petroleum products. PAA’s assets include approximately 17,000 miles of pipelines, 85 million barrels of storage capacity, and a significant fleet of trucks, trailers, tugs, barges and railcars.


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Through its transportation, storage and commercial activities, PAA physically handles approximately 3 million barrels per day of petroleum products.
 
PAA and its predecessors have been active participants in the hydrocarbon storage industry since the early 1990s. PAA has a long history of successfully expanding its energy infrastructure businesses through a combination of organic growth projects and complementary acquisitions. Since its initial public offering in 1998, PAA has grown its asset base from approximately $600 million to over $12 billion and increased the annualized distribution on its limited partner units by over 100%, from $1.80 per unit as of PAA’s initial public offering to $3.71 per unit for the distribution paid in February 2010.
 
Our partnership will own all of the natural gas storage business and assets formerly owned by PAA and PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business. Upon completion of this offering, as the ultimate owner of our 2.0% general partner interest, all of our incentive distribution rights and an approximate     % limited partner interest in us (including common units, Series A subordinated units and Series B subordinated units), PAA will have a significant economic stake in us and a commensurate incentive to promote and support the successful execution of our growth plan and strategy.
 
We will also enter into an omnibus agreement with PAA and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by PAA’s general partner to us of certain general and administrative services and employees, our agreement to reimburse PAA’s general partner for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Plains All American,” “PAA” and related marks, and other matters. Please read “Certain Relationships and Related Transactions — Agreements Governing the Transactions — Omnibus Agreement.”
 
We believe PAA’s significant presence in the energy sector, its successful track record of growth and its significant investment in, and sponsorship and support of, us will enhance our ability to grow our business. While we believe this relationship with PAA is a significant positive attribute, it may also be a source of conflicts. For example, PAA is not restricted in its ability to compete with us. Please read “Conflicts of Interest and Fiduciary Duties.”
 
Ongoing Acquisition Activities.  Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase of natural gas storage assets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as “auction” processes, as well as situations where we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations.
 
In connection with our acquisition activities, we routinely incur evaluation and due diligence costs, which are expensed as incurred. In addition to the in-house costs of our personnel and ancillary overhead expenditures allocated to us by our general partner for time devoted to evaluating acquisition opportunities which can be substantial, we also budget approximately $250,000 per year associated with third party evaluation or due diligence costs for transactions that are assumed not to be consummated.
 
Working with PAA, we are currently involved in discussions and, in certain cases, negotiations, with a number of potential sellers regarding the purchase of natural gas storage assets. Certain of these discussions are more advanced than others, but past experience has demonstrated that any of these discussions and negotiations could advance or terminate in a short period of time. However, regardless of their outcome, because of the current increased level of activity, third party expenses may exceed our typical budgeted levels in the near term. Additionally, certain of the opportunities under evaluation are of a size that would likely involve PAA’s assistance with respect to financing or jointly purchasing such assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Potential PAA Financial Support.” We can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us. See


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“Risk Factors — If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.”
 
Customers
 
Pine Prairie and Bluewater collectively provide storage services to a broad mix of customers including LDCs, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. LDCs use storage services for seasonal balancing, to meet peak day deliveries and ensure reliability. Pipelines use storage services to manage short-term operational balancing requirements. Power generators, marketers and producers generally use storage services for short-term balancing, to manage risk and to take advantage of the pricing differential between near-term and long-term natural gas. LNG importers use storage to insure they have adequate storage capacity to accommodate imported LNG cargoes.
 
As of December 31, 2009, Pine Prairie had 11 customers with firm storage contracts and 45 customers with hub services contracts and Bluewater had 30 customers with firm storage contracts and 46 customers with hub services contracts. For the year ended December 31, 2009, Iberdrola Renewables, Inc. and Guardian Pipeline, LLC accounted for approximately 17% and 13% of our revenues, respectively.
 
Contracts
 
Pine Prairie and Bluewater contract with their customers to provide firm storage services and hub services. Under firm storage contracts, in exchange for an assured amount of storage capacity for an agreed period of time, customers pay a fixed monthly capacity reservation fee that is payable regardless of the actual amount of storage capacity utilized. Under these contracts, Pine Prairie and Bluewater also typically collect a “cycling fee” based on the volume of natural gas nominated for injection and/or withdrawal and retain a small portion of natural gas nominated by their customers for injection as compensation for their fuel costs. The firm storage contracts at Pine Prairie and Bluewater typically have terms of 3 to 5 years, and 1 to 3 years, respectively. Our general contracting philosophy at both Pine Prairie and Bluewater is to commit a high percentage of our available working gas capacity to firm storage contracts at attractive rates, while simultaneously contracting for hub services to increase asset utilization and capture margin based on market conditions. Effective as of April 1, 2010, the weighted average remaining tenor of our existing portfolio of firm storage contracts will be approximately 3.9 years at Pine Prairie and approximately 2.2 years at Bluewater.
 
Despite an increase in the number of competitors in recent years, especially in the markets served by our Pine Prairie facility, we have been able to contract all of our available storage capacity at acceptable rates. As an example, in June 2009 Pine Prairie concluded an open season pursuant to which it requested non-binding bids for 2 Bcf of capacity starting April 1, 2010. In response to such request, Pine Prairie received 26 individual bids for an aggregate capacity of over 29 Bcf with initial contract terms ranging from 3 to 5 years. We also concluded an open season at Bluewater in July of 2009 pursuant to which we requested nonbinding bids for 2.5 Bcf of capacity starting April 1, 2010. In response to such request, Bluewater received 22 individual bids for an aggregate capacity of 31 Bcf with initial contract terms ranging generally from 1 to 5 years. We believe our contracting success at Pine Prairie and Bluewater is due to various positive attributes of such storage facilities, including their favorable access to neighboring pipeline systems and the flexibility and reliability of their service offerings.
 
Pine Prairie and Bluewater also contract with their customers to provide hub services. Hub services include (i) “interruptible” storage services pursuant to which customers do not receive any assurances regarding the availability of capacity in our storage facilities and pay fees based on their actual utilization of our assets, (ii) non-seasonal “park and loan” services, pursuant to which customers pay fees for the right to store gas in our facilities, and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through our facilities from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from our facilities.


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For the year ended December 31, 2009, approximately 92% of our total revenues were derived from the provisions of firm storage services and approximately 7% were derived from the provision of hub services.
 
Competition
 
The principal elements of competition among storage facilities are rates, terms of service, types of service, supply and market access, and flexibility and reliability of service. An increase in competition in our markets could arise from new ventures or expanded operations from existing competitors.
 
Pine Prairie competes with several regional high-deliverability storage facilities along the Gulf Coast as well as the storage services offered by interstate and intrastate pipelines that serve the same markets as Pine Prairie. Pine Prairie’s regional competitors include the Egan storage facility owned by Market Hub Partners, which is controlled by Spectra Energy Corp., the Southern Pines storage facility owned by SGR Holdings, the Bobcat storage facility owned by Haddington Ventures and GE Capital, the Petal storage facility owned by Enterprise Products Partners, L.P., the Jefferson Island storage facility owned by AGL Resources and the Bay Gas storage facility owned by Sempra Energy. We anticipate that growing demand for natural gas storage along the Gulf Coast will be met with increasing storage capacity, either through the expansion of existing facilities or the construction of new storage facilities. For example, we expect additional regional competition from proposed storage facilities or expansions at the Southern Pines storage facility, the Bobcat storage facility, the Petal storage facility, the Perryville Gas Storage facility owned by Cardinal Gas Storage Partners, the Leaf River storage facility owned by NGS Energy, L.P. and the Mississippi Hub storage facility owned by Sempra Energy.
 
Bluewater competes with several Midwest utility and pipeline storage providers. Bluewater’s main regional competitors include DTE Energy, a Michigan gas and electric utility, ANR Pipeline Company, a major interstate pipeline company that is a subsidiary of TransCanada, and Union Gas Limited, a subsidiary of Spectra Energy engaged in the natural gas storage, transmission and distribution business. We anticipate growing demand for natural gas storage in the markets served by Bluewater as well as increased competition from existing regional competitors.
 
Regulation
 
Our operations are subject to extensive laws and regulations. We are subject to regulatory oversight by numerous federal, state, and local regulatory agencies, many of which are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas storage and pipeline industry, related businesses and individual participants. The failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. Except for certain exemptions that apply to smaller companies, however, we do not believe that we are affected by these laws and regulations in a significantly different manner than are our competitors.
 
Following is a discussion of certain laws and regulations affecting us. However, you should not rely on such discussion as an exhaustive review of all regulatory considerations affecting our operations.
 
Our natural gas storage assets are subject to several kinds of regulation. Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. The following is a summary of the kinds of regulation that may impact our operations.
 
Natural Gas Storage Regulation
 
Interstate Regulation.  Our natural gas storage facilities, Pine Prairie and Bluewater, are both classified as “natural-gas companies” under the NGA, and are therefore subject to regulation by the FERC. The NGA requires that tariff rates for gas storage facilities be just and reasonable and non-discriminatory. The FERC has authority to regulate rates and charges for natural gas transported and stored in U.S. interstate commerce or


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sold by a natural gas company in interstate commerce for resale. The FERC has granted the Pine Prairie and Bluewater natural gas storage facilities market-based rate authority. Market-based rate authorization allows Pine Prairie and Bluewater to negotiate rates with individual customers based on market demand, which Pine Prairie and Bluewater then make public via postings on their respective websites.
 
The FERC also has authority over the construction and operation of U.S. pipeline transportation and storage facilities and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. In addition, the FERC’s authority extends to maintenance of accounts and records, terms and conditions of service, depreciation and amortization policies, acquisition and disposition of facilities, initiation and discontinuation of services, imposition of creditworthiness and credit support requirements applicable to customers and relationships among pipelines and storage companies and certain affiliates.
 
Standards of Conduct for Transmission Providers.  Historically, the FERC’s standards of conduct regulations (now vacated) generally restricted access to U.S. interstate natural gas storage customer data by marketing and other energy affiliates, and placed certain conditions on services provided by U.S. storage facility operators to their affiliated gas marketing entities. The standards of conduct did not apply, however, to natural gas storage providers authorized to charge market-based rates that (i) were not interconnected with the jurisdictional facilities of any affiliated interstate natural gas pipeline and (ii) had no exclusive franchise area, no captive ratepayers, and no market power. The FERC found that Pine Prairie qualified for this exemption from the standards of conduct in January 2006 and Bluewater qualified for this exemption in October 2006.
 
In November 2006, the D.C. Circuit vacated the standards of conduct regulations with respect to natural gas pipelines and storage companies, and remanded the matter to the FERC. Following a notice of proposed rulemaking, in October 2008, the FERC issued revised Standards of Conduct for Transmission Providers (“Standards of Conduct”). The Standards of Conduct continue to exempt natural gas storage providers like Pine Prairie and Bluewater. The FERC has since issued two Orders on Rehearing and Clarification in October and November 2009. However, requests for rehearing of the October 2009 order are pending with the FERC. Accordingly, there may be further modifications to the Standards of Conduct upon rehearing.
 
Natural Gas Price Transparency.  In April 2007, the FERC issued a notice of proposed rulemaking (“NOPR”) regarding price transparency provisions of the NGA and the EPAct 2005. In the notice, the FERC proposed to revise its regulations to, among other things, require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC. In December 2007, the FERC issued Order No. 704 implementing the annual reporting provisions of the NOPR with minimal changes to the original proposal. The order became effective in February 2008. Pine Prairie and Bluewater are subject to these annual reporting requirements.
 
In November 2008, the FERC issued a final rule that requires interstate pipelines and certain non-interstate facilities to post certain daily capacity and volume information. The rule extends to storage facilities (such as Bluewater) that provide no-notice service. The rule has been appealed, but pending the results of that appeal, Bluewater will be subject to a requirement to post volumes with respect to no-notice service flows at each receipt and delivery point.
 
Energy Policy Act of 2005.  Under the EPAct 2005 and related regulations, it is unlawful in connection with the purchase or sale of natural gas or transportation services subject to FERC jurisdiction to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. The anti-manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
 
Other Proposed Regulation.  Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry


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historically has been heavily regulated. Accordingly, we cannot provide assurances that the less stringent and pro-competition regulatory approach recently pursued by the FERC and Congress will continue.
 
Environmental Matters
 
General
 
Our natural gas storage operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, and other approvals. These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities, increases in operating expenses or curtailment of certain operations to limit or prevent the release of materials from our facilities, the incurrence of capital expenditures associated with the installation of pollution control equipment, and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.
 
We believe that we are in substantial compliance with existing federal, state, and local environmental laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance of the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of some of the environmental laws and regulations that are applicable to our natural gas storage operations.
 
Waste management
 
Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws and regulations, which impose detailed requirements for the handling, storage, treatment, and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment. RCRA also requires waste generators subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities receiving such wastes. Generators of hazardous wastes must also comply with certain standards for the accumulation and storage of hazardous wastes and meet recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities.
 
Site remediation
 
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA,” also known as “Superfund”) and comparable state laws and regulations impose liability — without regard to fault or the legality of the original conduct — on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include current and prior owners or operators of the site where the release occurred and companies that disposed of, or arranged for the disposal of, hazardous substances found at offsite locations such as landfills. The CERCLA also authorizes the EPA and, in some instances, third parties, to respond to threats to public health or the environment and seek recovery of response costs from the class of responsible persons. Although natural gas is not classified as a hazardous substance under CERCLA, we may nonetheless handle hazardous substances within the meaning of CERCLA or similar state statutes in the course of our ordinary operations; as a result, we may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites where such hazardous substances have been released into the environment, natural resource damages, and the cost of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.


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Air emissions
 
Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and regulations. These laws and regulations regulate the emission of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, and/or utilize specific emission control technologies to limit our emissions. To comply with, maintain, or obtain our air emissions operating permits, we may be required to incur certain capital expenditures in the future for the purchase and installation of air pollution control equipment. For example, we may be required to supplement or modify our air emission control equipment and strategies due to changes in state implementation plans for controlling air emissions or more stringent regulation of hazardous air pollutants.
 
Water discharges
 
The Clean Water Act (“CWA”) and analogous state laws impose strict control of the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The CWA prohibits the discharge of pollutants into regulated waters, except in accordance with the terms of a permit issued by the EPA or analogous state agency. The CWA also regulates the discharge of storm water runoff from certain industrial facilities. Accordingly, some states require industrial facilities to obtain and maintain storm water discharge permits, which require monitoring and sampling of storm water runoff from such facilities.
 
Safe Drinking Water Act
 
As part of our operations, we employ underground injection wells to inject natural gas into our underground storage facilities. Such operations are subject to the Safe Drinking Water Act (“SDWA”) and analogous state laws, which regulate drinking water quality in the United States, including above ground and underground sources designated for actual or potential drinking water use. In particular, to protect underground sources of drinking water, the Underground Injection Control (“UIC”) Program of the SDWA regulates the construction, operation, maintenance, monitoring, testing, and closure of underground injection wells. The UIC Program also requires that all underground injection wells be authorized, either under the general rules of the UIC Program or through specific permits. In most jurisdictions, states have primary enforcement authority over the implementation of the UIC Program, including the issuance of permits.
 
Climate Change
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs), which include carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the U.S. Congress is actively considering legislation to reduce anthropogenic GHG emissions. One bill recently approved by the U.S. House of Representatives, known as the American Clean Energy and Security Act of 2009, or “ACESA,” would require an 80% reduction in GHG emissions from sources within the United States between 2012 and 2050. The U.S. Senate is currently considering its own climate change legislation, S. 1733, known as the Clean Energy Jobs and American Power Act, which requires a similar reduction in GHG emissions. Moreover, almost half of the states have taken legal measures to reduce GHG emissions. Both the state programs and proposed federal programs function primarily through the development of GHG emission inventories and/or a GHG cap and trade program. Most of these cap and trade programs work by requiring major sources of emissions (such as electric power plants) or major fuel producers (such as refineries and gas processing plants) to acquire and surrender emission allowances. The number of government-issued allowances under the cap, and correspondingly, the number of allowances available for trade, are reduced each year until the overall goal of GHG emission reductions is achieved.


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Depending on the scope of any particular GHG program, either at the state, regional, or federal level, we could be required to obtain and surrender allowances for GHG emissions statutorily attributed to our operations (e.g., emissions from compressor stations or the injection and withdrawal of natural gas). Although we would not be impacted to any greater degree than other similarly situated natural gas storage companies, a stringent GHG control program could have an adverse effect on our cost of doing business and reduce demand for the natural gas storage services we provide.
 
In addition, in December 2009, the EPA issued a final rule declaring that six GHGs, including carbon dioxide and methane, “endanger both the public health and the public welfare of current and future generations.” The issuance of this “endangerment finding” allows the EPA to begin regulating GHG emissions under existing provisions of the CAA. In late September and early October 2009, in anticipation of the issuance of the endangerment finding, the EPA officially proposed two sets of rules regarding possible future regulation of GHG emissions under the CAA, one that would regulate GHG emissions from motor vehicles and the other GHG emissions from large stationary sources such as power plants or industrial facilities. Although it may take EPA several years to adopt and impose regulations limiting GHG emissions, any limitation on such emissions from our equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.
 
As part of the 2008 Consolidated Appropriations Act, the EPA was also required to issue a rule requiring mandatory reporting of GHG emissions above certain thresholds from all sectors of the U.S. economy. The proposed rule included GHG reporting requirements for oil and natural gas systems (“Subpart W”), including underground natural gas storage facilities, but the EPA received extensive comments to Subpart W relating to the reporting of fugitive and vented methane emissions from the oil and gas sector. As a result, when the final rule was promulgated in October 2009, the EPA decided not to issue Subpart W so that the agency could further consider alternative data collection procedures and methodologies. We anticipate that the EPA will re-issue a proposed rule regarding the reporting of GHG emissions from oil and natural gas systems sometime in 2010. Despite the delayed finalization of Subpart W, our compressors at the Pine Prairie facility may be subject to GHG reporting requirements under a separate section of the GHG reporting rule regulating General Stationary Fuel Combustion Sources. Any GHG reporting rule covering our facilities will require us to meet additional recordkeeping and reporting requirements, but we do not believe that any such future requirement will have a material adverse affect on our business, financial position, or results of operations.
 
Chemical Facility Anti-Terrorism Standards
 
The Department of Homeland Security Appropriation Act of 2007 required the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities, deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards under the act and, on November 20, 2007, issued Appendix A to the interim rule, which established chemicals of interest and their respective threshold quantities triggering compliance with the interim rule. Covered facilities determined by the DHS to pose a high level of security risk are required to prepare and submit Security Vulnerability Assessments and Site Security Plans, and comply with other regulatory requirements involving inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. While the DHS has determined that Bluewater will not be a covered facility at this time, it has not issued a determination for Pine Prairie; however, we do not anticipate compliance costs associated with the interim rule to have a material adverse affect on our business, financial position, or results of operations.
 
Pipeline Safety
 
As part of our natural gas storage operations, we own and operate pipeline header systems connecting our natural gas storage facilities to various interstate pipelines. As a result, our pipeline operations are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”). The NGPSA regulates safety requirements in the design, installation, testing, construction, operation and maintenance of gas pipeline facilities. The NGPSA has since been amended by the Pipeline Safety Act of 1992 (“PSA”), the Pipeline Safety Improvement Act of 2002


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(“PSIA”), and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES”). These amendments have imposed additional safety requirements on pipeline operators such as the development of a written qualification program for individuals performing covered tasks on pipeline facilities and the implementation of pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventative measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. Accordingly, we will continue to focus on pipeline integrity management for any of the pipelines we currently own or acquire in the future, and significant additional expenses could be incurred if new or more stringent pipeline safety requirements are implemented. We believe that our operations are in substantial compliance with all existing federal, state, and local pipeline safety laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations.
 
