PROSPECTUS SUPPLEMENT
(To Prospectus dated April 5, 2004)
[GRAPHIC OMITTED]
ATLAS PIPELINE PARTNERS, L.P.
2,300,000 COMMON UNITS
REPRESENTING LIMITED PARTNER INTERESTS
We are offering to sell 2,300,000 of our common units representing limited
partner interests. Our common units trade on the New York Stock Exchange under
the symbol "APL." The last reported sales price of our common units on the New
York Stock Exchange on May 26, 2005 was $41.95 per common unit.
INVESTING IN OUR COMMON UNITS INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING
ON PAGE S-11 OF THIS PROSPECTUS SUPPLEMENT AND ON PAGE 12 OF THE ACCOMPANYING
PROSPECTUS.
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PER COMMON UNIT TOTAL
--------------------------------------------------------------------------------
Public offering price.................. $41.95 $96,485,000
--------------------------------------------------------------------------------
Underwriting discount.................. $ 1.89 $ 4,341,825
--------------------------------------------------------------------------------
Proceeds to us (before expenses)....... $40.06 $92,143,175
================================================================================
We have granted the underwriters a 30-day option to purchase up to an
additional 345,000 common units on the same terms and conditions as set forth
above to cover over-allotments of common units, if any.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF
THIS PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS IS TRUTHFUL OR
COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
Friedman Billings Ramsey, on behalf of the underwriters, expects to deliver
the common units on or about
June 2, 2005.
----------------
FRIEDMAN BILLINGS RAMSEY A.G. EDWARDS WACHOVIA SECURITIES
----------------
KEYBANC CAPITAL MARKETS SANDERS MORRIS HARRIS
May 27, 2005
[GRAPHIC OMITTED]
MAPS
This document is in two parts. The first part is this prospectus supplement,
which describes our business and the terms of this offering of common units.
The second part is the accompanying prospectus, which gives more general
information, some of which may not apply to this offering of common units. If
information varies between this prospectus supplement and the accompanying
prospectus, you should rely on the information in this prospectus supplement.
You should rely only on the information contained in or incorporated by
reference into this prospectus supplement or the accompanying prospectus. We
have not authorized anyone to provide you with different information.
We are not making an offer of these securities in any state where the offer
is not permitted. You should not assume that the information contained in this
prospectus supplement or the accompanying prospectus is accurate as of any
date other than the dates shown in these documents or that any information we
have incorporated by reference is accurate as of any date other than the date
of the document incorporated by reference. Our business, financial condition,
results of operations and prospects may have changed since those dates.
TABLE OF CONTENTS
PROSPECTUS SUPPLEMENT
SUMMARY ................................................................. S-1
RISK FACTORS ............................................................ S-11
USE OF PROCEEDS ......................................................... S-21
CAPITALIZATION .......................................................... S-22
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS ........................... S-23
PRO FORMA FINANCIAL DATA ................................................ S-24
BUSINESS ................................................................ S-30
MANAGEMENT .............................................................. S-48
OUR PARTNERSHIP AGREEMENT ............................................... S-51
TAX CONSIDERATIONS ...................................................... S-58
UNDERWRITING ............................................................ S-73
LEGAL MATTERS ........................................................... S-75
EXPERTS ................................................................. S-75
WHERE YOU CAN FIND MORE INFORMATION ..................................... S-76
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE ......................... S-76
INDEX TO FINANCIAL STATEMENTS ........................................... F-1
PROSPECTUS
PROSPECTUS SUMMARY ....................................................... 2
RISK FACTORS ............................................................. 12
USE OF PROCEEDS .......................................................... 15
RATIO OF EARNINGS TO FIXED CHARGES ....................................... 15
PRO FORMA FINANCIAL DATA ................................................. 15
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES ..................... 19
GENERAL DESCRIPTION OF SECURITIES THAT WE MAY SELL ....................... 23
DESCRIPTION OF COMMON UNITS .............................................. 23
DESCRIPTION OF SUBORDINATED UNITS ........................................ 23
DESCRIPTION OF DEBT SECURITIES ........................................... 23
DESCRIPTION OF WARRANTS .................................................. 33
OUR PARTNERSHIP AGREEMENT ................................................ 34
EXPERTS .................................................................. 51
LEGAL MATTERS ............................................................ 51
WHERE YOU CAN FIND MORE INFORMATION ...................................... 51
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE .......................... 51
PLAN OF DISTRIBUTION ..................................................... 52
ALASKA PIPELINE COMPANY CONSOLIDATED FINANCIAL STATEMENTS ................ F-1
i
NOTE ABOUT CERTAIN TERMS USED IN THIS PROSPECTUS SUPPLEMENT
In this prospectus supplement, unless the context indicates otherwise:
o the terms "the Partnership," "we," "our" and "us" refer to Atlas
Pipeline Partners, L.P. and its subsidiaries;
o the term "our general partner" refers to Atlas Pipeline Partners GP,
LLC, a wholly-owned subsidiary of Atlas America, Inc., which we refer
to as "Atlas America";
o we refer to natural gas liquids, such as ethane, propane, normal
butane, isobutane and natural gasoline, as `'NGLs";
o we refer to billion cubic feet as "Bcf," million cubic feet as "MMcf,"
thousand cubic feet as "Mcf," million cubic feet per day as "MMcf/d"
and thousand cubic feet per day as "Mcf/d";
o we refer to barrels as "Bbl" and barrels per day as "Bbl/d";
o we refer to million British Thermal Units as "MMbtu" and million
British Thermal Units per day as "MMbtu/d";
o the information presented assumes that the underwriters do not
exercise their over-allotment option; and
o references to "pro forma" mean financial or operating results which
are presented on a pro forma basis, as adjusted for:
o our acquisition of Spectrum Field Services, Inc, which we refer
to as "Spectrum" or "Velma," which we acquired on July 16, 2004;
o our acquisition of ETC Oklahoma Pipeline, Ltd, which we refer to
as "Elk City," which we acquired on April 14, 2005;
o consummation of our new $270 million credit facility; and
o this offering.
For a description of the assumptions and adjustments used in preparing the
pro forma financial data, please read "Pro Forma Financial Data" in this
prospectus supplement.
ii
SUMMARY
This summary highlights information contained elsewhere in this prospectus
supplement and in the accompanying prospectus. You should read the entire
prospectus supplement, the accompanying prospectus, the documents incorporated
by reference and the other documents to which we refer for a more complete
understanding of this offering. You should read "Risk Factors" beginning on
page S-11 of this prospectus supplement and on page 12 of the accompanying
prospectus for more information about important factors that you should
consider before buying common units in this offering.
ATLAS PIPELINE PARTNERS, L.P.
We are a publicly-traded, midstream energy services provider engaged in the
gathering and processing of natural gas. We conduct our business through two
regional operating segments: our Appalachian operations and our Mid-Continent
operations. We own and operate approximately:
o 1,440 miles of natural gas gathering systems located in eastern Ohio,
western New York and western Pennsylvania, which we refer to as our
"Appalachian operations," and
o 1,400 miles of active natural gas gathering systems located in
Oklahoma and northern Texas, together with two processing plants and
one treating facility located in Oklahoma, which we refer to as our
"Mid-Continent operations."
Both our Appalachian and Mid-Continent operations are located in areas of
abundant and long-lived natural gas production and significant new drilling
activity. We provide our services to over 5,700 wells and central delivery
points giving us significant scale in our service areas. We provide
transportation and processing services to the wells connected to our system,
primarily under long-term contracts.
We completed our initial public offering in January 2000 at an initial
public offering price of $13.00 per common unit. Since our initial public
offering, we have completed four acquisitions, including, most recently, our
acquisitions of Elk City in April 2005 and Spectrum in July 2004, and we have
increased our quarterly cash distribution by 67% from $0.45 per unit for our
first full quarter ended June 30, 2000, or $1.80 per unit on an annualized
basis, to $0.75 per unit for the quarter ended March 31, 2005, or $3.00 on an
annualized basis. We intend to continue to grow our business through strategic
acquisitions and expansion projects that increase cash flow per unit.
As a result of the location and capacity of our gathering systems and
processing plants, we believe we are strategically positioned to capitalize on
the significant increase in drilling activity in our service areas. The
attractiveness of these regions is reflected by the growth in our pro forma
gathered volumes to 343 MMcf/d for the year ended December 31, 2004, a 20%
increase over the prior year, and to 372 MMcf/d for the three months ended
March 31, 2005, a 17% increase over the three months ended March 31, 2004. We
believe our experienced management team and our disciplined growth strategy
will enable us to continue to expand our operations and generate significant
cash flow from operations. For the year ended December 31, 2004, we generated
pro forma revenue of $294.3 million and pro forma adjusted EBITDA of $46.1
million, and for the three month period ended March 31, 2005, we generated pro
forma revenue of $88.0 million and pro forma adjusted EBITDA of $10.3 million.
Please see "-- Summary Historical Consolidated Financial and Other Data" for a
definition of adjusted EBITDA and a reconciliation of adjusted EBITDA to our
net income.
For the year ended December 31, 2004, on a pro forma basis, our Appalachian
operations accounted for 30% of our gross margin, our Velma operations
accounted for 43% and our Elk City operations accounted for 27%, and for the
three months ended March 31, 2005, on a pro forma basis, Appalachia accounted
for 31%, Velma accounted for 43% and Elk City accounted for 26% of our gross
margin. Please see "-- Summary Historical Consolidated Financial and Other
Data" for a definition of gross margin and a reconciliation of pro forma gross
margin to our net income.
S-1
RECENT DEVELOPMENTS
Elk City Acquisition. On April 14, 2005, we acquired all of the outstanding
equity interests in Elk City for $194.4 million, including related transaction
costs. Elk City's principal assets include approximately 300 miles of natural
gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas
processing facility in Elk City, Oklahoma, with a total capacity of
approximately 130 MMcf/d and a gas treatment facility in Prentiss, Oklahoma,
with a total capacity of approximately 200 MMcf/d. Gathered volumes averaged
255 MMcf/d for the three months ended February 28, 2005. The system connects
to over 300 receipt points. The acquisition expands our activities in the
Mid-Continent area and provides the potential for further growth in our
operations based in Tulsa, Oklahoma.
New Credit Facility. In conjunction with the acquisition of Elk City, we
entered into a new $270 million credit facility with a bank syndicate led by
Wachovia Bank, National Association and Fleet National Bank. The facility
consists of a $225 million five-year revolving loan and a $45 million
five-year term loan. There is currently $204.5 million of outstanding debt on
our revolving loan facility and $45 million outstanding on our term loan
facility. The loan proceeds were used to refinance the $53.8 million
outstanding on our previous credit facility and to finance the Elk City
acquisition.
Updated Hedging Positions. In our Mid-Continent operations, we have hedged
portions of our exposure to natural gas, NGLs and condensate prices for
various periods through 2007. As a result of backwardated markets, we have
hedged more of our exposure in 2005 than in 2006, as well as more in 2006 than
in 2007. During this period, we have hedged approximately 52% of our natural
gas exposure, 34% of our NGL exposure, and 41% of our condensate exposure. Our
natural gas exposure is hedged at an average fixed price of $6.26/MMbtu,
including the basis differential between NYMEX and Mid-Continent prices. Our
NGL exposure is hedged at an average fixed price of $0.68/gallon and our
condensate is hedged at an average fixed price of $42.84/Bbl. In addition, a
portion of our plant shrinkage at Elk City is hedged at an average fixed price
of $6.74/MMbtu, including the basis differential, for the period July
2005-December 2006.
Conversion of Subordinated Units. On January 1, 2005, the 1,641,026
subordinated units held by our general partner converted to common units in
accordance with the terms of our partnership agreement.
Recent Distribution Increase. We declared on March 8, 2005, and paid on
May 15, 2005, a quarterly cash distribution of $0.75 per common unit for the
quarter ended March 31, 2005, which represented a 19% increase from the
quarter ended March 31, 2004.
BUSINESS STRATEGY
Our primary objective is to increase cash flow and achieve sustainable,
profitable growth by:
o maximizing use of our facilities and controlling our operating costs;
o expanding operations through strategic acquisitions;
o expanding our existing systems through new construction;
o securing additional long-term, fee-based contracts; and
o maintaining a flexible capital structure.
COMPETITIVE STRENGTHS
We believe we are well-positioned to successfully execute our business
strategy because of the following competitive strengths:
o Strategically positioned for organic growth. We are a leading provider
of natural gas gathering services in the Appalachian and Anadarko
Basins and the Golden Trend area and of natural gas processing
services in Oklahoma. We expect the breadth of our operations in our
service areas,
S-2
our customer focus and our relationship with Atlas America will allow
us to continue to connect new wells and capture new natural gas
volumes quickly and cost effectively.
o Experienced management team. Through our general partner we have
significant management and technical expertise. Our senior management
team averages over 20 years of experience in the oil and natural gas
industry and currently manages 89 public and drilling investment
partnerships. Our operational and technical expertise has enabled us
to identify assets that have not been fully utilized and to improve
their performance upon integration into our operations.
o Stability from long-term contracts and strong customer relations. Our
Appalachian operation generates substantially all of its volumes under
an omnibus agreement with Atlas America whereby Atlas America is
required to commit to our gathering system all wells it drills and
operates that are within 2,500 feet of the system. Wells under this
agreement are committed for the life of their respective leases,
typically over 30 years. Our 15 largest Mid-Continent customers, which
account for a substantial majority of our throughput, have been adding
wells to our systems for an average of approximately eight years.
o Relationship with Atlas America. As a result of our omnibus agreement
with Atlas America, we believe that the growth in the number of wells
drilled by Atlas America and its affiliates in the Appalachian Basin
will serve as an engine for our growth in the region.
o Active commodity risk management program. We are able to mitigate a
portion of the commodity price risk associated with our percentage of
proceeds and keep-whole contractual arrangements with our Mid-
Continent producers through an active risk management program, as well
as through our ability to reject ethane and to by-pass gas around our
Elk City gas plant. In our Appalachian operations, we are the
beneficiary of, and consult with Atlas America with respect to, the
hedging program it has established for its Appalachian natural gas
production that mitigates the risks of our percentage of proceeds
agreements with it.
o Attractive characteristics of our assets, system flexibility and
customer service. We believe that we have a competitive advantage in
our service areas due to the attractive characteristics of our assets,
our system flexibility, and our strong emphasis on customer service.
S-3
OUR ORGANIZATIONAL STRUCTURE
We conduct operations through, and our operating assets are owned by, our
subsidiaries. Our general partner has sole responsibility for conducting our
business and managing our operations. Our general partner does not receive any
management fee or other compensation in connection with its management of our
business apart from its general partner and incentive distribution rights, but
it is reimbursed for direct and indirect expenses incurred on our behalf. Our
principal executive offices are located at 311 Rouser Road, Moon Township,
Pennsylvania 15108 and our telephone number is (412) 262-2830. The following
diagram depicts our organizational structure and ownership after giving effect
to this offering:
Aggregate ownership of Atlas Pipeline Partners, L.P. and the
operating partnership after this offering:
Common Units:
Public Unitholders................................. 81.1%
Atlas Pipeline Partners GP, LLC.................... 16.9%
General Partner Interest............................... 2.0%
------
100.0%
======
RESOURCE AMERICA, INC.
Nasdaq: "REXI"
|
80.2%
|
Common Shareholders ATLAS AMERICA, INC.
19.8% Nasdaq: "ATLS"
|
100%
|
ATLAS PIPELINE PARTNERS GP, LLC
1,641,026 Common Units
| |
2.0% GP Interest 16.9% LP Interest
| |
Public Common Unitholders ATLAS PIPELINE PARTNERS, L.P.
7,863,990 Common Units NYSE: "APL"
81.1%
LP Interest |
100% Interest
|
ATLAS PIPELINE OPERATING
PARTNERSHIP, L.P.
| |
100% Interest 100% Interest
| |
ATLAS PIPELINE APPALACHIAN SUBSIDIARIES ATLAS PIPELINE MID-CONTINENT SUBSIDIARIES
S-4
THE OFFERING
COMMON UNITS OFFERED. . . . . . . . . . . . 2,300,000 common units.
2,645,000 common units if the
underwriters exercise their
over-allotment option in
full.
UNITS OUTSTANDING AFTER THIS OFFERING . . . 9,505,016 common units.
9,850,016 common units if the
underwriters exercise their
over-allotment option in
full.
USE OF PROCEEDS . . . . . . . . . . . . . . After fees and related
expenses, we expect to use
the net offering proceeds,
which we estimate will be
approximately $91.6 million,
to repay in full our $45
million term loan and reduce
outstanding indebtedness
under the revolving credit
portion of our credit
facility.
DISTRIBUTION POLICY . . . . . . . . . . . . We must distribute all of our
cash on hand at the end of
each quarter, less reserves
established by our general
partner in its discretion.
The amount of this cash may
be greater than or less than
the minimum quarterly
distribution referred to in
the next paragraph. We
generally make cash
distributions within 45 days
after the end of each
quarter.
When quarterly cash
distributions exceed $0.42
per unit in any quarter, our
general partner receives a
higher percentage of the cash
distributed in excess of that
amount, in increasing
percentages up to 50% if the
quarterly cash distribution
exceeds $0.60 per unit. We
refer to our general
partner's right to receive
these higher amounts of cash
as "incentive distribution
rights."
For a discussion of our cash
distribution policy, please
read "Our Partnership
Agreement--Cash Distribution
Policy" in this prospectus
supplement.
On March 8, 2005 we declared,
and on May 15, 2005 paid, a
quarterly cash distribution
of $0.75 per common unit.
Since the distribution
exceeded $0.42, our general
partner received an incentive
distribution.
RATIO OF TAXABLE INCOME TO DISTRIBUTIONS. . We estimate that if you
purchase common units in this
offering and own them through
December 31, 2007, you will
be allocated an amount of
federal taxable income for
that period which is less
than 30% of the cash we
expect to distribute for that
period. We anticipate that,
for taxable years beginning
after December 31, 2007, the
taxable income allocable to
you will represent a higher
percentage of cash
distributed to you. Please
read "Tax Considerations--Tax
Consequences of Unit
Ownership--Ratio of Taxable
Income to Distributions" in
this prospectus supplement
for an explanation of the
basis of this estimate.
NEW YORK STOCK EXCHANGE SYMBOL. . . . . . . APL.
S-5
SUMMARY HISTORICAL CONSOLIDATED AND OTHER FINANCIAL DATA
The following table sets forth summary consolidated financial data as of and
for each of the three years ended December 31, 2002, 2003 and 2004 and the
three months ended March 31, 2004 and 2005. We derived the financial data for
each of the years ended December 31, 2002, 2003 and 2004 and at December 31,
2003 and 2004 from our consolidated financial statements incorporated by
reference in this prospectus supplement, which have been audited by Grant
Thornton LLP, independent registered accountants. We derived the financial
data as of and for the three months ended March 31, 2004 and 2005 from our
unaudited consolidated financial statements incorporated by reference in this
prospectus supplement.
We have also included unaudited pro forma financial data that reflects our
historical results as adjusted on a pro forma basis to give effect to our
April 2004 and July 2004 offerings of common units, the completion of the
Spectrum and Elk City acquisitions and this equity offering.
The unaudited pro forma balance sheet information reflects the following
transactions as if they occurred as of March 31, 2005:
o the Elk City acquisition, which occurred on April 14, 2005, for
consideration of $191.6 million, plus $2.8 million in estimated
transaction costs;
o the closing of our $270 million credit facility, which occurred on
April 14, 2005, and borrowings of $249.5 million under it to finance
the Elk City acquisition and repay $53.8 million outstanding under our
previous credit facility; and
o this offering and the application of the net proceeds as described
under "Use of Proceeds."
The unaudited pro forma statement of income information for the year ended
December 31, 2004 reflects the following transactions as if they occurred as
of January 1, 2004:
o the Spectrum acquisition, which occurred on July 16, 2004, for
consideration of $143 million, including payment of income taxes due
as a result of the transaction;
o the Elk City acquisition, which occurred on April 14, 2005, for
consideration of $191.6 million, plus $2.8 million in estimated
transaction costs;
o the closing of our $270 million credit facility, which occurred on
April 14, 2005, and borrowings of $249.5 million under it to finance
the Elk City acquisition and repay $53.8 million outstanding under our
previous credit facility; and
o this offering and the application of the net proceeds as described
under "Use of Proceeds."
The unaudited pro forma statement of income information for the three months
ended March 31, 2005 reflects the following transactions as if they occurred
as of January 1, 2005:
o the Elk City acquisition, which occurred on April 14, 2005, for
consideration of $191.6 million, plus $2.8 million in estimated
transaction costs;
o the closing of our $270 million credit facility, which occurred on
April 14, 2005, and borrowings of $249.5 million under it to finance
the Elk City acquisition and repay $53.8 million outstanding under our
previous credit facility; and
o this offering and the application of the net proceeds as described
under "Use of Proceeds."
Elk City's historical fiscal year ended August 31, 2004 is not within 93
days of our fiscal year end. Accordingly, for pro forma purposes, statement of
income information for the year ended December 31, 2004 is based on Elk City's
historical financial results for the twelve months ended November 30, 2004 and
was created by subtracting the quarter ended November 30, 2003 from Elk City's
income statement for the year ended August 31, 2004 and adding the quarter
ended November 30, 2004. Similarly, the
S-6
comparable period as of and for our three months ended March 31, 2005 is as of
and for Elk City's three months ended February 28, 2005.
The financial data below should be read together with, and are qualified in
their entirety by reference to, our historical consolidated and pro forma
combined financial statements and the accompanying notes, "Management's
Discussion and Analysis of Financial Condition and Results of Operations," and
the historical consolidated financial statements and the accompanying notes of
Elk City and its predecessor, each of which is set forth elsewhere or
incorporated by reference in this prospectus supplement. The pro forma data
are not necessarily reflective of what our results would actually have been
had the transactions actually occurred on the indicated date, nor do they
reflect what may actually occur in the future.
S-7
PRO FORMA, AS ADJUSTED
------------------------------
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31 MARCH 31, YEAR ENDED THREE MONTHS
------------------------------ ------------------ DECEMBER 31, ENDED MARCH 31,
2002 2003 2004(1) 2004 2005 2004 2005
------- ------- --------- ------- -------- ------------ ---------------
(in thousands)
STATEMENTS OF INCOME DATA:
Revenue:
Natural gas and liquids................. $ -- $ -- $ 72,109 $ -- $ 42,334 $275,102 $ 83,066
Transportation and compression.......... 10,660 15,651 18,800 4,210 4,862 18,800 4,862
Interest income and other............... 7 98 382 36 81 383 81
------- ------- --------- ------- -------- -------- --------
Net revenue before expenses.......... 10,667 15,749 91,291 4,246 47,277 294,285 88,009
Operating expenses:
Natural gas and liquids................. -- -- 58,707 -- 35,459 231,809 72,124
Plant operating......................... -- -- 2,032 -- 1,204 9,105 2,567
Transportation and compression.......... 2,062 2,421 2,260 607 676 2,260 676
General and administrative.............. 1,482 1,661 4,643 581 2,488 6,623 2,698
Depreciation and amortization........... 1,475 1,770 4,471 518 1,929 14,754 3,788
Loss (gain) on arbitration settlement,
net.................................... -- -- (1,457) -- 136 (1,457) 136
Interest................................ 250 258 2,301 63 1,135 7,717 3,124
Other expense........................... -- -- -- -- -- 555 --
------- ------- --------- ------- -------- -------- --------
Total costs and expenses.............. 5,269 6,110 72,957 1,769 43,027 271,366 85,113
------- ------- --------- ------- -------- -------- --------
Net income............................... $ 5,398 $ 9,639 $ 18,334 $ 2,477 $ 4,250 $ 22,919 $ 2,896
======= ======= ========= ======= ======== ======== ========
BALANCE SHEET DATA (AT PERIOD END):
Property, plant and equipment, net....... $23,764 $29,628 $ 175,259 $30,294 $179,847 $372,968
Total assets............................. 28,515 49,512 216,785 47,350 215,887 415,683
Total debt, including current portion.... 6,500 -- 54,452 -- 53,873 158,099
Total partners' capital.................. 19,686 44,245 136,704 43,603 125,786 218,186
CASH FLOW DATA:
Net cash flow provided by (used in):
Operating activities.................... $ 8,138 $13,702 $ 25,593 $ 1,320 $ 6,910
Investing activities.................... (5,231) (9,154) (151,797) (1,305) (7,029)
Financing activities.................... (3,211) 8,671 129,340 (3,114) (8,400)
OTHER FINANCIAL DATA:
Gross margin(2).......................... $10,660 $15,651 $ 32,202 $ 4,210 $ 11,737 $ 62,093 $ 15,804
EBITDA(3)................................ 7,123 11,667 25,106 3,058 7,314 45,390 9,808
Adjusted EBITDA(3)....................... 7,123 11,667 25,806 3,058 7,763 46,090 10,257
Maintenance capital expenditures......... $ 170 $ 3,109 $ 1,516 $ 369 $ 342
Growth capital expenditures.............. 5,060 4,526 8,527 816 5,735
------- ------- --------- ------- --------
Total capital expenditures............ $ 5,230 $ 7,635 $ 10,043 $ 1,185 $ 6,077
======= ======= ========= ======= ========
OPERATING DATA:
Appalachia:
Average throughput volumes
(Mcf/d)(4)............................ 50,363 52,472 53,343 51,437 52,371 53,343 52,371
Average transportation rate per Mcf..... $ 0.58 $ 0.82 $ 0.96 $ 0.90 $ 1.03 $ 0.96 $ 1.03
Mid-Continent:
Velma system:
Gathered gas volume (Mcf/d)(5) ....... -- -- 56,441 -- 64,956 54,330 64,956
Processed gas volume (Mcf/d)(6)....... -- -- 55,202 -- 62,985 52,394 62,985
Residue gas volume (Mcf/d)(7)......... -- -- 42,659 -- 49,982 40,701 49,982
NGL production (Bbl/d)(7)............. -- -- 5,799 -- 6,404 5,710 6,404
Condensate volume (Bbl/d)............. -- -- 185 -- 234 191 234
Average gross margin rate per
processed Mcf........................ -- -- $ 1.44 -- $ 1.21 $ 1.38 $ 1.21
Elk City system:
Gathered gas volume (Mcf/d)(5)........ -- -- -- -- -- 235,000 255,000
Processed gas volume (Mcf/d)(6)....... -- -- -- -- -- 120,855 119,078
Treated gas volume (Mcf/d)(6)......... -- -- -- -- -- 105,790 126,380
Off system gas delivery
(Mcf/d)(8)........................... -- -- -- -- -- 2,913 733
NGL production (Bbl/d)(7)............. -- -- -- -- -- 5,072 5,455
Condensate volume (Bbl/d)............. -- -- -- -- -- 106 152
Average gross margin rate per
Mcf.................................. -- -- -- -- -- $ 0.20 $ 0.18
S-8
---------------
(1) Includes the acquisition of Spectrum on July 16, 2004, representing five
and one-half months' operations in the year ended December 31, 2004.