Occupational Safety and Health
 
Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes designed to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local governmental authorities, and the public. Our operations are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process that involves a chemical at or above specified thresholds or any process that involves 10,000 pounds or more of a flammable liquid or gas in one location. We believe that our operations are in substantial compliance with all existing federal, state, and local occupations health and safety laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position, or results of operations.
 
Seasonality
 
Because a high percentage of our baseline cash flow is derived from fixed-capacity reservation fees under multi-year contracts, our revenues are not generally seasonal in nature, nor are they typically affected by weather and price volatility. Weather impacts natural gas demand for power generation and heating purposes, which in turn influences the value of storage across our systems. Peak demand for natural gas typically occurs during the winter months, caused by the heating load, although certain markets such as the Florida market peak in the summer months due to cooling demands.
 
Title to Properties and Rights-of-Way
 
Our real property falls into two categories: (1) parcels that we (or entities in which we own an interest) own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our facilities are located are owned by us (or entities in which we own an interest) in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our major facilities are located are held by us (or entities in which we own an interest) pursuant to leases between us (or entities in which we own an interest), as lessee, and the fee owner of the lands, as lessors. We believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
 
In May 2006, in order to receive a substantial tax exemption with respect to a portion of the Pine Prairie facility located in Evangeline Parish, Louisiana, we sold a portion of the facility located in the parish to the Industrial Development Board No. 1 of the Parish of Evangeline State of Louisiana, Inc. and entered into a


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15 year agreement to lease back such leased portion of the facility. Simultaneously with the execution of the lease, the Industrial Development Board issued and sold $50 million in bonds to us. Our rental obligations under the lease consist of an amount equal to the annual interest payment due from the Industrial Development Board on the bonds and the amount (if any) required for repayment in full of the outstanding indebtedness with respect to the bonds at the end of the lease term. Additionally, we are required to pay an annual $15,000 administrative fee to the Industrial Development Board, as well as reasonable fees, expenses and charges of the trustee in connection with the bonds.
 
The lease has a 15-year term, which commenced in January 2008, and is terminable by us upon payment to the Industrial Development Board of the amount required for repayment in full of its outstanding indebtedness under the bonds. We also have an option to purchase the leased properties at any time during the lease term for the sum of $5,000 plus the amount required for the repayment in full of any outstanding indebtedness under the bonds.
 
We are not subject to ad valorem property tax in the Parish of Evangeline for the property included in this arrangement during the term of the lease except for ad valorem tax on inventory. We are required to make certain annual payments in lieu of ad valorem property taxes, including (i) a fee not to exceed $45,000 per annum with respect to a portion of our header system known as the “Chalk Line” and (ii) beginning in 2010, an amount calculated as the difference between $500,000 and a three year average of ad valorem inventory tax revenues applicable to natural gas stored in the facility for the prior three consecutive calendar years.
 
The passive ownership of the facilities by the Industrial Development Board will not result in any impact to the operation of the Pine Prairie facility. In addition, the tax exemption enables Pine Prairie to offer more competitively priced storage services to respond to market forces.
 
Insurance
 
We share insurance coverage with PAA, for which we reimburse PAA’s general partner pursuant to the terms of the omnibus agreement. To the extent PAA experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased. Our insurance program includes general liability insurance, auto liability insurance, worker’s compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate.
 
Employees
 
Plains All American GP LLC employs all of our personnel. We are managed and operated by the directors and officers of our general partner. We rely on an omnibus agreement with Plains All American GP LLC to provide us with employees needed to carry out our operations.
 
Legal Proceedings
 
We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are also a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “Regulation — Natural Gas Storage Regulation.”


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MANAGEMENT
 
Partnership Management and Governance
 
Our general partner will manage our operations and activities. The directors of our general partner will oversee our operations. Unitholders will not be entitled to elect our general partner or the directors of our general partner and will not participate in the management of our operations. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Our general partner has the discretion to incur indebtedness or other obligations on our behalf on a non-recourse basis to the general partner and we expect that it will do so.
 
The officers of our general partner will be employed by PAA’s general partner and will manage the day-to-day affairs of our business. Certain of our officers are dedicated to managing our business, while other officers will have responsibilities for both us and PAA. We will also utilize a significant number of employees of PAA’s general partner to operate our business and provide us with general and administrative services.
 
We will enter into an omnibus agreement with PAA and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by PAA’s general partner to us of certain general and administrative services and employees, our agreement to reimburse PAA’s general partner for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Plains All American,” “PAA” and related marks, and other matters. Please read “Certain Relationships and Related Transactions — Agreements Governing the Transactions — Omnibus Agreement.” Additionally, the omnibus agreement will not increase or decrease our general partner’s fiduciary duties to us under our partnership agreement. For more information on the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties — Duties of Our General Partner.”
 
Directors of our General Partner
 
PAA is the sole member of our general partner and will have the right to elect all seven members to the board of directors of our general partner. Subject to the transition described under “—Our Board Committees — Audit Committee” below, at least three of the members of our general partner’s board of directors must be “independent” (as defined in applicable NYSE and SEC rules) and eligible to serve on the audit committee. At least two of such directors must also meet the criteria for service on a conflicts committee in accordance with our partnership agreement.
 
In evaluating director candidates, PAA will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the partnership, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.
 
Our Board Committees
 
Because we are a limited partnership, the listing standards of the NYSE do not require that we or our general partner have a majority of independent directors or a nominating or compensation committee of the board of directors. We are, however, required to have an audit committee of at least three members, and all of its members are required to be independent as defined by the NYSE.
 
Audit Committee.  Upon completion of the offering, we will have at least one director who satisfies the applicable NYSE and SEC requirements for independence and eligibility to serve on the audit committee. Within 90 days of the closing of this offering, we will have a total of two independent directors who meet the requirements for audit committee service. Within one year of the closing of this offering, we will have a total of three independent directors who meet the requirements for audit committee service.
 
Pursuant to the NYSE listing standards, a director will be considered independent if the board determines that he or she does not have a material relationship with our general partner or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with our general partner or us)


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and otherwise meets the board’s stated criteria for independence. These three board members will serve as the members of the audit committee.
 
In addition to these general independence requirements, as required by the Sarbanes-Oxley Act of 2002, the SEC has adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy additional independence requirements. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member, and may not be considered an affiliate of the public company. Subject to the transition period described above, the board of directors of our general partner expects that all members of its audit and conflicts committees will satisfy this heightened independence requirement.
 
Further, SEC rules require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. The board of directors of our general partner anticipates that at least one of its independent directors will satisfy the definition of “audit committee financial expert.”
 
Compensation Committee.  Our general partner’s board of directors intends to establish a compensation committee. The compensation committee will administer our Long-Term Incentive Plan and other equity and executive compensation plans.
 
Conflicts Committee.  Our partnership agreement provides for the establishment or activation of a conflicts committee, as circumstances warrant, to review conflicts of interest between us and our general partner or between us and PAA or its affiliates. Such a committee would consist of a minimum of two members, none of whom can be officers or employees of our general partner or directors, officers or employees of its affiliates and each of whom must meet the independence standards for service on an audit committee established by the NYSE and the SEC. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us or our unitholders.
 
Board Leadership Structure and Role in Risk Oversight
 
Our CEO also serves as Chairman of the Board.  The board has no policy with respect to the separation of the offices of chairman and CEO; rather, that relationship is currently defined and governed by the limited liability company agreement of our general partner, which requires coincidence of the offices. We do not have a lead independent director. The chairmanship of non-management executive sessions of the board rotates among the non-management directors, sequenced alphabetically by last name. Directors of our general partner are designated or elected by its sole member, PAA. Accordingly, unlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.
 
The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to creation of value for our unitholders. The board has delegated to management the primary responsibility for enterprise-level risk management, while the board has retained responsibility for oversight of management in that regard. Management will offer an enterprise-level risk assessment to the Board at least once every year.
 
Directors and Executive Officers of Our General Partner
 
The following table sets forth certain information with respect to the executive officers, directors and certain other officers and key employees of our general partner. Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board. There are no family


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relationships among any of our directors or executive officers. Some of our directors and executive officers also serve as directors or executive officers of PAA.
 
             
    Age (as of
   
Name
  12/31/2009)  
Position with Our General Partner
 
Greg L. Armstrong
    51     Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis
    52     Vice Chairman and Director
Dean Liollio
    51     President and Director
Al Swanson
    45     Senior Vice President, Chief Financial Officer and Director
Richard McGee
    48     Vice President — Legal and Business Development and Secretary
Dan Noack
    39     Vice President — Operations
Richard Tomaski
    38     Vice President — Marketing
Tina L. Summers
    40     Vice President — Accounting and Chief Accounting Officer
Donald C. O’Shea
    39     Controller
 
Greg L. Armstrong has served as Chairman of the Board, Chief Executive Officer and Director of our general partner since January 2010 and as Chairman of the Board, Chief Executive Officer and Director of PAA’s general partner since PAA’s formation in 1998. In addition, he was President, Chief Executive Officer and director of Plains Resources Inc. from 1992 to May 2001. He previously served Plains Resources as President and Chief Operating Officer from October to December 1992; Executive Vice President and Chief Financial Officer from June to October 1992; Senior Vice President and Chief Financial Officer from 1991 to 1992; Vice President and Chief Financial Officer from 1984 to 1991; Corporate Secretary from 1981 to 1988; and Treasurer from 1984 to 1987. Mr. Armstrong is also a director of National Oilwell Varco, Inc. Mr. Armstrong previously served as a director of BreitBurn Energy Partners, L.P. Our general partner’s limited liability company agreement specifies that Mr. Armstrong, as the Chief Executive Officer of the general partner, be a member of the board of directors.
 
Harry N. Pefanis has served as Vice Chairman and Director of our general partner since January 2010 and as President and Chief Operating Officer of PAA’s general partner since PAA’s formation in 1998. In addition, he was Executive Vice President — Midstream of Plains Resources from May 1998 to May 2001. He previously served Plains Resources as Senior Vice President from February 1996 until May 1998; Vice President — Products Marketing from 1988 to February 1996; Manager of Products Marketing from 1987 to 1988; and Special Assistant for Corporate Planning from 1983 to 1987. Mr. Pefanis was also President of several former midstream subsidiaries of Plains Resources until PAA’s formation. Mr. Pefanis is also a director of Settoon Towing. We believe that Mr. Pefanis’ extensive energy industry background, particularly the five years he has spent serving as part of the management team of PAA’s natural gas storage business, brings important experience and skill to the board.
 
Dean Liollio has served as President and Director of our general partner since January 2010. He has served as President of PAA’s natural gas storage business since November 2008. Prior to joining PAA’s natural gas storage business, Mr. Liollio served as President, Chief Executive Officer and Director of Energy South, Inc. from August 2006 until its acquisition by Sempra in October 2008. He previously spent 23 years at Centerpoint Energy, most recently serving as Division President and COO of Southern Gas Operations. We believe that Mr. Liollio’s extensive energy industry background and his experiences serving as the chief executive of a public company bring important experience and skill to the board.
 
Al Swanson has served as Senior Vice President, Chief Financial Officer and Director of our general partner since January 2010 and as Senior Vice President and Chief Financial Officer of PAA’s general partner since November 2008. He previously served as Senior Vice President — Finance of PAA’s general partner from August 2008 until November 2008 and as Senior Vice President — Finance and Treasurer from August 2007 until August 2008. He served as Vice President — Finance and Treasurer of PAA’s general partner from August 2005 to August 2007, as Vice President and Treasurer from February 2004 to August 2005 and as Treasurer from May 2001 to February 2004. In addition, he held finance related positions at Plains Resources


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including Treasurer from February 2001 to May 2001 and Director of Treasury from November 2000 to February 2001. Prior to joining Plains Resources, he served as Treasurer of Santa Fe Snyder Corporation from 1999 to October 2000 and in various capacities at Snyder Oil Corporation including Director of Corporate Finance from 1998, Controller — SOCO Offshore, Inc. from 1997, and Accounting Manager from 1992. Mr. Swanson began his career with Apache Corporation in 1986 serving in internal audit and accounting. We believe that Mr. Swanson’s extensive energy industry and financial background and his experience serving as part of the management team of PAA’s natural gas storage business, brings important experience and skill to the board.
 
Richard McGee has served as Vice President — Legal and Business Development and Secretary of our general partner since January 2010. He has served as Vice President of PAA’s natural gas storage business since September 2009. From January 1999 to July 2009, he was employed by Duke Energy, serving as President of Duke Energy International from October 2001 through July 2009 and serving as general counsel of Duke Energy Services from January 1999 through September 2001. He previously spent 12 years at Vinson & Elkins L.L.P., where he was a partner with a focus on acquisitions, divestitures and development work for various clients in the energy industry.
 
Dan Noack has served as Vice President — Operations of our general partner since January 2010. He has served as Vice President of Operations of PAA’s natural gas storage business since July 2008. Most recently, from January 2005 until June 2008, he served as storage manager for Energy Transfer Partners responsible for their three storage assets and 76 Bcf of working gas capacity, and from January 2002 until December 2004, he served as a storage consultant for El Paso Field Services (GulfTerra) responsible for their eight storage assets, 26 cavern wells, 23 Bcf of working gas capacity and 40 MMbbls of liquid storage capacity.
 
Richard Tomaski has served as Vice President — Marketing of our general partner since January 2010. He has served as Vice President of PAA’s natural gas storage business since September 2005. From April 2002 until September 2005, he served as Vice President of Sempra Energy Trading, where he had responsibility for natural gas trading and gas storage marketing at Bluewater and Pine Prairie. From August 1996 until April 2002, he served in several capacities with Enron Corp. and Enron North America.
 
Tina L. Summers has served as Vice President — Accounting and Chief Accounting Officer of our general partner since January 2010 and as Vice President — Accounting and Chief Accounting Officer of PAA’s general partner since June 2003. She served as Controller from April 2000 until she was elected to her current position. From January 1998 to January 2000, Ms. Summers served as a consultant to Conoco de Venezuela S.A. She previously served as Senior Financial Analyst for Plains Resources from October 1994 to July 1997.
 
Donald C. O’Shea has served as Controller of our general partner since February 2010. Previously he served as Director, Special Projects from November 2009 to January 2010. Prior to joining us, Mr. O’Shea spent 15 years working for the accounting firm PricewaterhouseCoopers LLP.
 
Compensation of Our Officers
 
We and our general partner were formed in January 2010. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for our directors and officers for the fiscal year ended December 31, 2009 or for any prior periods. Accordingly, we are not presenting any compensation for historical periods.
 
The officers of our general partner will be employed by PAA’s general partner and will manage the day-to-day affairs of our business. Certain of our officers are dedicated to managing our business and will devote the substantial majority of their time to our business, while other officers will have responsibilities for both us and PAA and will devote less than a majority of their time to our business. Because the executive officers of our general partner are employees of PAA’s general partner, compensation will be paid by PAA’s general partner and reimbursed by us. The officers of our general partner, as well as the employees of PAA’s general partner who provide services to us, may participate in employee benefit plans and arrangements sponsored by PAA, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of our officers. We anticipate that, in connection with the closing


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of this offering, the board of directors of our general partner will grant awards to our key employees and our outside directors pursuant to the Long-Term Incentive Plan described below; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted. Certain of our key employees hold grants under PAA’s long-term incentive plan. It is our intent to replace such grants with grants of equivalent value under our Long-Term Incentive Plan following the closing of this offering.
 
Our Long-Term Incentive Plan
 
Our general partner intends to adopt the PAA Natural Gas Storage Long-Term Incentive Plan for the employees, directors and consultants of our general partner and its affiliates, including PAA, who perform services for us. The Long-Term Incentive Plan will consist of restricted units, phantom units, unit options and deferred common units. The Long-Term Incentive Plan will limit the number of units that may be delivered pursuant to awards under the plan to           units. Units forfeited or withheld to satisfy tax withholding obligations become available for delivery pursuant to other awards. The Long-Term Incentive Plan will be administered by the board of directors and compensation committee of our general partner.
 
The board of directors of our general partner may terminate or amend the Long-Term Incentive Plan at any time with respect to any units for which a grant has not yet been made. Our board of directors also has the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as may be required by the exchange upon which the common units are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. The Long-Term Incentive Plan will expire upon its termination by the board of directors or, if earlier, when no units remain available under the Long-Term Incentive Plan for awards. Upon termination of the Long-Term Incentive Plan, awards then outstanding will continue pursuant to the terms of their grants.
 
Restricted Units.  A restricted unit is a common unit that vests over a period of time and that during such time is subject to forfeiture. In the future, the plan administrator may determine to make grants of restricted units under the Long-Term Incentive Plan to employees, directors and consultants, containing such terms as the plan administrator determines. The plan administrator will determine the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units may vest upon a change in control, as defined in the relevant grant letter. Distributions made on restricted units may be subjected to vesting provisions. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the plan administrator or the terms of the award agreement provide otherwise.
 
Phantom Units.  A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. In the future, the plan administrator may determine to make grants of phantom units under the plan to employees, consultants and directors containing such terms as the plan administrator determines. The plan administrator will determine the period over which phantom units granted to employees and members of our board will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the phantom units may vest upon a change in control, as defined in the relevant grant letter. If a grantee’s employment, consulting arrangement or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the plan administrator or the terms of the award agreement provide otherwise.
 
The plan administrator, in its discretion, may grant distribution equivalent rights, which we refer to as DERs, with respect to a phantom unit. DERs entitle the grantee to receive a cash payment equal to the cash distributions made on a common unit during the period the phantom unit is outstanding. The plan administrator will establish whether the DERs are paid currently, when the tandem phantom unit vests or on some other basis.


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We intend the grant of restricted units and issuance of any common units upon vesting of the phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.
 
Deferred Common Units.  The plan administrator may determine to make grants of deferred common units to non-employee directors of our general partner. A deferred common unit represents one common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner. Deferred common units awarded to directors receive all cash or other distributions paid by us on account of our common units.
 
Common units to be delivered as restricted units, upon the vesting of phantom units, or in connection with deferred common units, may be newly issued common units, common units acquired by us in the open market, common units acquired by us from any other person, or any combination of the foregoing. If we issue new common units upon vesting of the phantom units, the total number of common units outstanding will increase.
 
Unit Options.  The Long-Term Incentive Plan also permits the grant of options covering common units and unit appreciation rights. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by the plan administrator. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the plan administrator may determine that are consistent with the plan; however, a unit option or unit appreciation right must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant.
 
U.S. Federal Income Tax Consequences of Awards Under the Long-Term Incentive Plan.  Generally, when restricted units, phantom units, deferred common units or unit options are granted, there are no income tax consequences for the participant or us. Upon the payment to the participant of common units and/or cash in respect of the award of phantom units or deferred common units or the release of restrictions on restricted units, including any distributions that have been made thereon, the participant recognizes compensation equal to the fair market value of the cash and/or units as of the date of delivery or release.
 
Class B Units of Our General Partner
 
We expect our general partner to authorize the issuance to members of our management team Class B units, each representing a profits interest in our general partner. The Class B units will be limited to proportionate participation in cash distributions paid by our general partner above specified quarterly distribution levels.
 
The cost of the obligations represented by the Class B units will be borne solely by our general partner. We will not be obligated to reimburse our general partner for such costs and any distributions made on such Class B units will not reduce the amount of cash available for distribution to our unitholders. Under generally accepted accounting principles, however, the Class B units represent an equity compensation plan for our benefit. Accordingly, once the likelihood of achievement of a performance threshold is considered probable, we will record an expense related to the fair market value of the associated interest at the date of grant, proportionate to the relevant service period incurred through such date. Any balance will be amortized over the remaining service period through the achievement of such performance threshold. An offsetting entry will be recorded to partners’ capital to reflect a capital contribution from our general partner equal to the amount recorded as expense in our financial statements.
 
Terms of each grant will vary, but are expected to include performance benchmarks that encourage and reward the growth of our partnership through acquisitions and other terms that encourage retention.


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Compensation of Our Directors
 
The officers or employees of our general partner or of PAA’s general partner who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner or of PAA’s general partner will receive compensation as set by our general partner’s board of directors upon recommendation from our general partner’s compensation committee. In addition, non-employee directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees.
 
Each director will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.
 
Compensation Committee Interlocks and Insider Participation
 
Our general partner’s board of directors intends to establish a compensation committee, but has yet to do so.
 
Compensation Discussion and Analysis
 
All of our executive officers and other personnel necessary for our business to function will be employed and compensated by PAA’s general partner, subject to reimbursement by us. We and our general partner were formed in January 2010, therefore, we incurred no cost or liability with respect to compensation of our executive officers, nor has our general partner accrued any liabilities for management incentive or retirement benefits for our executive officers for the fiscal year ended December 31, 2009 or for any prior periods.
 
Responsibility and authority for compensation-related decisions for executive officers dedicated to our business will reside with the compensation committee of our general partner. Responsibility and authority for compensation-related decisions for executive officers with responsibilities to both us and PAA will reside with the compensation committee of PAA’s general partner. Our officers will manage our business as part of the service provided by PAA under the omnibus agreement, and the compensation for all of our executive officers will be indirectly paid by us through reimbursements to PAA. Our general partner’s compensation committee will also be responsible for the future administration of our LTIP and for compensation of our general partner’s non-employee directors.
 
We expect that the future compensation of our executive officers will be structured in a manner similar to that of PAA. PAA employs a compensation philosophy that emphasizes pay-for-performance (primarily the ability to increase sustainable quarterly distributions to unitholders), both on an individual and entity level, and places the majority of each executive officer’s compensation at risk. PAA believes its pay-for-performance approach aligns the interests of its executive officers with that of its unitholders, and at the same time enables PAA to maintain a lower level of base overhead in the event its operating and financial performance fails to meet expectations. PAA designs its executive compensation to attract and retain individuals with the background and skills necessary to successfully execute its business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of its unitholders, and to reward success in reaching such goals. PAA uses three primary elements of compensation to fulfill that design — salary, cash bonus and long-term equity incentive awards. Cash bonuses and equity incentives (as opposed to salary) represent the performance driven elements. They are also flexible in application and can be tailored to meet PAA’s objectives. The determination of specific individuals’ cash bonuses reflects their relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term incentive awards is based on their expected contribution in respect of longer term performance objectives. PAA does not maintain a defined benefit or pension plan for its executive officers, because it believes such plans primarily reward longevity rather than performance. PAA provides a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance. Employees provided to us under the omnibus agreement will enjoy the same basic benefits. In instances considered necessary for the execution of their job responsibilities, PAA also reimburses certain of its executive officers and other employees for club dues and similar expenses.


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Relation of Compensation Policies and Practices to Risk Management
 
We anticipate that our compensation policies and practices will reflect the same philosophy and approach as PAA’s. Accordingly, such policies and practices will be designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach performance thresholds which qualify them for additional compensation. For us, such risks would primarily attach to the commercial marketing activities that we intend to develop, as well as to the execution of capital expansion projects and acquisitions and the realization of associated returns.
 
From a risk management perspective, our policy will be to conduct our commercial activities within pre-defined risk parameters that are closely monitored and are structured in a manner intended to control and minimize the potential for unwarranted risk-taking. See “Management’s Discussion and Analysis — Future Trends and Outlook — Commercial Management Activities.” We also routinely monitor and measure the execution and performance of our capital projects and acquisitions relative to expectations.
 
We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking unwarranted risk to achieve short-term, unsustainable results. Those elements include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our code of conduct. See “Compensation Discussion and Analysis.”
 
In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.


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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
The following table sets forth the beneficial ownership of our units that, upon the consummation of this offering and the related transactions and assuming that underwriters do not exercise their option to purchase up to           additional common units, will be owned by:
 
  •  each person or group of persons known by us to be a beneficial owner of 5% or more of the then outstanding units;
 
  •  each member of and nominee to the board of directors of our general partner;
 
  •  each executive officer of our general partner; and
 
  •  all directors and officers of our general partner as a group.
 
                                                         
                      Percentage of
          Percentage
    Percentage of
 
          Percentage
    Series A
    Series A
    Series B
    of Series B
    Total Common
 
    Common
    of Common
    Subordinated
    Subordinated
    Subordinated
    Subordinated
    and Subordinated
 
    Units to be
    Units to be
    Units to be
    Units to be
    Units to be
    Units to be
    Units to be
 
Name and Address of
  Beneficially
    Beneficially
    Beneficially
    Beneficially
    Beneficially
    Beneficially
    Beneficially
 
Beneficial Owner(1)
  Owned(2)     Owned     Owned     Owned     Owned     Owned     Owned  
 
Plains All American Pipeline, L.P. 
            %             100 %             100 %     %
Greg L. Armstrong
            %                                 %
Harry N. Pefanis
            %                                 %
Dean Liollio
            %                                 %
Al Swanson
            %                                 %
Richard McGee
            %                                 %
Dan Noack
            %                                 %
Richard Tomaski
            %                                 %
Tina L. Summers
            %                                 %
All directors and executive officers of our general partner as a group (8 persons)
            %                                 %
 
 
Less than 1%
 
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 333 Clay Street, Suite 1500, Houston, Texas 77002.
 
(2) Does not include common units that may be purchased in the directed unit program. See “Underwriting.”
 
The following table sets forth, as of December 31, 2009, the number of common units of Plains All American Pipeline, L.P. owned by beneficial owners of 5% or more of PAA’s units, each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group. As of December 31, 2009, there were 136,135,988 common units of Plains All American Pipeline issued and outstanding.
 
                 
    PAA Common Units Owned Directly
    Percentage of PAA Common
 
Name and Address of Beneficial Owner(1)
  or Indirectly(2)     Units Beneficially Owned  
 
Paul G. Allen
    16,293,279 (3)     12.0 %(4)
Vulcan Energy Corporation
    12,390,120 (5)     9.1 %
Richard Kayne/Kayne Anderson Capital Advisors, L.P. 
    7,281,859 (6)     5.3 %
Greg L. Armstrong
    347,490       *  
Harry N. Pefanis
    221,118       *  
Dean Liollio
    10,000       *  
Al Swanson
    15,803       *  
Richard McGee
           
Dan Noack
           
Richard Tomaski
    3,400       *  
Tina L. Summers
    15,543       *  
All directors and executive officers of our general partner as a group (8 persons)
    613,354       *  


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Less than 1%
 
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 333 Clay Street, Suite 1500, Houston, Texas 77002.
 
(2) Does not include unvested phantom units under PAA’s Long-Term Incentive Plans, none of which will vest within 60 days after December 31, 2009.
 
(3) Mr. Allen owns approximately 80% of the outstanding shares of common stock of Vulcan Energy Corporation. Mr. Allen also controls Vulcan Capital Private Equity I LLC (“Vulcan I LLC”), which is the record holder of 3,706,044 common units of PAA, and Vulcan Capital Private Equity II LLC (together with Vulcan I LLC, “Vulcan LLC”), which is the record holder of 197,215 common units of PAA. The address for Mr. Allen and Vulcan LLC is 505 Fifth Avenue S, Suite 900, Seattle, Washington 98104. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of PAA’s partner interests held by Vulcan Energy Corporation or any of its affiliates.
 
(4) Giving effect to the indirect ownership by Vulcan Energy Corporation of a portion of PAA’s general partner, Mr. Allen may be deemed to beneficially own approximately 12.7% of PAA’s total equity. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of PAA’s partner interests held by Vulcan Energy Corporation or any of its affiliates.
 
(5) The address for Vulcan Energy Corporation is c/o Plains All American GP LLC, 333 Clay Street, Suite 1600, Houston, Texas 77002.
 
(6) Richard A. Kayne is Chief Executive Officer and Director of Kayne Anderson Investment Management, Inc., which is the general partner of Kayne Anderson Capital Advisors, L.P. (“KACALP”). Various accounts (including KAFU Holdings, L.P., which owns a portion of PAA’s general partner) under the management or control of KACALP own 7,016,623 common units of PAA. Mr. Kayne may be deemed to beneficially own such units. In addition, Mr. Kayne directly owns or has sole voting and dispositive power over 265,236 common units of PAA. Mr. Kayne disclaims beneficial ownership of any of PAA’s partner interests other than units held by him or interests attributable to him by virtue of his interests in the accounts that own PAA’s partner interests. The address for Mr. Kayne and Kayne Anderson Investment Management, Inc. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.


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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
 
After this offering, PAA will own           common units,     Series A subordinated units and           Series B subordinated units, representing an aggregate     % limited partner interest in us. In addition, PAA will own our general partner, which will own a 2.0% general partner interest in us and all of our incentive distribution rights.
 
Distributions and Payments to Our General Partner and Its Affiliates
 
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of the partnership, assuming that the underwriters do not exercise their option to purchase additional common units. These distributions and payments were determined by and among affiliated entities.
 
Formation stage
The aggregate consideration received by PAA for the contribution of the assets and liabilities to us
•          common units;
•          Series A subordinated units;
•          Series B subordinated units;
• 2.0% general partner interest; and
• our incentive distribution rights.
 
Operational stage
Distributions of available cash to our general partner and its affiliates We will generally make cash distributions 98.0% to our unitholders pro rata, including PAA as the holder of common units and           Series A subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level, including the general partner’s 2% general partner interest.
 
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding common units and Series A subordinated units for four quarters, our general partner would receive an annual distribution of approximately $      million on its general partner interest and PAA would receive an annual distribution of approximately $      million on its common units and Series A subordinated units.
 
If our general partner elects to reset the target distribution levels, it will be entitled to receive common units. The Series B subordinated units are not entitled to cash distributions unless and until they convert to Series A subordinated units or common units.
 
Payments to our general partner and its affiliates Our general partner does not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines the amount of these expenses. In addition, we will reimburse PAA for the provision of various general and administrative services


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for our benefit pursuant to the omnibus agreement and the costs and expenses of employees provided to us. Please read “— Agreements Governing the Transaction — Omnibus Agreement” below.
 
Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of Our General Partner.”
 
Liquidation stage
Liquidation Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
 
Agreements Governing the Transactions
 
We and other parties have or will enter into the various documents and agreements that will affect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements have been negotiated among affiliated parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.
 
Omnibus Agreement
 
Concurrently with the closing of our initial public offering, we will enter into an omnibus agreement with PAA and certain of its affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including, among other things:
 
  •  the provision by PAA’s general partner to us of certain general and administrative services and our agreement to reimburse PAA’s general partner for such services;
 
  •  the provision by PAA’s general partner of such employees as may be necessary to operate and manage our business, and our agreement to reimburse PAA’s general partner for the expenses associated with such employees;
 
  •  certain indemnification obligations; and
 
  •  our use of the name “Plains All American,” “PAA” and related marks.
 
PAA’s indemnification obligations will include certain liabilities relating to:
 
  •  for a period of three years after the closing of this offering, environmental liabilities, including (i) any violation or correction of violation of environmental laws associated with our assets, where a correction of violation would include assessment, investigation, monitoring, remediation, or other similar action and (ii) any event, omission or condition associated with the ownership of our assets (including presence of hazardous materials), including (A) the cost and expense of any assessment, investigation, monitoring, remediation or other similar action and (B) the cost and expense of any environmental or toxic tort litigation, provided that (i) the aggregate amount payable to us pursuant to this bullet point does not exceed $15 million and (ii) amounts are only payable to us pursuant to this bullet point after liabilities relating to this bullet point have exceeded $250,000;
 
  •  until 60 days after the applicable statute of limitations, any of our federal, state and local income tax liabilities attributable to the ownership and operation of our assets and the assets of our subsidiaries prior to the closing of this offering;
 
  •  for a period of three years after the closing of this offering, the failure to have all necessary consents and governmental permits where such failure renders us unable to use and operate our assets in substantially the same manner in which they were used and operated immediately prior to the closing of this offering; and


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  •  for a period of three years after the closing of this offering, our failure to have valid and indefeasible easement rights, rights-of-way, leasehold and/or fee ownership interest in the lands where our assets are located and such failure prevents us from using or operating our assets in substantially the same manner as operated immediately prior to the closing of this offering.
 
In no event will PAA be obligated to indemnify us for any claims, losses or expenses or income taxes referred to above to the extent either (i) reserved for in our financial statements as of December 31, 2010, or (ii) we recover any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party.
 
In addition, we will also agree to indemnify PAA and its general partner from any losses, costs or damages incurred by PAA or its general partner that are attributable to the ownership and operation of our assets and the assets of our subsidiaries following the closing of this offering, subject to the same limitations on PAA’s indemnity to us.
 
With respect to the provision by PAA’s general partner of certain general and administrative services and such management and operating services as may be necessary to manage and operate the business of the Partnership, we will reimburse PAA’s general partner for all reasonable costs and expenses incurred by it in connection with the performance of these services and will also reimburse PAA’s general partner for any sales, use, excise, value added or similar taxes incurred by it in connection with the provision of the services and all insurance coverage expenses it incurs or payments it makes with respect to our assets.
 
The omnibus agreement will also provide that PAA’s general partner will provide specified employees to our general partner to provide our general partner with those services necessary to operate, manage, maintain and report the operating results of the Partnership’s assets. Such employees will be under the direction, supervision and control of our general partner and our general partner will reimburse PAA’s general partner for all costs and expenses incurred by it in connection with the employees.
 
The omnibus agreement can be amended by written agreement of all the parties to the agreement. However, the partnership may not agree to any amendment or modification that will, in the reasonable discretion of our general partner, have an adverse affect on the holders of our common units without the prior approval of the conflicts committee.
 
Except for the indemnification provisions set forth in the agreement, the omnibus agreement will terminate if PAA ceases to own more than 50% of our or our general partner’s voting securities or may be terminated by PAA if PNGS GP LLC is removed as our general partner under circumstances where “cause” does not exist and the common units held by PAA and its affiliates were not voted in favor of such removal.
 
Related Party Transactions
 
Potential PAA Financial Support
 
PAA may elect, but is not obligated, to provide financial support to us under certain circumstances, such as in connection with an acquisition or expansion capital project. Our partnership agreement contains provisions designed to facilitate this process and reduce concerns regarding conflicts of interest by describing certain transactions which, by definition, will be deemed fair to our unitholders. For example, our partnership agreement contains provisions designed to facilitate PAA’s ability to provide us with financial support while reducing concerns regarding conflicts of interest by defining certain potential financing transactions between PAA and us as fair to our unitholders. In that regard, the following forms of potential PAA financial support will be deemed fair to our unitholders, and will not constitute a breach of any duty by our general partner, if consummated on terms not less favorable than those described below:
 
  •  We may issue common units to PAA at a price per common unit of no less than 95% of the trailing 20-day average closing price per common unit; provided, however, we may redeem any such common units (assuming PAA’s agreement) at a price per common unit no greater than 95% of the trailing 20-day average closing price per common unit.


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  •  We may borrow funds from PAA on terms that include a tenor of no more than three years and a fixed rate of interest that is no more than (i) 100 basis points higher than the fixed rate of interest incurred by PAA on any senior notes or other financial instruments issued by PAA to fund such loan to us or (ii) in the event no such notes or other financial instruments have been issued by PAA to fund such loans to us, 100 basis points higher than the weighted average of PAA’s outstanding senior note issues.
 
We have no obligation to seek financing from PAA on the terms described above or to accept such financing if offered to us. In addition, PAA will have no obligation to provide financial support under these or any other circumstances. We would anticipate that PAA would provide such support to us only if permitted under the relevant provisions of its debt instruments at the time. Finally, the existence of these provisions will not preclude other forms of financial support from PAA, including financial support on significantly less favorable terms if we conclude that such support is in, or not opposed to, our best interests.
 
Intercompany Note with PAA
 
In conjunction with the PAA Ownership Transaction, all third party debt was terminated and replaced with a related party note payable to PAA. The note is a demand note and accrues interest at a fixed rate of 6.5%. PAA has issued a waiver stating that it will not demand payment during the year ended December 31, 2010, and PAA has indicated that it will not request repayment prior to December 31, 2013. The interest on the note is paid in-kind and added to the principal amount of the note. To the extent necessary, we have the ability to incur additional borrowings under the note. Upon closing of this offering, we intend to use the net proceeds from this offering, together with borrowings under our credit facility, to repay approximately $      million of the intercompany note.
 
Contracts with Affiliates
 
In December 2008, PAA made a $600,000 loan to Dean Liollio, President of PAA’s natural gas storage business, to assist him with the payment of relocation expenses incurred in connection with his employment with PAA’s general partner. The loan did not bear any interest and has since been repaid in full.
 
Review, Approval or Ratification of Transactions with Related Persons
 
We expect that we will adopt policies for the review, approval and ratification of transactions with related persons similar to those that have been adopted by PAA, as embodied in PAA’s Governance Guidelines and Code of Business Conduct.
 
Upon our adoption of Governance Guidelines similar to those of PAA, a director would be expected to bring to the attention of the CEO or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and the Partnership or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.
 
If a conflict or potential conflict of interest arises between the Partnership and our general partner, the resolution of any such conflict or potential conflict should be addressed by the board in accordance with the provisions of the Partnership Agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a “conflicts committee” meeting the definitional requirements for such a committee under the Partnership Agreement.
 
Upon our adoption of a Code of Business Conduct similar to PAA’s, any Executive Officer will be required to avoid conflicts of interest unless approved by the board of directors.
 
In the case of any sale of equity by the Partnership in which an owner or affiliate of an owner of our general partner participates, we anticipate that our practice will be to obtain general approval of the full board for the transaction. We anticipate that the board will typically delegate authority to set the specific terms to a pricing committee, consisting of the CEO and one independent director. Actions by the pricing committee will require unanimous approval.


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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
 
Conflicts of Interest
 
Potential conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including PAA, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have legal duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a legal duty to manage our partnership in a manner beneficial to us and our unitholders. It is not possible to predict the nature or extent of these potential future conflicts of interest at this time, nor is it possible to determine how we will address and resolve any such future conflicts of interest. The resolution of these conflicts may not always be in the best interest of our unitholders.
 
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner’s board of directors or its conflicts committee will resolve, on behalf of our public unitholders, that conflict. Our partnership agreement contains provisions that define and limit our general partner’s duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might be challenged as breaches of its fiduciary duty.
 
Our partnership agreement provides that any resolution or course of action adopted by our general partner in respect of a conflict of interest will be permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement or any duty stated or implied by law or equity if the resolution or course of action in respect of such conflict of interest is fair and reasonable to us. Such resolution will be deemed fair and reasonable if:
 
  •  approved by the conflicts committee of our general partner after due inquiry, based on a subjective belief that the course of action or determination that is the subject of such approval is fair and reasonable to us (although our general partner is not obligated to seek such approval);
 
  •  approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
 
  •  determined by our general partner (after due inquiry) to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  •  approved by our general partner after due inquiry, based on a subjective belief that the course of action or determination that is the subject of such approval is fair and reasonable to us.
 
Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith. Under our partnership agreement, a determination made in good faith means that the person making the determination does so with the subjective belief that the determination is in, or not opposed to, the best interests of our partnership and in connection therewith such person or persons may take into account the circumstances and relationships involved (including our short-term or long-term interests and other arrangements or relationships that could be considered favorable or advantageous to us). When our partnership agreement requires someone to act after due inquiry, the person or persons making such determination or taking or declining to take an action subjectively believe that such person or persons had available adequate information to make such determination or to take or decline to take such action.
 
Our partnership agreements also provides that, to the fullest extent permitted by law, in connection with any action or inaction of, or determination made by, our general partner’s board of directors or its conflicts committee with respect to any matter relating to us, it shall be presumed that our general partner’s board of directors or its conflicts committee acted in a manner that satisfied the contractual standards set forth in our partnership agreement, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or our partnership challenging any such action or inaction of, or


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determination made by, our general partner, the person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption.
 