(2) We define gross margin as revenue less purchased product costs. Purchased
product costs include the cost of natural gas and NGLs we purchase from
third parties. Our management views gross margin as an important
performance measure of the core profitability of our operations and as a
key component of our internal financial reporting. We believe that
investors benefit from having access to the same financial measures that
our management uses. The GAAP measure most directly comparable to gross
margin is net income. The following table reconciles our net income to
gross margin:
PRO FORMA, AS ADJUSTED
------------------------------
THREE MONTHS
ENDED
YEAR ENDED DECEMBER 31 MARCH 31, YEAR ENDED THREE MONTHS
---------------------------- ---------------- DECEMBER 31, ENDED MARCH 31,
2002 2003 2004 2004 2005 2004 2005
------- ------- ------- ------ ------- ------------ ---------------
(in thousands)
Net income................................... $ 5,398 $ 9,639 $18,334 $2,477 $ 4,250 $22,919 $ 2,896
Minus:
Interest income and other................... 7 98 382 36 81 383 81
Plus:
Plant operating............................. -- -- 2,032 -- 1,204 9,105 2,567
Transportation and compression.............. 2,062 2,421 2,260 607 676 2,260 676
General and administrative.................. 1,482 1,661 4,643 581 2,488 6,623 2,698
Depreciation and amortization............... 1,475 1,770 4,471 518 1,929 14,754 3,788
Loss (gain) on arbitration settlement, net.. -- -- (1,457) -- 136 (1,457) 136
Interest.................................... 250 258 2,301 63 1,135 7,717 3,124
Other expense............................... -- -- -- -- -- 555 --
------- ------- ------- ------ ------- ------- -------
Gross margin................................. $10,660 $15,651 $32,202 $4,210 $11,737 $62,093 $15,804
======= ======= ======= ====== ======= ======= =======
(3) EBITDA means net income before net interest expense, income taxes and
depreciation and amortization. Adjusted EBITDA is calculated by adding to
EBITDA other non-cash items such as compensation expenses associated with
unit issuances to employees of our general partner and managers. EBITDA
and adjusted EBITDA are not intended to represent cash flow and do not
represent the measure of cash available for distribution. Our method of
computing EBITDA may not be the same method used to compute similar
measures reported by other companies. The EBITDA calculation below is
different from the EBITDA calculation under our credit facility. See
"Business--Credit Facility."
Certain items excluded from EBITDA are significant components in
understanding and assessing a company's financial performance, such as a
company's cost of capital and its tax structure, as well as historic
costs of depreciable assets. We have included information concerning
EBITDA and adjusted EBITDA because they provide investors and management
with additional information as to our ability to pay our fixed charges
and are presented solely as a supplemental financial measure. EBITDA and
adjusted EBITDA should not be considered as alternatives to, or more
meaningful than, net income or cash flow as determined in accordance with
generally accepted accounting principles or as indicators of our
operating performance or liquidity. The table below reconciles adjusted
EBITDA to EBITDA and EBITDA to our net income.
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PRO FORMA, AS ADJUSTED
------------------------------
THREE MONTHS
ENDED
YEAR ENDED DECEMBER 31 MARCH 31, YEAR ENDED THREE MONTHS
--------------------------- --------------- DECEMBER 31, ENDED MARCH 31,
2002 2003 2004 2004 2005 2004 2005
------ ------- ------- ------ ------ ------------ ---------------
(in thousands)
Net income..................................... $5,398 $ 9,639 $18,334 $2,477 $4,250 $22,919 $ 2,896
Plus:
Interest expense.............................. 250 258 2,301 63 1,135 7,717 3,124
Depreciation and amortization................. 1,475 1,770 4,471 518 1,929 14,754 3,788
------ ------- ------- ------ ------ ------- -------
EBITDA......................................... 7,123 11,667 25,106 3,058 7,314 45,390 9,808
Plus:
Non-cash compensation expense................. -- -- 700 -- 449 700 449
------ ------- ------- ------ ------ ------- -------
Adjusted EBITDA................................ $7,123 $11,667 $25,806 $3,058 $7,763 $46,090 $10,257
====== ======= ======= ====== ====== ======= =======
(4) Based on amount delivered.
(5) Based on lease meter volumes on gathering systems.
(6) Based on amount received at plant inlet.
(7) Based on amount at plant outlet.
(8) Amounts shown are not treated or processed.
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RISK FACTORS
Limited partner interests are inherently different from the capital stock of
a corporation, although many of the business risks we encounter are similar to
those that would be faced by a corporation engaged in a similar business. You
should consider the following risk factors and those described in the section
entitled "Risk Factors" in the accompanying prospectus together with all of
the other information included or incorporated by reference in this prospectus
supplement and the accompanying prospectus in evaluating an investment in the
common units. If any of these risks actually occurs, our business, financial
condition or results of operations could be materially adversely affected. In
that case, the trading price of our common units could decline and you may
lose some or all of your investment.
RISKS RELATING TO OUR BUSINESS
THE AMOUNT OF CASH WE GENERATE DEPENDS IN PART ON FACTORS BEYOND OUR CONTROL.
The amounts of cash that we generate may not be sufficient to pay
distributions at current or any other level of distributions. The actual
amounts of cash we generate will depend upon numerous factors relating to our
business which may be beyond our control, including:
o the demand for and price of natural gas and NGLs;
o the volume of natural gas we transport;
o continued development of wells for connection to our gathering
systems;
o the availability of local, intrastate and interstate transportation
systems;
o the expenses we incur in providing our gathering services;
o the cost of acquisitions and capital improvements;
o our issuance of equity securities;
o required principal and interest payments on our debt;
o fluctuations in working capital;
o prevailing economic conditions;
o fuel conservation measures;
o alternate fuel requirements;
o government regulation and taxation; and
o technical advances in fuel economy and energy generation devices.
Our ability to make cash distributions depends primarily on our cash flow.
Cash distributions do not depend directly on our profitability, which is
affected by non-cash items. Therefore, cash distributions may be made during
periods when we record losses and may not be made during periods when we
record profits.
WE MAY BE UNSUCCESSFUL IN INTEGRATING THE OPERATIONS OF VELMA AND ELK CITY OR
ANY FUTURE ACQUISITIONS WITH OUR OPERATIONS AND IN REALIZING ALL OF THE
ANTICIPATED BENEFITS OF THESE ACQUISITIONS.
We acquired Velma in July 2004 and Elk City in April 2005 and are currently
in the process of integrating their operations with ours. We also have an
active, on-going program to identify other potential acquisitions. The
integration of previously independent operations with ours can be a complex,
costly and time-consuming process. The difficulties of combining Velma and Elk
City, as well as any operations we may acquire in the future, with us include,
among other things:
o operating a significantly larger combined company;
o the necessity of coordinating geographically disparate organizations,
systems and facilities;
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o integrating personnel with diverse business backgrounds and
organizational cultures;
o consolidating operational and administrative functions;
o integrating internal controls, compliance under Sarbanes-Oxley Act of
2002 and other corporate governance matters;
o the diversion of management's attention from other business concerns;
o customer or key employee loss from the acquired businesses;
o a significant increase in our indebtedness; and
o potential environmental or regulatory liabilities and title problems.
The process of combining companies or the failure to integrate them
successfully could harm our business or future prospects, and result in
significant decreases in our gross margin and cash flows.
OUR PROFITABILITY IS AFFECTED BY THE VOLATILITY OF PRICES FOR NATURAL GAS AND
NGL PRODUCTS.
We derive a substantial portion of our gathering fees from percentage of
proceeds contracts. For January through April 2005, approximately 63% of our
pro forma gross margin was derived from percentage of proceeds contracts. In
addition, approximately 4% of our pro forma gross margin was derived from
keep-whole contracts which significantly depend on the relationship between
NGL and natural gas prices. As a result, our income depends to a significant
extent upon the prices at which the natural gas we transport and the NGLs we
produce are sold. A 10% increase in the average price of NGLs, natural gas and
crude oil we process and sell would result in an increase to our 2005 annual
income of approximately $420,000. A 10% decrease in the average price of NGLs,
natural gas and crude oil we process and sell would result in a decrease to
our 2005 annual income of $420,000. Additionally, changes in natural gas
prices may indirectly impact our profitability since prices can influence
drilling activity and well operations and thus the volume of gas we gather and
process. Historically, the price of both natural gas and NGLs has been subject
to significant volatility in response to relatively minor changes in the
supply and demand for natural gas and NGL products, market uncertainty and a
variety of additional factors beyond our control, including those we describe
in "--The amount of cash we generate depends in part on factors beyond our
control," above. We expect this volatility to continue. For example, during
the year ended December 31, 2004, the NYMEX settlement price for the prompt
month contract ranged from a high of $7.98 per MMbtu to a low of $5.08 per
MMbtu. A composite of the monthly Mont Belvieu average NGLs price based upon
our average NGLs composition during the year ended December 31, 2004, ranged
from a high of $0.80 per gallon to a low of $0.53 per gallon. This volatility
may cause our gross margin and cash flows to vary widely from period to
period. Our hedging strategies may not be sufficient to offset price
volatility risk and, in any event, do not cover all of the throughput volumes
subject to percentage of proceeds contracts. Moreover, hedges are subject to
inherent risks, which we describe in "--Our hedging strategies may fail to
protect us and could reduce our gross margin and cash flow."
THE AMOUNT OF NATURAL GAS WE TRANSPORT WILL DECLINE OVER TIME UNLESS WE ARE
ABLE TO ATTRACT NEW WELLS TO CONNECT TO OUR GATHERING SYSTEMS.
Production of natural gas from a well generally declines over time until the
well can no longer economically produce natural gas and is plugged and
abandoned. Failure to connect new wells to our gathering systems could,
therefore, result in the amount of natural gas we transport reducing
substantially over time and could, upon exhaustion of the current wells, cause
us to abandon one or more of our gathering systems and, possibly, cease
operations. The primary factors affecting our ability to connect new supplies
of natural gas to our gathering systems include our success in contracting for
existing wells that are not committed to other systems, the level of drilling
activity near our gathering systems and, in the Mid-Continent region, our
ability to attract natural gas producers away from our competitors' gathering
systems. Fluctuations in energy prices can greatly affect production rates and
investments by third parties in the development of new oil and natural gas
reserves. Drilling activity generally decreases as oil and natural gas prices
decrease. We have no control over the level of drilling activity in our
service areas, the amount of
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reserves underlying wells that connect to our systems and the rate at which
production from a well will decline. In addition, we have no control over
producers or their production decisions, which are affected by, among other
things, prevailing and projected energy prices, demand for hydrocarbons, the
level of reserves, geological considerations, governmental regulation and the
availability and cost of capital. Because our operating costs are fixed to a
significant degree, a reduction in the natural gas volumes we transport or
process would result in a reduction in our gross margin and cash flows.
THE SUCCESS OF OUR APPALACHIAN OPERATIONS DEPENDS UPON ATLAS AMERICA'S ABILITY
TO DRILL AND COMPLETE COMMERCIAL PRODUCING WELLS.
Substantially all of the wells we connect to our gathering systems in our
Appalachian service area are drilled and operated by Atlas America for
drilling investment partnerships sponsored by it. As a result, our Appalachian
operations depend principally upon the success of Atlas America in sponsoring
drilling investment partnerships and completing wells for these partnerships.
Atlas America operates in a highly competitive environment for acquiring
undeveloped leasehold acreage and attracting capital. Atlas America may not be
able to compete successfully in the future in acquiring undeveloped leasehold
acreage or in raising additional capital through its drilling investment
partnerships. Furthermore, Atlas America is not required to connect wells for
which it is not the operator to our gathering systems. If Atlas America cannot
or does not continue to sponsor drilling investment partnerships, if the
amount of money raised by those partnerships decreases, or if the number of
wells actually drilled and completed as commercially producing wells
decreases, the amount of natural gas transported by our Appalachian gathering
systems would substantially decrease and could, upon exhaustion of the wells
currently connected to our gathering systems, cause us to abandon one or more
of our Appalachian gathering systems, thereby materially reducing our gross
margin and cash flows.
THE FAILURE OF ATLAS AMERICA TO PERFORM ITS OBLIGATIONS UNDER OUR NATURAL GAS
GATHERING AGREEMENTS WITH IT MAY ADVERSELY AFFECT OUR BUSINESS.
On a pro forma basis for the year ended December 31, 2004, wells operated by
Atlas America accounted for approximately 6% of our revenues and approximately
30% of our gross margin. Substantially all of our Appalachian operating system
revenues currently consist of the fees we receive under the master natural gas
gathering agreement and other transportation agreements we have with Atlas
America and its affiliates. We expect to derive a material portion of our
gross margin from the services we provide under our contracts with Atlas
America for the foreseeable future. Any factor or event adversely affecting
Atlas America's business or its ability to perform under its contracts with us
or any default or nonperformance by Atlas America of its contractual
obligations to us, could reduce our gross margin and cash flows.
THE SUCCESS OF OUR MID-CONTINENT OPERATIONS DEPENDS UPON OUR ABILITY TO
CONTINUALLY FIND AND CONTRACT FOR NEW SOURCES OF NATURAL GAS SUPPLY FROM
UNRELATED THIRD PARTIES.
Unlike our Appalachian operations, none of the drillers or operators in our
Mid-Continent service area is an affiliate of ours. Moreover, our agreements
with most of the drillers and operators with which our Mid-Continent
operations do business do not require them to dedicate significant amounts of
undeveloped acreage to our systems. As a result, we do not have assured
sources to provide us with new wells to connect to our Mid-Continent gathering
systems. Failure to connect new wells to our Mid-Continent operations will, as
described in "--The amount of natural gas we transport will decline over time
unless we are able to attract new wells to connect to our gathering systems,"
above, reduce our gross margin and cash flows.
OUR MID-CONTINENT OPERATIONS CURRENTLY DEPEND ON CERTAIN KEY PRODUCERS FOR
THEIR SUPPLY OF NATURAL GAS; THE LOSS OF ANY OF THESE KEY PRODUCERS COULD
REDUCE OUR REVENUES.
During 2004, Mack Energy Corporation, Zinke & Trumbo, Inc., Chevron
Corporation and Chesapeake Energy Corporation supplied our Velma system with
approximately 60% of its natural gas supply. During that same period,
Chesapeake, Kaiser-Francis Oil Company, Burlington Resources Inc. and St. Mary
Land and Exploration Company supplied our Elk City system with approximately
74% of its natural gas supply. If
S-13
these producers reduce the volumes of natural gas that they supply to us, our
gross margin and cash flows would be reduced unless we obtain comparable
supplies of natural gas from other producers.
THE CURTAILMENT OF OPERATIONS AT, OR CLOSURE OF, EITHER OF OUR PROCESSING
PLANTS COULD HARM OUR BUSINESS.
We have one processing plant for our Elk City operation and one active
processing plant for our Velma operation. If operations at either plant were
to be curtailed, or closed, whether due to accident, natural catastrophe,
environmental regulation or for any other reason, our ability to process
natural gas from the relevant gathering system and, as a result, our ability
to extract and sell NGLs, would be harmed. If this curtailment or stoppage
were to extend for more than a short period, our gross margin and cash flows
would be materially reduced.
WE MAY FACE INCREASED COMPETITION IN THE FUTURE IN OUR MID-CONTINENT SERVICE
AREAS.
Our Mid-Continent operations may face competition for well connections. Duke
Energy Field Services, LLC, ONEOK, Inc., Carrera Gas Company, Cimmarron
Transportation, LLC and Enogex, Inc. operate competing gathering systems and
processing plants in our Velma service area. In our Elk City service area,
ONEOK, Enbridge Energy Partners, L.P., CenterPoint Energy, Inc. and Enogex
operate competing gathering systems and processing plants. Some of our
competitors have greater financial and other resources than we do. If these
companies become more active in our Mid-Continent service areas, we may not be
able to compete successfully with them in securing new well connections or
retaining current well connections. If we do not compete successfully, the
amount of natural gas we transport, process and treat will decrease, reducing
our gross margin and cash flows.
THE AMOUNT OF NATURAL GAS WE TRANSPORT MAY BE REDUCED IF THE PUBLIC UTILITY
AND INTERSTATE PIPELINES TO WHICH WE DELIVER GAS CANNOT OR WILL NOT ACCEPT THE
GAS.
Our gathering systems principally serve as intermediate transportation
facilities between sales lines from wells connected to our systems and the
public utility or interstate pipelines to which we deliver natural gas. If one
or more of these pipelines has service interruptions, capacity limitations or
otherwise does not accept the natural gas we transport, and we cannot arrange
for delivery to other pipelines, local distribution companies or end users,
the amount of natural gas we transport may be reduced. Since our revenues
depend upon the volumes of natural gas we transport, this could result in a
material reduction in our gross margin and cash flows.
BEFORE ACQUIRING OUR VELMA AND ELK CITY OPERATIONS, WE HAD NO PREVIOUS
EXPERIENCE EITHER IN OUR MID-CONTINENT SERVICE AREA OR IN OPERATING NATURAL
GAS PROCESSING PLANTS.
Our Mid-Continent gathering systems are located in Oklahoma and northern
Texas, areas in which we have been involved only since July 2004 as a result
of the Velma acquisition and, in April 2005, the Elk City acquisition. In
addition, as a result of these acquisitions, we began to operate natural gas
processing plants, a business in which we had no prior operating experience.
We depend upon the experience, knowledge and business relationships that have
been developed by the senior management of our Mid-Continent operations to
operate successfully in the region. The loss of the services of one or more
members of our Mid-Continent senior management and, in particular, Robert R.
Firth, President, and David D. Hall, Chief Financial Officer, could limit our
growth or our ability to maintain our current level of operations in the
Mid-Continent region.
ACQUISITION OF OUR VELMA AND ELK CITY OPERATIONS HAS SUBSTANTIALLY CHANGED OUR
BUSINESS, MAKING IT DIFFICULT TO EVALUATE OUR BUSINESS BASED UPON OUR
HISTORICAL FINANCIAL INFORMATION.
The acquisition of our Velma and Elk City operations has significantly
increased our size and substantially redefined our business plan, expanded our
geographic market and resulted in large changes to our revenues and expenses.
As a result of these acquisitions, and our continued plan to acquire and
integrate additional companies that we believe present attractive
opportunities, our financial results for any period or changes in our results
across periods may continue to dramatically change. Our historical financial
results,
S-14
therefore, should not be relied upon to accurately predict our future
operating results, thereby making the evaluation of our business more
difficult.
WE MAY NOT BE ABLE TO EXECUTE OUR GROWTH STRATEGY SUCCESSFULLY.
Our strategy contemplates substantial growth through both the acquisition of
other gathering systems and processing assets and the expansion of our
existing gathering systems and processing assets. Our growth strategy involves
numerous risks, including:
o we may not be able to identify suitable acquisition candidates;
o we may not be able to make acquisitions on economically acceptable
terms;
o our costs in seeking to make acquisitions may be material, even if we
cannot complete any acquisition we have pursued;
o irrespective of estimates at the time we make an acquisition, the
acquisition may prove to be dilutive to earnings and operating
surplus;
o we may encounter difficulties in integrating operations and systems;
and
o any additional debt we incur to finance an acquisition may impair our
ability to service our existing debt.
LIMITATIONS ON OUR ACCESS TO CAPITAL OR ON THE MARKET FOR OUR COMMON UNITS
WILL IMPAIR OUR ABILITY TO EXECUTE OUR GROWTH STRATEGY.
Our ability to raise capital for acquisitions and other capital expenditures
depends upon ready access to the capital markets. Historically, we have
financed our acquisitions, and to a much lesser extent, expansions of our
gathering systems by bank credit facilities and the proceeds of public and
private equity offerings of our common units and preferred units of our
operating partnership. If we are unable to access the capital markets, we may
be unable to execute out strategy of growth through acquisitions.
OUR HEDGING STRATEGIES MAY FAIL TO PROTECT US AND COULD REDUCE OUR GROSS
MARGIN AND CASH FLOW.
We pursue various hedging strategies to seek to reduce our exposure to
losses from adverse changes in the prices for natural gas and NGLs. Our
hedging activities will vary in scope based upon the level and volatility of
natural gas and NGL prices and other changing market conditions. Our hedging
activity may fail to protect or could harm us because, among other things:
o hedging can be expensive, particularly during periods of volatile
prices;
o available hedges may not correspond directly with the risks against
which we seek protection;
o the duration of the hedge may not match the duration of the risk
against which we seek protection; and
o the party owing money in the hedging transaction may default on its
obligation to pay.
LITIGATION OR GOVERNMENTAL REGULATION RELATING TO ENVIRONMENTAL PROTECTION AND
OPERATIONAL SAFETY MAY RESULT IN SUBSTANTIAL COSTS AND LIABILITIES.
Our operations are subject to federal and state environmental laws under
which owners of natural gas pipelines can be liable for clean-up costs and
fines in connection with any pollution caused by their pipelines. We may also
be held liable for clean-up costs resulting from pollution which occurred
before our acquisition of the gathering systems. In addition, we are subject
to federal and state safety laws that dictate the type of pipeline, quality of
pipe protection, depth, methods of welding and other construction-related
standards. Any violation of environmental, construction or safety laws could
impose substantial liabilities and costs on us.
We are also subject to the requirements of the Occupational Health and
Safety Act, or OSHA, and comparable state statutes. Any violation of OSHA
could impose substantial costs on us.
S-15
We cannot predict whether or in what form any new legislation or regulatory
requirements might be enacted or adopted, nor can we predict our costs of
compliance. In general, we expect that new regulations would increase our
operating costs and, possibly, require us to obtain additional capital to pay
for improvements or other compliance action necessitated by those regulations.
WE ARE SUBJECT TO OPERATING AND LITIGATION RISKS THAT MAY NOT BE COVERED BY
INSURANCE.
Our operations are subject to all operating hazards and risks incidental to
transporting and processing natural gas and NGLs. These hazards include:
o damage to pipelines, plants, related equipment and surrounding
properties caused by floods and other natural disasters;
o inadvertent damage from construction and farm equipment;
o leakage of natural gas, NGLs and other hydrocarbons;
o fires and explosions;
o other hazards, including those associated with high-sulfur content, or
sour gas, that could also result in personal injury and loss of life,
pollution and suspension of operations; and
o acts of terrorism directed at our pipeline infrastructure, production
facilities, transmission and distribution facilities and surrounding
properties.
As a result, we may be a defendant in various legal proceedings and
litigation arising from our operations. 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 some of our
insurance policies have increased substantially, and could escalate further.
In some instances, insurance could become unavailable or available only for
reduced amounts of coverage. For example, insurance carriers are now requiring
broad exclusions for losses due to war risk and terrorist acts. If we were to
incur a significant liability for which we were not fully insured, our gross
margin and cash flows would be materially reduced.
GOVERNMENTAL REGULATION OF OUR PIPELINES COULD INCREASE OUR OPERATING COSTS,
DECREASE OUR REVENUES, OR BOTH.
Currently our gathering of natural gas from wells is exempt from regulation
under the Natural Gas Act. However, the implementation of new laws or
policies, or interpretations of existing laws, could subject us to regulation
by the Federal Energy Regulatory Commission under the Natural Gas Act. We
expect that any such regulation would increase our costs, decrease our gross
margin and cash flows, or both.
Gas gathering operations are subject to regulation at the state level.
Matters subject to regulation include rates, service and safety. We have been
granted an exemption from regulation as a public utility in Ohio. Presently,
our rates are not regulated in New York and Pennsylvania. The state of
Oklahoma has adopted a complaint-based statute that allows the Oklahoma
Corporation Commission to remedy discriminatory rates for providing gathering
service where the parties are unable to agree. Similarly, the Texas Railroad
Commission sponsors a complaint procedure for resolving grievances about
natural gas gathering access and rate discrimination. The gathering fees we
charge are deemed just and reasonable under Oklahoma and Texas law unless
challenged by a complaint. Should a complaint be filed or regulation by either
of the commissions become more active, our revenues could decrease.
Changes in state regulations, or our change in status under these
regulations that subjects us to further regulation, could increase our
operating costs or require material capital expenditures.
S-16
RISKS INHERENT IN AN INVESTMENT IN US
YOU WILL HAVE VERY LIMITED VOTING RIGHTS AND ABILITY TO CONTROL MANAGEMENT,
WHICH MAY DIMINISH THE PRICE AT WHICH THE COMMON UNITS WILL TRADE.
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 managing board on an annual or other
continuing basis. The managing board of our general partner is chosen by the
members of our general partner, all of which are subsidiaries of Atlas
America.
In addition, our general partner may be removed only upon the vote of the
holders of at least 66 2/3% of the outstanding common units, excluding common
units held by our general partner and its affiliates, and a successor general
partner must be elected by a vote of the holders of at least a majority of the
outstanding common units, excluding common units held by our general partner
and its affiliates. Further, if any person or group, other than our general
partner or its affiliates, acquires beneficial ownership of 20% or more of any
class of units, that person or group will lose voting rights for all of its
units. These provisions have the practical effect of making removal of our
general partner difficult. Our partnership agreement requires that amendments
to our partnership agreement must first be proposed or consented to by our
general partner before they can be considered by unitholders. As a result,
unitholders will not be able to initiate amendments to our partnership
agreement not supported by our general partner. These provisions may diminish
the price at which the common units trade.
OUR PARTNERSHIP AGREEMENT CONTAINS PROVISIONS THAT WILL DISCOURAGE ATTEMPTS TO
CHANGE CONTROL OF US, WHICH MAY DIMINISH THE PRICE AT WHICH THE COMMON UNITS
TRADE AND MAY PREVENT A CHANGE OF CONTROL EVEN IF DOING SO WOULD BE BENEFICIAL
TO THE HOLDERS OF COMMON UNITS.
Our partnership agreement contains provisions that may discourage a person
or group from attempting to remove our general partner or otherwise seeking to
change our management. As described in the immediately preceding risk factor,
any person or group, other than our general partner or its affiliates, that
acquires beneficial ownership of 20% or more of any class of units will lose
voting rights for all of its units. In addition, if our general partner is
removed under circumstances where cause does not exist and our general partner
does not consent to that removal, then:
o the obligations of Atlas America under the omnibus agreement to
connect wells to our Appalachian Basin gathering systems and to
provide assistance for the expansion of our Appalachian Basin
gathering systems will terminate;
o the obligations of Atlas America under the master natural gas
gathering agreement will terminate as to any future wells drilled and
completed by Atlas America; and
o our general partner will have the right to convert its general partner
interest and incentive distribution rights into common units or
receive cash in exchange for those interests.
These provisions may diminish the price at which the common units trade.
These provisions may also prevent a change of control of us even if a change
of control would be beneficial to the holders of the common units.
WE MAY ISSUE ADDITIONAL COMMON UNITS OR SECURITIES SENIOR TO THE COMMON UNITS
WITHOUT YOUR APPROVAL, WHICH WOULD DILUTE EXISTING UNITHOLDERS' INTERESTS.
Our general partner can cause us to issue additional common units without
the approval of unitholders. We may also issue securities senior to the common
units without the approval of unitholders. The issuance of additional common
units or senior securities may dilute the value of the interests of the
existing unitholders in our net assets and dilute the interests of unitholders
in distributions by us.
S-17
ATLAS AMERICA AND ITS AFFILIATES HAVE CONFLICTS OF INTEREST AND LIMITED
FIDUCIARY RESPONSIBILITIES, WHICH MAY PERMIT THEM TO FAVOR THEIR OWN INTERESTS
TO THE DETRIMENT OF OUR NOTEHOLDERS.
Atlas America and its affiliates own and control our general partner, which
will also own a 16.9% limited partner interest in us after this offering. We
do not have any employees and rely solely on employees of Atlas America and
its affiliates who serve as our agents, including all of the senior managers
who operate our business. A number of officers and employees of Atlas America
also own interests in us. Conflicts of interest may arise between Atlas
America, our general partner and their affiliates, on the one hand, and us, on
the other hand. As a result of these conflicts, our general partner may favor
its own interests and the interests of its affiliates over our interests and
the interests of our unitholders. These conflicts include, among others, the
following situations:
o Employees of Atlas America who provide services to us also devote
significant time to the businesses of Atlas America in which we 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 employees who provide services to our
general partner, which could result in insufficient attention to the
management and operation of our business.
o Neither our partnership agreement nor any other agreement requires
Atlas America to pursue a future business strategy that favors us or,
apart from our agreements with Atlas America relating to our
Appalachian region operations, use our assets for transportation or
processing services we provide. Atlas America directors and officers
have a fiduciary duty to make these decisions in the best interests of
the stockholders of Atlas America.
o Our general partner is allowed to take into account the interests of
parties other than us, such as Atlas America, in resolving conflicts
of interest, which has the effect of limiting its fiduciary duty to
us.
o Our general partner controls the enforcement of obligations owed to us
by our general partner and its affiliates, including our agreements
with Atlas America.
Conflicts of interest with Atlas America and its affiliates, including these
factors, could exacerbate periods of lower or declining performance, or
otherwise reduce our gross margin and cash flows.
COST REIMBURSEMENTS DUE OUR GENERAL PARTNER MAY BE SUBSTANTIAL AND WILL REDUCE
THE CASH AVAILABLE FOR DISTRIBUTIONS.
We reimburse Atlas America, our general partner and their affiliates,
including officers and directors of Atlas America, for all expenses they incur
on our behalf. Our general partner has sole discretion to determine the amount
of these expenses. In addition, Atlas America and its affiliates provide us
with services for which we are charged reasonable fees as determined by Atlas
America in its sole discretion. The reimbursement of expenses or payment of
fees could impair our ability to make distributions.
TAX RISKS TO COMMON UNITHOLDERS
For a discussion of the expected material federal income tax consequences of
owning and disposing of common units, see "Tax Considerations" in this
prospectus supplement.
THE IRS COULD TREAT US AS A CORPORATION, WHICH WOULD SUBSTANTIALLY REDUCE THE
CASH AVAILABLE FOR DISTRIBUTION TO UNITHOLDERS.
The federal income tax benefit of an investment in the 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 IRS on
this or any other matter affecting us. We have, however, received an opinion
of Ledgewood, counsel to us and our general partner, that we will be
classified as a partnership for federal income tax purposes. Opinions of
counsel are based on specific factual assumptions and are not binding on the
IRS or any court.
S-18
If we were classified as a corporation for federal income tax purposes, we
would pay tax on our income at the corporate tax rate, which is currently 35%.
Distributions would generally be taxed again to the unitholders as corporate
distributions, and no income, gains, losses or deductions would flow through
to unitholders. Because a tax would be imposed upon us as an entity, the cash
available for distribution to you would be substantially reduced, likely
causing a substantial reduction in the value of the common units.
We cannot assure you that the law will not be changed and cause us to be
treated as a corporation for federal income tax purposes or otherwise to be
subject to entity-level taxation. 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, then
specified provisions of the partnership agreement will be subject to change,
including a decrease in distributions to reflect the impact of that law on us.
WE MAY INCUR SIGNIFICANT LEGAL, ACCOUNTING AND RELATED COSTS IF THE IRS
CHALLENGES OUR CHARACTERIZATION AS A LIMITED PARTNERSHIP.
We have not requested a ruling from the IRS with respect to any matter
affecting us. The IRS may adopt positions that differ from the conclusions of
our counsel expressed in this prospectus supplement or from the positions we
take. It may be necessary to resort to administrative or court proceedings to
sustain counsel's conclusions or the positions we take. A court may not concur
with our conclusions. Any contest with the IRS may materially and adversely
impact the market for the common units and the prices at which common units
trade. In addition, the costs of any contest with the IRS, principally legal,
accounting and related fees and expenses, will be borne directly or indirectly
by our unitholders and our general partner.
YOU MAY BE REQUIRED TO PAY TAXES ON INCOME FROM US EVEN IF YOU DO NOT RECEIVE
CASH DISTRIBUTIONS.
You will be required to pay federal income taxes and, in certain cases,
state and local income taxes on your allocable share of our income, whether or
not you receive cash distributions from us. We cannot assure you that you will
receive cash distributions equal to your allocable share of our taxable income
or even equal to the tax liability to you resulting from that income. Further,
you may incur a tax liability in excess of the amount of cash received upon
the sale of your common units or upon our liquidation.
In prior taxable years, unitholders received cash distributions that
exceeded the amount of taxable income allocated to the unitholders. This
excess was partially the result of depreciation deductions, but was primarily
the result of special allocations to our general partner of taxable income
earned by our operating subsidiary, which caused a corresponding reduction in
the amount of taxable income allocable to us. Our general partner has agreed
to receive additional special allocations from our operating subsidiary
through the year 2006. We describe these special allocations in "Tax
Considerations--Tax Consequences of Unit Ownership--Ratio of Taxable Income to
Distributions." Since these special allocations increase our general partner's
capital account, it will receive an increased distribution upon our
liquidation and distributions to unitholders will be correspondingly reduced.
TAX GAIN OR LOSS ON DISPOSITION OF COMMON UNITS COULD BE DIFFERENT THAN
EXPECTED.
Upon the sale of common units, you will recognize gain or loss equal to the
difference between the amount realized and your adjusted tax basis in those
common units. Prior distributions in excess of the net taxable income you were
allocated for a common unit which decreased your tax basis in that common unit
will, in effect, become taxable income if you sell the common unit at a price
greater than your tax basis in that common unit, even if the price is less
than your original cost. A substantial portion of the amount realized, whether
or not representing gains, may be ordinary income. Furthermore, should the IRS
successfully contest our conventions, including our method of allocating
income and loss as between transferors and transferees, you could realize more
gain on the sale of common units than would be the case under those
conventions without the benefit of decreased income in prior years.
S-19
INVESTORS, OTHER THAN INDIVIDUALS WHO ARE U.S. RESIDENTS, MAY HAVE ADVERSE TAX
CONSEQUENCES FROM OWNING UNITS.
Investment in common units by tax-exempt entities, regulated investment
companies and foreign persons raises issues unique to them. For example,
virtually all of our income will be unrelated business taxable income and will
be taxable to organizations exempt from federal income tax, including IRAs and
other retirement plans. Very little of our income will be qualifying income to
a regulated investment company for taxable years beginning on or before
October 22, 2004. Distributions to foreign persons will be reduced by
withholding taxes.
WE REGISTERED AS A TAX SHELTER; THIS MAY INCREASE THE RISK OF AN AUDIT OF US
OR A UNITHOLDER.
We registered as a "tax shelter" with the Secretary of the Treasury. The
Secretary of the Treasury requires partnerships meeting specified
characteristics to register as "tax shelters" in response to the perception
that they claim to generate tax benefits that the IRS may believe to be
unwarranted. We cannot assure unitholders that as a result of our registration
as a tax shelter we will not be audited by the IRS or that tax adjustments
will not be made. The rights of a unitholder owning less than a 1% profit
interest in us to participate in the income tax audit process are very
limited. Further, any adjustments in our tax returns will lead to adjustments
in the unitholders' tax returns and may lead to audits of unitholders' tax
returns and adjustments of items unrelated to us. Each unitholder would bear
the cost of any expenses incurred in connection with an examination of his
personal tax return.
WE TREAT A PURCHASER OF UNITS AS HAVING THE SAME TAX BENEFITS AS THE SELLER;
THE IRS MAY CHALLENGE THIS TREATMENT WHICH COULD ADVERSELY AFFECT THE VALUE OF
THE UNITS.
Because we cannot match transferors and transferees of common units, we will
take certain tax positions that may not conform with all aspects of proposed
and final Treasury regulations. For example, upon a transfer of units, we
treat a portion of the Section 743(b) adjustment to a common unitholder's tax
basis in our assets as amortizable over the same remaining life and by the
same method as the underlying assets, or nonamortizable if the underlying
assets are nonamortizable. A successful IRS challenge to those conventions,
including our method of amortizing Section 743(b) adjustments, 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 the common units or
result in audit adjustments to your tax returns.
YOU WILL LIKELY BE SUBJECT TO STATE AND LOCAL TAXES AS A RESULT OF AN
INVESTMENT IN COMMON UNITS.
In addition to federal income taxes, you will likely be subject to other
taxes, including state and local taxes, unincorporated business taxes and
estate, inheritance or intangible taxes imposed by the various jurisdictions
in which we do business or own property. 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 the various jurisdictions in which we do business or own
property. Further, you may be subject to penalties for failure to comply with
those requirements. We currently own assets and do business in Ohio, Oklahoma,
Pennsylvania, Texas and New York. Each of these states, except Texas,
currently imposes a personal income tax. It is your responsibility to file all
United States federal, state and local tax returns. Our counsel has not
rendered an opinion on the state or local tax consequences of an investment in
the common units.
S-20
USE OF PROCEEDS
We expect to receive net proceeds of approximately $91.6 million from the
sale of the 2,300,000 common units we are offering, after deducting
underwriting discounts and commissions and estimated offering expenses of $4.9
million. We intend to use the net proceeds of this offering to repay in full
the term loan portion of our credit facility and approximately $46.6 million
of indebtedness outstanding under the revolving loan portion of our credit
facility. For a description of the interest rate and maturity of both the term
loan and revolving portions of our credit facility, see "Business--Credit
Facility." We used $249.5 million of the borrowings under our credit facility
to fund our Elk City acquisition and repay $53.8 million outstanding under our
previous credit agreement. See "Business--General--Acquisition of Elk City
Operations."
S-21
CAPITALIZATION
The following table sets forth our consolidated capitalization as of
March 31, 2005 on an actual basis and on a pro forma basis to give effect to
our acquisition of Elk City and our new $270 million credit facility, and on a
pro forma as adjusted basis to give effect to the sale of common units in this
offering and the application of the net proceeds as described in "Use of
Proceeds."
You should read the following table in conjunction with our historical
consolidated financial statements and related notes, "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and other
financial information included elsewhere or incorporated by reference in this
prospectus supplement. See also "Use of Proceeds" and "Pro Forma Financial
Data."
AS OF MARCH 31, 2005
-----------------------------------
PRO FORMA,
ACTUAL PRO FORMA AS ADJUSTED
-------- --------- -----------
(IN THOUSANDS)
(UNAUDITED)
Cash and cash equivalents................................................................... $ 9,695 $ 9,284 $ 11,213
======== ======== ========
Long-term debt.............................................................................. $ 51,570 $248,496 $158,036
Partners' capital:
Common unitholders....................................................................... 133,192 133,089 223,685
General partner.......................................................................... 2,181 2,179 4,088
Accumulated other comprehensive loss..................................................... (9,587) (9,587) (9,587)
-------- -------- --------
Total partners' capital................................................................ 125,786 125,681 218,186
-------- -------- --------
Total capitalization........................................................................ $177,356 $374,177 $376,222
======== ======== ========
S-22
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
As of May 23, 2005, we had 7,205,016 common units outstanding held by 83
holders, including common units held in street name. As of May 14, 2004, our
common units began trading on the New York Stock Exchange under the symbol
"APL." Before that, our common units were traded on the American Stock
Exchange under the symbol "APL." In connection with our initial public
offering, we also issued 1,641,026 subordinated units to our general partner,
all of which converted into common units on January 1, 2005.
The following table sets forth the range of high and low sales prices of our
common units and cash distributions on our common units for the periods
indicated. The last reported sale price of our common units on the New York
Stock Exchange on May 26, 2005 was $41.95 per unit.
DISTRIBUTIONS
HIGH LOW DECLARED(1)
------ ------ -------------
FISCAL 2005
Second quarter (through May 26, 2005).......................................................... $46.39 $41.91 $ --(2)
First quarter.................................................................................. 49.00 40.00 0.750
FISCAL 2004
Fourth quarter................................................................................. 42.90 37.67 0.720
Third quarter.................................................................................. 38.32 33.46 0.690
Second quarter................................................................................. 40.03 32.60 0.630
First quarter.................................................................................. 41.50 34.00 0.630
FISCAL 2003
Fourth quarter................................................................................. 42.50 34.70 0.625
Third quarter.................................................................................. 36.00 29.40 0.620
Second quarter................................................................................. 31.70 24.16 0.580
First quarter.................................................................................. 28.96 24.90 0.560
FISCAL 2002
Fourth quarter................................................................................. 27.90 21.80 0.540
Third quarter.................................................................................. 26.95 20.40 0.540
Second quarter................................................................................. 29.10 22.00 0.540
First quarter.................................................................................. 29.60 23.51 0.520
FISCAL 2001
Fourth quarter................................................................................. 29.50 19.25 0.580
Third quarter.................................................................................. 31.95 25.01 0.600
Second quarter................................................................................. 53.95 24.00 0.670
First quarter.................................................................................. 28.00 19.19 0.650
---------------
(1) Distributions are shown in the quarter with respect to which they were
declared.
(2) Distribution not yet declared.
S-23
PRO FORMA FINANCIAL DATA
The following unaudited pro forma financial data reflects our historical
results as adjusted on a pro forma basis to give effect to our April 2004 and
July 2004 offerings of common units, the completion of the Spectrum and Elk
City acquisitions and this equity offering. The acquisition and offering
adjustments are described in the notes to the unaudited pro forma financial
data. The unaudited pro forma financial data and accompanying notes should be
read together with our "Management's Discussion and Analysis of Financial
Condition and Results of Operations," our historical financial statements and
related notes and the historical financial statements and related notes of Elk
City and its predecessor included or incorporated by reference in this
prospectus supplement.
We accounted for the acquisitions of Spectrum and Elk City in the unaudited
pro forma financial data using the purchase method in accordance with the
guidance of Statement of Financial Accounting Standards No. 141, "Business
Combinations." For purposes of developing the unaudited pro forma financial
information, we have allocated the purchase prices to Spectrum's and Elk
City's gas gathering and transmission facilities based on their fair market
value.
The unaudited pro forma balance sheet reflects the following transactions as
if they occurred as of March 31, 2005:
o the Elk City acquisition, which occurred on April 14, 2005, for
consideration of $191.6 million, plus $2.8 million in estimated
transaction costs;
o the closing of our $270 million credit facility, which occurred on
April 14, 2005, and borrowings of $249.5 million under it to finance
the Elk City acquisition and repay $53.8 million outstanding under our
previous credit facility; and
o this offering and the application of the net proceeds as described
under "Use of Proceeds."
The unaudited pro forma condensed statement of income for the year ended
December 31, 2004 reflects the following transactions as if they occurred as
of January 1, 2004:
o the Spectrum acquisition, which occurred on July 16, 2004, for
consideration of $143 million, including payment of income taxes due
as a result of the transaction;
o the Elk City acquisition, which occurred on April 14, 2005, for
consideration of $191.6 million, plus $2.8 million in estimated
transaction costs;
o the closing of our $270 million credit facility, which occurred on
April 14, 2005, and borrowings of $249.5 million under it to finance
the Elk City acquisition and repay $53.8 million outstanding under our
previous credit facility; and
o this offering and the application of the net proceeds as described
under "Use of Proceeds."
The unaudited pro forma condensed statement of income for the three months
ended March 31, 2005 reflects the following transactions as if they occurred
as of January 1, 2005:
o the Elk City acquisition, which occurred on April 14, 2005, for
consideration of $191.6 million, plus $2.8 million in estimated
transaction costs;
o the closing of our $270 million credit facility, which occurred on
April 14, 2005, and borrowings of $249.5 million under it to finance
the Elk City acquisition and repay $53.8 million outstanding under our
previous credit facility; and
o this offering and the application of the net proceeds as described
under "Use of Proceeds."
Elk City's historical fiscal year ended August 31, 2004 is not within 93
days of our fiscal year end. Accordingly, for pro forma purposes, statement of
income information for the year ended December 31, 2004 is based on Elk City's
historical financial results for the twelve months ended November 30, 2004 and
was created by subtracting the quarter ended November 30, 2003 from Elk City's
income statement for the year ended August 31, 2004 and adding the quarter
ended November 30, 2004. Similarly, the comparable period
S-24
as of and for our three months ended March 31, 2005 is as of and for Elk
City's three months ended February 28, 2005.
The unaudited pro forma balance sheet and the pro forma statements of income
were derived by adjusting our historical financial statements. However, our
management believes that the adjustments provide a reasonable basis for
presenting the significant effects of the transactions described above. The
unaudited pro forma financial data presented are for informational purposes
only and are based upon available information and assumptions that we believe
are reasonable under the circumstances. You should not construe the unaudited
pro forma financial data as indicative of the combined financial position or
results of operations that we, Spectrum and Elk City would have achieved had
the transactions been consummated on the dates assumed. Moreover, they do not
purport to represent our, Spectrum's and Elk City's combined financial
position or results of operations for any future date or period.