Potential for Conflicts
 
Conflicts of interest could arise in the situations described below, among others.
 
Neither our partnership agreement nor any other agreement requires PAA to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Directors of the ultimate general partner of PAA have a fiduciary duty to make these decisions in the best interests of the owners of PAA, which may be contrary to our interests.
 
Because certain of the directors of our general partner are also directors and/or officers of PAA’s general partner, such directors have fiduciary duties to PAA that may cause them to pursue business strategies that disproportionately benefit PAA or which otherwise are not in our best interests.
 
Our general partner and its affiliates are allowed to take into account the interests of parties other than us in resolving conflicts of interest.
 
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples include our general partner’s limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.
 
Certain of the executive officers of our general partner will devote a substantial portion of time to the business of PAA and will be compensated by PAA accordingly.
 
Certain of the executive officers of our general partner are also executive officers of PAA’s general partner, including Greg L. Armstrong, Harry N. Pefanis, Al Swanson and Tina L. Summers, and will devote a substantial portion of their time to PAA’s business and affairs. We will also utilize a significant number of employees of PAA to operate our business and for which we will reimburse PAA under the omnibus agreement for expenses of operational personnel who perform services for our benefit and for allocated general and administrative expenses. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.” Our general partner and PAA will also conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the executive officers of our general partner.
 
PAA may engage in competition with us.
 
While PAA has stated that it intends to utilize our partnership as the primary vehicle through which it will participate in the natural gas storage business, PAA and its affiliates are not limited in their ability to compete with us.
 
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
 
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought


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conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:
 
  •  the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;
 
  •  the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;
 
  •  the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;
 
  •  the negotiation, execution and performance of any contracts, conveyances or other instruments;
 
  •  the distribution of our cash;
 
  •  the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
 
  •  the maintenance of insurance for our benefit and the benefit of our partners;
 
  •  the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;
 
  •  the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;
 
  •  the indemnification of any person against liabilities and contingencies to the extent permitted by law;
 
  •  the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and
 
  •  the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.
 
Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement provides that in order for a determination to be made in “good faith,” our general partner must subjectively believe that the determination is in, or not opposed to, our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.
 
Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.
 
The amount of cash that is available for distribution to our unitholders is affected by the decisions of our general partner regarding such matters as:
 
  •  the amount and timing of asset purchases and sales;
 
  •  cash expenditures;
 
  •  borrowings;
 
  •  the issuance of additional units; and
 
  •  the creation, reduction or increase of cash reserves in any quarter.
 
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces distributable cash flow. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner,


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the ability of the Series A subordinated units to convert into common units and the ability of the Series B subordinated units to convert into Series A subordinated units or common units.
 
In addition, our general partner may use an amount, initially equal to $40 million, which would not otherwise constitute available cash from distributable cash flow, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of Series A subordinated units into common units and the conversion of Series B subordinated units into Series A subordinated units or common units. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions.”
 
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:
 
  •  enabling our general partner or its affiliates to receive distributions on any Series A subordinated units held by them or the incentive distribution rights;
 
  •  hastening the expiration of the subordination period; or
 
  •  achieving the financial conditions necessary for the Series B subordinated units to convert to Series A subordinated units or common units.
 
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and Series A subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all of our outstanding common units and Series A subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Moreover, our general partner and its affiliates may borrow funds from us, or our subsidiaries.
 
Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.
 
We will reimburse our general partner and its affiliates for the costs incurred in managing and operating us, including costs incurred both by it and on its behalf pursuant to service arrangements with PAA. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
 
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or from entering into additional contractual arrangements with any of these entities on our behalf.
 
Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering are contracts with affiliates. In some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to such arrangements.
 
Our general partner will determine, in good faith, the terms of any such transactions entered into after the close of this offering.
 
Our general partner and its affiliates will have no obligation to permit us to use any of its or its affiliates’ facilities or assets, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.


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Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets, and not against our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability.
 
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of our common units.
 
Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may be required to sell his common units at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”
 
Our general partner controls the enforcement of its and its affiliates’ obligations to us.
 
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
 
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
 
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
Our general partner has the right to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election if and when (i) there are no Series A subordinated units outstanding and (ii) it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and each target distribution level will be reset to the correspondingly higher amount that causes such reset target distribution level to exceed the reset minimum quarterly distribution by the same percentage that such distribution level exceeds the then-current minimum quarterly distribution. Our general partner will have the right to reset the minimum quarterly distribution whether or not any Series B subordinated units remain outstanding.
 
We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such


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situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner Interest and Incentive Distribution Rights.”
 
Duties of our General Partner
 
The duties owed to unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the duties (including any fiduciary duties) otherwise owed by a general partner to limited partners and the partnership.
 
Our partnership agreement contains various provisions that waive or consent to conduct by our general partner that might otherwise be challenged under state law standards. We have adopted these modified duties to allow our general partner or its affiliates to engage in transactions with us that might otherwise be limited by state-law standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors has duties to manage our general partner in a manner beneficial to its owner, as well as to our unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications of state law standards enable our general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications may be detrimental to our unitholders because they restrict the remedies available to unitholders for actions that might otherwise constitute breaches of fiduciary or other duties, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest.
 
State-law fiduciary duty standards Fiduciary duties are generally considered to include a duty of care and a duty of loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require that a general partner (i) be attentive and inform itself of all material facts regarding a decision before taking action, (ii) protect the financial and other interests of the partnership and proceed with a critical eye in assessing information, and (iii) act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that a general partner’s actions be motivated solely by the best interests of the partnership and all of its partners as a whole. Hence, in the absence of a provision in the partnership agreement providing otherwise, a general partner would not be permitted to use its position of trust and confidence to further its private interests, but rather would have to act at all times in the best interests of the partnership and all of its partners as a whole.
 
Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might


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otherwise be challenged under state law standards. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act or proceed in “good faith” and will not, unless another express standard is provided for in our partnership agreement, be subject to any other standard under applicable law. When our partnership agreement requires someone to act in good faith, it requires that the person or persons making a determination or taking or declining to take an action subjectively believe that the determination, or other action or anticipated result thereof is in, or not opposed to, our best interest and in connection therewith such person or persons may take into account the circumstances and relationships involved (including our short-term or long-term interests and other arrangements or relationships that could be considered favorable or advantageous to us). When our partnership agreement requires someone to act after due inquiry, the person or persons making such determination or taking or declining to take such action are required to subjectively believe that such person or persons had available adequate information to make such determination or to take or decline to take such action. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any duty or obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
 
For a description of our partnership agreement’s conflict resolution procedures and the effects of any such resolution, please read “— Conflicts of Interest.”
 
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.
 
The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.
 
By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.


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Indemnification
 
Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”


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DESCRIPTION OF THE COMMON UNITS
 
The Units
 
The common units, the Series A subordinated units and the Series B subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units, Series A subordinated units and Series B subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”
 
Transfer Agent and Registrar
 
Duties.  American Stock Transfer & Trust Company will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:
 
  •  surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
 
  •  special charges for services requested by a common unitholder; and
 
  •  other similar fees or charges.
 
There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
 
Resignation or Removal.  The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
 
Transfer of Common Units
 
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:
 
  •  represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
 
  •  automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and
 
  •  is deemed to have given the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.
 
A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.
 
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.


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Common units are securities that are transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.
 
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.


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THE PARTNERSHIP AGREEMENT
 
The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A and will be adopted contemporaneously with the closing of this offering. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.
 
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
 
  •  with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions;”
 
  •  with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”
 
  •  with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units;” and
 
  •  with regard to allocations of taxable income and taxable loss, please read “Material Income Tax Consequences.”
 
Organization and Duration
 
Our partnership was organized in January 2010 and will have a perpetual existence.
 
Purpose
 
Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
 
Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of the acquisition, development, operation and commercial management of natural gas storage facilities and related activities, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
 
Power of Attorney
 
Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to grant consents and waivers under, our partnership agreement.
 
Cash Distributions
 
Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”
 
Capital Contributions
 
Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”


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If we issue additional units, our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.
 
Voting Rights
 
The following is a summary of the unitholder vote required for approval of the matters specified below. The 2.0% general partner interest is not deemed outstanding for purposes of voting rights and such interest represents a non-voting general partner interest. Matters that require the approval of a “unit majority” require:
 
  •  during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and
 
  •  after the subordination period, the approval of a majority of the common units, voting as a single class.
 
In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.
 
Issuance of additional units No approval right.
 
Amendment of the partnership agreement Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”
 
Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”
 
Dissolution of our partnership Unit majority. Please read “— Termination and Dissolution.”
 
Continuation of our business upon dissolution Unit majority. Please read “— Termination and Dissolution.”
 
Withdrawal of our general partner Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2020 in a manner that would cause dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”
 
Removal of our general partner Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”
 
Transfer of our general partner interest Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general


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partner interest to a third party prior to June 30, 2020. Please read “— Transfer of General Partner Interest.”
 
Transfer of incentive distribution rights Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in our general partner, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to June 30, 2020. Please read “— Transfer of Incentive Distribution Rights.”
 
Transfer of ownership interests in our general partner No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”
 
Limited Liability
 
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:
 
  •  to remove or replace our general partner;
 
  •  to approve some amendments to our partnership agreement; or
 
  •  to take other action under our partnership agreement;
 
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
 
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
 
Our subsidiaries conduct business in two states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there.


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Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
 
Issuance of Additional Securities
 
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.
 
It is possible that we will fund acquisitions through the issuance of additional common units, Series A subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.
 
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.
 
Upon issuance of additional partnership securities (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, Series A subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and Series A subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.
 
Amendment of the Partnership Agreement
 
General.  Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.


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Prohibited Amendments.  No amendment may be made that would:
 
  •  enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
 
  •  enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.
 
The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, affiliates of our general partner will own an aggregate of approximately     % of our outstanding common units, Series A subordinated units and Series B subordinated units.
 
No Unitholder Approval.  Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:
 
  •  a change in our name, the location of our principal place of business, our registered agent or our registered office;
 
  •  the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
 
  •  a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
 
  •  an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;
 
  •  an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or the right to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:
 
  •  the adjustments of the minimum quarterly distribution, first target distribution and second target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels,” or
 
  •  any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;
 
  •  any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
 
  •  an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
 
  •  any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;


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  •  a change in our fiscal year or taxable year and related changes;
 
  •  conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or
 
  •  any other amendments substantially similar to any of the matters described in the clauses above.
 
In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:
 
  •  do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
 
  •  are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
 
  •  are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
 
  •  are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
 
  •  are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
 
Opinion of Counsel and Unitholder Approval.  Our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. Except for amendments not requiring limited partner approval, no other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.
 
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.
 
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets
 
A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.
 
In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our


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general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.
 
If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.
 
Termination and Dissolution
 
We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
 
  •  the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
 
  •  there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
 
  •  the entry of a decree of judicial dissolution of our partnership; or
 
  •  the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.
 
Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:
 
  •  the action would not result in the loss of limited liability of any limited partner; and
 
  •  neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.
 
Liquidation and Distribution of Proceeds
 
Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in-kind if it determines that a sale would be impractical or would cause undue loss to our partners.
 
Withdrawal or Removal of our General Partner
 
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2020 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and


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furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2020, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights.”
 
Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”
 
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a single class, and the outstanding subordinated units, voting as a single class. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the close of this offering, affiliates of our general partner will own an aggregate of approximately     % of our outstanding common units, including all of our Series A subordinated units and Series B subordinated units.
 
Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and the units held by our general partner and its affiliates are not voted in favor of that removal:
 
  •  the subordination period will end, and all outstanding Series A subordinated units will immediately convert into common units on a one-for-one basis;
 
  •  each Series B subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.
 
In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon


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an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
 
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
 
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.
 
Transfer of General Partner Interest
 
Except for transfer by our general partner of all, but not less than all, of its general partner interest to:
 
  •  an affiliate of our general partner (other than an individual); or
 
  •  another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,
 
our general partner may not transfer all or any of its general partner interest to another person prior to June 30, 2020 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters. A change of control of our general partner does not constitute a transfer of the general partner interest.
 
Our general partner and its affiliates may, at any time, transfer common units or subordinated units to one or more persons, without unitholder approval, except that they may not transfer Series A subordinated units or Series B subordinated units to us.
 
Transfer of Ownership Interests in the General Partner
 
At any time, PAA and its affiliates may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.
 
Transfer of Incentive Distribution Rights
 
Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interests in such holder or the sale of all or substantially all of such holder’s assets to that entity without the prior approval of the unitholders; provided that, in the case of the sale of ownership interests in such holder, the initial holder of the incentive distribution rights continues to remain the general partner following such sale. Prior to June 30, 2020, any other transfer of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after June 30, 2020, the incentive distribution rights will be freely transferable.
 
Change of Management Provisions
 
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove PNGS GP LLC as our general partner or from otherwise changing our management. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.


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Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
 
  •  the subordination period will end and all outstanding Series A subordinated units will immediately convert into common units on a one-for-one basis;
 
  •  each Series B subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.
 
Limited Call Right
 
If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:
 
  •  the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
 
  •  the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date three days before the date the notice is mailed.
 
Our general partner may assign its limited call right to its affiliates.
 
As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Income Tax Consequences — Disposition of Common Units.”
 
Ineligible Assignees; Redemption
 
Our general partner, acting on our behalf, may at any time require any or all unitholders to certify:
 
  •  that the unitholder is a U.S. individual or an entity subject to U.S. federal income taxation on the income generated by us; or
 
  •  that, if the unitholder is a U.S. entity not subject to U.S. federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us.
 
This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.
 
If a unitholder fails to furnish:
 
  •  the required certification within 30 days after request; or
 
  •  provides a false certification; then


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we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, our general partner may elect not to make distributions or allocate income or loss to such unitholder.
 
The purchase price in the event of such an acquisition for each unit held by such unitholder will be the lesser of:
 
(1) the price paid by such unitholder for the relevant unit; and
 
(2) the average of the daily closing prices of the units for the prior 20 consecutive trading days.
 
The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.
 
Non-Citizen Assignees; Redemption
 
If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by that limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days of a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.
 
Meetings; Voting
 
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.
 
Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting, if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
 
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.


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Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
 
Status as Limited Partner
 
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.
 
Indemnification
 
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
 
  •  our general partner;
 
  •  any departing general partner;
 
  •  any person who is or was an affiliate of our general partner or any departing general partner;
 
  •  any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;
 
  •  any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner, any departing general partner, an affiliate of our general partner or an affiliate of any departing general partners; and
 
  •  any person designated by our general partner.
 
Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.
 
Reimbursement of Expenses
 
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with the operation of our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.
 
Books and Reports
 
Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
 
We will furnish or make available to record holders of our common units, within 120 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
 
We will furnish each record holder with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form


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so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.
 
Right to Inspect Our Books and Records
 
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:
 
  •  a current list of the name and last known address of each partner;
 
  •  a copy of our tax returns;
 
  •  information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;
 
  •  copies of our partnership agreement, our certificate of limited partnership and related amendments and powers of attorney under which they have been executed;
 
  •  information regarding the status of our business and our financial condition; and
 
  •  any other information regarding our affairs as is just and reasonable.
 
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.
 
Registration Rights
 
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of PNGS GP LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and fees. Please read “Units Eligible for Future Sale.”


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UNITS ELIGIBLE FOR FUTURE SALE
 
After the sale of the common units offered hereby, PAA will hold an aggregate of          common units, assuming that the underwriters do not exercise their option to purchase up to          additional common units,          Series A subordinated units and           Series B subordinated units. All of the Series A subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The Series B subordinated units are also eligible for conversion into common units if certain operational and financial conditions are satisfied and the end of the subordination period has occurred. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.
 
The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
 
  •  1% of the total number of the securities outstanding, or
 
  •  the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.
 
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.
 
The partnership agreement does not restrict our ability to issue any partnership securities. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”
 
Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or the prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and fees. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.
 
PAA, our partnership, our general partner and its affiliates, including the executive officers and directors of our general partner, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”


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MATERIAL INCOME TAX CONSEQUENCES
 
This section is a discussion of the material income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to PAA Natural Gas Storage, L.P. and our operating companies.
 
The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.
 
No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which the common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
 
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.
 
For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).
 
Partnership Status
 
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.


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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.
 
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating company for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.
 
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. Among the representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are the following:
 
  •  Neither we nor the operating company has elected or will elect to be treated as a corporation;
 
  •  For each taxable year, more than 90% of our gross income has been and will be income from sources that Vinson & Elkins L.L.P. has opined or will opine as generating “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and
 
  •  Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.
 
We believe that these representations have been true in the past and expect that these representations will be true in the future.
 
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
 
If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to


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zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
 
The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.
 
Limited Partner Status
 
Unitholders who have become limited partners of PAA Natural Gas Storage, L.P. will be treated as partners of PAA Natural Gas Storage, L.P. for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of PAA Natural Gas Storage, L.P. for federal income tax purposes.
 
A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”
 
Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in PAA Natural Gas Storage, L.P. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in PAA Natural Gas Storage, L.P. for federal income tax purposes.
 
Tax Consequences of Unit Ownership
 
Flow-Through of Taxable Income.  We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
 
Treatment of Distributions.  Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under ‘‘— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”
 
A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the


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non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.
 
Ratio of Taxable Income to Distributions.  We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2012, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all common units and Series A subordinated units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:
 
  •  gross income from operations exceeds the amount required to make minimum quarterly distributions on all common units and Series A subordinated units, yet we only distribute the minimum quarterly distributions on all common units and Series A subordinated units; or
 
  •  we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.
 
Basis of Common Units.  A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Limitations on Deductibility of Losses.  The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or a corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at-risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.
 
In general, a unitholder will be at-risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis


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representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
 
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, (including our investments or a unitholder’s investments in other publicly traded partnerships, such as PAA), or a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted by the unitholder in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.
 
A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships, such as PAA.
 
Limitations on Interest Deductions.  The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
 
  •  interest on indebtedness properly allocable to property held for investment;
 
  •  our interest expense attributed to portfolio income; and
 
  •  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
 
The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest deduction limitation. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
 
Entity-Level Collections.  If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.


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Allocation of Income, Gain, Loss and Deduction.  In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us; provided that there will be no allocations of income, gain, loss or deduction in respect of the Series B subordinated units prior to their conversion. At any time that distributions are made to the common units in excess of distributions to the Series A subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. In addition, we may make special allocations of income, gain, loss, deduction, unrealized gain, and unrealized loss among the partners in a manner to create economic uniformity among the common units into which the Series A subordinated units and Series B subordinated units convert and the common units held by public unitholders. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.
 
Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” These “Section 704(c) Allocations” are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity.” The effect of these Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and our other unitholders immediately prior to such issuance or other transactions to account for the Book-Tax Disparity of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
 
An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c) of the Internal Revenue Code to eliminate Book-Tax Disparities will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
 
  •  his relative contributions to us;
 
  •  the interests of all the partners in profits and losses;
 
  •  the interest of all the partners in cash flow; and
 
  •  the rights of all the partners to distributions of capital upon liquidation.
 
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in ‘‘— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.
 
Treatment of Short Sales.  A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax


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purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
 
  •  any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
 
  •  any cash distributions received by the unitholder as to those units would be fully taxable; and
 
  •  all of these distributions would appear to be ordinary income.
 
Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Alternative Minimum Tax.  Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
 
Tax Rates.  Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
 
Section 754 Election.  We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price of units acquired from another unitholder. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.
 
We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property subject to depreciation under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”
 
Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any


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unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.
 
A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built — in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built — in loss or a basis reduction is substantial if it exceeds $250,000.
 
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
 
Tax Treatment of Operations
 
Accounting Method and Taxable Year.  We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in his taxable income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve


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months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”
 
Initial Tax Basis, Depreciation and Amortization.  The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and other unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”
 
To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
 
If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”
 
The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.
 
Valuation and Tax Basis of Our Properties.  The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
 
Disposition of Common Units
 
Recognition of Gain or Loss.  Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
 
Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.
 
Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2010 and 20% thereafter (absent new legislation extending or


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adjusting the current rate). However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
 
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
 
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
 
  •  a short sale;
 
  •  an offsetting notional principal contract; or
 
  •  a futures or forward contract with respect to the partnership interest or substantially identical property.
 
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
 
Allocations Between Transferors and Transferees.  In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
 
Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under


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existing Treasury Regulations. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
 
A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
 
Notification Requirements.  A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.
 
Constructive Termination.  We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, PAA will own more than 50% of the total interests in our capital and profits interests. Therefore, a transfer by PAA of all or a portion of its interests in us, including a deemed transfer as a result of a termination of PAA’s partnership for federal income tax purposes, could result in a termination of our partnership for federal income tax purposes. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and could result in unitholders receiving two Schedules K-1) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has announced recently that it plans to issue guidance regarding the treatment of constructive terminations of publicly traded partnerships such as us. Any such guidance may change the application of the rules discussed above and may affect the tax treatment of a unitholder.
 
Uniformity of Units
 
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”


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We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the Treasury Regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable methods and lives as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”
 
Tax-Exempt Organizations and Other Investors
 
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Moreover, under our partnership agreement, non-U.S. persons are not Eligible Holders of our common units and common units held by non-U.S. persons may be subject to redemption. Please read “The Partnership Agreement — Ineligible Assignees; Redemption” and “The Partnership Agreement — Non-Citizen Assignees; Redemption.”
 
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income less certain allowable deductions allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.
 
Non-resident aliens and non-U.S. corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, cash distributions to non-U.S. unitholders will be subject to withholding at the highest applicable effective tax rates. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
 
In addition, because a non-U.S. corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the non-U.S. corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States


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and the country in which the non-U.S. corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
 
A non-U.S. unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a non-U.S. unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the Partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.
 
Administrative Matters
 
Information Returns and Audit Procedures.  We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
 
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.
 
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names PNGS GP LLC as our Tax Matters Partner.
 
The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
 
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.


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Nominee Reporting.  Persons who hold an interest in us as a nominee for another person are required to furnish to us:
 
  •  the name, address and taxpayer identification number of the beneficial owner and the nominee;
 
  •  whether the beneficial owner is:
 
  •  a person that is not a United States person;
 
  •  a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
 
  •  a tax-exempt entity;
 
  •  the amount and description of units held, acquired or transferred for the beneficial owner; and
 
  •  specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
 
Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
 
Accuracy-Related Penalties.  An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
 
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
 
  •  for which there is, or was, “substantial authority”; or
 
  •  as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
 
If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.
 
A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.
 
No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.
 
Reportable Transactions.  If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a


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reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”
 
Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:
 
  •  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;
 
  •  for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and
 
  •  in the case of a listed transaction, an extended statute of limitations.
 
We do not expect to engage in any “reportable transactions.”
 
State, Local, Foreign and Other Tax Considerations
 
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Louisiana and Michigan. Each of these states imposes a personal income tax on individuals and imposes an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.
 
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.


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INVESTMENT IN PAA NATURAL GAS STORAGE, L.P. BY EMPLOYEE BENEFIT PLANS
 
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:
 
  •  whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
 
  •  whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and
 
  •  whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Income Tax Consequences — Tax-Exempt Organizations and Other Investors.”
 
The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
 
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code.
 
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.
 
The Department of Labor regulations provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:
 
(a) the equity interests acquired by the employee benefit plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under some provision of the federal securities laws;
 
(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or
 
(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.
 
Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.
 
In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code.


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UNDERWRITING
 
Barclays Capital Inc. and UBS Securities LLC are acting as joint book-running managers of this offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.
 
         
    Number
 
Underwriter
  of Common Units  
 
Barclays Capital Inc. 
       
UBS Securities LLC
       
         
Total
       
         
 
The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the option to purchase additional common units as described below) if they purchase any of the common units.
 
Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $      per common unit. Any of these securities dealers may resell any common units purchased from the underwriters to other brokers or dealers at a discount of up to $      per common unit from the initial public offering price. If all the common units are not sold at the initial offering price, the representatives may change the offering price and the other selling terms.
 
Option to Purchase Additional Units
 
If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to          additional common units at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment.
 
No Sales of Similar Securities
 
We, our general partner, certain of our general partner’s officers and directors, certain of our affiliates, including PAA, and certain of their officers and directors have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Barclays Capital Inc. and UBS Securities LLC, offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any common units or any securities convertible into or exercisable or exchangeable for common units, or enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, whether any such transaction described above is to be settled by delivery of common units or such other securities, in cash or otherwise.
 
Barclays Capital Inc. and UBS Securities LLC, in their sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice. Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our company occurs or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.


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Determination of Offering Price
 
Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.
 
New York Stock Exchange
 
We intend to apply to list our common units on the NYSE under the symbol “PNG.” The underwriters have undertaken to sell common units to a minimum of 400 beneficial owners in lots of 100 or more common units to meet the NYSE distribution requirements for trading.
 
Discounts and Commissions
 
The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.
 
                 
    No Exercise   Full Exercise
 
Per common unit
  $       $    
Total
  $       $  
 
We estimate that our portion of the total expenses of this offering will be approximately $           .
 
Price Stabilization; Short Positions
 
In connection with this offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the option to purchase additional common units, and stabilizing purchases.
 
  •  Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in this offering.
 
  •  “Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ option to purchase additional common units.
 
  •  “Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ option to purchase additional common units.
 
  •  Covering transactions involve purchases of common units either pursuant to the over-allotment option or in the open market after the distribution has been completed in order to cover short positions.
 
  •  To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering.
 
  •  To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the option to purchase additional common units. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open


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  market as compared to the price at which they may purchase common units through the option to purchase additional common units.
 
  •  Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.
 
The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the underwriters, in covering short positions or making stabilizing purchases, repurchase common units originally sold by that syndicate member.
 
Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on The New York Stock Exchange, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.
 
Electronic Distribution
 
A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. The representatives will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.
 
Directed Unit Program
 
At our request, certain of the underwriters have reserved up to           common units for sale at the initial public offering price to the officers, directors and employees of our general partner and its sole member and certain other persons associated with us. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units prior to the effectiveness of the registration statement relating to this offering.
 
Discretionary Sales
 
The underwriters have advised us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.
 
Affiliations
 
Certain of the underwriters have in the past provided and may from time to time in the future provide commercial banking, investment banking and advisory services for us, PAA and our respective affiliates for which they have received and in the future will be entitled to receive, customary fees and reimbursement of expenses. In particular, an affiliate of UBS Securities LLC is a lender under PAA’s revolving credit facility and affiliates of Barclays Capital Inc. and UBS Securities LLC are lenders under PAA’s hedged inventory facility. As stated in “Use of Proceeds,” we intend to use the net proceeds from this offering to repay intercompany indebtedness owed to PAA. In addition, at the closing of this offering we intend to borrow approximately $200 million under our new credit facility to repay an additional portion of the intercompany indebtedness owed to PAA. PAA expects to use all or a portion of these proceeds to repay amounts outstanding under its credit facilities and for general partnership purposes. As a result, Barclays Capital Inc. and UBS Securities LLC will receive their proportionate share of any such repayment by PAA of its credit facilities.


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Indemnification
 
We and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.
 
FINRA
 
Because the Financial Industry Regulatory Authority views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
 
Foreign Selling Restrictions
 
European Economic Area
 
In relation to each Member State of the European Economic Area, or EEA, which has implemented the Prospectus Directive (each, a “Relevant Member State”), with effect from, and including, the date on which the Prospectus Directive is implemented in that Relevant Member State (“the Relevant Implementation Date”), an offer to the public of our securities which are the subject of the offering contemplated by this prospectus may not be made in that Relevant Member State, except that, with effect from, and including, the Relevant Implementation Date, an offer to the public in that Relevant Member State of our securities may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:
 
  •  to legal entities which are authorized or regulated to operate in the financial markets, or, if not so authorized or regulated, whose corporate purpose is solely to invest in our securities;
 
  •  to any legal entity which has two or more of: (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; or
 
  •  to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or
 
  •  in any other circumstances falling within Article 3(2) of the Prospectus Directive.
 
provided that no such offer of our securities shall result in a requirement for the publication by us or any underwriter or agent of a prospectus pursuant to Article 3 of the Prospectus Directive.
 
As used above, the expression “offered to the public” in relation to any of our securities in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and our securities to be offered so as to enable an investor to decide to purchase or subscribe for our securities, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.
 
The EEA selling restriction is in addition to any other selling restrictions set out in this prospectus.
 
Germany
 
This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht — BaFin) nor any other German authority has been notified of the intention to distribute the units in Germany. Consequently, the units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner AND THIS DOCUMENT AND ANY OTHER DOCUMENT RELATING TO THE


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OFFERING, AS WELL AS INFORMATION OR STATEMENTS CONTAINED THEREIN, MAY NOT BE SUPPLIED TO THE PUBLIC IN GERMANY OR USED IN CONNECTION WITH ANY OFFER FOR SUBSCRIPTION OF THE UNITS TO THE PUBLIC IN GERMANY OR ANY OTHER MEANS OF PUBLIC MARKETING. The units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.
 
Switzerland
 
The shares may not be publicly offered, distributed or re-distributed on a professional basis in or from Switzerland and neither this document nor any other solicitation for investments in the shares may be communicated or distributed in Switzerland in any way that could constitute a public offering within the meaning of Articles 1156/652a of the Swiss Code of Obligations (“CO”). This document may not be copied, reproduced, distributed or passed on to others without the Offeror’s prior written consent. This document is not a prospectus within the meaning of Articles 1156/652a CO and the shares will not be listed on the SIX Swiss Exchange. Therefore, this document may not comply with the disclosure standards of the CO and/or the listing rules (including any prospectus schemes) of the SIX Swiss Exchange. In addition, it cannot be excluded that the Offeror could qualify as a foreign collective investment scheme pursuant to Article 119 para. 2 Swiss Federal Act on Collective Investment Schemes (“CISA”). The shares will not be licensed for public distribution in and from Switzerland. Therefore, the shares may only be offered and sold to so-called “qualified investors” in accordance with the private placement exemptions pursuant to applicable Swiss law (in particular, Article 10 para. 3 CISA and Article 6 of the implementing ordinance to the CISA). The Offeror has not been licensed and is not subject to the supervision of the Swiss Financial Market Supervisory Authority (“FINMA”). Therefore, investors in the shares do not benefit from the specific investor protection provided by CISA and the supervision of the FINMA.
 
United Kingdom
 
This prospectus is only being distributed to and is only directed at: (1) persons who are outside the United Kingdom; (2) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”); or (3) high net worth companies, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons falling within (1)-(3) together being referred to as “relevant persons”). The securities are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such securities will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.


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VALIDITY OF THE COMMON UNITS
 
The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
 
EXPERTS
 
The consolidated financial statements of PAA Natural Gas Storage, LLC as of December 31, 2009 and 2008 and for the periods of September 3, 2009 to December 31, 2009, January 1, 2009 to September 2, 2009, and the years ended December 31, 2008 and 2007; the balance sheet of PAA Natural Gas Storage, L.P. as of January 22, 2010; and the balance sheet of PNGS GP LLC as of January 22, 2010 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
 
WHERE YOU CAN FIND MORE INFORMATION
 
We have filed with the SEC a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement, of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.
 
We intend to furnish our unitholders annual reports containing our audited consolidated financial statements and to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.
 
FORWARD-LOOKING STATEMENTS
 
Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.


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INDEX TO FINANCIAL STATEMENTS
 
         
PAA Natural Gas Storage, L.P.
       
    F-2  
    F-3  
    F-4  
    F-5  
       
PAA Natural Gas Storage, LLC
       
    F-6  
    F-7  
    F-8  
    F-9  
    F-10  
    F-11  
    F-12  
       
PAA Natural Gas Storage, L.P.
       
    F-29  
    F-30  
    F-31  
       
PNGS GP LLC
       
    F-32  
    F-33  
    F-34  


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PAA Natural Gas Storage, L.P.
 
Unaudited Pro Forma Condensed Combined Financial Statements
 
The following unaudited pro forma condensed combined financial statements give effect to the following transactions:
 
(i) The PAA Ownership Transaction which took place on September 3, 2009 whereby Plains All American Pipeline, L.P. (“PAA”) acquired the remaining 50% ownership interest in PAA Natural Gas Storage, LLC (“PNGS LLC”) and pushed down the fair value of the assets and liabilities to PNGS; and
 
(ii) The contribution by PAA of the equity interests in the entities that own PAA’s gas storage business and the initial public offering of PAA Natural Gas Storage, L.P. (“PNGS LP”) and anticipated borrowings under our credit facility.
 
The following unaudited pro forma condensed combined statement of operations for the year ended December 31, 2009 has been prepared as if the transactions described above had taken place on January 1, 2009. The unaudited pro forma condensed combined balance sheet at December 31, 2009 assumes the transactions were consummated on that date. The unaudited pro forma financial statements should be read in conjunction with and are qualified in their entirety by reference to the notes accompanying such unaudited pro forma financial statements as well as the notes included in the historical financial statements of PNGS for the periods ended September 2, 2009 and December 31, 2009, which are included in this document.
 
The unaudited pro forma financial statements are based on assumptions that we believe are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the results of the actual or future operations or financial condition that would have been achieved had the transactions occurred at the dates assumed (as noted above).


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PAA Natural Gas Storage, L.P.
 
Unaudited Pro Forma Condensed Combined Balance Sheet
As of December 31, 2009
 
                         
          Pro Forma
       
          Adjustments        
          PNGS LP
       
    PNGS LLC
    Formation
    PNGS LP
 
    Historical     Transactions     Pro Forma  
    (in thousands)  
 
Cash and cash equivalents
  $ 3,124     $          (a)   $ 3,124  
              (        )(a)        
Accounts receivable
    6,439             6,439  
Other current assets
    2,680             2,680  
                         
Total current assets
    12,243             12,243  
Property and equipment, net
    813,263             813,263  
Base gas
    27,927             27,927  
Goodwill and intangibles, net
    46,974             46,974  
                         
Total assets
  $ 900,407     $     $ 900,407  
                         
                         
Accounts payable and accrued liabilities
  $ 14,034     $     $ 14,034  
Other current liabilities
    2,010             2,010  
                         
Total current liabilities
    16,044             16,044  
Credit facility
          200,000  (b)     200,000  
Note payable to PAA
    450,523       (        )(a)        
              (200,000 )(b)        
Other long-term liabilities
    1,096             1,096  
                         
Total liabilities
    467,663                  
                         
Members’ capital
    432,744       (432,744 )(c)      
Held by Public:
                       
Common units
             (a)        
Held by PAA:
               (a)        
Common/subordinated/general partner
          432,744  (c)        
                         
      432,744                  
                         
Total liabilities and partners’ capital
  $ 900,407     $     $ 900,407  
                         
 
The accompanying notes are an integral part of these Unaudited Pro Forma Condensed
Combined Financial Statements.


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Table of Contents

 
PAA Natural Gas Storage, L.P.
 
Unaudited Pro Forma Condensed Combined Statement of Operations
Year Ended December 31, 2009
 
                                         
    PNGS LLC
                   
    Historical     Pro Forma
    Pro Forma
    PNGS LP
 
    Successor     Predecessor     Adjustments     Adjustments     Pro Forma  
    September 3,
    January 1,
                Year
 
    2009 to
    2009 to
    PAA
    PNGS, L.P.
    Ended
 
    December 31,
    September 2,
    Ownership
    Formation
    December 31,
 
    2009     2009     Transaction     Transactions     2009  
    (In thousands)  
 
Firm storage services
  $ 23,972     $ 42,649     $     $     $ 66,621  
Hub services
    1,637       2,988                   4,625  
Other
    (358 )     1,292                   934  
                                         
Total revenues
    25,251       46,929                   72,180  
Storage related costs
    7,003       8,792                   15,795  
Operating cost (except those shown below)
    3,257       4,820                   8,077  
Fuel expense
    578       1,816                   2,394  
General and administrative expenses
    4,083       3,562       (1,000 )(d)           8,897  
                      2,252 (d)                
Depreciation, depletion and amortization
    3,578       8,054       (190 )(e)           11,442  
                                         
Total costs and expenses
    18,499       27,044       1,062             46,605  
Operating income
    6,752       19,885       (1,062 )           25,575  
Interest expense
    (4,262 )     (4,352 )           8,614 (f)     (759 )
                              (759 )(f)        
Interest income
          139                   139  
Income tax expense
          (473 )                 (473 )
Gain on interest rate swaps
          336                   336  
Other income (expense)
    (2 )     (17 )                 (19 )
                                         
Net income
  $ 2,488     $ 15,518     $ (1,062 )   $ 7,855     $ 24,799  
                                         
 
The accompanying notes are an integral part of these Unaudited Pro Forma Condensed
Combined Financial Statements.


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PAA Natural Gas Storage, L.P.
 
Notes to the Unaudited Pro Forma Condensed Combined Financial Statements
 
These unaudited pro forma condensed combined financial statements and underlying pro forma adjustments are based upon currently available information and certain estimates and assumptions made by management; therefore, actual results could differ materially from the pro forma information. However, we believe the assumptions provide a reasonable basis for presenting the significant effects of the transactions noted herein. We believe the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma information.
 
The pro forma adjustments reflected herein assume no exercise of the underwriters’ option to purchase additional common units. The proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem from PAA a number of common units corresponding to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts.
 
Upon completion of this offering, we anticipate incurring incremental general and administrative expenses associated with being a publicly traded limited partnership in an annual amount of approximately $2.6 million, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, Sarbanes-Oxley compliance, New York Stock Exchange listing, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs and director compensation. The unaudited pro forma condensed combined financial statements do not reflect these incremental general and administrative expenses.
 
Pro Forma Adjustments
 
(a) Reflects the issuance by PNGS of common units to the public at an assumed initial offering price of $      per common unit (resulting in aggregate gross proceeds of $      million) and the use of the net proceeds of $      million, after issue costs of $      million, to repay related party indebtedness owed to PAA.
 
(b) Reflects expected borrowings by PNGS of $200 million under its new $400 million revolving credit facility to repay $200 million of related party indebtedness owed to PAA.
 
(c) Reflects the contribution by PAA of the equity interests in the entities that own PAA’s gas storage business in exchange for:
 
(i)           common units,
 
(ii)           Series A subordinated units,
 
(iii)           Series B subordinated units, and
 
(iv) a 2.0% general partner interest as well as all of our incentive distribution rights.
 
(d) In conjunction with the PAA Ownership Transaction, the allocation of PAA personnel to PNGS increased due to increased levels of activity of PNGS. This entry reverses the $1.0 million of PAA personnel costs that were allocated to PNGS in the first eight months of 2009 and replaces it with the higher allocation amount to more appropriately reflect the amount that would have been allocated to PNGS if the PAA Ownership Transaction had occurred on January 1, 2009.
 
(e) In conjunction with the PAA Ownership Transaction, the fair value and estimated useful lives of the assets acquired were reassessed. This entry reflects the resulting change in depreciation expense as if the fair value and estimated useful lives were changed effective January 1, 2009.
 
(f) Reflects the reversal of historical interest expense and the recording of pro forma interest expense on the $200 million of borrowing under the new revolving credit facility referenced in (b) above. The pro forma rate on these borrowings is assumed to be 3.5%, which is based on a forecast of LIBOR rates during the period plus the margin expected under our new credit facility, net of capitalized interest.