S-25
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA CONSOLIDATED BALANCE SHEET (UNAUDITED)
March 31, 2005
(in thousands)
HISTORICAL
ATLAS HISTORICAL ACQUISITION OFFERING PRO FORMA,
PIPELINE ELK CITY ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
---------- ---------- ----------- --------- ----------- -----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 9,695 $ -- $ (560)(1) $ 9,284 $ 91,585(6) $ 11,213
149(2) 1,929(7)
(91,585)(8)
Accounts receivable -
affiliates ............. -- 27,671 (27,671)(5) -- -- --
Accounts receivable ...... 16,566 3,010 3,837(4) 20,403 -- 20,403
(3,010)(5)
Inventories .............. -- 63 (63)(5) -- -- --
Prepaid expenses and
other current assets ... 1,155 497 56(2) 2,448 -- 2,448
1,237(4)
(497)(5)
-------- ------- -------- -------- -------- --------
Total current assets ..... 27,416 31,241 (26,522) 32,135 1,929 34,064
PROPERTY AND EQUIPMENT
Gas gathering and
transmission facilities 193,605 50,004 193,121(4) 386,726 -- 386,726
(50,004)(5)
Less - accumulated
depreciation ........... (13,758) (5,243) 5,243(5) (13,758) -- (13,758)
-------- ------- -------- -------- -------- --------
Net property and
equipment .............. 179,847 44,761 148,360 372,968 -- 372,968
GOODWILL .................. 2,305 -- -- 2,305 -- 2,305
OTHER ASSETS .............. 6,319 -- 1,562(2) 7,355 (1,009)(9) 6,346
(526)(3)
-------- ------- -------- -------- -------- --------
$215,887 $76,002 $122,874 $414,763 $ 920 $415,683
======== ======= ======== ======== ======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable and
accrued liabilities .... $ 25,201 $23,577 $ (600)(2) $ 28,371 $ -- $ 28,371
3,770(4)
(23,577)(5)
Accounts payable -
affiliates ............. 963 -- -- 963 -- 963
Current portion of long-
term debt .............. 2,303 -- (560)(1) 1,188 (1,125)(8) 63
(1,680)(2)
1,125(2)
Distribution payable ..... 6,904 -- -- 6,904 -- 6,904
-------- ------- -------- -------- -------- --------
Total current liabilities 35,371 23,577 (21,522) 37,426 (1,125) 36,301
OTHER LONG-TERM
LIABILITIES ............ 3,160 -- -- 3,160 -- 3,160
SENIOR SECURED DEBT ....... 51,449 -- 249,500(2) 248,375 (90,460)(8) 157,915
(51,449)(2)
(1,125)(2)
OTHER DEBT ................ 121 -- -- 121 -- 121
PARTNERS' CAPITAL:
Common unitholders ....... 133,192 52,373 (103)(2) 133,089 91,585(6) 223,685
(52,373)(5) (989)(9)
General partner .......... 2,181 52 (2)(2) 2,179 1,929(7) 4,088
(52)(5) (20)(9)
Accumulated other
comprehensive loss ..... (9,587) -- -- (9,587) -- (9,587)
-------- ------- -------- -------- -------- --------
Total partners' capital .. 125,786 52,425 (52,530) 125,681 92,505 218,186
-------- ------- -------- -------- -------- --------
$215,887 $76,002 $122,874 $414,763 $ 920 $415,683
======== ======= ======== ======== ======== ========
See notes to consolidated pro forma financial statements
S-26
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
FOR THE YEAR ENDED DECEMBER 31, 2004
(in thousands, except per unit data)
HISTORICAL
ATLAS HISTORICAL HISTORICAL ACQUISITION OFFERING PRO FORMA,
PIPELINE SPECTRUM ELK CITY ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
---------- ---------- ---------- ----------- --------- ----------- -----------
REVENUES:
Natural gas and liquids - third party . $72,109 $ 67,643 $ 11,376 $ 123,975(10) $275,103 $ -- $275,103
Natural gas and liquids -
affiliates .......................... -- -- 123,975 (123,975)(10) -- -- --
Transportation - affiliates ........... 18,724 -- -- -- 18,724 -- 18,724
Transportation - third party .......... 76 -- -- -- 76 -- 76
Interest and other .................... 382 -- -- -- 382 -- 382
------- -------- -------- --------- -------- ------- --------
91,291 67,643 135,351 -- 294,285 -- 294,285
COSTS AND EXPENSES:
Cost of gas sold ...................... 58,707 54,565 118,537 -- 231,809 -- 231,809
Operating expenses .................... 2,032 2,474 4,599 -- 9,105 -- 9,105
Transportation ........................ 2,260 -- -- -- 2,260 -- 2,260
General and administrative ............ 4,643 7,509 2,482 840(11) 6,623 -- 6,623
(2,482)(11)
(6,369)(12)
Gain on arbitration settlement, net ... (1,457) -- -- -- (1,457) -- (1,457)
Depreciation and amortization ......... 4,471 1,638 2,153 (3,791)(13) 14,754 -- 14,754
10,283(13)
------- -------- -------- --------- -------- ------- --------
70,656 66,186 127,771 (1,519) 263,094 -- 263,094
------- -------- -------- --------- -------- ------- --------
OPERATING INCOME ....................... 20,635 1,457 7,580 1,519 31,191 -- 31,191
------- -------- -------- --------- -------- ------- --------
OTHER (INCOME) EXPENSE:
Interest expense ...................... 2,301 1,712 -- 11,949(15)(17)
(4,002)(15) 11,960 (4,243)(9)(16) 7,717
Other (income) expense ................ -- (88,551) (3) 89,109(12) 555 -- 555
------- -------- -------- --------- -------- ------- --------
2,301 (86,839) (3) 97,056 12,515 (4,243) 8,272
------- -------- -------- --------- -------- ------- --------
Income before income taxes ............. 18,334 88,296 7,583 (95,537) 18,676 4,243 22,919
Provision for income taxes ............. -- (32,319) -- 32,319(12)(18) -- -- --
------- -------- -------- --------- -------- ------- --------
Net income ............................. 18,334 55,977 7,583 (63,218) 18,676 4,243 22,919
Premium on preferred unit
redemption .......................... 400 -- -- -- 400 -- 400
------- -------- -------- --------- -------- ------- --------
Net income attributable to
partners ............................ $17,934 $ 55,977 $ 7,583 $ (63,218) $ 18,276 $ 4,243 $ 22,519
======= ======== ======== ========= ======== ======= ========
Net income - limited partners .......... $14,864 $ 14,847(19) $ 18,322(19)
======= ======== ========
Net income - general partner ........... $ 3,070 $ 3,429(19) $ 4,197(19)
======= ======== ========
Basic and diluted net income
per limited partner unit ............ $ 2.53 $ 2.06 $ 1.93
======= ======== ========
Weighted average units
outstanding ......................... 5,886 7,204 9,504
======= ======== ========
See notes to consolidated pro forma financial statements
S-27
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
FOR THE THREE MONTHS ENDED MARCH 31, 2005
(in thousands, except per unit data)
HISTORICAL
ATLAS HISTORICAL ACQUISITION OFFERING PRO FORMA,
PIPELINE ELK CITY ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
---------- ---------- ----------- --------- ----------- -----------
REVENUES:
Natural gas and liquids - third party ........... $42,334 3,497 $ 37,235(10) $83,066 $ -- $83,066
Natural gas and liquids - affiliates ............ -- 37,235 (37,235)(10) -- -- --
Transportation - affiliates ..................... 4,847 -- -- 4,847 -- 4,847
Transportation - third party .................... 15 -- -- 15 -- 15
Interest and other .............................. 81 -- -- 81 -- 81
------- ------- -------- ------- ----- -------
47,277 40,732 -- 88,009 -- 88,009
COSTS AND EXPENSES:
Cost of gas sold ................................ 35,459 36,665 -- 72,124 -- 72,124
Operating expenses .............................. 1,204 1,363 -- 2,567 -- 2,567
Transportation .................................. 676 -- -- 676 -- 676
General and administrative ...................... 2,488 850 (850)(11) 2,698 -- 2,698
210(11)
Gain on arbitration settlement, net ............. 136 -- -- 136 -- 136
Depreciation and amortization ................... 1,929 628 (628)(14) 3,788 -- 3,788
1,859(14)
------- ------- -------- ------- ----- -------
41,892 39,506 591 81,989 -- 81,989
------- ------- -------- ------- ----- -------
OPERATING INCOME ................................. 5,385 1,226 (591) 6,020 -- 6,020
------- ------- -------- ------- ----- -------
OTHER EXPENSE:
Interest expense ................................ 1,135 -- (1,131)(15) 3,712 (588)(9)(16) 3,124
3,708(15)(17)
------- ------- -------- ------- ----- -------
Income before income taxes ....................... 4,250 1,226 (3,168) 2,308 588 2,896
Provision for income taxes ....................... -- -- -- -- -- --
------- ------- -------- ------- ----- -------
Net income ....................................... $ 4,250 $ 1,226 $ (3,168) $ 2,308 $ 588 $ 2,896
======= ======= ======== ======= ===== =======
Net income - limited partners .................... $ 2,830 $ 927(19) $ 1,077(19)
======= ======= =======
Net income - general partner ..................... $ 1,420 $ 1,381(19) $ 1,819(19)
======= ======= =======
Basic and diluted net income per limited partner
unit .......................................... $ 0.39 $ 0.13 $ 0.11
======= ======= =======
Weighted average units
outstanding ................................... 7,205 7,205 9,505
======= ======= =======
See notes to consolidated pro forma financial statements
S-28
ATLAS PIPELINE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
1. To reflect a $560,000 principal payment in April 2005 under our previous
credit facility. This entry is needed because we used the proceeds from
our new credit facility to pay off our previous credit facility after
this payment.
2. To reflect the application of $249,500,000 of proceeds ($1,125,000 shown
as current maturities) from our new credit facility to repay $53,129,000
on our previous credit facility ($1,680,000 included in current portion
of long-term debt); interest of $705,000, $600,000 of which was included
in accounts payable and accrued liabilities and $105,000 of which relates
to post-March 31, 2005 interest included in the payoff and charged herein
to partners' capital; payment of $1,618,000 of loan costs, $56,000 of
which was included in prepaid expenses and other current assets and
$1,562,000 of which was included in other assets; $193,899,000 for
various acquisition costs and payment to sellers allocated within the
purchase allocation described in note 4 below and $149,000 cash to us. We
describe our new senior credit facility under "Business-New Credit
Facility."
3. To remove $526,000 from our prepaid expenses and other current assets for
acquisition costs previously paid and include that amount in the purchase
price allocation described in note 4 below.
4. To reflect the allocation of purchase price to assets and liabilities as
follows: gas gathering and transmission facilities: $193,121,000;
accounts receivable: $3,837,000; prepaid expenses and other current
assets: $1,237,000; and accounts payable: $(3,770,000).
5. To eliminate Elk City assets not acquired and liabilities not assumed.
6. To reflect net proceeds from this offering of $91,585,000 after offering
costs of $4,900,000, assuming 2,300,000 common units at a price of $41.95
per unit, used to repay $45,000,000 of borrowings under the term loan
portion of our new credit facility and $46,585,000 of borrowings under
the revolving credit portion of our new credit facility.
7. To reflect our general partner's 2% capital contribution associated with
this offering in accordance with the terms of our partnership agreement.
8. To repay the $45,000,000 term loan and $46,585,000 of the revolving
credit portion of our new credit facility.
9. To reflect the write-off of deferred financing costs associated with the
repayment of the $45,000,000 term loan.
10. To reclassify affiliated revenues to third-party revenues.
11. To reflect the elimination of the overhead allocated to Elk City by its
parent company and its replacement with an overhead allocation to be made
by our general partner in accordance with a new allocation agreement.
12. To reflect the elimination of non-cash compensation costs of $6,369,000
related to the vesting of stock options upon change of control and the
gain of $89,109,000, in each case, on the sale of Spectrum's assets
to us.
13. To reflect the adjustment to depreciation expense for Spectrum for six
and one half months and for Elk City for 12 months based upon the cost of
the acquired gas gathering and transmission facilities using depreciable
lives ranging from 3 to 40 years and using the straight-line method.
14. To reflect the adjustment to depreciation expense for Elk City based upon
the cost of the acquired gas gathering and transmission facilities using
depreciable lives ranging from 3 to 40 years and using the straight-line
method.
15. To reflect the adjustments to interest expense resulting from
$249,500,000 of borrowings under our new credit facility bearing interest
at LIBOR plus 2.75%, assumed to be 4.29% for the twelve months ended
December 31, 2004, and 5.46% for the three months ended March 31, 2005
and from $100,000,000 of borrowings during the twelve months ended
December 31, 2004 for the Spectrum acquisition under our credit facility
bearing interest at LIBOR plus 3.75%, ranging from 6.75% to 7.5% for the
six and one half months ended July 15, 2004.
16. To reflect the adjustment to interest expense resulting from the
repayment of the $45,000,000 term loan and $46,585,000 of borrowings
under the revolving loan with proceeds from this offering.
17. To reflect the amortization of deferred financing costs related to our
new credit facility to finance the Elk City acquisition and, for the
twelve months ended December 31, 2004, the amortization of deferred
financing costs for six and one half months related to our previous
credit facility to finance the Spectrum acquisition.
18. To reflect the elimination of federal and state income taxes following
the conversion of Spectrum, which was a C-corporation, to a limited
liability company concurrent with its acquisition by us.
19. It is impracticable to determine what cash available for distribution
would have been on a pro forma basis. Accordingly, the allocation of net
income between the general partner and the limited partners reflects
historical incentive distributions.
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BUSINESS
GENERAL
We are a midstream energy services provider engaged in the gathering and
processing of natural gas. We are a leading provider of natural gas gathering
services in the Appalachian Basin region in the eastern United States and in
the Anadarko Basin and Golden Trend area of the mid-continent United States.
In addition, we are a leading provider of natural gas processing services in
Oklahoma. We own and operate approximately:
o 1,440 miles of natural gas gathering systems located in eastern Ohio,
western New York and western Pennsylvania and
o 1,400 miles of active natural gas gathering systems located in
Oklahoma and northern Texas, together with two processing plants and
one treating facility located in Oklahoma.
Both our Appalachian and Mid-Continent operations are located in areas of
abundant and long-lived natural gas production and significant new drilling
activity. We provide our services to over 5,700 wells and central delivery
points giving us significant scale in our service areas. We provide
transportation and processing services to the wells connected to our system,
primarily under long-term contracts.
We completed our initial public offering in January 2000 at an initial
public offering price of $13.00 per common unit. Since our initial public
offering, we have completed four acquisitions, and we have increased our
quarterly cash distribution by 67% from $0.45 per unit for our first full
quarter ended June 30, 2000, or $1.80 per unit on an annualized basis, to
$0.75 per unit for the quarter ended March 31, 2005, or $3.00 on an annualized
basis. We intend to continue to grow our business through strategic
acquisitions and expansion projects that increase cash flow per unit.
As a result of the location and capacity of our gathering systems and
processing plants, we believe we are strategically positioned to capitalize on
the significant increase in drilling activity in our service areas. The
attractiveness of these regions is reflected by the growth in our pro forma
gathered volumes to 343 MMcf/d for the year ended December 31, 2004, a 20%
increase over the prior year, and to 372 MMcf/d for the three months ended
March 31, 2005, a 17% increase over the three months ended March 31, 2004. We
believe our experienced management team and our disciplined growth strategy
will enable us to continue to expand our operations and generate significant
cash flow from operations. For the year ended December 31, 2004, we generated
pro forma revenue of $294.3 million and pro forma adjusted EBITDA of $46.1
million, and for the three month period ended March 31, 2005, we generated pro
forma revenue of $88.0 million and pro forma adjusted EBITDA of $10.3 million.
Please see "Summary--Summary Historical Consolidated Financial and Other Data"
for a definition of adjusted EBITDA and a reconciliation of adjusted EBITDA to
our net income.
We conduct our business through two regional operating segments: our
Appalachian operations and our Mid-Continent operations. Our Appalachian
operations consist of our Appalachian gathering systems. Our Mid-Continent
operations consist of two distinct gathering and processing systems, the Velma
gas gathering and processing system, which we acquired in our acquisition of
Spectrum, and the Elk City gas gathering and processing system, which we
acquired in our acquisition of Elk City. For the year ended December 31, 2004,
on a pro forma basis, our Appalachian operations accounted for 30% of our
gross margin, our Velma operations accounted for 43% and our Elk City
operations accounted for 27%, and for the three months ended March 31, 2005,
on a pro forma basis, Appalachia accounted for 31%, Velma accounted for 43%
and Elk City accounted for 26% of our gross margin. Please see
"Summary--Summary Historical Consolidated Financial and Other Data" for a
definition of gross margin and a reconciliation of pro forma gross margin to
our net income.
CONTRACTS AND CUSTOMER RELATIONSHIPS
Substantially all of the gas we transport in our Appalachian operations is
under a percentage of proceeds contract with Atlas America where we calculate
our transportation fee as a percentage of the price of the natural gas we
transport.
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In our Mid-Continent operations, we have a variety of contractual
relationships with our producers, included fixed-fee, percentage of proceeds
and keep-whole. Under the percentage of proceeds contracts, we purchase
natural gas at the wellhead and sell the plant residue gas and NGLs at
market-based prices, remitting to producers a percentage of the proceeds.
Under keep-whole contracts, our profitability is dependent upon the spread
between the price of natural gas and NGLs. Under the fixed-fee contracts, we
provide gathering, compression, treating and dehydration services to our
customers for a flat fee. Gross margin from fee-based services depends solely
on throughput volume and is not affected by changes in commodity prices. The
gross margin associated with each of these contractual arrangements varies
from period to period based on a variety of factors, including changing prices
of natural gas and NGLs, producers' optionality between contract types (e.g.,
percent of proceeds and keep-whole), and producers' optionality between
transporting gas and selling gas.
For January through April 2005, approximately 33% of our pro forma gross
margin was from fixed-fee arrangements, 63% was from percentage of proceeds
and 4% was from keep-whole.
COMPETITIVE STRENGTHS
Strategically positioned for organic growth. We are a leading provider of
natural gas gathering services in the Appalachian and Anadarko Basins and the
Golden Trend area and of natural gas processing services in Oklahoma. These
regions are characterized by long-lived wells and substantial developed and
undeveloped natural gas reserves which we believe will continue to promote
significant drilling activity. We provide our gathering and processing
services to over 5,700 wells and central delivery points. We expect the
breadth of our operations in our service areas, our customer focus and our
relationship with Atlas America will allow us to continue to connect new wells
and capture new natural gas volumes quickly and cost effectively.
Experienced management and engineering team. Through our general partner we
have significant management and technical expertise. Our senior management
team averages over 20 years of experience in the oil and natural gas industry
and currently manages 89 public and drilling investment partnerships. Our
operational and technical expertise has enabled us to identify assets that
have not been fully utilized and to improve their performance upon integration
into our operations. The technical team includes degreed pipeline, geological
and processing engineers, and environmental, safety, title and rights of way
specialists who average 19 years of experience in the construction and
operation of pipeline systems. In addition, upon completion of our acquisition
of Velma, the senior management team became Atlas America employees and
continues to manage the Mid-Continent operations while assisting us in our
efforts to grow. The Mid-Continent senior management team averages 20 years of
experience in all facets of the midstream natural gas industry.
Stability from long-term contracts and strong customer relationships. Our
Appalachian operation generates substantially all of its volumes under an
omnibus agreement with Atlas America whereby Atlas America is required to
commit to our gathering system all wells it drills and operates that are
within 2,500 feet of the system. Wells under this agreement are committed for
the life of their respective leases, typically over 30 years. Our 15 largest
Mid-Continent customers, which account for a substantial majority of our
throughput, have been adding wells to our systems for an average of
approximately eight years.
Relationship with Atlas America. As a result of our omnibus agreement with
Atlas America, we believe that the growth in the number of wells drilled by
Atlas America and its affiliates in the Appalachian Basin will serve as an
engine for our growth in the region. Since our inception in January 2000
through March 31, 2005, Atlas America has connected 1,192 new wells to our
system. In addition, third party producers and acquisitions have added 511
wells. In the year ended December 31, 2004, Atlas America added 335 wells to
our system compared to 270 wells in the year ended December 31, 2003, an
increase of over 24%.
Active commodity risk management program. For January through April 2005,
approximately 33% of our pro forma gross margin was from fixed-fee service
contracts that do not depend on commodity prices, while approximately 63% of
our gross margin was under percentage of proceeds contracts and only 4% was
under keep-whole contracts. In our Appalachian operations, we are the
beneficiary of natural gas gathering agreements with Atlas America under which
we receive gathering fees generally equal to a percentage, typically 16%, of
the selling price of the natural gas we transport. We are the beneficiary of,
and consult with
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Atlas America with respect to, the hedging program it has established for its
Appalachian natural gas production that mitigates the downside risks of our
percentage of proceeds agreement with it. We have an active hedging program to
mitigate a portion of the commodity price risk associated with our percentage
of proceeds and keep-whole contracts in our Mid-Continent operations. In
addition, we are able to mitigate the commodity price risk often associated
with keep-whole contracts in our Mid-Continent operations during periods of
unfavorable processing margins by bypassing our Elk City processing plant and
delivering the natural gas directly into connecting pipelines since the
natural gas behind the Elk City Plant does not require processing to meet
pipeline quality specifications.
Attractive characteristics of our assets, system flexibility and customer
service. We believe that we have a competitive advantage in our service areas
due to the attractive characteristics of our assets, our system flexibility,
and our strong emphasis on customer service.
We have made capital expenditures at our Velma processing plant to improve
the efficiency and competitiveness of the facility:
o We utilize electric-powered compressors rather than the higher-cost
natural gas-powered compressors used by many of our competitors which
results in higher revenues from lower fuel costs and higher
efficiency.
o We are one of only two processors in our area of operations that can
process natural gas with high hydrogen sulfide and carbon dioxide
content.
o We provide our customers with higher NGL recovery rates than many of
our competitors in the service area.
Our Velma and Elk City gathering systems provide our customers increased
flexibility:
o Our Velma gathering system provides low pressure service enabling our
customers to produce their wells at higher rates and extend the
economic lives of their wells.
o Our Elk City gathering system provides our customers with superior
access to natural gas markets through multiple pipeline
interconnections.
We believe we provide superior service to our customers as demonstrated by:
o Our willingness to incur upfront capital expenditures to fund pipeline
extensions, well connections and increased compression.
o Our ability to respond quickly on new well connections to enable our
customers to bring their wells on production in an efficient manner.
o Our flexibility to structure competitive and innovative natural gas
purchase, gathering and processing contracts for our customers.
As a result of our strong asset base and system flexibility, over the last
three years only two wells have been withdrawn from our Mid-Continent systems
while, over this same period, we have captured over 138 wells from competing
systems.
BUSINESS STRATEGY
Our primary objective is to increase cash flow and achieve sustainable,
profitable growth while maintaining a strong credit profile and financial
flexibility by executing the following strategies:
Maximize use of facilities and control our operating costs. We intend to
control our operating costs by efficiently managing our existing and acquired
businesses and achieving economies of scale. We have additional capacity in
our gathering systems and have, or can upgrade at minimal cost, the capacity
at our processing and treating facilities. As a result we can readily increase
the amount of natural gas we transport and process. A significant portion of
our gathering systems, as well as the Velma and Elk City processing plants,
have been recently expanded or upgraded.
Expand operations through strategic acquisitions. Our recent acquisitions
have provided geographic diversification and expanded the midstream services
we provide. We intend to continue to make accretive
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acquisitions of midstream energy assets such as natural gas gathering systems
and natural gas and NGL transmission, processing and storage facilities. We
will seek strategic opportunities in our current areas of operation, as well
as other regions of the U.S. with significant natural gas and oil reserves or
with growing demand for natural gas and oil. We believe that there will
continue to be attractive acquisition opportunities in the midstream sector of
the energy industry.
Expand existing systems through new construction. We continually evaluate
opportunities to expand our operations through the construction of pipeline
extensions to connect additional wells and access additional reserves. In
2004, our Velma operation completed a 29-mile, large diameter high-pressure
trunkline to connect natural gas from a new development northwest of our
processing plant, while our Appalachian operations added over 60 miles of
newly-constructed pipelines. We believe that our agreements with Atlas America
present a favorable source of internal growth and that our competitive
position and customer relationships in the Golden Trend area and Anadarko
Basin will continue to yield additional expansion opportunities.
Secure additional long-term, fee-based contracts. We intend to continue to
secure long-term, fee-based contracts both in our existing operations and
through strategic acquisitions in order to reduce further our exposure to
changes in commodity prices.
Maintain a flexible capital structure. To provide financial flexibility to
fund future acquisition and expansion opportunities, we will continue to
opportunistically access the capital markets and maintain a conservative
financial profile. We intend to continue strengthening our balance sheet by
financing growth with a combination of long-term debt and equity. Including
our initial public offering in 2000, we have accessed the equity markets four
times, raising approximately $135.3 million in net proceeds. Upon the
completion of this offering, we also expect to have unused capacity under our
revolving credit facility to finance system expansions, acquisitions and
working capital needs. Historically, because of our financial flexibility, we
have been able to take advantage of opportunities for expansion and
optimization as they arise.
THE MIDSTREAM NATURAL GAS GATHERING AND PROCESSING INDUSTRY
The midstream natural gas gathering and processing industry is characterized
by regional competition based on the proximity of gathering systems and
processing plants to producing natural gas wells.
The natural gas gathering process begins with the drilling of wells into
natural gas or oil bearing rock formations. Once a well has been completed,
the well is connected to a gathering system. Gathering systems generally
consist of a network of small diameter pipelines that collect natural gas from
points near producing wells and transport it to larger pipelines for further
transmission. Gathering systems are operated at design pressures that will
maximize the total throughput from all connected wells.
While natural gas produced in some areas, such as the Appalachian Basin,
does not require treatment or processing, natural gas produced in many other
areas, such as our Velma service area, is not suitable for long-haul pipeline
transportation or commercial use and must be compressed, transported via
pipeline to a central processing facility, and then processed to remove the
heavier hydrocarbon components such as NGLs and other contaminants that would
interfere with pipeline transportation or the end use of the gas. Natural gas
processing plants generally treat (remove carbon dioxide and hydrogen sulfide)
and remove the NGLs, enabling the treated, "dry" gas (stripped of liquids) to
meet pipeline specification for long-haul transport to end users. After being
separated from natural gas at the processing plant, the mixed NGL stream,
commonly referred to as "y-grade" or "raw mix," is typically transported on
pipelines to a centralized facility for fractionation into discrete NGL purity
products: ethane, propane, normal butane, isobutane, and natural gasoline.
OUR APPALACHIAN BASIN OPERATIONS
We own and operate approximately 1,440 miles of intrastate gas gathering
systems and own or lease 56 compressors located in eastern Ohio, western New
York and western Pennsylvania. Our Appalachian operations serve approximately
4,850 wells with an average throughput of 53.3 MMcf/d and 52.4 MMcf/d of
natural gas for the year ended December 31, 2004 and the three months ended
March 31, 2005, respectively.
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Our gathering systems provide a means through which well owners and operators
can transport the natural gas produced by their wells to interstate and public
utility pipelines for delivery to customers. To a lesser extent, our gathering
systems transport natural gas directly to customers. Our gathering systems
connect with public utility pipelines operated by Peoples Natural Gas Company,
National Fuel Gas Supply, Tennessee Gas Pipeline Company, National Fuel Gas
Distribution Company, East Ohio Gas Company, Columbia of Ohio, Consolidated
Natural Gas Co., Texas Eastern Pipeline, Columbia Gas Transmission Corp.
Equitrans Pipeline Company, Gatherco Incorporated, National Gas Company and
Equitable Utilities. Our systems are strategically located in the Appalachian
Basin, a region characterized by long-lived, predictable natural gas reserves
that are close to major eastern U.S. markets.
Appalachian Basin Overview
The Appalachian Basin includes the states of Kentucky, Maryland, New York,
Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most
mature oil and gas producing region in the United States, having established
the first oil production in 1859. In addition, the Appalachian Basin is
strategically located near the energy-consuming regions of the mid-Atlantic
and northeastern United States which has historically resulted in Appalachian
producers selling their natural gas at a premium to the benchmark price for
natural gas on the NYMEX.
According to the Energy Information Administration, a branch of the U.S.
Department of Energy, in 2003 there were 22.4 Tcf of natural gas consumed in
the United States which represented approximately 22.9% of the total energy
used. The Appalachian Basin accounted for approximately 3.3% of total 2003
domestic natural gas production, or 647.9 Bcf. Additionally, in 2003 there
were approximately 145,189 gas wells in the Appalachian Basin which
represented roughly 36.9% of the total number of gas wells in the United
States. Of those wells, Atlas America and its drilling investment partnerships
own interests in approximately 5,755 proved developed producing wells, 84% of
which Atlas America operated in 2004.
Furthermore, according to the Natural Gas Annual 2003, an annual report
published by the Energy Information Administration, Office of Oil and Gas, the
Appalachian Basin holds 10.9 Tcf of economically recoverable gas reserves,
representing approximately 5.8% of total domestic reserves as of December 31,
2003. World Oil magazine, in its February 2005 issue, predicted that
approximately 5,316 oil and gas wells will be drilled in the Appalachian Basin
during 2005, approximately 13.3% of the total number of wells they predict
will be drilled in the United States during 2005, and an increase of 8% over
the number of Appalachian Basin wells estimated to have been drilled during
2004, compared to an increase of 7.2% in the wells drilled in the United
States from 2004 to 2005.
Appalachian Basin Gathering Systems
We set forth in the following table the volumes of the natural gas we
transported, in MMcfs, for the periods indicated:
YEARS ENDED DECEMBER 31,
-------------------------
2004 2003 2002
------ ------ ------
New York systems...................................................................................... 423 450 494
Ohio systems.......................................................................................... 4,685 5,060 5,397
Pennsylvania systems.................................................................................. 14,416 13,642 12,492
------ ------ ------
19,524 19,152 18,383
====== ====== ======
The gathering systems are generally constructed with 2, 4, 6, 8 and 12 inch
cathodically protected and wrapped steel pipe and are generally buried 36
inches below the ground. Pipelines constructed in this manner typically are
expected to last at least 50 years from the date of construction. For the
years ended December 31, 2004, 2003 and 2002, the cost of operating the
gathering systems, excluding depreciation, was approximately $2.3 million,
$2.4 million and $2.1 million, respectively. We do not believe that there are
any significant geographic limitations upon our ability to expand in the areas
served by our Appalachian Basin gathering systems.
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Natural Gas Supply
Substantially all of the natural gas we transport in the Appalachian Basin
is derived from wells operated by Atlas America, the leading sponsor of
natural gas drilling investment partnerships in the Appalachian Basin. Atlas
America is the corporate parent of our general partner and, through it, has a
2% general partner and will have a 16.9% limited partner interest in us after
this offering. We are party to an omnibus agreement with Atlas America which
is intended to maximize the use and expansion of our gathering systems and the
amount of natural gas which we transport in the region. Among other things,
the omnibus agreement requires Atlas America to connect to our gathering
systems wells it operates that are located within 2,500 feet. Atlas America
can require us to extend our lines to connect an Atlas America-operated well
located more than 2,500 feet from our gathering system if it extends a flow
line to within 1,000 feet; for other Atlas America-operated wells located more
than 2,500 feet from our gathering systems, we have a right to extend our
lines. We are also party to natural gas gathering agreements with Atlas
America under which we receive gathering fees generally equal to a percentage,
typically 16%, of the selling price of the natural gas we transport. During
the five years ended December 31, 2004, we connected 1,616 new wells to our
Appalachian gathering system, 433 of which were added through acquisitions of
other gathering systems. Based on Atlas America's announced drilling program,
we expect that we will connect more than 500 Atlas America-operated wells to
our gathering systems in 2005. Our ability to increase the flow of natural gas
through our gathering systems and to offset the natural decline of the
production already connected to our gathering systems will be determined
primarily by the number of wells drilled by Atlas America and connected to our
gathering systems and by our ability to acquire additional gathering assets.
Natural Gas Revenues
Our Appalachian Basin revenues are determined primarily by the amount of
natural gas flowing through our gathering systems and the price received for
this natural gas. We have an agreement with Atlas America under which it pays
us gathering fees generally equal to a percentage, typically 16%, of the gross
or weighted average sales price of the natural gas we transport subject, in
most cases, to minimum prices of $0.35 or $0.40 per Mcf. During the year ended
December 31, 2004 and the three months ended March 31, 2005, we received
gathering fees averaging $0.96 per Mcf and $1.03 per Mcf, respectively, while
during the years ended December 31, 2003 and 2002, our average gathering fees
were $0.82 and $0.58 per Mcf, respectively. We charge other operators fees
negotiated at the time we connect their wells to our gathering systems or, in
a pipeline acquisition, that were established by the entity from which we
acquired the pipeline.
Because we do not buy or sell gas in connection with our Appalachian
operations, we do not engage in hedging. Atlas America maintains a hedging
program. Since we receive transportation fees from Atlas America generally
based on the selling price received by Atlas America, these physical hedges
mitigate the risk of our percentage of proceeds arrangements.
OUR MID-CONTINENT OPERATIONS
We own and operate approximately 2,200 miles of intrastate natural gas
gathering systems, including approximately 800 miles of inactive pipeline, and
own or lease 59 compressors located in Oklahoma and northern Texas, and two
processing plants and one treating facility in Oklahoma. Our Mid-Continent
operations were formed through our acquisition of the Velma operations in July
2004 and expanded through our Elk City acquisition in April 2005. Our
gathering and processing assets service long-lived natural gas basins that
continue to experience an increase in drilling activity, including the
Anadarko Basin and the Golden Trend area of Oklahoma. Our systems gather
natural gas from oil and natural gas wells and process the raw natural gas
into merchantable, or residue gas, by extracting NGLs and removing impurities.
In the aggregate, our Mid-Continent gathering systems have approximately 880
receipt points, consisting primarily of individual connections and,
secondarily, of central delivery points which are linked to multiple wells.
Our gathering systems currently connect with interstate and intrastate
pipelines operated by ONEOK Gas Transportation, LLC, Southern Star Central Gas
Pipeline, Inc., Panhandle Eastern Pipe Line Company, LP, Northern Natural Gas
Company, CenterPoint Energy, Inc., ANR Pipeline Company and Natural Gas
Pipeline Company of America.
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Mid-Continent Overview
The heart of the Mid-Continent region is generally defined as running from
Kansas through Oklahoma, branching into North and West Texas, southeast New
Mexico as well as western Arkansas. The primary producing areas in the region
include the Hugoton field in southwest Kansas, the Anadarko basin in western
Oklahoma, the Permian basin in West Texas and the Arkoma basin in western
Arkansas and eastern Oklahoma.
Oklahoma accounted for approximately 7.8% of total 2003 domestic natural gas
production, or 1.6 Tcf. From 2000 to 2003, Oklahoma reserves, which were 15.4
Tcf at December 31, 2003, grew at an annual compound growth rate of 4.0%,
significantly higher than total domestic reserves which grew at a rate of
2.1%. From 2000 to 2004, natural gas production in Oklahoma grew at a compound
annual rate of 1.2% while domestic natural gas production as a whole decreased
at a compound annual rate of (.6%).
The number of active drilling rigs serving Oklahoma has increased
significantly over the last three years. In 2004, the number of active rigs
drilling in Oklahoma averaged 159 or a 75% increase over 2002. The areas
served by our Velma and Elk City assets have also experienced an increase in
oil and natural gas development as evidenced by a growth in well completions
in the counties that the Elk City System and Velma System serve. In 2004, well
completions in Carter, Garvin, Grady, Stephens, Beckham and Washita counties
totaled 430, a 16% increase compared to 2002.
Processing Plants
Velma. The Velma processing plant, located in Stephens County, Oklahoma, is
a single-train twin-expander cryogenic facility with a natural gas inlet
capacity of approximately 100 MMcf/d. The Velma plant is one of only two
facilities in the area that is capable of treating both high-content hydrogen
sulfide and carbon dioxide gas. We sell natural gas to purchasers at the
tailgate of the Velma plant and sell NGL production to Koch. The plant
processed an average of 63 MMcf/d for the three months ended March 31, 2005, a
42% increase over the three months ended March 31, 2004. Our Velma operations
gather and process natural gas for approximately 155 producers.
Enville. Our Enville, Oklahoma gas plant is currently inactive and is used
as a field compression booster station.
Elk City. The Elk City processing plant, located in Beckham County,
Oklahoma, is a twin-train cryogenic natural gas processing plant with a total
capacity of approximately 130 MMcf/d. We sell natural gas to purchasers at the
tailgate of our Elk City processing plant and sell NGL production to Koch. The
plant processed an average of 119 MMcf/d for the three months ended
February 28, 2005, a 4% decrease over the three months ended February 29,
2004. The Prentiss treating facility, also located in Beckham County, is an
amine treating facility with a total capacity of approximately 200 MMcf/d. The
Prentiss facility treated and blended an average of 126 MMcf/d for the three
months ended February 28, 2005, a 46% increase over the three months ended
February 29, 2004. Our Elk City operations gather and process gas for
approximately 135 producers. We recently began work on four new gathering and
compression projects which will increase gathered volumes and, we believe,
have a significant positive effect on our earnings.
Mid-Continent Gathering Systems
Velma. The Velma gathering system is located in Southern Oklahoma and North
Texas, principally in the Golden Trend area. As of March 31, 2005, the
gathering system had approximately 1,100 miles of active pipeline with
approximately 580 receipt points consisting primarily of individual
connections and, secondarily, of central delivery points which are linked to
multiple wells. The system includes approximately 800 miles of inactive
pipeline, much of which can be returned to active status as local drilling
activity warrants. Gathered volumes averaged 65 MMcf/d for the three months
ended March 31, 2005, a 35% increase over the three months ended March 31,
2004. The following table shows the average daily volumes of natural gas
gathered by the Velma system, in MMcfs, for the periods indicated:
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Year ended December 31, 2004 ............................................ 54.3
Year ended December 31, 2003 ............................................ 47.1
Year ended December 31, 2002 ............................................ 47.6
Elk City. The Elk City gathering system includes approximately 300 miles of
natural gas pipelines located in the Anadarko Basin in western Oklahoma. The
Elk City gathering system connects to over 300 receipt points, with a majority
of the western end of the system located in close proximity to areas of high
drilling activity. Gathered volumes averaged 255 MMcf/d for the three months
ended February 28, 2005, a 17% increase over the three months ended
February 29, 2004. The following table shows the average daily volumes of
natural gas gathered by the Elk City system, in MMcfs, for the periods
indicated:
Twelve months ended November 30, 2004 .................................... 235
Twelve months ended November 30, 2003 .................................... 187
Twelve months ended November 30, 2002 .................................... 139
Natural Gas Supply
We have gas purchase, gathering and processing contracts with approximately
250 producers in connection with our Mid-Continent operations under fixed-fee,
percentage of proceeds or keep-whole arrangements. In addition, most of the
contracts include compression fees, treating fees, and/or low volume fees,
which we are entitled to charge in instances where a producer's deliveries do
not meet a pre-determined level. Producers provide, in-kind, their
proportionate share of the fuel required to gather the gas and operate the
Velma and Elk City processing plants. In addition, the producers bear their
proportionate share of all other plant shrinkage and gathering system line
loss.
We have enjoyed long-term relationships with the majority of our
Mid-Continent producers. On the Velma system, where we have producer
relationships going back over 20 years, our top four producers, which
accounted for approximately 60% of our Velma volumes for the year ended
December 31, 2004, have recently executed renegotiated contracts with primary
terms running into 2009 and 2010. On our Elk City system, where we also have
some 20 year relationships, the top four producers, which accounted for 74% of
our Elk City volumes for the year ended December 31, 2004, have long-term
contracts with primary terms expiring in 2006 and 2009. Most of our Velma
producers have year-to-year evergreen term extensions in their contracts while
the Elk City producers have month-to-month evergreen language in their
contracts.
Natural Gas and NGL Marketing
We sell natural gas to purchasers at the tailgate of both the Velma and Elk
City plants. During the year ended December 31, 2004, in our Velma operations,
ONEOK Energy Marketing and Trading accounted for 31% of our residue natural
gas sales and Tenaska Marketing Ventures accounted for 12% of such sales. We
currently sell the majority of our residue natural gas at the average of ONEOK
Gas Transportation, LLC and Southern Star Central Gas Pipeline first-of-month
indices as published in Inside FERC. The Velma plant has access to ONEOK Gas
Transportation, an intrastate pipeline, and Southern Star Central Gas
Pipeline, an interstate pipeline. In our Elk City operations, we sell
substantially all of our residue gas to ETC Marketing, Ltd. at first-of-month
index pricing. In April 2005, we began selling 10,000 MMbtu/d to Seminole
Energy Services under a seasonal April to October arrangement. The Elk City
plant has access to five major interstate and intrastate downstream pipelines:
Natural Gas Pipeline of America, Panhandle Eastern Pipe Line Co., CenterPoint
Energy Gas Transmission Company, Northern Natural Gas Company and Enogex, Inc.
We sell our NGL production to Koch under two separate agreements. Under the
Velma agreement, we have the right to elect on a monthly basis until
January 31, 2006 whether the NGLs are sold into the Mont Belvieu or Conway
markets. After that, NGLs will be sold on a 50% Mont Belvieu/50% Conway
combined price. NGLs are priced at the average monthly Oil Price Information
Service, or OPIS, price for the selected market. The Velma agreement has an
initial term expiring February 1, 2011. NGL production from our Elk City plant
is also sold to Koch based on Conway OPIS postings. The Elk City agreement has
an initial term expiring October 1, 2008.
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Condensate is collected at the Velma gas plant and around the Velma
gathering system and sold for our account to SemGroup, L.P. and EnerWest
Trading.
Natural Gas and NGL Hedging
Our Mid-Continent operations are exposed to certain commodity price risks.
These risks result from either (a) taking title to natural gas and NGLs
(including condensate) or (b) being obligated to purchase natural gas to
satisfy contractual obligations with certain producers. We mitigate a portion
of these risks through a comprehensive risk management program which employs a
variety of hedging tools. The resulting combination of the underlying physical
business and the financial risk management program is a conversion from a
physical environment that consists of floating prices to a risk-managed
environment that is characterized by fixed prices.
We (a) purchase natural gas and subsequently sell processed natural gas and
the resulting NGLs, or (b) purchase natural gas and subsequently sell the
unprocessed gas, or (c) transport and/or process the natural gas for a fee
without taking title to the commodities. Scenario (b) exposes us to a
generally neutral price risk (long sales approximate short purchases) while
scenario (c) does not expose us to any price risk; in both scenarios, risk
management is not required.
We are exposed to commodity price risks when natural gas is purchased for
processing. The amount and character of this price risk is a function of our
contractual relationships with natural gas producers, or, alternatively, a
function of cost of sales. We are therefore exposed to price risk at a gross
profit level rather than revenue level. These cost-of-sales or contractual
relationships are generally of two types:
o Percentage of proceeds: require us to pay a percentage of revenue to
the producer. This results in us being net long physical natural gas
and NGLs.
o Keep-whole: require us to deliver the same quantity of natural gas at
the delivery point as we received at the receipt point; any resulting
NGLs produced belong to us. This results in our being long physical
NGLs and short physical natural gas.
We hedge a portion of these risks by using fixed-for-floating swaps, which
result in a fixed price, or by utilizing the purchase or sale of options,
which result in a range of fixed prices. A summary of these business
scenarios/contractual relationships and the corresponding risk management, if
any, is illustrated in the following table:
PHYSICAL FINANCIAL FINANCIAL NET
FLOATING + FLOATING + FIXED = POSITION
---------------------------------------------------------------------------------------------------------------------------------
POP (NATURAL GAS) LONG (GREATER (LESS LONG FIXED LONG
P THAN) SHORT THAN)
R ---------------------------------------------------------------------------------------------------------------------------------
O POP (NGL) LONG (GREATER (LESS LONG FIXED LONG
C THAN) SHORT THAN)
E ---------------------------------------------------------------------------------------------------------------------------------
S KEEP-WHOLE (NATURAL GAS) (GREATER (LESS LONG (GREATER (LESS FIXED (GREATER (LESS
S THAN) SHORT THAN) THAN) SHORT THAN) THAN) SHORT THAN)
I ---------------------------------------------------------------------------------------------------------------------------------
N KEEP-WHOLE (NGL) LONG SHORT LONG FIXED LONG
G ---------------------------------------------------------------------------------------------------------------------------------
MERCHANT (BUY-SELL) NEUTRAL N/A N/A NEUTRAL
----------------------------------------------------------------------------------------------------------------------------
TRANSPORT (FEE) N/A N/A N/A N/A
----------------------------------------------------------------------------------------------------------------------------
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We recognize gains and losses from the settlement of our hedges in revenue
when we sell the associated physical residue natural gas or NGLs. Any gain or
loss realized as a result of hedging is substantially offset in the market
when we sell the physical residue natural gas or NGLs. All of our hedges are
characterized as cash flow hedges as defined in SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Accounting." We determine gains or losses
on open and closed hedging transactions as the difference between the hedge
price and the physical price. This mark-to-market methodology uses daily
closing NYMEX prices when applicable and an internally-generated algorithm for
hedged commodities that are not traded on a market. To insure that these
financial instruments will be used solely for hedging price risks and not for
speculative purposes, we have established a hedging committee to review our
hedges for compliance with our hedging policies and procedures. In addition,
we do not enter into a hedge where we cannot offset the hedge with physical
residue natural gas or NGL sales.
As of May 10, 2005, we had the following natural gas, plant reduction, NGL
and crude oil volumes hedged.
NATURAL GAS FIXED - PRICE SWAPS
PRODUCTION PERIOD
ENDED DECEMBER 31, VOLUMES AVERAGE FIXED PRICE FAIR VALUE LIABILITY(1)
------------------ (MMbtu) (PER MMbtu) (IN THOUSANDS)
--------- ------------------- -----------------------
2005 840,000 $6.24 $ (693)
2006 1,200,000 $6.98 (314)
2007 720,000 $7.10 165
------
$(842)
======
NATURAL GAS BASIS SWAPS
PRODUCTION PERIOD
ENDED DECEMBER 31, VOLUMES AVERAGE FIXED PRICE FAIR VALUE LIABILITY(2)
------------------ (MMbtu) (PER MMbtu) (IN THOUSANDS)
--------- ------------------- -----------------------
2005 770,000 $(0.50) $ (5)
2006 1,200,000 $(0.55) (69)
2007 720,000 $(0.52) (18)
----
$(92)
====
PLANT VOLUME REDUCTION FIXED - PRICE SWAPS
PRODUCTION PERIOD
ENDED DECEMBER 31, VOLUMES AVERAGE FIXED PRICE FAIR VALUE LIABILITY(1)
------------------ (MMbtu) (PER MMbtu) (IN THOUSANDS)
---------- ------------------- -----------------------
2005 (900,000) $7.15 $(14)
2006 (1,800,000) $7.26 (21)
----
$(35)
====
PLANT VOLUME REDUCTION BASIS SWAPS
PRODUCTION PERIOD
ENDED DECEMBER 31, VOLUMES AVERAGE FIXED PRICE FAIR VALUE LIABILITY(2)
------------------ (MMbtu) (PER MMbtu) (IN THOUSANDS)
---------- ------------------- -----------------------
2005 (900,000) $(0.46) $ (31)
2006 (1,800,000) $(0.50) 2
-----
$(29)
=====
NATURAL GAS LIQUIDS FIXED - PRICE SWAPS
PRODUCTION PERIOD
ENDED DECEMBER 31, VOLUMES AVERAGE FIXED PRICE FAIR VALUE LIABILITY(2)
------------------ (GALLONS) (PER GALLON) (IN THOUSANDS)
---------- ------------------- -----------------------
2005 22,256,000 $0.65 $ (1,536)
2006 35,784,000 $0.67 (1,677)
2007 9,072,000 $0.69 (177)
--------
$(3,390)
========
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CRUDE OIL FIXED - PRICE SWAPS
PRODUCTION PERIOD
ENDED DECEMBER 31, VOLUMES AVERAGE FIXED PRICE FAIR VALUE LIABILITY(2)
------------------ (Bbl) (PER Bbl) (IN THOUSANDS)
------- ------------------- -----------------------
2005 13,500 $57.00 $ 42
2006 63,600 $48.61 (276)
2007 30,000 $52.78 56
-----
$(178)
=====
CRUDE OIL OPTIONS
PRODUCTION PERIOD
ENDED DECEMBER 31, VOLUMES AVERAGE FIXED PRICE FAIR VALUE LIABILITY(1)
------------------ OPTION TYPE (Bbl) (PER Bbl) (IN THOUSANDS)
-------------- ------- ------------------- -----------------------
2005 Puts purchased 40,000 $30.00 $ --
2005 Calls sold 40,000 $34.25 (777)
--------
$ (777)
========
Total liability $(5,342)
========
---------------
(1) Fair value based on forward NYMEX natural gas and light crude prices, as
applicable.
(2) Fair value based on our internal model which forecasts forward natural
gas liquid prices as a function of forward NYMEX natural gas and light
crude prices.
RECENT ACQUISITIONS
Acquisition of Elk City. In April 2005, we acquired our Elk City operations
for approximately $194.4 million, including transaction costs. The purchase
price is subject to post-closing adjustment based, among other things, on gas
imbalances, certain prepaid costs and expenses and capital expenditures, and
title defects, if any.
We financed the Elk City acquisition, including approximately $2.8 million
of transaction costs, by borrowing $45.0 million of the term loan portion and
$204.5 million of the revolving loan portion of our current $270.0 million
senior secured term loan and revolving credit facility administered by
Wachovia Bank, National Association. We describe this credit facility in "--
Credit Facility."
Acquisition of Velma. In July 2004, we acquired our Velma operations, which
we describe in "-- Our Mid-Continent Operations." The purchase price was
$142.4 million, including transaction costs and taxes due as a result of the
transaction.
We financed the Velma acquisition, including approximately $4.2 million of
transaction costs, as follows:
o borrowing $100 million under the term loan portion of our then $135
million senior secured term loan and revolving credit facility
administered by Wachovia Bank, National Association;
o using the $20 million of net proceeds received from the sale to
Resource America and Atlas America of preferred units in our operating
subsidiary; and
o using $22.4 million of the net proceeds from our April 2004 common
unit offering.
We subsequently used a portion of the net proceeds of our July 2004 offering
to repay $40 million of the credit facility borrowings and to repurchase for
$20.4 million the preferred units issued to Resource America and Atlas
America.
CREDIT FACILITY
Concurrently with the completion of the Elk City acquisition, in April 2005,
we entered into a $270 million senior secured term loan and revolving credit
facility administered by Wachovia Bank that replaced
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our $135 million facility. The facility includes a $225 million five-year
revolving line of credit and a $45 million five-year term loan. Up to $10
million of the facility may be used for standby letters of credit. We borrowed
$204.5 million under the revolving loan facility and $45 million under the
term loan facility to fund the acquisition of our Elk City operations. We
intend to use the proceeds of this offering to repay the term loan and pay
approximately $46.6 million of the revolving credit loan. Borrowings under the
facility are secured by a lien on and security interest in all of our property
and that of our subsidiaries and by a guaranty of each of our subsidiaries.
The credit facility bears interest at one of two rates, elected at our
option:
o the base rate plus the applicable margin; or
o the adjusted LIBOR plus the applicable margin.
The base rate for any day equals the higher of the federal funds rate plus
1/2 of 1% or the Wachovia Bank prime rate. The applicable margin for the
revolving line of credit is as follows:
o where our funded debt ratio, that is, the ratio of our debt to our
earnings before interest, taxes, depreciation and amortization, or
EBITDA, is less than or equal to 2.5, the applicable margin is 0.50%
for base rate loans and 1.50% for LIBOR loans;
o where our funded debt ratio is greater than 2.5 but less than or equal
to 3.0, the applicable margin is 0.75% for base rate loans and 1.75%
for LIBOR loans;
o where our funded debt ratio is greater than 3.0 but less than or equal
to 3.5, the applicable margin is 1.00% for base rate loans and 2.00%
for LIBOR loans;
o where our funded debt ratio is greater than 3.5 but less than or equal
to 4.0, the applicable margin will be 1.25% for base rate loans and
2.25% for LIBOR loans;
o where our funded debt ratio is greater than 4.0 but less than or equal
to 4.5, the applicable margin will be 1.5% for base rate loans and
2.5% for LIBOR loans; and
o where our funded debt ratio is greater than 4.5, the applicable margin
will be 1.75% for base rate loans and 2.75% for LIBOR loans.
The applicable margin is reduced by 0.5% if the ratio of our senior secured
debt to EBITDA is less than 1.5.