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Report of Independent Registered Public Accounting Firm
 
To the Members of PAA Natural Gas Storage, LLC:
 
In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, of changes in members’ capital and of cash flows present fairly, in all material respects, the financial position of PAA Natural Gas Storage, LLC and its subsidiaries at December 31, 2009, and the results of their operations and their cash flows for the period of September 3, 2009 to December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
 
Houston, Texas
January 22, 2010
 
/s/ PricewaterhouseCoopers LLP


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Table of Contents

 
Report of Independent Registered Public Accounting Firm
 
To the Members of PAA Natural Gas Storage, LLC:
 
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of changes in members’ capital and of cash flows present fairly, in all material respects, the financial position of PAA Natural Gas Storage, LLC and its subsidiaries at December 31, 2008, and the results of their operations and their cash flows for the period of January 1, 2009 to September 2, 2009, and the years ended December 31, 2008 and 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
Houston, Texas
January 22, 2010
 
/s/ PricewaterhouseCoopers LLP


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Table of Contents

PAA Natural Gas Storage, LLC

Consolidated Balance Sheets
 
                   
    Successor       Predecessor  
    As of
      As of
 
    December 31,
      December 31,
 
    2009       2008  
    (in thousands)  
Assets
                 
Current assets
                 
Cash and cash equivalents
  $ 3,124       $ 32,650  
Restricted cash and cash equivalents
            13,994  
Accounts receivable
    6,439         4,294  
Natural gas imbalance receivables
    400         1,700  
Other current assets
    2,280         1,209  
                   
Total current assets
    12,243         53,847  
                   
Property and equipment
                 
Property and equipment
    816,267         605,582  
Less: Accumulated depreciation, depletion and amortization
    (3,004 )       (13,001 )
                   
Property and equipment, net
    813,263         592,581  
                   
Other assets
                 
Base gas
    27,927         50,116  
Goodwill and intangibles, net
    46,974         105,336  
Deferred financing fees and other assets, net
            9,556  
                   
Total other assets, net
    74,901         165,008  
                   
Total assets
  $ 900,407       $ 811,436  
                   
Liabilities and Members’ Capital
                 
Current liabilities
                 
Accounts payable and accrued liabilities
  $ 14,034       $ 18,980  
Natural gas imbalance payables
    400         1,700  
Accrued income and other taxes
    1,610         1,435  
Current maturities of long-term debt
            2,450  
                   
Total current liabilities
    16,044         24,565  
Third-party long-term debt
            415,263  
Note payable to PAA
    450,523          
Other long-term liabilities
    1,096         8,379  
                   
Total liabilities
    467,663         448,207  
Commitments and contingencies (Note 8)
                 
Total members’ capital
    432,744         363,229  
                   
Total liabilities and members’ capital
  $ 900,407       $ 811,436  
                   
 
The accompanying notes are an integral part of these consolidated financial statements.


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PAA Natural Gas Storage, LLC

Consolidated Statements of Operations
 
                                   
    Successor       Predecessor  
    September 3,
      January 1,
    Year
    Year
 
    2009 to
      2009 to
    Ended
    Ended
 
    December 31,
      September 2,
    December 31,
    December 31,
 
    2009       2009     2008     2007  
    (in thousands)  
Revenues
                                 
Firm storage services
  $ 23,972       $ 42,649     $ 42,871     $ 31,357  
Hub services
    1,637         2,988       1,417       4,802  
Other
    (358 )       1,292       4,889       786  
                                   
Total revenues
    25,251         46,929       49,177       36,945  
                                   
Costs and expenses
                                 
Storage related costs
    7,003         8,792       8,934       3,847  
Operating costs (except those shown below)
    3,257         4,820       4,059       3,947  
Fuel expense
    578         1,816       2,320       1,140  
General and administrative expenses
    4,083         3,562       3,874       3,755  
Depreciation, depletion and amortization
    3,578         8,054       6,245       4,520  
                                   
Total costs and expenses
    18,499         27,044       25,432       17,209  
                                   
Operating income
    6,752         19,885       23,745       19,736  
Other income (expense)
                                 
Interest expense
    (4,262 )       (4,352 )     (4,941 )     (7,108 )
Interest income
            139       1,147       4,011  
Income tax expense
            (473 )     (887 )      
Gain on interest rate swaps
            336       548       524  
Other income (expense)
    (2 )       (17 )     (26 )     843  
                                   
Net income
  $ 2,488       $ 15,518     $ 19,586     $ 18,006  
                                   
Other comprehensive income (loss)
            1,990       (11,074 )     (5,998 )
                                   
Comprehensive income
  $ 2,488       $ 17,508     $ 8,512     $ 12,008  
                                   
 
The accompanying notes are an integral part of these consolidated financial statements.


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PAA Natural Gas Storage, LLC

Consolidated Statements of Changes in Members’ Capital
 
         
    Total
 
    Members’
 
    Capital  
    (in thousands)  
 
Predecessor:
       
Balance at December 31, 2006
  $ 264,109  
Contributions from members
    18,600  
Net income
    18,006  
Other comprehensive loss
    (5,998 )
         
Balance at December 31, 2007
  $ 294,717  
         
Contributions from members
    74,500  
Distributions to members
    (14,500 )
Net income
    19,586  
Other comprehensive loss
    (11,074 )
         
Balance at December 31, 2008
  $ 363,229  
         
Contributions from members
    8,500  
Distributions to members
    (8,500 )
Net income
    15,518  
Other comprehensive income
    1,990  
         
Balance at September 2, 2009
  $ 380,738  
         
 
         
    Total
 
    Members’
 
    Capital  
    (in thousands)  
 
Successor:
       
Balance at September 2, 2009 (Predecessor)
  $ 380,738  
Net income
    2,488  
Net effect of pushdown accounting (see Note 1)
    49,518  
         
Balance at December 31, 2009 (Successor)
  $ 432,744  
         
 
The accompanying notes are an integral part of these consolidated financial statements.


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PAA Natural Gas Storage, LLC

Consolidated Statements of Cash Flows
 
                                   
    Successor       Predecessor  
    September 3,
      January 1,
    Year
    Year
 
    2009 to
      2009 to
    Ended
    Ended
 
    December 31,
      September 2,
    December 31,
    December 31,
 
    2009       2009     2008     2007  
    (in thousands)  
Cash flows from operating activities
                                 
Net income
  $ 2,488       $ 15,518     $ 19,586     $ 18,006  
Adjustments to reconcile to cash flow from operations
                                 
Depreciation, depletion and amortization
    3,578         8,054       6,245       4,520  
Gain on interest rate swaps
                  (548 )     (524 )
Non-cash interest on borrowing from parent
    4,262                      
Change in assets and liabilities
                                 
Accounts receivable and other assets
    (480 )       (2,166 )     (5,097 )     1,540  
Accounts payable and accrued liabilities
    5,417         1,197       1,632       (1,199 )
                                   
Net cash provided by operating activities
    15,265         22,603       21,818       22,343  
                                   
Cash flows from investing activities
                                 
Additions to property and equipment
    (19,301 )       (47,542 )     (111,697 )     (199,071 )
Cash paid for acquisitions
                        (12,392 )
Cash paid for base gas
    (4,366 )       (11,193 )     (12,913 )     (445 )
Decrease (increase) in restricted cash and cash equivalents
    14,000         (6 )     5,090       34,325  
Proceeds from sale of assets
    11         180       630       303  
                                   
Net cash used in investing activities
    (9,656 )       (58,561 )     (118,890 )     (177,280 )
                                   
Cash flows from financing activities
                                 
Proceeds from term loan agreement
                        110,000  
Repayments on term loan agreement
    (25,213 )       (1,225 )     (2,450 )     (1,837 )
Borrowings on revolving credit facility, net
            29,500       65,000       19,700  
Borrowing from parent
    2,400                      
Costs incurred in connection with financing arrangements
            (4,639 )     (206 )     (720 )
Contributions from members
            8,500       74,500       18,600  
Distributions to members
            (8,500 )     (14,500 )      
                                   
Net cash (used in) provided by financing activities
    (22,813 )       23,636       122,344       145,743  
                                   
Net increase/(decrease) in cash and cash equivalents
    (17,204 )       (12,322 )     25,272       (9,194 )
Cash and cash equivalents
                                 
Beginning of period
    20,328         32,650       7,378       16,572  
                                   
End of period
  $ 3,124       $ 20,328     $ 32,650     $ 7,378  
                                   
Cash paid for interest, net of amounts capitalized
  $       $ 2,298     $ 5,197     $ 7,324  
                                   
Change in noncash asset purchases included in accounts payable
  $ 1,008       $ 1,534     $ (6,582 )   $ (6,999 )
                                   
Cash paid for income taxes
  $       $ 795     $ 290     $ —   
                                   
 
The accompanying notes are an integral part of these consolidated financial statements.


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PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements
 
1.   Organization, Nature of Operations and Basis of Presentation
 
Organization and Nature of Operations
 
PAA Natural Gas Storage, LLC, a limited liability company, is a fee based, growth-oriented company engaged in the acquisition, development, operation and commercial management of natural gas storage facilities. We currently own and operate two natural gas storage facilities located in Louisiana and Michigan.
 
Our Pine Prairie facility is a recently constructed, high-deliverability salt cavern natural gas storage complex located in Evangeline Parish, Louisiana. As of December 31, 2009, Pine Prairie had a total working gas storage capacity of 14 Bcf in two caverns. Our Bluewater facility is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. As of December 31, 2009, Bluewater had a total working gas storage capacity of approximately 26 Bcf in two depleted reservoirs.
 
As used in this document, the terms “we,” “us,” “our” and similar terms refer to PAA Natural Gas Storage, LLC and its subsidiaries (“PNGS”), unless the context indicates otherwise.
 
Basis of Consolidation and Presentation
 
On September 3, 2009 Plains All American Pipeline, L.P. (“PAA”) became our sole owner by acquiring Vulcan Capital’s 50% interest in us (“PAA Ownership Transaction”) for an aggregate purchase price of $215 million). Although PNGS continued as the same legal entity after the PAA Ownership Transaction, all of our assets and liabilities were adjusted to fair value at the time of the transaction under push down accounting. This change in value resulted in a new cost basis for accounting for PNGS. The changes in carrying value can be summarized as follows:
 
         
PP&E, net
  $ 153,800  
Base gas
    (38,338 )
Goodwill (see Note 2)
    (61,515 )
Other long term assets
    (4,429 )
         
    $ 49,518  
         
 
Accordingly, the accompanying consolidated financial statements are presented for Predecessor and Successor periods, which relate to the accounting periods preceding and succeeding the PAA Ownership Transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods was prepared under two different cost bases of accounting. The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2009 and December 31, 2008, and the consolidated results of our operations, cash flows and changes in member’s capital for the periods ended December 31, 2009, September 2, 2009, December 31, 2008 and December 31, 2007. The accompanying consolidated financial statements include the accounts of PNGS and its subsidiaries, all of which are wholly-owned. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the previous years to conform to the 2009 presentation. These reclassifications do not affect net income.
 
Subsequent events have been evaluated through the financial statements issuance date of January 22, 2010 and have been included within the following footnotes where applicable.
 
2.   Summary of Significant Accounting Policies
 
Use of Estimates
 
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amount of assets and liabilities and the


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Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to: (i) mark-to-market estimates of derivative instruments, (ii) accruals and contingent liabilities, (iii) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iv) accruals related to incentive compensation, (v) valuation and recoverability of long-lived assets including property and equipment and goodwill and (vi) depreciation and depletion expense. Although we believe these estimates are reasonable, actual results could differ from these estimates.
 
Revenue Recognition
 
We provide various types of natural gas storage services to customers. Revenues from these activities are classified as firm storage services or hub services.
 
Firm storage services consist of:
 
(i) firm storage reservation fees — fixed monthly capacity reservation fees which are owed to us regardless of the actual storage capacity utilized by the customer. These fees are recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized; this also includes seasonal “park and loan” services, pursuant to which a customer will pay fees for the “firm” right to store gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.
 
(ii) firm storage cycling fees and fuel-in-kind — fees for the use of injection and withdrawal services based on the volume of natural gas nominated for injection and/or withdrawal; these fees are recognized in revenue in the period the volumes are nominated. We retain a small portion of the natural gas nominated for injection as compensation for our fuel use; the fuel-in-kind is reflected as revenue when received and in operating expense in the period the fuel is used in operations. Any excess fuel collected is carried as inventory at average cost.
 
Hub services consist of:
 
(i) fees from (i) “interruptible” storage services pursuant to which customers receive only limited assurances regarding the availability of capacity in our storage facilities and pay fees based on their actual utilization of our assets, (ii) non-seasonal “park and loan” services and (iii) “wheeling and balancing” services pursuant to which customers pay fees for the right to move a volume of gas through our facilities from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from, our facilities. We may also retain a small portion of natural gas nominated for injection as compensation for our fuel use. These fees are recognized in revenue in the month that the services are provided.
 
Other revenue includes revenues from the sale of crude oil and liquids produced in conjunction with the operation of our Bluewater facility, net of royalties and taxes. Additionally, we periodically sell any fuel-in-kind volumes in excess of actual volumes needed as fuel for our facilities. Such revenue is recognized at the time title to the product sold transfers to the purchaser or its designee. Other revenue also includes unrealized and realized gains and losses associated with certain commodity derivatives which we have entered into which have not been eligible for hedge accounting.
 
Storage Related Costs
 
Storage related costs consist of: (i) fees incurred to lease third party storage capacity and pipeline transportation capacity; and (ii) costs associated with certain loan services (see “Base Gas”). These costs are incurred to increase our operational flexibility and enhance the services we offer our customers.


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Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
Cash, Restricted Cash and Cash Equivalents
 
Cash, restricted cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. Restricted cash consisted of cash that was restricted in accordance with the terms of our Pine Prairie revolving credit facility and term loan agreement which were terminated in conjunction with the PAA Ownership Transaction. At December 31, 2009 and December 31, 2008, the cash, restricted cash and cash equivalents are concentrated in two financial institutions and at times may exceed federally insured limits. We periodically assess the financial condition of the financial institutions and believe that our credit risk is minimal. As of December 31, 2009 and December 31, 2008, accounts payable included approximately $1.0 million and $0.9 million, respectively, of outstanding checks that were reclassed from cash and cash equivalents to accounts payable and accrued liabilities.
 
Accounts Receivable and Allowance for Doubtful Accounts
 
Our accounts receivable are from a broad mix of customers, including local gas distribution companies, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities. We have a rigorous credit review process and closely monitor the potential credit risks associated with these counterparties in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit or “parental” guarantees.
 
We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of an outstanding receivable balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method. As of December 31, 2009 and December 31, 2008, substantially all of our accounts receivable were current and we had no allowance for doubtful accounts. At December 31, 2009 and 2008, we had an income tax refund receivable of approximately $1.1 million and $0.1 million, respectively, included in Other Current Assets on our balance sheet. We have not had any material accounts receivable write-offs since our inception.
 
Goodwill and Other Intangible Assets
 
Our goodwill and other intangible assets balances at December 31, 2009 and December 31, 2008 consisted of the following (in thousands):
 
                   
    Successor       Predecessor  
    December 31,
      December 31,
 
    2009       2008  
Goodwill
  $ 24,549       $ 86,064  
Intangible assets
    23,000         21,075  
                   
Goodwill and intangibles
    47,549         107,139  
Accumulated amortization
    (575 )       (1,803 )
                   
Goodwill and intangibles, net
  $ 46,974       $ 105,336  
                   
 
We test goodwill at least annually and on an interim basis if a triggering event occurs to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by management. Our reporting units are our operating segments. Our operating segments are our Bluewater facility and our Pine Prairie facility (see Note 10). It is a two step process to test goodwill for impairment. In Step 1, we compare the fair value of the reporting unit with the respective book values, including goodwill. When the fair value is greater than book


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Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then we proceed to Step 2. In Step 2, we compare the implied fair value of the reporting unit’s goodwill with the book value. A goodwill impairment loss is recognized if the carrying amount exceeds its fair value. In conjunction with the PAA Ownership Transaction, we revalued all of our assets and liabilities to fair value, resulting in a new Successor goodwill balance of $24.5 million at December 31, 2009. On a go forward basis, we will test goodwill at least annually on June 30 of each year to determine if an impairment has occurred. No impairments have occurred since our inception.
 
The table below reflects our changes in goodwill for the periods ended December 31, 2009 and December 31, 2008 (in thousands):
 
         
Predecessor
       
Balance at December 31, 2007
  $ 86,064  
         
Balance at December 31, 2008
  $ 86,064  
         
Balance at September 2, 2009
  $ 86,064  
         
Successor
       
Elimination of predecessor goodwill
    (86,064 )
Goodwill pushed down from PAA Ownership Transaction
    24,549  
         
Change in goodwill
    (61,515 )
         
Balance at December 31, 2009
  $ 24,549  
         
 
We amortize finite lived intangible assets over our best estimate of their useful life and in the periods that we estimate that the economic benefits of the intangible assets are consumed. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. Intangible assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The intangible costs are amortized on a straight-line basis. In conjunction with the PAA Ownership Transaction, we revalued all of our assets and liabilities to fair value.
 
Our intangible assets consisted of the following (in thousands):
 
                       
    Successor       Predecessor  
    Lives(1)
  December 31,
      December 31,
 
    (In Years)   2009       2008  
Customer contracts and relationships(2)
  n/a   $       $ 9,029  
NPI acquisition(2)
  n/a             12,046  
Property tax abatement
  13     23,000          
                       
Total intangible assets
        23,000         21,075  
Less: Accumulated amortization
        (575 )       (1,803 )
                       
Total intangible assets, net of amortization
      $ 22,425       $ 19,272  
                       
 
 
(1) At the point of revaluing our assets to fair value, we also reassessed the estimated useful lives used for amortization purposes and revised them accordingly.
 
(2) The change in values are the result of fair value adjustments under push down accounting.


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Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
 
Amortization expense related to our intangible assets was $0.6 million, $1.6 million, $1.1 million and $0.6 million for the periods ended December 31, 2009, September 2, 2009, December 31, 2008 and December 31, 2007, respectively. We estimate that our amortization expense related to our finite lived intangible assets for the next five years will be as follows (in thousands):
 
         
Calendar Year
  Expense
 
2010
  $ 1,725  
2011
    1,725  
2012
    1,725  
2013
    1,725  
2014
    1,725  
 
Other Assets, net
 
Other assets, net of accumulated amortization at December 31, 2009 and December 31, 2008 consisted of the following (in thousands):
 
                   
    Successor       Predecessor  
    December 31,
      December 31,
 
    2009       2008  
Debt issue costs(1)
  $       $ 9,577  
School bond retirement, in lieu of property tax(2)
            3,240  
Other
            1,014  
                   
Other assets
            13,831  
Accumulated amortization
            (4,275 )
                   
Other assets, net
  $       $ 9,556  
                   
 
 
(1) Costs incurred in connection with the issuance of the long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. The remaining balance of debt issues costs were eliminated in conjunction with the repayment of the debt on September 2, 2009.
 
(2) Effective with the PAA Ownership Transaction, the school bond retirement and tax abatement agreement were recorded at fair value in intangibles.
 
Amortization expense related to other assets was $0.0 million, $0.5 million, $0.3 million and $0.3 million for the periods ended December 31, 2009, September 2, 2009, December 31, 2008 and December 31, 2007, respectively.
 
Asset Retirement Obligations
 
Financial Accounting Standards Board (“FASB”) guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.
 
Some of our assets have contractual or regulatory obligations to perform remediation when the assets are abandoned. These assets, with regular maintenance, will continue to be in service for many years to come. It is not possible to predict when demands for our services will cease and we do not believe that such demand


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Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligation. We will record an asset retirement obligation in the period in which sufficient information becomes available for us to reasonably determine the settlement date.
 
Impairment of Long-Lived Assets
 
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance over the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.
 
We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to:
 
  •  Whether there is an indication of impairment;
 
  •  The grouping of assets;
 
  •  The intention of “holding” versus “selling” an asset;
 
  •  The forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
 
  •  If an impairment exists, the fair value of the asset or asset group.
 
There were no impairments in the 2009, 2008 and 2007 periods.
 