The credit facility requires us to maintain a ratio of senior secured debt
to EBITDA of not more than 5.5 to 1.0, reducing to 4.5 to 1.0 on September 30,
2005 and 3.5 to 1.0 on March 31, 2006; a funded debt to EBITDA ratio of not
more than 5.5 to 1.0, reducing to 4.5 to 1.0 on September 30, 2005; and an
interest coverage ratio of not less than 3.0 to 1.0. In addition, we will be
required to prepay amounts outstanding under the revolving loan with the net
proceeds of any asset sales or issuances of debt to the extent our ratio of
senior secured debt to EBITDA exceeds 3.5 to 1.0. The credit facility defines
EBITDA to include pro forma adjustments, acceptable to Wachovia Bank as
administrator of the facility, following material acquisitions. This
calculation differs materially from the calculation set forth in
"Summary--Summary Historical Consolidated Financial and Other Data."
The credit agreement contains covenants customary for loans of this size,
including restrictions on incurring additional debt and making material
acquisitions, and a prohibition on paying distributions to our unitholders if
an event of default occurs. We are permitted to have up to $250 million of
senior unsecured debt and up to $500,000 in other debt. The events which
constitute an event of default are also customary for loans of this size,
including payment defaults, breaches of our representations or covenants
contained in the credit agreement, adverse judgments against us in excess of a
specified amount, and a change of control of our general partner.
OUR RELATIONSHIP WITH ATLAS AMERICA
We began our operations in January 2000 by acquiring the gathering systems
of Atlas America. Atlas America will own a 16.9% limited partner interest and
a 2% general partner interest in us after this offering through its ownership
of our general partner, Atlas Pipeline Partners GP. Atlas America and its
affiliates
S-41
sponsor limited and general partnerships to raise funds from investors to
explore for, develop and produce natural gas and, to a lesser extent, oil from
locations in eastern Ohio, western New York and western Pennsylvania. Our
gathering systems are connected to approximately 4,300 wells developed and
operated by Atlas America in the Appalachian Basin. Through agreements between
us and Atlas America, we gather substantially all of the natural gas for our
Appalachian Basin operations from wells operated by Atlas America.
Omnibus Agreement
Under the omnibus agreement, Atlas America and its affiliates agreed to add
wells to the gathering systems and provide consulting services when we
construct new gathering systems or extend existing systems. The omnibus
agreement also imposes conditions upon our general partner's disposition of
its general partner interest in us. The omnibus agreement is a continuing
obligation, having no specified term or provisions regarding termination
except for a provision terminating the agreement if our general partner is
removed as general partner without cause.
Well Connections. Under the omnibus agreement, with respect to any well
Atlas America drills and operates for itself or an affiliate, or Atlas America
Well, that is within 2,500 feet of one of our gathering systems, Atlas America
must, at its sole cost and expense, construct small diameter (two inches or
less) sales or flow lines from the wellhead of any such well to a point of
connection to the gathering system. Where an Atlas America Well is located
more than 2,500 feet from one of our gathering systems, but Atlas America has
extended the flow line from the well to within 1,000 feet of the gathering
system, Atlas America has the right to require us, at our cost and expense, to
extend our gathering system to connect to that well. With respect to other
Atlas America Wells that are more than 2,500 feet from our gathering systems,
we have the right, at our cost and expense, to extend our gathering system to
within 2,500 feet of the well and to require Atlas America, at its cost and
expense, to construct up to 2,500 feet of flow line to connect to the
gathering system extension. If we elect not to exercise our right to extend
our gathering systems, Atlas America may connect an Atlas America Well to a
natural gas gathering system owned by someone other than us or one of our
subsidiaries or to any other delivery point; however, we will have the right
to assume the cost of construction of the necessary flow lines, which then
become our property and part of our gathering systems.
Consulting Services. The omnibus agreement requires Atlas America to assist
us in identifying existing gathering systems for possible acquisition and to
provide consulting services to us in evaluating and making a bid for these
systems. Atlas America must give us notice of identification by it or any of
its affiliates of any gathering system as a potential acquisition candidate,
and must provide us with information about the gathering system, its seller
and the proposed sales price, as well as any other information or analyses
compiled by Atlas America with respect to the gathering system. We will have
30 days to determine whether we want to acquire the identified system and
advise Atlas America of our intent. If we intend to acquire the system, we
have an additional 60 days to complete the acquisition. If we do not complete
the acquisition, or advise Atlas America that we do not intend to acquire the
system, then Atlas America may do so.
Gathering System Construction. The omnibus agreement requires Atlas America
to provide us with construction management services if we determine to expand
one or more of our gathering systems. We must reimburse Atlas America for its
costs, including an allocable portion of employee salaries, in connection with
its construction management services.
Disposition of Interest in Our General Partner. Direct and indirect
wholly-owned subsidiaries of Atlas America act as the general partners,
operators or managers of the drilling investment partnerships sponsored by
Atlas America. Our general partner is a subsidiary of Atlas America. Under the
omnibus agreement, those subsidiaries, including our general partner, that
currently act as the general partners, operators or managers of partnerships
sponsored by Atlas America must also act as the general partners, operators or
managers for all new drilling investment partnerships sponsored by Atlas
America. Atlas America and its affiliates may not divest their ownership of
one entity without divesting their ownership of the other entities to the same
acquirer. For these purposes, divestiture means a sale of all or substantially
all of the assets of an entity, the disposition of more than 50% of the
capital stock or equity interest of an entity, or a merger or consolidation
S-42
that results in Atlas America and its affiliates, on a combined basis, owning,
directly or indirectly, less than 50% of the entity's capital stock or equity
interest.
Natural Gas Gathering Agreements
Under the master natural gas gathering agreement, we receive a fee from
Atlas America for gathering natural gas, determined as follows:
o for natural gas from well interests allocable to Atlas America or its
affiliates (excluding general or limited partnerships sponsored by
them) that were connected to our gathering systems at February 2,
2000, the greater of $0.40 per Mcf or 16% of the gross sales price of
the natural gas transported;
o for (i) natural gas from well interests allocable to general and
limited partnerships sponsored by Atlas America that drill wells on or
after December 1, 1999 that are connected to our gathering systems
(ii) natural gas from well interests allocable to Atlas America or its
affiliates (excluding general or limited partnerships sponsored by
them) that are connected to our gathering systems after February 2,
2000, and (iii) well interests allocable to third parties in wells
connected to our gathering systems at February 2, 2000, the greater of
$0.35 per Mcf or 16% of the gross sales price of the natural gas
transported; and
o for natural gas from well interests operated by Atlas America and
drilled after December 1, 1999 that are connected to a gathering
system that is not owned by us and for which we assume the cost of
constructing the connection to that gathering system, an amount equal
to the greater of $0.35 per Mcf or 16% of the gross sales price of the
natural gas transported, less the gathering fee charged by the other
gathering system.
Atlas America receives gathering fees from contracts or other arrangements
with third party owners of well interests connected to our gathering systems.
However, Atlas America must pay gathering fees owed to us from its own
resources regardless of whether it receives payment under those contracts or
arrangements.
The master natural gas gathering agreement is a continuing obligation and,
accordingly, has no specified term or provisions regarding termination.
However, if our general partner is removed as our general partner without
cause, then no gathering fees will be due under the agreement with respect to
new wells drilled by Atlas America.
In addition to the master natural gas gathering agreement, we have three
other gas gathering agreements with subsidiaries of Atlas America. Under two
of these agreements, relating to wells located in southeastern Ohio which
Atlas America acquired from Kingston Oil Corporation and wells located in
Fayette County, Pennsylvania which Atlas America acquired from American
Refining and Exploration Company, we receive a fee of $0.80 per Mcf. Under the
third agreement, which covers wells owned by third parties unrelated to Atlas
America or the investment partnerships it sponsors, we receive fees that range
between $0.20 to $0.29 per Mcf or between 10% to 16% of the weighted average
sales price for the natural gas we transport.
COMPETITION
We have encountered competition in acquiring midstream assets owned by third
parties. In several instances we submitted bids in auction situations and in
direct negotiations for the acquisition of such assets and were either outbid
by others or were unwilling to meet the sellers' expectations. In the future,
we expect to encounter equal if not greater competition for midstream assets
because, as natural gas prices increase, the economic attractiveness of owning
such assets increases.
Appalachian Basin. Our Appalachian Basin operations do not encounter direct
competition in their service areas since Atlas America controls the majority
of the drillable acreage in each area. However, because our Appalachian Basin
operations principally serve wells drilled by Atlas America, we are affected
by competitive factors affecting Atlas America's ability to obtain properties
and drill wells, which affects our ability to expand our gathering systems and
to maintain or increase the volume of natural gas we transport and, thus, our
transportation revenues. Atlas America also may encounter competition in
obtaining drilling services from third-party providers. Any competition it
encounters could delay Atlas America in drilling wells
S-43
for its sponsored partnerships, and thus delay the connection of wells to our
gathering systems. These delays would reduce the volume of gas we otherwise
would have transported, thus reducing our potential transportation revenues.
As our omnibus agreement with Atlas America generally requires it to connect
wells it operates to our system, we do not expect any direct competition in
connecting wells drilled and operated by Atlas America in the future. In
addition, we occasionally connect wells operated by third parties. During 2004
and the first quarter of 2005, we did not connect any such wells.
Mid-Continent. In our Mid-Continent service area, we compete for the
acquisition of well connections with several other gathering/servicing
operations. These operations include plants operated by Duke Energy Field
Services, ONEOK Field Services, Enbridge and Enogex. We believe that the
principal factors upon which competition for new well connections is based
are:
o the price received by an operator for its production after deduction
of allocable charges, principally the use of the natural gas to
operate compressors; and
o responsiveness to a well operator's needs.
We believe that our electric compressors operate more efficiently than the
gas-operated compressors used by our competitors. As a result, we believe that
we can operate as or more cost-effectively than our competitors. We also
believe that our relationships with operators connected to our system are good
and that we present an attractive alternative for producers. During the past
three years, only two wells have been withdrawn from our Mid-Continent
systems, while, over the same period, we have taken over 138 wells from our
competitors to these systems. However, if we cannot compete successfully, we
may be unable to obtain new well connections and, possibly, could lose wells
already connected to our systems.
REGULATION
Federal Regulation. Under the Natural Gas Act, the Federal Energy
Regulatory Commission regulates various aspects of the operations of any
"natural gas company," including the transportation of natural gas, rates and
charges, construction of new facilities, extension or abandonment of services
and facilities, the acquisition and disposition of facilities, reporting
requirements, and similar matters. However, the Natural Gas Act definition of
a "natural gas company" requires that the company be engaged in the
transportation of natural gas in interstate commerce, or the sale in
interstate commerce of natural gas for resale. Since we believe that each of
our individual gathering systems perform primarily gathering functions, we
believe that we are not subject to regulation under the Natural Gas Act. If we
were determined to be a natural gas company, our operations would become
regulated under the Natural Gas Act. We believe the expenses associated with
seeking certificates of authority for construction, service and abandonment,
establishing rates and a tariff for our gas gathering activities, and meeting
the detailed regulatory accounting and reporting requirements under the
Natural Gas Act would substantially increase our operating costs and would
adversely affect our profitability, thereby reducing our ability to make
distributions to unitholders.
State Regulation. Our operations are subject to regulation by the Public
Utility Commission of Ohio, the New York Public Service Commission and the
Pennsylvania Public Utilities Commission. Our Mid-Continent operations are
subject to regulation by the Oklahoma Corporation Commission and the Texas
Railroad Commission.
In Ohio, a producer or gatherer of natural gas may file an application
seeking exemption from regulation as a public utility. We have been granted an
exemption by the Public Utility Commission of Ohio for our Ohio facilities.
The New York Public Service Commission imposes traditional public utility
regulation on the transportation of natural gas by companies subject to its
regulation. This regulation includes rates, services and siting authority for
the construction of certain facilities. Our gas gathering operations currently
are not subject to regulation by the New York Public Service Commission. Our
operations in Pennsylvania currently are not subject to the Pennsylvania
Public Utility Commission's regulatory authority since they do not provide
service to the public generally and, accordingly, do not constitute the
operation of a public utility. In the event the New York and Pennsylvania
authorities seek to regulate our operations, we believe that our
S-44
operating costs could increase and our transportation fees could be adversely
affected, thereby reducing our net revenues and ability to make distributions
to unitholders.
Our Mid-Continent operations are subject to regulation by the Oklahoma
Corporation Commission and the Texas Railroad Commission. The state of
Oklahoma has adopted a complaint-based statute that allows the Oklahoma
Corporation Commission to remedy discriminatory rates for providing gathering
service where the parties are unable to agree. In a similar way, the Texas
Railroad Commission sponsors a complaint procedure for resolving grievances
about natural gas gathering access and rate discrimination. No such complaint
has been made against our Mid-Continent operations to date in either Oklahoma
or Texas.
Environmental and Safety Regulation. Under the Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA, the Toxic Substances
Control Act, the Resource Conservation and Recovery Act, or RCRA, the Clean
Air Act, the Clean Water Act and other federal and state laws relating to
discharges of materials into the environment or otherwise protective of the
environment, owners and operators of natural gas pipelines and associated
storage and processing facilities can be liable, sometimes on a strict, joint
and several basis, for fines, penalties investigatory and remedial costs, and
compliance costs including capital expenditures with respect to pollution
caused by the pipelines and associated facilities. Moreover, the owners' and
operators' liability can extend to pollution costs that arose from activities
or incidents that occurred prior to such owners' or operators' acquisition of
the pipelines and associated facilities, even in circumstances where the
current owner or operator did not cause or contribute to the pollution.
We own, lease or operate properties that in the past have been subject to
pipeline gathering and/or oil and gas processing activities. Although we have
used operating and disposal practices that were standard in the industry at
the time, hydrocarbons and wastes may have been disposed of or released on or
under these properties or on or under other locations where such materials
have been taken for disposal. A number of these properties have been operated
by previous owners or operators whose environmental activities were not under
our control. These properties and the hydrocarbons and wastes disposed thereon
may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we
could be required to remove or remediate previously disposed hydrocarbons,
hazardous substances, or wastes or property contamination, or to perform
investigatory and remedial actions to prevent future contamination.
Natural gas pipelines are also subject to safety regulation, administered by
state regulators, under the Natural Gas Pipeline Safety Act of 1968 and the
Pipeline Safety Act of 1992 which, among other things, dictate the type of
pipeline, quality of pipeline, depth, methods of welding and other
construction-related standards and subjects pipelines to regular inspections.
The state public utility regulators in our service areas have either adopted
the federal standards or promulgated their own safety requirements consistent
with federal regulations. Although we believe that our gathering systems
comply in all material respects with applicable environmental and safety
regulations, risks of substantial costs and liabilities are inherent in
pipeline operations, and we cannot assure you that we will not incur these
costs and liabilities. Moreover, it is possible that other developments, such
as increasingly rigorous environmental laws, regulations and enforcement
policies, and claims for damages to property or persons resulting from our
operations, could result in substantial costs and liabilities to us.
We are also subject to the requirements of the Occupational Safety and
Health Act, or OSHA, and comparable state statutes. We believe that our
operations comply in all material respects with OSHA requirements, including
general industry standards, record keeping, hazard communication requirements
and monitoring of occupational exposure and other regulated substances.
We have not expended and do not anticipate that we will be required in the
near future to expend, amounts that are material in relation to our revenues
by reason of environmental and safety laws. However, we cannot predict
legislative or regulatory developments or the costs of compliance with those
developments. In general, however, we anticipate that new laws, regulations or
policies will increase our operating costs and impose additional capital
expenditure requirements on us.
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EMPLOYEES
As is commonly the case with publicly traded limited partnerships, we do not
directly employ any of the persons responsible for our management or
operations. In general, employees of Atlas America manage our gathering
systems and operate our business. Affiliates of our general partner will
conduct business 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 between us, our general
partner and affiliates of our general partner for the time and effort of the
officers and employees who provide services to our general partner. The
officers of our general partner who provide services to us are not required to
work full time on our affairs. These officers may devote significant time to
the affairs of our general partner's affiliates and be compensated by these
affiliates for the services rendered to them. There may be significant
conflicts between us and affiliates of our general partner regarding the
availability of these officers to manage us.
PROPERTIES
As of December 31, 2004 our principal facilities in Appalachia include
approximately 1,440 miles of 2 to 12 inch diameter pipeline and 56
compressors, of which four are leased. Our principal facilities in the
Mid-Continent area consist of three natural gas processing plants,
approximately 2,200 miles of active and inactive 2-to-42 inch diameter
pipeline, and 59 compressors, of which eight are leased. Substantially all of
our gathering systems are constructed within rights-of-way granted by property
owners named in the appropriate land records. In a few cases, property for
gathering system purposes was purchased in fee. All of our compressor stations
are located on property owned in fee or on property under long-term leases.
Our property or rights-of-way are subject to encumbrances, restrictions and
other imperfections, although these imperfections have not interfered, and our
general partner does not expect that they will materially interfere with the
conduct of our business. In many instances, lands over which rights-of-way
have been obtained are subject to prior liens which have not been subordinated
to the right-of-way grants. In a few instances, our rights-of-way are
revocable at the election of the land owners. In some cases, not all of the
owners named in the appropriate land records have joined in the right-of-way
grants, but in substantially all such cases signatures of the owners of
majority interests have been obtained. Substantially all permits have been
obtained from public authorities to cross over or under, or to lay facilities
in or along, water courses, county roads, municipal streets, and state
highways, where necessary, although in some instances these permits are
revocable at the election of the grantor. Substantially all permits have also
been obtained from railroad companies to cross over or under lands or
rights-of-way, many of which are also revocable at the grantor's election.
Certain of our rights to lay and maintain pipelines are derived from
recorded gas well leases, for wells that are currently in production; however,
the leases are subject to termination if the wells cease to produce. In some
of these cases, the right to maintain existing pipelines continues in
perpetuity, even if the well associated with the lease ceases to be
productive. In addition, because many of these leases affect wells at the end
of lines, these rights-of-way will not be used for any other purpose once the
related wells cease to produce.
We rent 8,000 square feet of office space through July 2005 and 12,222
square feet of office space through November 2009 in Tulsa, Oklahoma for our
Mid-Continent operations. For a description of our natural gas processing
plants, see "-- Our Mid-Continent Operations -- Processing Plants."
LEGAL PROCEEDINGS
On March 9, 2004, the Oklahoma Tax Commission filed a petition against
Spectrum alleging that Spectrum underpaid gross production taxes beginning in
June 2000. The OTC is seeking a settlement of $5.0 million plus interest and
penalties. We plan on defending ourselves vigorously. We have asserted a claim
for indemnification by Chevron under the provisions of our contract with it.
Chevron has acknowledged our claim notice pursuant to which Chevron will be
responsible for the payment of any underpayment of taxes, which would be the
basis for any monetary judgment against us, but Chevron will reserve the
issues of payment of penalties and reimbursement of our attorneys fees and
costs for determination by arbitration following the end of the litigation. In
addition, under the terms of the Spectrum purchase agreement, $14.0
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million has been placed in escrow to cover the costs of any adverse settlement
resulting from the petition and other indemnification obligations of the
purchase agreement.
In September 2003, we entered into an agreement with SEMCO Energy, Inc. to
purchase all of the stock of Alaska Pipeline Company. In order to complete the
acquisition, we needed the approval of the Regulatory Commission of Alaska.
The Regulatory Commission initially approved the transaction, but on June 4,
2004 it vacated its order of approval based upon a motion for clarification or
reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent us a notice
purporting to terminate the transaction. We pursued our remedies under the
acquisition agreement. On December 30, 2004, we entered into a settlement
agreement with SEMCO settling all issues and matters related to SEMCO's
termination of the sale of Alaska Pipeline Company to us and SEMCO paid us
$5.5 million. In connection with the acquisition, subsequent termination, and
settlement of the legal action, we incurred costs of approximately $4.0
million in the year ended December 31, 2004.
We are not subject to any other pending legal proceedings.
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MANAGEMENT
DIRECTORS, EXECUTIVE OFFICERS AND OTHER KEY EMPLOYEES
Our general partner manages our activities. Our unitholders do not directly
or indirectly participate in our management or operation or have actual or
apparent authority to enter into contracts on our behalf or to otherwise bind
us. Our general partner will be liable, as general partner, for all of our
debts to the extent not paid, except to the extent that indebtedness or other
obligations incurred by us are specifically with recourse only to our assets.
Whenever possible, our general partner intends to make any of our indebtedness
or other obligations with recourse only to our assets.
Three members of the managing board of our general partner who are neither
officers nor employees of our general partner nor directors, managing board
members, officers or employees of any affiliate of our general partner (and
have not been for the past five years) serve on the conflicts committee.
Messrs. Curtis Clifford and Martin Rudolph and Dr. Gayle P.W. Jackson
currently serve as the conflicts committee of the managing board. The
conflicts committee has the authority to review specific matters as to which
the managing board believes there may be a conflict of interest in order to
determine if the resolution of the conflict proposed by our general partner is
fair and reasonable to us. Any matters approved by the conflicts committee are
conclusively judged to be fair and reasonable to us, approved by all our
partners and not a breach by our general partner or its managing board of any
duties they may owe us or the unitholders. In addition, the members of the
conflicts committee also constitute an audit committee which reviews the
external financial reporting by our management, the audit by our independent
public accountants, the procedures for internal auditing and the adequacy of
our internal accounting controls. The board of managers has determined that
the members of the conflicts committee meet the independence standards for
audit committee members set forth in the listing standards of the NYSE,
including those set forth in Rule 10A-3(b)(1) of the Securities Exchange Act,
and that Mr. Rudolph qualifies as an "audit committee financial expert" as
that term is defined in applicable rules and regulations of the Securities
Exchange Act.
As is commonly the case with publicly traded limited partnerships, we do not
directly employ any of the persons responsible for our management or
operation. Rather, Atlas America personnel manage and operate our business.
Officers of our general partner may spend a substantial amount of time
managing the business and affairs of Atlas America and its affiliates and may
face a conflict regarding the allocation of their time between our business
and affairs and their other business interests.
MANAGING BOARD MEMBERS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER
The following table sets forth information with respect to the executive
officers and managing board members of our general partner.
YEAR
NAME IN WHICH
------------- AGE POSITION WITH GENERAL PARTNER SERVICE BEGAN
--- -------------------------------------- -------------
Edward E. Cohen 66 Chairman of the Managing Board and 1999
Chief Executive Officer
Jonathan Z. Cohen 34 Vice Chairman of the Managing Board 1999
President, Chief Operating Officer and
Michael L. Staines 55 Managing Board Member 1999
Matthew A. Jones 43 Chief Financial Officer 2005
Tony C. Banks 50 Managing Board Member 1999
Curtis D. Clifford 62 Managing Board Member 2004
Gayle P.W. Jackson 58 Managing Board Member 2005
Martin Rudolph 58 Managing Board Member 2005
Edward E. Cohen has been Chairman of the Board of Directors of Resource
America since 1990, and a director since 1988. Mr. Cohen served as Chief
Executive Officer of Resource America from 1988 to May 2004 and President of
Resource America from 2000 to 2003. He has been Chairman of the Board of
Directors and Chief Executive Officer of Atlas America from its formation in
2000. He is Chairman of the Board of Directors of Brandywine Construction &
Management, Inc., a property management company, and a
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director of TRM Corporation, a publicly traded consumer services company. Mr.
Cohen is the father of Jonathan Z. Cohen.
Jonathan Z. Cohen has been the President of Resource America since 2003,
Chief Executive Officer of Resource America since 2004 and a director since
2002. He was the Chief Operating Officer of Resource America from 2002 to 2004
and Executive Vice President of Resource America from 2001 until 2003. Before
that, Mr. Cohen had been a Senior Vice President since 1999. Mr. Cohen has
been Vice Chairman of Atlas America since its formation in 2000. Mr. Cohen has
also served as Trustee and Secretary of RAIT Investment Trust, a publicly-
traded real estate investment trust, since 1997, Vice Chairman of RAIT since
2003 and Chairman of the Board of Directors of The Richardson Company, a sales
consulting company, since 1999. Mr. Cohen is the son of Edward E. Cohen.
Michael L. Staines was Senior Vice President of Resource America from 1989
to May 2004 and served as a director from 1989 through 2000 and Secretary from
1989 through 1998. Since its formation in 2000, Mr. Staines has been an
Executive Vice President of Atlas America. Mr. Staines is a member of the Ohio
Oil and Gas Association, the Independent Oil and Gas Association of New York
and the Independent Petroleum Association of America.
Matthew A. Jones has been Chief Financial Officer of Atlas America since
March 2005. Mr. Jones spent his last 9 years with the Investment Banking group
at Friedman Billings Ramsey, most recently as Managing Director. For the last
five years, Mr. Jones had been with Friedman Billings Ramsey's Energy
Investment Banking Group. Before that, Mr. Jones had been associated with
Friedman Billings Ramsey's Specialty Finance and Real Estate Group. Before
Friedman Billings Ramsey, Mr. Jones held positions with Nationsbank and its
predecessors for 12 years in the Commercial and Real Estate Finance division.
Mr. Jones is a Chartered Financial Analyst.
Tony C. Banks has been the Director of Marketing for First Energy Solutions
Corp, a public utility, since 2004. Prior thereto, Mr. Banks was a consultant
to utilities, energy service companies and energy technology firms. From 2000
through early 2002, Mr. Banks was President of RAI Ventures, Inc. and Chairman
of the Board of Optiron Corporation, which was an energy technology subsidiary
of Atlas America until 2002. In addition, Mr. Banks served as President of our
general partner during 2000. He was Chief Executive Officer and President of
Atlas America from 1998 through 2000.
Curtis D. Clifford has been the principal of CL4D CO, an energy consulting,
marketing and reporting firm since 1998. Mr. Clifford has 37 years' experience
in the natural gas industry, from exploration, production and gathering to
procurement, marketing and consulting. He has been president of Amity Manor,
Inc. since 1988 when he founded the company to develop housing for low-income
elderly using tax credit financing. Mr. Clifford holds bachelor degrees in
Civil Engineering and Social Science from Union College, Schenectady NY and is
a registered professional engineer in Pennsylvania.
Gayle P.W. Jackson has been President of Energy Global, Inc., a consulting
firm which specializes in corporate development, diversification and
government relations strategies for energy companies, since 2001. From 2001 to
2004, Dr. Jackson served as Managing Director of FE Clean Energy Group, a
global private equity management firm that invests in energy companies and
projects in Central and Eastern Europe, Latin America and Asia. From 1985 to
2001, Dr. Jackson was President of Gayle P.W. Jackson, Inc., a consulting firm
that advised energy companies on corporate development and diversification
strategies and also advised national and international governmental
institutions on energy policy. Dr. Jackson has been Deputy Chairman of the
Federal Reserve Bank of St. Louis since 2003 and a Board member since 2000,
and has been a member of the Board of Directors of Ameren Corporation, a
publicly-traded public utility holding company, since February 2005.
Martin Rudolph has been the director of tax planning, research and
compliance for RSM McGladrey, Inc., a business services firm offering public
and private mid-sized companies business and tax consulting, wealth
management, retirement resources, payroll services and corporate finance
services, since 2001. From 1990 to 2001, he was a Managing Partner of Rudolph,
Palitz LLC, which was merged with RSM McGladrey. Mr. Rudolph is a certified
public accountant.
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OTHER SIGNIFICANT EMPLOYEES
Sean P. McGrath, 34, has been the Chief Accounting Officer of our general
partner since May 2005. Before that, Mr. McGrath had been the Chief Accounting
Officer of Sunoco Logistics Partners L.P., a publicly-traded company that
transports, terminals and stores refined products and crude oil, since June
2002. From November 1998 to May 2002, Mr. McGrath was Assistant Controller of
Asplundh Tree Expert Co., a utility services and vegetation management
company, and from June 1993 to November 1998, he was an accountant at Arthur
Andersen LLP, ending his tenure there as a manager.
Robert F. Firth, 50, has been the President and Chief Executive Officer of
Spectrum (acquired by us in July 2004 and now known as Atlas Pipeline
Mid-Continent LLC) since 2002. From 1999 to 2002, Mr. Firth served as Vice
President, Operations and Commercial Services at ScissorTail Energy. Mr. Firth
has 30 years experience in the midstream gas industry.
David D. Hall, 47, has been the Executive Vice President and Chief Financial
Officer of Spectrum (acquired by us in July 2004 and now known as Atlas
Pipeline Mid-Continent LLC) since 2002. From 2000 to 2002, Mr. Hall served as
a senior business analyst at ScissorTail Energy. Mr. Hall has more than 25
years experience as a financial executive in the energy industry.
Nancy J. McGurk, 49, was the Chief Accounting Officer of our general partner
from 1999 until May 2005 and has been Chief Accounting Officer of Atlas
America since January 2001 and Senior Vice President since January 2002. Ms.
McGurk had been Vice President of Resource America from 1992 and Treasurer and
Chief Accounting Officer from 1989 to May 2004.
Daniel C. Herz, 28, has been an employee of Atlas America since January 2004
where he now serves as Vice President of Corporate Development. Mr. Herz was
an Associate Investment Banker with Banc of America Securities from 2002 to
2003 and an Analyst from 1999 to 2002.
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OUR PARTNERSHIP AGREEMENT
The following supersedes selected portions of the summary of our partnership
agreement contained in the accompanying prospectus. The revised sections
reflect the conversion of 1,641,026 subordinated units to 1,641,026 common
units on January 1, 2005 in accordance with the terms of our partnership
agreement.
LIMITED VOTING RIGHTS
Holders of our units have limited voting rights and generally are entitled
to vote only with respect to the following matters:
o a sale or exchange of all or substantially all of our assets;
o our dissolution or reconstitution;
o our merger; and
o termination or material modification of the omnibus agreement or
master natural gas gathering agreement.
Removal of our general partner requires a two-thirds vote of all outstanding
common units, excluding those held by our general partner and its affiliates.
Our partnership agreement permits our general partner generally to make
amendments to it that do not materially adversely affect unitholders without
the approval of any unitholders.
CASH DISTRIBUTION POLICY
Quarterly Distributions of Available Cash. Our operating partnership is
required by the operating partnership agreement to distribute to us, within 45
days of the end of each fiscal quarter, all of its available cash for that
quarter. We, in turn, distribute to our partners all of the available cash
received from our operating partnership for that quarter.
Available cash generally means, for any of our fiscal quarters, all cash on
hand at the end of the quarter less cash reserves that our general partner
determines are appropriate to provide for our operating costs, including
potential acquisitions, and to provide funds for distributions to the partners
for any one or more of the next four quarters. We generally make distributions
of all available cash within 45 days after the end of each quarter to holders
of record on the applicable record date.
Distributions of Available Cash from Operating Surplus. Cash distributions
are characterized as distributions from either operating surplus or capital
surplus. This distinction affects the amounts distributed to unitholders
relative to our general partner.
Operating surplus means:
o our cash balance, excluding cash constituting capital surplus, less
o all of our operating expenses, debt service payments, maintenance
costs, capital expenditures and reserves established for future
operations.
Capital surplus means capital generated only by borrowings other than
working capital borrowings, sales of debt and equity securities and sales or
other dispositions of assets for cash, other than inventory, accounts
receivable and other assets disposed of in the ordinary course of business.
We treat all available cash distributed from any source as distributed from
operating surplus until the sum of all available cash distributed since we
began operations equals our total operating surplus from the date we began
operations until the end of the quarter that immediately preceded the
distribution. This method of cash distribution avoids the difficulty of trying
to determine whether available cash is distributed from operating surplus or
capital surplus. We treat any excess available cash, irrespective of its
source, as capital surplus, which would represent a return of capital, and we
will distribute it accordingly. For a discussion of distributions of capital
surplus, see "--Distributions of Capital Surplus" below.
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We distribute available cash from operating surplus for any quarter in the
following manner:
o first, 98% to the common units, pro rata, and 2% to our general
partner, until we have distributed $0.42 for each outstanding common
unit; and
o after that, in the manner described in "--Incentive Distribution
Rights" below.
The 2% allocation of available cash from operating surplus to our general
partner includes our general partner's percentage interest in distributions
from us and our operating partnership on a combined basis.
Adjusted operating surplus for any period generally means operating surplus
generated during that period, less:
o any net increase in working capital borrowings during that period and
o any net reduction in cash reserves for operating expenditures during
that period not relating to an operating expenditure made during that
period,
and plus:
o any net decrease in working capital borrowings during that period and
o any net increase in cash reserves for operating expenditures during
that period required by any debt instrument for the repayment of
principal, interest or premium.
Operating surplus generated during a period is equal to the difference
between:
o the operating surplus determined at the end of that period and
o the operating surplus determined at the beginning of that period.
Incentive Distribution Rights. By "incentive distribution rights" we mean
our general partner's right to receive an increasing percentage of quarterly
distributions of available cash from operating surplus after we have made the
minimum quarterly distributions and we have met specified target distribution
levels, as described below. Our general partner may transfer its incentive
distribution rights separately from its general partner interest without the
consent of the unitholders.
We make incentive distributions to our general partner for any quarter in
which we have distributed available cash from operating surplus to the common
unitholders in an amount equal to the minimum quarterly distribution. If this
condition is satisfied, the remaining available cash will be distributed as
follows:
o first, 85% to all units, pro rata, and 15% to our general partner,
until each unitholder has received a total of $0.52 per unit for that
quarter, in addition to any distributions to common unitholders to
eliminate any cumulative arrearages in payment of the minimum
quarterly distribution on the common units;
o second, 75% to all units, pro rata, and 25% to our general partner,
until each unitholder has received a total of $0.60 per unit for that
quarter, in addition to any distributions to common unitholders to
eliminate any cumulative arrearages in payment of the minimum
quarterly distribution on the common units; and
o after that, 50% to all units, pro rata, and 50% to our general
partner.
The distributions to our general partner that exceed its aggregate 2%
general partner interest represent the incentive distribution rights.
Distributions from Capital Surplus. We distribute available cash from
capital surplus in the following manner:
o first, 98% to all units, pro rata, and 2% to our general partner,
until each common unit has received distributions equal to $13.00 per
unit; and
o after that, we will distribute all available cash from capital
surplus, as if it were from operating surplus.
S-52
When we make a distribution from capital surplus, we will treat it as if it
were a repayment of your investment in your common units. For these purposes,
the partnership agreement deems the investment to be $13.00 per common unit,
which is the unit price from our initial public offering, regardless of the
price you actually pay for your common units in this offering. To reflect this
repayment, we will reduce the amount of the minimum quarterly distribution and
the distribution levels at which our general partner's incentive distribution
rights begin, which we refer to in this prospectus as "target distribution
levels," by multiplying each amount by a fraction, determined as follows:
o the numerator is $13.00 less all distributions from capital surplus
including the distribution just made, and
o the denominator is $13.00 less all distributions from capital surplus
excluding the distribution just made.
We refer to the initial public offering price of $13.00 per common unit,
less any distributions from capital surplus, as the "unrecovered unit price."
After the minimum quarterly distribution and the target distribution levels
have been reduced to zero, we will treat all distributions of available cash
from all sources as if they were from operating surplus. Because the minimum
quarterly distribution and the target distribution levels will have been
reduced to zero, our general partner will then be entitled to receive 50% of
all distributions of available cash in its capacity as general partner and
holder of the incentive distribution rights, in addition to any distributions
to which it may be entitled as a holder of units.
Distributions from capital surplus will not reduce the minimum quarterly
distribution or target distribution levels for the quarter in which they are
distributed.
Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.
In addition to adjustments made upon a distribution of available cash from
capital surplus, we will proportionately adjust each of the following upward
or downward, as appropriate, if any combination or subdivision of units
occurs:
o the minimum quarterly distribution,
o the target distribution levels,
o the unrecovered unit price,
o the number of common units issuable upon conversion of the
subordinated units, and
o other amounts calculated on a per unit basis.
For example, if a two-for-one split of the common units occurs, we will
reduce the minimum quarterly distribution, the target distribution levels and
the unrecovered initial unit price of the common units to 50% of their initial
levels.
We will not make any adjustment for the issuance of additional common units
for cash or property.
We may also adjust the minimum quarterly distribution and the target
distribution levels if legislation is enacted or if existing law is modified
or interpreted in a manner that causes us or our operating partnership to
become taxable as a corporation or otherwise subject to taxation as an entity
for federal, state or local income tax purposes. In this event, we will reduce
the minimum quarterly distribution and the target distribution levels for each
quarter after that time to amounts equal to the product of:
o the minimum quarterly distribution and each of the target distribution
levels multiplied by
o one minus the sum of:
o the highest marginal federal income tax rate which could apply to
the partnership that is taxed as a corporation plus
o any increase in the effective overall state and local income tax
rate that would have been applicable in the preceding calendar
year as a result of the new imposition of the entity level tax,
after taking into account the benefit of any deduction allowable
for federal income tax purposes
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for the payment of state and local income taxes, but only to the
extent of the increase in rates resulting from that legislation
or interpretation.
For example, assuming we are not previously subject to state and local income
tax, if we became taxable as a corporation for federal income tax purposes and
subject to a maximum marginal federal, and effective state and local, income
tax rate of 40%, then we would reduce the minimum quarterly distribution and
the target distribution levels to 60% of the amount immediately before the
adjustment.
Distributions of Cash Upon Liquidation. When we commence dissolution and
liquidation, we will sell or otherwise dispose of our assets and adjust the
partners' capital account balances to reflect any resulting gain or loss. We
will first apply the proceeds of liquidation to the payment of our creditors
in the order of priority provided in our partnership agreement and by law.
After that, we will distribute the proceeds to the unitholders and our general
partner in accordance with their capital account balances, as so adjusted.
We maintain capital accounts in order to ensure that the partnership's
allocations of income, gain, loss and deduction are respected under the
Internal Revenue Code. The balance of a partner's capital account also
determines how much cash or other property the partner will receive on
liquidation of the partnership. A partner's capital account is credited with
(increased by) the following items:
o the amount of cash and fair market value of any property (net of
liabilities) contributed by the partner to the partnership, and
o the partner's share of "book" income and gain (including income and
gain exempt from tax).
A partner's capital account is debited with (reduced by) the following
items:
o the amount of cash and fair market value (net of liabilities) of
property distributed to the partner, and
o the partner's share of loss and deduction (including some items not
deductible for tax purposes).
Partners are entitled to liquidating distributions in accordance with their
capital account balances.
Upon our liquidation, any gain, or unrealized gain attributable to assets
distributed in kind, will be allocated to the partners in the following
manner:
o 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;
o second, 98% to the common units, pro rata, and 2% to our general
partner, until the capital account for each common unit is equal to
the sum of:
o the unrecovered unit price, and
o the amount of the minimum quarterly distribution for the quarter
during which our liquidation occurs.
o third, 85% to all units, pro rata, and 15% to our general partner,
until there has been allocated under this paragraph an amount per unit
equal to:
o the excess of the $0.52 target distribution per unit over the
minimum quarterly distribution per unit for each quarter of our
existence less
o the cumulative amount per unit of any distribution of available
cash from operating surplus in excess of the minimum quarterly
distribution per unit that was distributed 85% to the units, pro
rata, and 15% to our general partner for each quarter of our
existence;
o fourth, 75% to all units, pro rata, and 25% to our general partner,
until there has been allocated under this paragraph an amount per unit
equal to:
o the excess of the $0.60 target distribution per unit over the
$0.52 target distribution per unit for each quarter of our
existence less
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o the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the first target
distribution per unit that was distributed 75% to the units, pro
rata, and 25% to our general partner for each quarter of our
existence; and
o after that, 50% to all units, pro rata, and 50% to our general
partner.
Upon our liquidation, any loss will generally be allocated to our general
partner and the unitholders in the following manner:
o first, 98% to the holders of common units in proportion to the
positive balances in their capital accounts and 2% to our general
partner, until the capital accounts of the common unitholders have
been reduced to zero; and
o after that, 100% to our general partner.
In addition, we will make interim adjustments to the capital accounts at the
time we issue additional equity interests or make distributions of property.
We will base these adjustments on the fair market value of the interests or
the property distributed and we will allocate any gain or loss resulting from
the adjustments to the unitholders and our general partner in the same manner
as we allocate gain or loss upon liquidation. In the event that we make
positive interim adjustments to the capital accounts, we will allocate any
later negative adjustments to the capital accounts resulting from the issuance
of additional equity interests, our distributions of property, or upon our
liquidation, in a manner which results, to the extent possible, in the capital
account balances of our general partner equaling the amount which would have
been our general partner's capital account balances if we had not made any
earlier positive adjustments to the capital accounts.
ISSUANCE OF ADDITIONAL SECURITIES
Our partnership agreement authorizes us to issue an unlimited number of
additional limited partner interests, debt and other securities for the
consideration and on the terms and conditions established by our general
partner in its sole discretion without the approval of any limited partners.
We have funded, and will likely continue to fund, acquisitions through the
issuance of additional common units or other equity 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 partnership interests 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, in the
sole discretion of our general partner, may have special voting rights to
which the common units are not entitled.
Upon issuance of additional partnership securities, our general partner must
make additional capital contributions to the extent necessary to maintain its
combined 2% general partner interest in us and in our operating partnership.
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, subordinated units or other equity 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 its percentage
interest that existed immediately before each issuance. The holders of common
units will not have preemptive rights to acquire additional common units or
other partnership interests.
WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER
Our general partner may withdraw as our general partner without first
obtaining approval from the unitholders by giving 90 days' written notice. Our
general partner may also sell or otherwise transfer all of its general partner
interests in us without the approval of the unitholders as described below
under "--Transfer of General Partner Interest and Incentive Distribution
Rights." Upon withdrawal, we must reimburse our general partner for all
expenses incurred by it on our behalf or allocable to us in connection with
operating our business.
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If our general partner withdraws, other than as a result of a transfer of
all or a part of its general partner interests in us, the holders of a
majority of the units may elect a successor to the 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 and liquidated, unless within 180 days after that withdrawal
the holders of a majority of the units agree in writing to continue our
business and to appoint a successor general partner.
Our general partner may not be removed except by the vote of the holders of
at least 66 2/3% of the outstanding common units, excluding common units held
by our general partner and its affiliates, and we receive an opinion of
counsel regarding limited liability and tax matters. Any removal is also
subject to the approval of a successor general partner by the vote of the
holders of a majority of the common units, excluding common units held by our
general partner and its affiliates. If our general partner is removed under
circumstances where cause does not exist and does not consent to that removal:
o the agreement of Atlas America to connect wells to our gathering
systems will terminate;
o the master natural gas gathering agreement with Atlas America will not
apply to any future wells drilled by Atlas America although it will
continue as to wells connected to the gathering system at the time of
removal;
o the obligations of Atlas America to provide assistance for the
extension of our gathering systems and in the identification and
acquisition of gathering systems from third parties will terminate;
and
o our general partner will have the right to convert its general partner
interests and incentive distribution rights into common units or to
receive cash in exchange for those interests from the successor
general partner.
Our partnership agreement defines "cause" as existing where a court has
rendered a final, non-appealable judgment that our general partner has
committed fraud, gross negligence or willful or wanton misconduct in its
capacity as general partner.
Withdrawal or removal of our general partner as our general partner also
constitutes its withdrawal or removal as the general partner of our operating
partnership.
In the event of removal of our general partner under circumstances where
cause exists or a withdrawal of our general partner that violates our
partnership agreement, a successor general partner will have the option to
purchase the general partner interests 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, the departing general partner will have the
option to require the successor general partner to purchase those interests
for their fair market value. In each case, fair market value will be
determined by agreement between the departing general partner and the
successor general partner. If they cannot reach an agreement, an independent
expert selected by the departing general partner and the successor general
partner will determine the fair market value. If the departing general partner
and the successor general partner cannot agree on an expert, then an expert
chosen by agreement of the experts selected by each of them will determine the
fair market value. If the purchase option is not exercised by either the
departing general partner or the successor general partner, the general
partner interests and incentive distribution rights will automatically convert
into common units equal to the fair market value of those interests. The
successor general partner must indemnify the departing general partner (or its
transferee) from all of our debt and liability arising on or after the date on
which the departing general partner becomes a common unitholder as a result of
the conversion. Except for this limited indemnity right and the right of the
departing general partner to receive distributions on its common units, no
other payments will be made to our general partner after withdrawal.
TRANSFER OF GENERAL PARTNER INTEREST AND INCENTIVE DISTRIBUTION RIGHTS
Our general partner may transfer all or any part of its general partner
interest without obtaining the consent of the unitholders. As a condition to
the transfer of a general partner interest, the transferee must assume the
rights and duties of the general partner to whose interest it has succeeded,
furnish an opinion of
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counsel regarding limited liability and tax matters, agree to acquire all of
the general partner's interest in our operating partnership and agree to be
bound by the provisions of the partnership agreement of our operating
partnership.
The members of our general partner may sell or transfer all or part of their
interest in our general partner to an affiliate without the approval of the
unitholders. Atlas America and its affiliates have agreed that they will not
divest their interest in our general partner without also divesting to the
same acquiror their ownership interest in subsidiaries which act as the
general partner of oil and gas investment partnerships sponsored by them.
Our general partner or a later holder may transfer its incentive
distribution rights to an affiliate or another person as part of its merger or
consolidation with or into, or sale of all or substantially all of its assets
to, that person without the prior approval of the unitholders. However, the
transferee must agree to be bound by the provisions of our partnership
agreement.
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TAX CONSIDERATIONS
GENERAL
The following summarizes material federal income tax considerations that may
be relevant to a prospective unitholder who is a citizen or resident of the
United States. The tax consequences of investing in us may not be the same for
all investors. A careful analysis of your particular tax situation is required
to analyze an investment in our common units properly. Moreover, this summary
does not purport to address all aspects of taxation that may be relevant to
particular unitholders, such as insurance companies, tax-exempt organizations,
foreign corporations and persons who are not citizens or residents of the
United States who may be subject to special treatment under federal income tax
laws, except to the extent specifically discussed in this summary. As a
consequence, we urge you to consult your own tax advisor.
OPINION OF TAX COUNSEL
We have obtained an opinion from Ledgewood, our tax counsel, concerning the
federal tax issues described in this section. The opinion is based on the
facts described in this prospectus supplement and the accompanying prospectus
and on additional facts that we provided to tax counsel about how we plan to
operate. Any alteration of our activities from the description we gave to tax
counsel may render the opinion unreliable.
The statements in this discussion and our counsel's opinion are based on
current provisions of the Internal Revenue Code, existing, temporary and
currently proposed Treasury Regulations promulgated under the Internal
Revenues Code, the legislative history of the Internal Revenue Code, existing
administrative rulings and practices of the IRS, and judicial decisions.
Future legislative, judicial or administrative actions or decisions, which may
be retroactive in effect, may cause actual tax consequences to vary
substantially from those discussed in this summary. Moreover, the tax opinion
represents only tax counsel's best legal judgment. It is not binding on the
IRS nor does it have any other official status. We cannot assure you that the
IRS will accept tax counsel's conclusions.
For the reasons set forth in the more detailed discussion as to each item,
Ledgewood has not rendered an opinion with respect to the following specific
federal income tax issues:
o the treatment of a unitholder whose common units are loaned to a short
seller to cover a short sale of common units (see "--Tax Consequences
of Unit Ownership--Treatment of Short Sales"),
o whether our monthly convention for allocating taxable income and
losses is permitted by existing Treasury Regulations (see
"--Disposition of Common Units--Allocations Between Transferors and
Transferees"), and
o whether our method for depreciating Section 743 adjustments is
sustainable (see "--Disposition of Common Units--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 or her allocable share of the partnership's items of income, gain,
loss and deduction in computing his or her federal income tax liability,
regardless of whether cash distributions are made. Distributions by a
partnership to a partner are generally not taxable unless the amount of cash
distributed is in excess of his or her adjusted basis in the partnership
interest immediately before the distribution.
Our counsel is of the opinion that we and our operating partnership will be
treated as a partnership for federal income tax purposes. We have not and will
not request a ruling from the IRS on this matter. Counsel's opinion is based
partially upon our representations that:
o neither we nor our operating partnership or any operating subsidiary
has elected or will elect to be treated as an association or
corporation;
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o we, our operating partnership and each operating subsidiary have been
operated and will be operated in accordance with all applicable
partnership statutes, its applicable partnership agreement or limited
liability company agreement; and
o for each taxable year, more than 90% of our gross income has been and
will be derived from:
o the exploration, development, production, processing, refining,
transportation or marketing of any mineral or natural resource,
including oil, gas or products thereof, or
o other items of income as to which counsel has opined or will
opine are "qualifying income" within the meaning of Section
7704(d) of the Code.
Section 7704 of the Code provides that publicly-traded partnerships such as
us will, as a general rule, be taxed as corporations. However, an exception,
referred to as the "qualifying income exception" exists if at least 90% of a
publicly-traded partnership's gross income for every taxable year consists of
"qualifying income." Qualifying income includes income and gains derived from
the transportation of crude oil, natural gas and products thereof. Other types
of qualifying income include interest from other than a financial business,
dividends, gains from the sale or lease 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. For this purpose, our share of
the gross income earned by our operating subsidiaries will be included in our
gross income as if we directly earned such income. We estimate that less than
1% 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, Ledgewood is of the opinion that
at least 90% of our current gross income constitutes qualifying income.
Moreover, unless our business changes from that of transporting and processing
natural gas, it is unlikely that we would fail to meet the 90% test in the
future.
If we fail to meet the qualifying income exception, other than a failure
which is determined by the IRS to be inadvertent and which is cured within a
reasonable time after discovery, 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 our unitholders in liquidation of their units. This contribution and
liquidation should be tax-free to us and our unitholders so long as we, at
that time, do not have liabilities in excess of the tax basis of our assets.
Although the tax basis of our assets is now greater than our liabilities, our
tax basis will be reduced over time by depletion and depreciation deductions.
If we incur substantial indebtedness in the future, it is possible that at
some time in the future our liabilities may exceed our tax basis in our
assets. If the deemed contribution and distribution in liquidation happened
after such time, our unitholders would be taxed on the excess of our
liabilities over our assets. Whether or not there is taxable income at the
time of this event, thereafter we would be treated as a corporation for
federal income tax purposes.