Property and Equipment
 
In accordance with our capitalization policy, costs associated with acquisitions and improvements that expand our existing capacity, including related interest costs, are capitalized. In addition, we capitalize expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production, and/or functionality of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day-to-day operation of our existing assets are charged to expense as incurred.
 
In conjunction with the development of our Pine Prairie facility, we capitalize direct and certain indirect costs, such as related interest costs associated with the development and construction project. For the periods ended December 31, 2009, September 2, 2009 and December 31, 2008, Pine Prairie capitalized interest was $5.4 million, $10.2 million and $19.0 million, respectively.


F-17


Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
Property and equipment, net is stated at cost and consisted of the following (in thousands):
 
                               
      Successor       Predecessor  
      Lives(1)
      December 31,
      December 31,
 
      (In Years)       2009       2008  
Natural gas storage facilities and equipment
      50 to 70       $ 539,870       $ 253,027  
Office property, equipment and other
      3 to 5         48         479  
Oil and gas properties
      n/a         1,986         4,811  
Land
      n/a         8,288         1,147  
Construction work in progress
      n/a         266,075         346,118  
                               
                  816,267         605,582  
Less: Accumulated depreciation and depletion
                (3,004 )       (13,001 )
                               
Property and equipment, net
              $ 813,263       $ 592,581  
                               
 
 
(1) At the point of revaluing our assets to fair value, we also reassessed the estimated useful lives used for depreciation purposes and revised them accordingly.
 
Depreciation and depletion expense related to our property and equipment for the periods ended December 31, 2009, September 3, 2009, December 2008 and December 31, 2007 was $3.0 million, $6.0 million, $4.8 million and $3.6 million, respectively.
 
Although our Bluewater facility includes certain oil and gas producing properties, the production of oil and gas is not our main line of business and thus, we view these assets as ancillary to our existing operations. The terms of our agreement with the former owners of Bluewater requires us to produce these crude oil proved reserves subject to certain conditions. We have capitalized our costs to acquire such properties, which are estimated to contain approximately 300,000 barrels of proved reserves. Such costs are depreciated and depleted by the unit of production method.
 
The Pine Prairie facility is being managed, developed and constructed as one project. We will place assets into service in several phases and begin depreciation of these assets and an applicable portion of the other related assets when they are complete and ready for their intended use.
 
We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.
 
At December 31, 2009 and 2008, the property and equipment balance includes approximately $6.4 million and $4.0 million, respectively, of accrued costs. Such amounts are reflected as a component of accounts payable and accrued liabilities in our consolidated balance sheets.
 
Base Gas
 
Base gas volumes at December 31, 2009 consisted of 9.2 Bcf of natural gas in the storage facilities, which is necessary to operate the facilities. Approximately 7.0 Bcf is recorded at fair value as of September 2, 2009 due to the PAA Ownership Transaction with the remainder representing native natural gas within a depleted reservoir that is ascribed zero value due to uncertainty regarding our ability to ultimately recover


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Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
such gas. All future purchases will be carried at historical cost. The level of necessary base gas fluctuates based on the utilization of the caverns and reservoirs. At times, dependent on market conditions and utilization of the facilities, base gas may be loaned to customers. We classify amounts outstanding under base gas loans as a component of base gas in the accompanying consolidated financial statements. This gas will continue to be utilized as base gas, a long-term asset, upon settlement of the loan. As of December 31, 2009, we had outstanding loan agreements totaling approximately 5.6 Bcf of natural gas. We expect the natural gas to be returned to us in the first quarter of 2010 in accordance with the terms of the agreements.
 
Gas Imbalances
 
We value gas imbalances due to or from interconnecting pipelines at market price as of the balance sheet date. Gas imbalances represent the difference between customer nominations and actual gas receipts from and gas deliveries to our interconnecting pipelines under various operational balancing agreements. As the settlements of imbalances are in-kind, changes in the balances do not have an impact on our earnings or cash flows.
 
Derivative Instruments and Hedging Activities
 
From time to time, we may utilize derivative instruments to manage our exposure to interest rates, future purchases of base gas and to economically hedge the intrinsic value of our natural gas storage facilities. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. FASB guidance requires that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met, in which case, the effective portion of changes in the fair value of cash flow hedges are deferred in other comprehensive income and reclassed into earnings when the underlying transaction affects earnings.
 
Commodity Derivatives.  In the fourth quarter of 2009, we entered into a natural gas calendar spread position consisting of NYMEX futures with a notional volume of approximately 3 Bcf. This derivative is not eligible for hedge accounting. We recognized a current liability of approximately $0.4 million within accounts payable and accrued liabilities on our consolidated balance sheet as of December 31, 2009 and recognized an offsetting $0.4 million mark-to-market loss within other revenue during the period ended December 31, 2009. We consider NYMEX natural gas futures contracts to be a level 1 item within the fair value hierarchy.
 
During the year ended December 31, 2008, we entered into and settled a natural gas storage related futures position with a notional volume of approximately 4 Bcf. This derivative instrument was not eligible for hedge accounting. Upon settlement of this transaction, we recognized a gain of approximately $1.1 million which is reflected as a component of other revenues during the year ended December 31, 2008.
 
Interest Rate Swap Agreements.  Our Predecessor had previously entered into a series of interest rate swap agreements which were designated as cash flow hedges. These interest rate swaps were utilized to mitigate exposure to changes in cash flows associated with variable rate interest payments on certain debt obligations. As of December 31, 2008, the fair market value of the interest rate swap agreements was a liability of approximately $17.8 million, of which approximately $9.7 million was included in other current liabilities in our consolidated financial statements with the balance being included in other long-term liabilities. The effective portion of the change in the fair value of these interest rate swap agreements is reflected as other comprehensive income (loss) in our consolidated financial statements. During each of the periods presented, we had no other components of other comprehensive income (loss). As of December 31, 2008, we had accumulated other comprehensive loss of approximately $17.1 million associated with these


F-19


Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
interest rate swap agreements which is reflected within members’ capital in the accompanying consolidated balance sheet. The ineffectiveness on these interest rate swap agreements was recognized as a gain on interest rate swaps in our consolidated financial statements. In conjunction with the PAA Ownership Transaction, all of the associated debt obligations were settled and all of these interest rate swap agreements were terminated. PAA paid approximately $17.6 million to settle these interest rate swap agreements, which included approximately $2.1 million associated with the net settlement due through the termination date. Such amount paid by PAA was included in the initial principal amount of our related party note payable to PAA as discussed in Note 7. Subsequent to the PAA Ownership Transaction, we have not entered into any additional interest rate swap agreements.
 
Among other things, ASC 820 “Fair Value Measurements and Disclosures” requires enhanced disclosures about assets and liabilities carried at fair value. As defined in ASC 820, fair value is the price that would be received from selling an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).
 
Our interest rate swap agreements which were outstanding during the predecessor period were classified as Level 3 liabilities.
 
The determination of the fair values incorporates various factors required under ASC 820. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements, but also the impact of nonperformance risk on our liabilities. Our interest rate swap agreements were designated as a Level 3 measurement in the fair value hierarchy as the broker or dealer price quotations used to measure the fair value and the pricing services used to corroborate the quotations are indicative quotations rather than quotations whereby the broker or dealer is ready and willing to transact. However, the fair value of these Level 3 derivatives are not based on significant management assumptions or subjective inputs.
 
The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our interest rate swap agreements which were classified as Level 3 measurements in the fair value hierarchy (in thousands of dollars) since our adoption of the applicable provisions of ASC 820 on January 1, 2008:
 
         
    Predecessor  
 
Beginning liability balance, January 1, 2008
  $ (7,265 )
Unrealized gains and (losses)
       
Included in earnings
    548  
Included in other comprehensive income(1)
    (14,224 )
Settlements(2)
    3,150  
         
Ending balance, December 31, 2008
  $ (17,791 )
Unrealized gains and (losses)
       
Included in earnings
    336  
Included in other comprehensive income(1)
    (4,628 )
Settlements(2)
    6,618  
         
Ending liability balance, September 2, 2009
  $ (15,465 )
         
 
 
(1) Reflects changes in accumulated other comprehensive income due changes in fair value.
 
(2) Reflects amounts reclassified out of accumulated other comprehensive income to interest expense concurrent with the interest expense accruals associated with the underlying hedged debt.


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Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
 
Income and Other Taxes
 
No provision for U.S. federal income taxes related to our operations is included in the accompanying consolidated financial statements as we are treated as a partnership not subject to federal income tax and the tax effect of our activities accrues to our members. Income tax expense shown on our income statement is related to Michigan state income tax. As a result of PAA obtaining control over us in conjunction with the PAA Ownership Transaction, we are considered part of a unitary group with PAA for purposes of Michigan state tax reporting. For the period from September 3, 2009 to December 31, 2009, our income tax provision reflects our allocated share of PAA’s consolidated Michigan tax obligation. Such amount was not material for the period. Other current assets as of December 31, 2009 includes a $1.1 million receivable associated with overpayments in 2008 and 2009. At December 31, 2009 and 2008, we have no material assets, liabilities or accrued interest associated with uncertain tax positions.
 
Environmental Matters
 
We record environmental liabilities when environmental assessments and/or remediation efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with the completion of a feasibility study or our commitment to a formal plan of action. Management is not aware of any association with any known material environmental liabilities as of December 31, 2009.
 
Recent Accounting Pronouncements
 
Standards Adopted as of January 1, 2010
 
In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance that requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest(s) provide a controlling financial interest in a variable interest entity (“VIE”). This analysis identifies the primary beneficiary of a VIE as the enterprise that has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could potentially be significant to the VIE. This guidance also (i) requires such assessments to be ongoing, (ii) amends certain guidance for determining whether an entity is a VIE and (iii) enhances disclosures that will provide users of financial statements with more transparent information regarding an enterprise’s involvement in a VIE. We adopted this guidance as of January 1, 2010 and are currently evaluating the impact of adoption on our consolidated financial statements.
 
In June 2009, the FASB issued guidance regarding accounting for transfers of financial assets. The guidance removes the concept of a qualified special purpose entity (QSPE), which will result in securitization and other asset-backed financing vehicles to be evaluated for consolidation in accordance with guidance for VIEs. This guidance also (i) expands legal isolation analysis, (ii) limits when a portion of a financial asset can be derecognized and (iii) clarifies that an entity must consider all arrangements or agreements made contemporaneously with, or in contemplation of, a transfer when applying the derecognition criteria. We adopted this guidance as of January 1, 2010; however, we currently do not maintain any QSPEs and as such, such adoption is not expected to have a material impact on our consolidated financial statements.
 
Standards Adopted as of July 1, 2009
 
In June 2009, the FASB issued the FASB Accounting Standards Codification (the “Codification”) to establish a single source of authoritative nongovernmental U.S. generally accepted accounting principles (“U.S. GAAP”). The Codification is meant to (i) simplify user access by codifying all authoritative U.S. GAAP into one location, (ii) ensure that codified content accurately represents authoritative U.S. GAAP and (iii) create a better structure and research system for U.S. GAAP. The Codification was effective for interim or annual


F-21


Table of Contents

 
PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
periods ending after September 15, 2009; therefore, we adopted this guidance as of July 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.
 
Standards Adopted as of April 1, 2009
 
In May 2009, the FASB issued guidance that establishes general standards of accounting for and disclosure of subsequent events for events that occur after the balance sheet date but before financial statements are issued. This guidance sets forth (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. This guidance was effective for interim or annual periods ending after June 15, 2009; therefore, we adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.
 
In April 2009, the FASB issued guidance that increases the frequency of fair value disclosures from annual to quarterly in an effort to provide financial statement users with more timely and transparent information about the effects of current market conditions on financial instruments. This is intended to address concerns raised by some financial statement users about the lack of comparability resulting from the use of different measurement attributes for financial instruments. These disclosures are also intended to stimulate more robust discussions about financial instrument valuations between users and reporting entities. We adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.
 
Standards Adopted as of January 1, 2009
 
In April 2008, the FASB issued guidance that amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previous guidance over goodwill and other intangible assets. The intent of this guidance is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset under generally accepted accounting principles. We adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.
 
In March 2008, the FASB issued guidance that amends previous guidance regarding the disclosures about derivative instruments and hedging activities. This guidance requires enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under the guidance, and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of this guidance were effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted this guidance as of January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.
 
In December 2007, the FASB issued further guidance regarding accounting for business combinations. This guidance establishes principles and requirements for how an acquirer: (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The provisions of this guidance were effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted this guidance as of January 1, 2009. Adoption has impacted our accounting for acquisitions subsequent to that date.


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PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
 
3.   Acquisitions and Dispositions
 
During 2009 and 2008, we sold various property and equipment for proceeds totaling approximately $0.2 million and $0.6 million, respectively. Losses recognized related to these dispositions were immaterial.
 
4.   Members’ Capital
 
We are required under our limited liability company agreement to distribute 100% of our available cash to our members in proportion to their relative ownership interest within 45 days after the end of each quarter. Available cash is generally defined as all cash and cash equivalents on hand at the end of the quarter less reserves established by the managing member for future requirements.
 
5.   Related Party Transactions
 
We do not directly employ any persons to manage or operate our business. These functions are provided by employees of Plains All American GP LLC (“GP LLC”), the general partner of Plains AAP, L.P. which is the sole member of PAA GP LLC, PAA’s general partner. References to PAA, unless the context otherwise requires, include GP LLC. We reimburse PAA for all direct and indirect expenses it incurs or payments in makes on our behalf and all other expenses allocable to us or otherwise incurred by PAA in connection with the operation of our business. These expenses are recorded in general and administrative expenses on our income statement and include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf. We record these costs on the accrual basis in the period in which PAA’s general partner incurs them. Our agreement with PAA provides that PAA will determine the expenses allocable to us in any reasonable manner determined by PAA in its sole discretion. The amount of the allocation increased after the PAA Ownership Transaction, as prior to September 2, 2009, the joint venture agreement with Vulcan Capital did not permit PAA to charge us for executive officer expenses. Instead, such items were compensated under a contingent management fee arrangement that was subject to achievement of performance benchmarks not considered probable. Such contingent management fee was addressed by the negotiation with Vulcan Capital and reflected in the total valuation. Total costs reimbursed by us to PAA for the periods ended December 31, 2009, September 2, 2009 and December 31, 2008, were approximately $3.7 million, $7.9 million and $9.3 million, respectively. Of these amounts $1.1 million, $1.0 million, and $1.0 million, respectively, were allocated personnel costs for shared services and the remainder consisted of direct costs that PAA paid on our behalf. PAA, in conjunction with input from our general partner, estimates the percentage of time that each shared service department spends on items related to our operations and allocates this percentage of their personnel costs to us. Due to our general partner’s close involvement in this process, we believe that the method used is reasonable. As of December 31, 2009 and December 31, 2008, we had a liability to PAA of approximately $1.8 million and $0.8 million, respectively, included in accounts payable and accrued liabilities on the consolidated balance sheet.
 
6.   Equity Compensation
 
Equity compensation expense for PAA employees that are directly involved in providing services to PNGS is pushed down from PAA to PNGS and is carried as an equity compensation liability on our balance sheet. The fair value of these awards, which are subject to liability classification, is calculated based on the closing price of PAA’s units at each balance sheet date adjusted for (i) the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients and (ii) an estimated forfeiture rate when appropriate. This fair value is recognized as compensation expense over the period the awards are earned. The awards typically contain performance conditions based on attainment of certain annualized PAA distribution levels or the attainment of specific PNGS EBITDA levels and vest upon the later of a certain date or the attainment of such levels. For awards with performance conditions, we recognize compensation expense only if the achievement of the performance


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PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
condition is considered probable and amortize that expense over the service period. When awards with performance conditions that were not previously considered probable of occurring become probable of occurring, we incur additional equity compensation expense necessary to adjust the life-to-date accrued liability associated with these awards.
 
At December 31, 2009, we have the following equity compensation awards outstanding (units in thousands):
 
                                         
Equity
                             
Compensation
        Estimated Vesting Date(1)
 
Units
        (# of units)  
Granted
   
Performance Condition Required for Vesting
  2010     2011     2012     2013  
 
  124     PAA annualized distributions of between $3.00 and $4.35     27       4       26       67  
  37     PNGS EBITDA targets     18       13       6        
                                         
  161           45       17       32       67  
                                         
 
 
(1) Awards are presented above assuming the performance conditions are attained, that all grantees remain employed with us, and that the awards will vest on the earliest date possible regardless of our current assessment of probability.
 
The expense and liability for the applicable periods was as follows (in thousands):
 
                                     
      Successor     Predecessor
      September 3,
    January 1,
       
      2009 through
    2009 through
  Year Ended
      December 31,
    September 2,
  December 31,
      2009     2009   2008   2007
Current liability
    $ 745               $ 188     $ 97  
Long-term liability
    $ 1,096               $ 265     $ 573  
Expense (income)(1)
    $ 1,467       $ 304     $ (110 )   $ 553  
 
 
(1) Substantially all of this amount is reflected general and administrative expense in the consolidated income statement.
 
Our accrual at December 31, 2009 includes an accrual associated with our assessment that PAA’s annualized distribution of $3.90 is probable of occurring at this time. We have not deemed a distribution of more than $3.90 to be probable.
 
We estimate that the remaining fair value of the outstanding awards will be recognized in expense as shown below (in thousands):
 
         
Calendar Year
  Expense(1)  
 
2010
  $ 980  
2011
    337  
2012
    224  
2013
    124  
2014
    11  
Beyond
    13  
         
Total
  $ 1,689  
         
 
 
(1) Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2009.


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PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
 
7.   Debt
 
In conjunction with the PAA Ownership Transaction, all third party debt was terminated and replaced with a related party note payable to PAA (“PAA Note”). In conjunction with PAA’s termination of our third party debt, PAA paid approximately $2.6 million in accrued unpaid interest at the time of termination. Such amount paid by PAA was included in the initial principal amount of our related party note payable to PAA. The PAA Note is a demand note and accrues interest at a fixed rate of 6.5%. PAA has issued a waiver stating that it will not demand payment during the year ended December 31, 2010. The interest on the note is paid in-kind and added to the principal amount of the note. To the extent necessary, we have the ability to incur additional borrowings under the note.
 
Long-term debt consisted of the following (in thousands):
 
                   
    Successor       Predecessor  
    December 31,
      December 31,
 
    2009       2008  
Short-term
                 
Term loan
  $       $ 2,450  
                   
Total short-term debt
            2,450  
Long-term
                 
Revolving credit facility
            112,000  
Term loan
            303,263  
Note payable to PAA
    450,523          
                   
Total long-term debt
    450,523         415,263  
                   
Total debt
  $ 450,523       $ 417,713  
                   
 
8.   Commitments and Contingencies
 
From time to time, we lease third party storage and pipeline capacity in order to increase our operational flexibility and enhance the services we offer our customers. As of December 31, 2009, we had 3 Bcf of storage capacity under lease from third parties and had secured the right to 379 MMcf per day of firm transportation service on various pipelines. In addition, we may enter into contracts related to construction costs associated with certain of our capital projects. Future, non-cancellable commitments related to these items at December 31, 2009, are summarized below (in thousands):
 
                                                         
    Total     2010     2011     2012     2013     2014     Thereafter  
 
Leases — storage, transportation, other
  $ 51,118     $ 16,103     $ 11,822     $ 10,522     $ 6,228     $ 4,448     $ 1,995  
Purchase obligations
    41,718       23,512       1,556       1,800       1,800       1,800       11,250  
                                                         
Total
  $ 92,836     $ 39,615     $ 13,378     $ 12,322     $ 8,028     $ 6,248     $ 13,245  
                                                         
 
We may experience releases of crude oil, natural gas, brine or other contaminants into the environment, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may affect our business. As of December 31, 2009, we have not identified any material environmental obligations.
 
Other.  A natural gas storage facility, associated pipeline header system, and gas handling and compression facilities may experience damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to and destruction of property, base gas, and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in


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PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating natural gas storage facility, associated pipeline header system, and gas handling and compression facilities, including the potential loss of significant revenues. The overall trend in the environmental insurance industry appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the environmental insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our environmental activities or incorporate higher retention in our insurance arrangements.
 
The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, although we believe that we have established adequate reserves to the extent that such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.
 
Pine Prairie Project Sale and Lease
 
In May 2006, in order to receive a substantial tax exemption with respect to a portion of the Pine Prairie facility located in Evangeline Parish, Louisiana, we sold a portion of the facility located in the parish to the Industrial Development Board No. 1 of the Parish of Evangeline State of Louisiana, Inc. (the “Industrial Development Board”) and leased back the property. Simultaneously with the execution of the lease, the Industrial Development Board issued and sold $50 million in bonds to us. Our rental obligations under the lease consist of an amount equal to the annual interest payment due from the Industrial Development Board on the bonds and the amount (if any) required for repayment in full of the outstanding indebtedness with respect to the bonds at the end of the lease term. Additionally, we are required to pay an annual $15,000 administrative fee to the Industrial Development Board, as well as reasonable fees, expenses and charges of the trustee in connection with the bonds.
 
The lease has a 15-year term, which commenced in January 2008, and is terminable by us upon payment to the Industrial Development Board of the amount required for repayment in full of its outstanding indebtedness under the bonds. We also have an option to purchase the leased properties at any time during the lease term for the sum of $5,000 plus the amount required for the repayment in full of any outstanding indebtedness under the bonds.
 
We will not be subject to ad valorem property tax in the Parish of Evangeline for the property included in this arrangement during the term of the lease except for ad valorem tax on inventory. We will be required to make certain payments in lieu of ad valorem property taxes beginning in 2010, calculated as the difference between $500,000 and a three year average of ad valorem inventory tax revenues applicable to natural gas in the facility for the prior three consecutive calendar years.
 
The passive ownership of the facilities by the Industrial Development Board will not result in any impact to the operation of the Pine Prairie facility. In addition, the tax exemption enables Pine Prairie to offer more competitively priced storage services to respond to market forces.
 
The Lease also contains certain covenants that Pine Prairie must comply with in order to obtain the related ad valorem property tax benefits during the term of the Lease including maintenance of a minimum level of employment at the facility. We are currently in compliance with the covenants in the Lease. In addition to the PILOT Payments, we were also obligated to make an additional payment to retire a school bond previously issued by the Parish in an unrelated transaction. We paid approximately $3.2 million in April


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PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
2008 in full satisfaction of this obligation. Amounts related to the revenue bond and lease obligation are presented on a net basis in our consolidated financial statements.
 
In conjunction with the PAA Ownership Transaction, this tax abatement agreement was valued at approximately $23 million and is reflected as a component of goodwill and other intangibles, net in our consolidated balance sheet as of December 31, 2009.
 
9.   Concentration of Risk
 
During the period from September 3, 2009 to December 31, 2009, Anadarko Energy Services, Iberdrola Renewables, Inc. and Guardian Pipeline, LLC accounted for approximately 10%, 16% and 12% of our storage revenues, respectively. During the period from January 1, 2009 to September 2, 2009, Iberdrola Renewables, Inc. and Guardian Pipeline, LLC accounted for approximately 17% and 13% of our storage revenues, respectively. During the year ended December 31, 2008, ONEOK Energy Services Company LP, Iberdrola Renewables, Inc. and Guardian Pipeline, LLC accounted for approximately 10%, 19% and 11% of our storage revenues, respectively. During the year ended December 31, 2007, ONEOK Energy Services Company LP, Iberdrola Renewables, Inc. and Cargill Inc. accounted for approximately 10%, 13% and 10% of our storage revenues, respectively.
 
This concentration in the volume of business transacted with a limited number of customers subjects us to risk. However, we believe that the loss of these customers would have only a short-term impact on our operating results as there are other customers to transact with.
 
Financial instruments that subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from customers that operate in the natural gas industry. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions, which subjects us to credit risk. We review credit exposure and financial information of our customers and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced.
 
10.   Reporting Segment
 
We manage our operations through two operating segments, Bluewater and Pine Prairie. We have aggregated these operating segments into one reporting segment, Gas Storage. Our Chief Operating Decision Maker (our Chairman of the Board) evaluates segment performance based on a variety of measures including adjusted EBITDA, volumes, adjusted EBITDA per mcf and maintenance capital investment. We have aggregated our two operating segments into one reportable segment based on the similarity of their economic and other characteristics, including the nature of services provided, methods of execution and delivery of services, types of customers served and regulatory requirements. We define adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring. The measure above excludes depreciation and amortization as we believe that depreciation and amortization are largely offset by repair and maintenance capital investments. Maintenance capital consists of expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of


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PAA Natural Gas Storage, LLC
 
Notes to Consolidated Financial Statements — (Continued)
 
production, and/or functionality of our existing assets. The following table reflects certain financial data for our reporting segment for the periods indicated (in thousands):
 
                                   
    Successor       Predecessor  
    September 3,
      January 1,
             
    2009 through
      2009 through
    Year Ended
 
    December 31,
      September 2,
    December 31,  
    2009       2009     2008     2007  
Revenues(1)
  $ 25,251       $ 46,929     $ 49,177     $ 36,945  
                                   
Adjusted EBITDA
  $ 12,165       $ 28,701     $ 31,001     $ 29,663  
                                   
Maintenance capital
  $ 320       $ 384     $ 377     $  
                                   
Long-lived assets(1)
  $ 889,413               $ 757,588     $ 641,305  
                                   
Total assets
  $ 900,407               $ 811,436     $ 674,765  
                                   
 
 
(1) We only have operations in the United States, thus no geographic data disclosure is necessary for revenues or long-lived assets.
 
The following table reconciles Adjusted EBITDA to consolidated net income (in thousands):
 
                                   
    Successor       Predecessor  
    September 3,
      January 1,
             
    2009 through
      2009 through
    Year Ended
 
    December 31,
      September 2,
    December 31,  
    2009       2009     2008     2007  
Adjusted EBITDA
  $ 12,165       $ 28,701     $ 31,001     $ 29,663  
Selected items impacting Adjusted EBITDA:
                                 
Equity compensation charge
    (1,467 )       (304 )     110       (553 )
Mark-to-market of open derivative positions
    (370 )             548       524  
Depreciation, depletion and amortization
    (3,578 )       (8,054 )     (6,245 )     (4,520 )
Interest expense
    (4,262 )       (4,352 )     (4,941 )     (7,108 )
Income tax expense
            (473 )     (887 )      
                                   
Net income
  $ 2,488       $ 15,518     $ 19,586     $ 18,006  
                                   


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Report of Independent Registered Public Accounting Firm
 
To the Board of Directors of the General Partner and the Limited Partner of PAA Natural Gas Storage, L.P.:
 
In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of PAA Natural Gas Storage, L.P. at January 22, 2010 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of PAA Natural Gas Storage, L.P.’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.
 
/s/ PricewaterhouseCoopers LLP
Houston, Texas
January 22, 2010


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PAA Natural Gas Storage, L.P.
 
Balance Sheet
 
 
         
    January 22, 2010  
 
Assets
       
Cash
  $ 1,000  
         
Total Assets
  $ 1,000  
         
Partners’ Equity
       
Limited Partner Equity
  $ 980  
General Partner Equity
    20  
         
Total Partners’ Equity
  $ 1,000  
         
 
See the accompanying note to the balance sheet


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Note to Financial Statement
 
 
1.   Nature of Operations
 
PAA Natural Gas Storage, L.P. (the “Partnership”) was formed on January 15, 2010.
 
Plains All American Pipeline, L.P. contributed $980 to the Partnership in exchange for a 98% limited partner interest and PNGS GP LLC contributed $20 in exchange for a 2% general partner interest.


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Report of Independent Registered Public Accounting Firm
 
To the Board of Directors and Member of PNGS GP LLC:
 
In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of PNGS GP LLC at January 22, 2010 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of PNGS GP LLC’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.
 
/s/ PricewaterhouseCoopers LLP
Houston, Texas
January 22, 2010


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PNGS GP LLC
 
Balance Sheet
 
 
         
    January 22, 2010  
 
Assets
       
Cash
  $ 980  
Investment in PAA Natural Gas Storage, L.P. 
  $ 20  
         
Total Assets
  $ 1,000  
         
Member’s Equity
       
Member’s Equity
  $ 1,000  
         
Total Members’ Equity
  $ 1,000  
         
 
See the accompanying note to the balance sheet


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Note to Financial Statement
 
 
1.   Nature of Operations
 
PNGS GP LLC (the “Company”), is a limited liability company formed on January 15, 2010 to become the general partner of PAA Natural Gas Storage, L.P. (the “Partnership”). The Company owns a 2% general partnership interest in the Partnership.
 
Plains All American Pipeline, L.P. (“PAA”), as sole member, contributed $1,000 to the Company in exchange for a 100% membership interest. The Company contributed $20 to the Partnership in exchange for a 2% general partner interest. There have been no other transactions involving the Company.


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APPENDIX A
 
AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP OF PAA NATURAL GAS STORAGE, L.P.


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APPENDIX B
 
GLOSSARY OF TERMS
 
Adjusted EBITDA:  A supplemental financial measure defined by us as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring.
 
available cash: For any quarter ending prior to liquidation:
 
(a) the sum of:
 
(1) all cash and cash equivalents of PAA Natural Gas Storage, L.P. and its subsidiaries on hand at the end of that quarter; and
 
(2) if our general partner so determines all or a portion of any additional cash or cash equivalents of PAA Natural Gas Storage, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter;
 
(b) less the amount of cash reserves established by our general partner to:
 
(1) provide for the proper conduct of the business of PAA Natural Gas Storage, L.P. and its subsidiaries (including cash reserves for future capital expenditures and for future credit needs of PAA Natural Gas Storage, L.P. and its subsidiaries) after that quarter;
 
(2) comply with applicable law or any debt instrument or other agreement or obligation to which PAA Natural Gas Storage, L.P. or any of its subsidiaries is a party or its assets are subject; and
 
(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;
 
provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of cash reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.
 
base gas (or cushion gas): The volume of gas that is injected into a storage facility to maintain adequate pressure and deliverability rates.
 
basis differential: The differences in pricing of natural gas due to location, quality, delivery timing or other factors.
 
Bcf:  One billion cubic feet.
 
Bcf/d:  One billion cubic feet per day.
 
capital account:  The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in PAA Natural Gas Storage, L.P. held by a partner.
 
capital surplus:  All available cash distributed by us on any date from any source will be treated as distributed from distributable cash flow until the sum of all available cash distributed since the closing of the initial public offering equals the distributable cash flow from the closing of the initial public offering through


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the end of the quarter immediately preceding that distribution. Any excess available cash distributed by us on that date will be deemed to be capital surplus.
 
closing price:  The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by the our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.
 
cumulative common unit arrearage:  The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from distributable cash flow actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.
 
current market price:  For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.
 
cycling fees:  Fees typically collected under a firm storage contract based on the volume of natural gas nominated for injection and/or withdrawal.
 
distributable cash flow:  A supplemental financial measure defined by us as net income adjusted for (i) any gain or loss from the sale of assets not in the ordinary course of business, (ii) any gain or loss as a result of a change in accounting principle, (iii) any non-cash gains or items of income and any non-cash losses or expenses, including mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities (iv) any acquisition-related expenses associated with (a) successful acquisitions or (b) all other acquisitions until the earlier to occur of the abandonment of such acquisition or one year from the date of incurrence and (v) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received; plus depreciation, depletion and amortization expense; and less maintenance capital expenditures.
 
header system:  The network of pipelines that connect a storage facility to interstate or intrastate pipelines, or both, as applicable, through a series of interconnects.
 
“interruptible” storage services:  Those services pursuant to which customers do not receive any assurances regarding the availability of capacity in any storage facility and pay fees based on their actual utilization of capacity.
 
firm storage services:  Those services including (i) multi-year storage services pursuant to which customers receive the assured or “firm” right to store gas in a storage facility over a multi-year period and (ii) seasonal “park and loan” services.
 
hub services:  Those services including (i) “interruptible” storage services, (ii) non-seasonal “park and loan” services and (iii) “wheeling and balancing” services.
 
LDC:  A local gas distribution company.
 
LNG:  Liquefied natural gas.
 
MMBtu:  One million British Thermal Units.
 
MMBtu/d:  One million British Thermal Units per day.
 
MMcf:  One million cubic feet of natural gas.


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MMcf/d:  One million cubic feet per day.
 
“park and loan” services:  Those services pursuant to which customers receive the “firm” right to store gas in (park), or borrow gas from (loan), a storage facility.
 
“take or pay” contracts:  Contracts under which purchasers pay for a minimum quantity of natural gas during a contract year even if the actual amount of gas received by the purchaser is less than the stated minimum.
 
Tcf:  One trillion cubic feet of natural gas.
 
“wheeling and balancing” services:  Those services pursuant to which customers pay fees for the right to move a volume of gas through a storage facility from one interconnection point to another and true up their deliveries of gas to, or takeaways of gas from, such facility.
 
working gas:  Assuming adequate operating pressures, the amount of gas that can be extracted during the normal operation of a storage facility.


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[Back cover art to come]
 


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PAA Natural Gas Storage, L.P.
 
Common Units
 
Representing Limited Partner Interests
 
 
 
 
 
 
Prospectus
 
               , 2010
 
 
 
 
 
 
Barclays Capital
UBS Investment Bank
 
 
 
 
 
 
 
 
 
 
Through and including          , 2010 (the 25th day after the date of this prospectus), federal securities law may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 


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Part II
 
Information required in the registration statement
 
ITEM 13.   OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
 
Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby, which will be paid by PAA Natural Gas Storage, L.P. With the exception of the Securities and Exchange Commission registration fee and the FINRA filing fee, the amounts set forth below are estimates.
 
         
SEC registration fee
  $ 14,260  
FINRA filing fee
    20,500  
Printing and engraving expenses
    400,000  
Fees and expenses of legal counsel
    850,000  
Accounting fees and expenses
    500,000  
Transfer agent and registrar fees
    25,000  
New York Stock Exchange listing fee
    50,000  
Miscellaneous
    140,240  
         
Total
  $ 2,000,000  
         
 
 
* To be included by amendment.
 
ITEM 14.   INDEMNIFICATION OF OFFICERS AND MEMBERS OF OUR GENERAL PARTNER’S BOARD OF DIRECTORS.
 
The section of the prospectus entitled “The Partnership Agreement — Indemnification” is incorporated herein by reference. Reference is also made to the underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which has been filed as an exhibit to this registration statement. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever. The officers and directors of our general partner will be insured against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.
 
ITEM 15.   RECENT SALES OF UNREGISTERED SECURITIES.
 
On January 15, 2010, in connection with the formation of PAA Natural Gas Storage, L.P. (the “Partnership”), the Partnership issued to (i) its general partner the 2.0% general partner interest in the Partnership for $20 and (ii) Plains All American Pipeline, L.P. the 98.0% limited partner interest in the Partnership for $980. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.
 
ITEM 16.   EXHIBITS.
 
The following documents are filed as exhibits to this registration statement:
 
             
Exhibit
       
Number
     
Description
 
  1 .1*     Form of Underwriting Agreement
  3 .1**     Certificate of Limited Partnership of PAA Natural Gas Storage, L.P.
  3 .2*     Form of Amended and Restated Limited Partnership Agreement of PAA Natural Gas Storage, L.P. (included as Appendix A in the prospectus included in this Registration Statement)


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Exhibit
       
Number
     
Description
 
  3 .3**     Certificate of Formation of PNGS GP LLC
  3 .4*     Form of Amended and Restated Limited Liability Company Agreement of PNGS GP LLC
  5 .1*     Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
  8 .1*     Opinion of Vinson & Elkins L.L.P. relating to tax matters
  10 .1*     Form of Contribution Agreement
  10 .2*     Form of Omnibus Agreement
  10 .3*†     Form of PAA Natural Gas Storage, L.P. Long-Term Incentive Plan
  10 .4*†     Form of Long-Term Incentive Plan Grant Letter
  10 .5*†     Form of GP Incentive Compensation Plan
  10 .6*†     Form of GP Incentive Compensation Plan Grant Letter
  10 .7*†     Form of Indemnification Agreement
  10 .8*     Agreement to Lease with Option to Purchase, dated May 1, 2006, between Industrial Development Board No. 1 of the Parish of Evangeline, State of Louisiana, Inc. and Pine Prairie Energy Center, LLC
  10 .9*     Credit Agreement dated as of          , 2010 by among PAA Natural Gas Storage, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto.
  21 .1*     List of Subsidiaries of PAA Natural Gas Storage, L.P.
  23 .1     Consent of PricewaterhouseCoopers
  23 .2*     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
  23 .3*     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
  24 .1**     Powers of Attorney
 
 
* To be filed by amendment.
** Previously Filed.
Compensatory plan or arrangement.
 
ITEM 17.   UNDERTAKINGS.
 
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
 
The undersigned registrant hereby undertakes that:
 
(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

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(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
 
The undersigned registrant undertakes to provide to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Plains All American, L.P. or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to Plains All American, L.P. or its subsidiaries for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
 
The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.


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Signatures
 
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on March 2, 2010.
 
PAA Natural Gas Storage, L.P.
 
  By:  PNGS GP LLC, its general partner
 
  By: 
/s/  Al Swanson
Name:     Al Swanson
Title:     Senior Vice President
      and Chief Financial Officer
 
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.
 
PNGS GP LLC, as general partner of PAA NATURAL GAS STORAGE, L.P.
 
             
Signature
 
Title
 
Date
 
         
*

Greg L. Armstrong
  Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)   March 2, 2010
         
*

Harry N. Pefanis
  Vice Chairman and Director   March 2, 2010
         
*

Dean Liollio
  President and Director   March 2, 2010
         
/s/  Al Swanson

Al Swanson
  Senior Vice President, Chief Financial Officer and Director (Principal Financial Officer)   March 2, 2010
         
*

Tina L. Summers
  Vice President — Accounting and Chief Accounting Officer (Principal Accounting Officer)   March 2, 2010
         
*By: 
/s/  Al Swanson

Al Swanson, Attorney-in-Fact
       


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Exhibit
       
Number
     
Description
 
  1 .1*     Form of Underwriting Agreement
  3 .1**     Certificate of Limited Partnership of PAA Natural Gas Storage, L.P.
  3 .2*     Form of Amended and Restated Limited Partnership Agreement of PAA Natural Gas Storage, L.P. (included as Appendix A in the prospectus included in this Registration Statement)
  3 .3**     Certificate of Formation of PNGS GP LLC
  3 .4*     Form of Amended and Restated Limited Liability Company Agreement of PNGS GP LLC
  5 .1*     Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
  8 .1*     Opinion of Vinson & Elkins L.L.P. relating to tax matters
  10 .1*     Form of Contribution Agreement
  10 .2*     Form of Omnibus Agreement
  10 .3*†     Form of PAA Natural Gas Storage, L.P. Long-Term Incentive Plan
  10 .4*†     Form of Long-Term Incentive Plan Grant Letter
  10 .5*†     Form of GP Incentive Compensation Plan
  10 .6*†     Form of GP Incentive Compensation Plan Grant Letter
  10 .7*†     Form of Indemnification Agreement
  10 .8*     Agreement to Lease with Option to Purchase, dated May 1, 2006, between Industrial Development Board No. 1 of the Parish of Evangeline, State of Louisiana, Inc. and Pine Prairie Energy Center, LLC
  10 .9*     Credit Agreement dated as of          , 2010 by among PAA Natural Gas Storage, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto.
  21 .1*     List of Subsidiaries of PAA Natural Gas Storage, L.P.
  23 .1     Consent of PricewaterhouseCoopers
  23 .2*     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
  23 .3*     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
  24 .1**     Powers of Attorney
 
 
* To be filed by amendment.
** Previously Filed.
Compensatory plan or arrangement.