If we were treated 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 the 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 basis in his or her common units, or taxable capital gain, after
his or her tax basis in his or her common units is reduced to zero.
Accordingly, treatment of us 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 common units.
The discussion below is based on the assumption that we will be treated as a
partnership for federal income tax purposes.
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LIMITED PARTNER STATUS
Unitholders who have become our limited partners will be treated as our
partners for federal income tax purposes. Counsel is also of the opinion,
based upon and in reliance upon those same representations set forth under
"--Partnership Status," that
o assignees who have executed and delivered transfer applications and
are awaiting admission as limited partners, and
o 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 our partners for federal income tax purposes. As there is
no direct authority addressing assignees of common units who are entitled to
execute and deliver transfer applications and thereby become entitled to
direct the exercise of attendant rights, but who fail to execute and deliver
transfer applications, Counsel's opinion does not extend to these persons.
Furthermore, a purchaser or other transferee of common units who does not
execute and deliver a transfer application may not receive some federal income
tax information or reports furnished to record holders of common units unless
the common units are held in a nominee or street name account and the nominee
or broker has executed and delivered a transfer application for those common
units.
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 or her status
as a partner with respect to such units for federal income tax purposes. See
"--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 be fully taxable as ordinary income. These
holders should consult their own tax advisors with respect to their status as
our partners for federal income tax purposes.
TAX CONSEQUENCES OF UNIT OWNERSHIP
Flow-through of Taxable Income. We do not pay any federal income tax.
Instead, each unitholder is required to report on his or her income tax return
his or her allocable share of our income, gains, losses and deductions without
regard to whether we make cash distributions to that unitholder. Consequently,
we may allocate income to our unitholders although we have made no cash
distribution to them. Each unitholder will be required to include in income
his or her allocable share of our income, gain, loss and deduction for our
taxable year ending with or within his or her taxable year.
Treatment of Distributions. Our distributions generally will not be taxable
for federal income tax purposes to the extent of a unitholders' tax basis in
his or her common units immediately before the distribution. Our cash
distributions in excess of that 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 our
general partner, bears the economic risk of loss, known as "nonrecourse
liabilities," will be treated as a distribution 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, the unitholder must recapture any
losses deducted in previous years. See "--Limitations on Deductibility of Our
Losses."
A decrease in a unitholder's percentage interest in us because of our
issuance of additional common units will decrease his or her share of our
nonrecourse liabilities, and thus will result in a corresponding deemed
distribution of cash. A non-pro rata distribution of money or property may
result in ordinary income to a unitholder, regardless of his or her tax basis
in our common units, if the distribution reduces his or her share of our
"unrealized receivables," including depreciation recapture, or substantially
appreciated "inventory items," both as defined in Section 751 of the Internal
Revenue Code, known collectively as "Section 751 assets." To that extent, a
unitholder will be treated as having been distributed his or her
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proportionate share of the Section 751 assets and having exchanged those
assets with us in return for the non-pro rata portion of the actual
distribution made to him or her. This latter deemed exchange will generally
result in the unitholder's realization of ordinary income under Section 751(b)
of the Internal Revenue Code. That income will equal the excess of:
o the non-pro rata portion of that distribution over
o his or her tax basis 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 December 31, 2007 will be allocated an amount
of federal taxable income for that period that will be less than 30% of the
cash distributed with respect to that period. We anticipate that after the
taxable year ending December 31, 2007, the ratio of taxable income to cash
distributions will increase. These estimates are based upon assumptions with
respect to gross income from operations, capital expenditures, cash flow and
anticipated cash distributions. These estimates and assumptions are subject
to, among other things, numerous business, economic, regulatory, competitive
and political uncertainties beyond our control. The actual taxable income that
will be allocated as a percentage of distributions could be higher or lower,
and any difference could be material and could materially affect the value of
the common units.
In prior taxable years, unitholders received cash distributions that
exceeded the amount of taxable income allocated to the unitholders. This
excess was partially the result of depreciation deductions, but was primarily
the result of special allocations to our general partner of taxable income
earned by our operating subsidiary which caused a corresponding reduction in
the amount of taxable income allocable to us. Our general partner has agreed
to receive additional special allocations of taxable income as follows:
o For 2005, the lesser of $2,400,000 or the amount necessary to make the
ratio of taxable income of all unitholders who own units throughout
2005 to the cash received by such unitholders with respect to 2005 not
higher than 39%.
o For 2006, the lesser of $2,800,000 or the amount necessary to make the
ratio of taxable income of all unitholders who own units throughout
2006 to the cash received by such unitholders with respect to 2006 not
higher than 39%.
Since these special allocations increase our general partner's capital
account, the distribution it will receive upon our liquidation will be
increased and distributions to unitholders will be correspondingly reduced. It
is possible that upon liquidation common unitholders will recognize taxable
income in excess of liquidation distributions.
Tax Rates. In general the highest effective United States federal income
tax rate for individuals for 2005 is 35% and the maximum United States federal
income tax rate for net capital gains of an individual for 2005 is 15% if the
asset disposed of was held for more than 12 months at the time of disposition.
Alternative Minimum Tax. Although we do not expect to generate significant
tax preference items or adjustments, each unitholder will be required to take
into account his distributive share of any items of our income, gain,
deduction or loss for purposes of the alternative minimum tax.
Basis of Common Units. A unitholder's initial tax basis for his or her
common units will be the amount he or she paid for the common units plus his
or her share of our nonrecourse liabilities. That basis will be increased by
his or her share of our income and by any increases in his or her share of our
nonrecourse liabilities. That basis will be decreased, but not below zero, by
our distributions to him or her, by his or her share of our losses, by any
decreases in his or her share of our nonrecourse liabilities and by his or her
share of our expenditures that are not deductible in computing taxable income
and are not required to be capitalized.
Limitations on Deductibility of Our Losses. The deduction by a unitholder
of his or her share of our losses will be limited to the tax basis in his or
her units and, in the case of an individual unitholder or a corporate
unitholder that is subject to the "at risk" rules (for example, if more than
50% of the value of its stock is owned directly or indirectly by five or fewer
individuals or some tax-exempt organizations), to the
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amount for which the unitholder is considered to be "at risk" with respect to
our activities, if that is less than its tax basis. A unitholder 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 to the extent that his
tax basis or at risk amount, whichever is the limiting factor, is subsequently
increased. 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 excess loss above that gain previously suspended by the at
risk or basis limitations is no longer utilizable.
In general, a unitholder will be at risk to the extent of the tax basis of
his or her units, excluding any portion of that basis attributable to his or
her share of our nonrecourse liabilities, reduced by any amount of money he or
she borrows to acquire or hold the 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 or her share of our nonrecourse liabilities.
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 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 only be available to offset
our passive income generated in the future and will not be available to offset
income from other passive activities or investments, including our investments
in other publicly-traded partnerships, or salary or active business income.
Passive losses that are not deductible because they exceed a unitholder's
share of our income may be deducted in full when the unitholder disposes of
his or her entire investment in us in a fully taxable transaction with an
unrelated party. The passive activity loss rules 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.
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." As noted, a unitholder's share of our
net passive income will be treated as investment income for this purpose. In
addition, a unitholder's share of our portfolio income will be treated as
investment income. Investment interest expense includes:
o interest on indebtedness properly allocable to property held for
investment;
o our interest expense attributed to portfolio income; and
o 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.
Allocation of Income, Gain, Loss and Deductions. 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. At any time that distributions are made to the
common units and in excess of distributions to the subordinated units, or that
incentive distributions are made to our general partner, gross income will be
allocated to the recipients to the extent of these distributions. If we have a
net loss for the entire year, the amount of that loss will generally be
allocated first to our general partner and the
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unitholders in accordance with their particular percentage interests in us to
the extent of their positive capital accounts and, second, to our general
partner.
As required by the Internal Revenue Code some items of our income,
deduction, gain and loss will be allocated to account for the difference
between the tax basis and fair market value of property contributed to us by
our general partner referred to in this discussion as "contributed property."
The effect of these allocations to a unitholder will be essentially the same
as if the tax basis of the contributed property were equal to its fair market
value at the time of contribution. In addition, specified items of recapture
income will be allocated to the extent possible to the partner 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.
Ledgewood is of the opinion that, with the exception of the issues described
in "--Disposition of Common Units--Section 754 Election" and "--Disposition of
Common Units--Allocations Between Transferors and Transferees," allocations
under our partnership agreement will be recognized for federal income tax
purposes in determining a partner's share of an item of our income, gain, loss
or deduction.
Entity-Level Collections. If we are required or elect under applicable law
to pay any federal, state or local 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 person 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
and our general partner. We are authorized to amend the 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 the 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 a unitholder in which
event he could file a claim for credit or refund.
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
ownership of those units. If so, the unitholder would no longer own units for
federal income tax purposes during the period of the loan and may recognize
gain or loss from the disposition. As a result, during this period:
o any of our income, gain, deduction or loss with respect to those units
would not be reportable by the unitholder;
o any cash distributions we make to that unitholder with respect to
those units would be fully taxable; and
o all of those distributions would appear to be treated as ordinary
income.
Unitholders desiring to assure ownership of their units for tax purposes and
avoid these consequences should modify any applicable brokerage account
agreements to prohibit their brokers from borrowing their units. The IRS has
announced that it is actively studying issues relating to the tax treatment of
short sales of partnership interests. See also "--Disposition of Common
Units--Recognition of Gain or Loss." Because the IRS has not announced the
results of its study and there is no authority addressing the treatment of
short sales of partnership interests, Ledgewood is unable to opine on the
treatment of such short sales.
TAX TREATMENT OF OPERATIONS
Accounting Method and Taxable Year. We use the accrual method of accounting
and the tax year ending December 31 for federal income tax purposes. Each
unitholder must include in income his or her share of our income, gain, loss
and deduction for our taxable year(s) ending within or with his or her taxable
year. In addition, a unitholder who has a taxable year ending on a date other
than December 31, and who
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disposes of all of his or her units following the close of our taxable year
but before the close of his or her taxable year, must include his or her share
of our income, gain, loss and deduction in income for his or her taxable year,
with the result that he or she will be required to report income for his or
her taxable year for his or her share of more than one year of our income,
gain, loss and deduction.
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 property contributed and the tax basis established for that property will
be borne by our general partner and the unitholders. See "--Tax Treatment of
Unitholders--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 are placed in service. We are not entitled to any
amortization deductions with respect to any goodwill conveyed to us on
formation. Property we acquire or construct is 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 our property may be required to
recapture those deductions as ordinary income upon a sale of his units. See
"--Tax Consequences of Unit Ownership--Allocation of Income, Gain, Loss and
Deduction" and "--Disposition of Common Units--Recognition of Gain or Loss."
Uniformity of Units. We must maintain economic and tax uniformity of the
units to all holders. A lack of tax uniformity can result from a literal
application of Treasury Regulation Sections 1.167(c)-1(a)(6) and
1.197-2(g)(3). Any resulting non-uniformity could have a negative impact on
the value of the common units by reducing the tax deductions available to a
purchaser of units. See "--Disposition of Common Units--Section 754 Election."
We intend to continue to depreciate or amortize the Section 743(b)
adjustment attributable to unrealized appreciation in the value of contributed
property in a way that will avoid non-uniformity of tax treatment among
unitholders. See "--Disposition of Common Units--Section 754 Election." If we
determine that this position cannot reasonably be taken, we may adopt a
different position in an effort to maintain uniformity. This could 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. The IRS may challenge any method of depreciating the
Section 743(b) adjustment we adopt. If such a challenge were made and
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.
See "--Disposition of Common Units--Recognition of Gain or Loss."
Valuation of Our Properties. The federal income tax consequences of the
ownership and disposition of units depends in part on our estimates of the
relative fair market values of our assets. Although we may from time to time
consult with professional appraisers regarding valuation matters, we make many
of the relative fair market value estimates ourselves. These estimates are
subject to challenge and will not be binding on the IRS or the courts. If the
estimates of fair market value 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
such 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 in 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
plus his or her share of our nonrecourse liabilities. Because the amount
realized includes a unitholder's share of our
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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 is less
than his original cost.
Should the IRS successfully contest our method of depreciating or amortizing
the Section 743(b) adjustment, described under "--Disposition of Common
Units--Section 754 Election," attributable to contributed property, a
unitholder could realize additional gain from the sale of units than had our
method been respected. In that case, the unitholder may have been entitled to
additional deductions against income in prior years but may be unable to claim
them, with the result to him of greater overall taxable income than
appropriate. Due to the lack of final regulations, Ledgewood is unable to
opine as to the validity of the convention but believes a contest by the IRS
is unlikely because a successful contest could result in substantial
additional deductions to other unitholders.
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 held for more than one
year will generally be taxable as capital gain or loss. Capital gain
recognized by an individual on the sale of units held more than 12 months will
generally be taxed at a maximum rate of 15%. However, a portion of this gain
or loss, which will likely be substantial, will be separately computed and
taxed as ordinary income 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. 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 that sale. Thus,
a unitholder may recognize both ordinary income and a capital loss upon a
disposition of units. Net capital loss may offset no more than $3,000 of
ordinary income in the case of individuals and may only be used to offset
capital gain 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. 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. Although the ruling is unclear as
to how the holding period of these interests is determined once they are
combined, Treasury regulations allow a selling unitholder, who can identify
units transferred with an ascertainable holding period, to use the actual
holding period of the units transferred. Thus, according to the ruling, a
unitholder will not be able to select high or low basis common units to sell,
as would be the case with corporate stock, but 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 units
transferred must consistently use that identification method for all
subsequent sales or exchanges of units. A unitholder considering the purchase
of additional common units or a sale of common units purchased in separate
transactions should 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 into:
o a short sale;
o an offsetting notional principal contract; or
o 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
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identical property. The Secretary of 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. Our taxable income and
losses are determined annually, prorated on a monthly basis and apportioned
among the unitholders in proportion to the number of units owned by each of
them as of the opening of the New York Stock Exchange on the first business
day of the month. However, gain or loss realized on a sale or other
disposition of our assets other than in the ordinary course of business is
allocated among the unitholders as of the opening of the New York Stock
Exchange on the first business day of 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 accrued after the date of transfer.
The use of this method may not be permitted under existing Treasury
regulations. Accordingly, Ledgewood is unable to opine on the validity of this
method of allocating income and deductions between transferors and transferees
of units. 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. Under our
partnership agreement, we are authorized to revise our method of allocation
between transferors and transferees, as well as among partners whose interests
otherwise vary during a taxable period, 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 a share of our income, gain, loss and deductions
attributable to that quarter but will not be entitled to receive that cash
distribution.
Section 754 Election. We have made the election permitted by Section 754 of
the Internal Revenue Code. That election is irrevocable without the consent of
the IRS. The election generally permits us to adjust a common unit purchaser's
tax basis in our assets ("inside basis") to reflect his or her purchase price.
This election does not apply to a person who purchases common units directly
from us. The adjustment belongs to the purchaser and not to other unitholders.
For purposes of this discussion, a partner's inside basis in our assets will
be considered to have two components:
o his or her share of our tax basis in our assets ("common basis") and
o his or her Section 743(b) adjustment to that basis.
Treasury regulations under Section 743 of the Internal Revenue Code require,
if the remedial allocation method is adopted, a portion of the adjustment
attributable to recovery property to be depreciated over the remaining cost
recovery period for built-in gain. Under Treasury Regulation Section
1.167(c)-1(a)(6), an 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. A
literal application of these different rules result in lack of uniformity.
Under our partnership agreement, our general partner is authorized to adopt a
position intended to preserve the uniformity of units even if that position is
not consistent with the Treasury Regulations. See "--Tax Treatment of
Operations--Uniformity of Units."
We intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of property previously
contributed to us, 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 common basis of the
property. If this contributed property is not amortizable, we will treat that
portion as non-amortizable. This method is consistent with the regulations
under Section 743. This method, however, is arguably inconsistent with
Treasury Regulation Section 1.167(c)-1(a)(6) and Treasury Regulation Section
1.197-2(g)(3), neither of which is expected to directly apply to a material
portion of our assets. To the extent this Section 743(b) adjustment exceeds
that amount, 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 different position which could result in lower annual
depreciation or amortization deductions than would otherwise be allowable to
specified unitholders. See "--Tax Treatment of Operations--Uniformity of
Units."
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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
allocate some or all of any Section 743(b) adjustment to goodwill not so
allocated by us. Goodwill, as an intangible asset, is generally amortizable
over a longer period of time or under a less accelerated method than our
tangible assets.
A Section 754 election is advantageous if the transferee's tax basis in his
or her units is higher than that 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 a higher tax basis in his or her share of
our assets for purposes of calculating, among other items, his or her
depreciation and depletion deductions and share of any gain or loss on a sale
of our assets. Conversely, a Section 754 election is disadvantageous if the
transferee's tax basis in his or her units is lower than that 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
adversely by the election.
The calculations involved in the Section 754 election are complex and we
will make them on the basis of assumptions as to the value of our assets and
other matters. There is no assurance 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.
Notification Requirements. A unitholder who sells or exchanges units is
required to notify us in writing of that sale or exchange within 30 days after
the sale or exchange. We are required to notify the IRS of that transaction
and to furnish information to the transferor and transferee. 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. Additionally, a transferor and a transferee of a unit will be required
to furnish statements to the IRS, filed with their income tax returns for the
taxable year in which the sale or exchange occurred, that describe the amount
of the consideration received for the unit that is allocated to our goodwill
or going concern value. Failure to satisfy these reporting obligations may
lead to the imposition of substantial penalties.
DISSOLUTIONS AND TERMINATIONS
Upon our dissolution, our assets will be sold and any resulting gain or loss
will be allocated among our general partner and the unitholders. See "--Tax
Consequences of Unit Ownership--Allocation of Income, Gain Loss and
Deductions." We will distribute all cash to our general partner and
unitholders in liquidation in accordance with their positive capital account
balances. See "Our Partnership Agreement--Cash Distribution
Policy--Distributions of Cash on Liquidation" in the accompanying prospectus.
We will be considered to have terminated for tax purposes if there is a sale
or exchange of 50% or more of the total interests in our capital and profits
within a 12-month period. Our termination would result 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 might result in more than 12 months of our taxable income or loss
being includable in his taxable income for the year of termination. See "--Tax
Treatment of Operations--Accounting Method and Taxable Year." 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
could 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.
TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS
Ownership of units by employee benefit plans, other tax-exempt
organizations, nonresident aliens, foreign corporations, other foreign persons
and regulated investment companies raises issues unique to those investors
and, as described below, may have substantially adverse tax consequences.
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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 taxable income allocated to a unitholder which is a
tax-exempt organization will be unrelated business taxable income and thus
will be taxable to that unitholder.
A regulated investment company or "mutual fund" is required to derive 90% or
more of its gross income from interest, dividends and gains from the sale of
stocks or securities or foreign currency or specified related sources. The
American Jobs Creation Act of 2004 generally treats income from the ownership
of publicly traded partnerships as derived from such a permitted source,
effective for taxable years of a regulated investment company beginning after
October 22, 2004. For taxable years of a regulated investment company
beginning on or before October 22, 2004 very little of our income will be
treated as derived from a permitted source. For any subsequent taxable year,
we anticipate that all of our income will be treated as derived from such a
permitted source.
Non-resident aliens and foreign corporations, trusts or estates that own
units will be considered to be engaged in business in the United States on
account of ownership of our units. As a consequence they will be required to
file federal tax returns reporting their share of our income, gain, loss or
deduction and pay federal income tax at regular rates on any net income or
gain. Generally, a partnership is required to pay a withholding tax on the
portion of the partnership's income that is effectively connected with the
conduct of a United States trade or business and which is allocable to foreign
partners. Under rules applicable to publicly traded partnerships, we will
withhold at the highest applicable effective tax rate on cash distributions
made to foreign unitholders. Each foreign unitholder must obtain a taxpayer
identification number from the IRS and submit that number to our transfer
agent on a Form W-8 BEN in order to obtain credit for the taxes withheld.
Because a foreign corporation that owns units will be treated as engaged in
a United States trade or business, that corporation may be subject to United
States branch profits tax a rate of 30%, in addition to regular federal income
tax, on its share of our income and gain, as adjusted for changes in its "U.S.
net equity," which are 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 and the country in which the foreign
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.
Under a ruling of the IRS, a foreign unitholder who sells or otherwise
disposes of a unit will be subject to federal income tax on gain realized on
the disposition of that unit to the extent that this gain is effectively
connected with a United States trade or business of the foreign unitholder.
Apart from the ruling, a foreign unitholder will not be taxed or subject to
withholding upon the disposition of a unit if he has owned less than 5% in
value of the units during the five-year period ending on the date of the
disposition and if the units are regularly traded on an established securities
market at the time of the disposition.
ADMINISTRATIVE MATTERS
Information Returns and Audit Procedures. We 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 or her share of our
income, gain, loss and deduction for our preceding taxable year. In preparing
this information, which is generally not reviewed by counsel, we take various
accounting and reporting positions, some of which have been mentioned earlier,
to determine the unitholder's share of income, gain, loss and deduction. We
cannot assure you that those accounting and reporting positions will yield a
result that conforms with the requirements of the Internal Revenue Code,
regulations, or administrative interpretations of the IRS. We also cannot
assure you that the IRS will not successfully contend in court that those
accounting and reporting 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 any such audit may require each unitholder to adjust a prior
year's tax liability, and possibly may result in an audit of that unitholder's
own 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.
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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 provides for one partner to be designated as the "tax matters partner"
for these purposes. The partnership agreement appoints our general partner as
our tax matters partner.
The tax matters partner 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 and by unitholders having in the aggregate at least a 5% profits
interest. 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 the
consistency requirement may subject a unitholder to substantial penalties.
Nominee Reporting. Persons who hold an interest in us as a nominee for
another person are required to furnish to us:
o the name, address and taxpayer identification number of the beneficial
owner and the nominee;
o whether the beneficial owner is
o a person that is not a United States person;
o a foreign government, an international organization or any wholly
owned agency or instrumentality of either of the foregoing; or
o a tax-exempt entity;
o the amount and description of units held, acquired or transferred for
the beneficial owner; and
o 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.
Registration as a Tax Shelter. The Internal Revenue Code requires that "tax
shelters" be registered with the Secretary of the Treasury. It is arguable
that we are not subject to the registration requirement on the basis that we
will not constitute a tax shelter. However, our general partner has registered
us as a tax shelter with the Secretary of Treasury in the absence of assurance
that we will not be subject to tax shelter registration and in light of the
substantial penalties which might be imposed if registration is required and
not undertaken. Our tax shelter registration number is 99344000008. Issuance
of this registration number does not mean that an investment in us or the
claimed tax benefits have been reviewed examined or approved by the IRS.
Registration as a tax shelter may increase the likelihood of an audit of our
tax return or the tax return of a holder of common units. See
"--Administrative Matters--Information Returns and Audit Procedures."
Registration as a tax shelter could also result in penalties being assessed to
a holder of units if he does not comply with the rules discussed in the next
paragraph.
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We will furnish the registration number to the unitholders, and a unitholder
who sells or otherwise transfers a unit in a later transaction must furnish
the registration number to the transferee. The penalty for failure of the
transferor of a unit to furnish the registration number to the transferee is
$100 for each failure. The unitholders must disclose our tax shelter
registration number on Form 8271 to be attached to the tax return on which any
deduction, loss or other benefit generated by us is claimed or on which any of
our income is included. A unitholder who fails to disclose the tax shelter
registration number on his return, without reasonable cause for that failure,
will be subject to a $250 penalty for each failure. These penalties are not
deductible for federal income tax purposes.
Recently issued Treasury regulations require taxpayers to report certain
information on Internal Revenue Service Form 8886 if they participate in a
"reportable transaction." Unitholders may be required to file this form with
the IRS if we participate in a "reportable transaction." A transaction may be
a reportable transaction based upon any of several factors. Unitholders are
urged to consult with their own tax advisor concerning the application of any
of these factors to their investment in our common units. The Treasury
regulations also impose obligations on "material advisors" that organize,
manage or sell interests in registered "tax shelters." Under the recently
enacted American Job Creation Act of 2004, significant penalties may be
imposed for failure to comply with these requirements. The new law also
expanded the responsibilities and potential penalties for promoters of tax
shelters. As stated in the accompanying prospectus, we have registered as a
tax shelter, and, thus, one of our material advisors will be required to
maintain a list with specific information, including unitholder names and tax
identification numbers, and to furnish this information to the IRS upon
request. Unitholders are urged to consult with their own tax advisor
concerning any possible disclosure obligation with respect to their investment
and should be aware that we and our material advisors intend to comply with
the list and disclosure requirements.
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 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.
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 ($10,000 for most
corporations). The amount of any understatement subject to penalty generally
is reduced if any portion is attributable to a position adopted on the return:
o for which there is, or was, "substantial authority" or
o as to which there is a reasonable basis and the pertinent facts of
that position are disclosed on the return.
More stringent rules apply to "tax shelters," a term that in this context
does not appear to include us. If any item of income, gain, loss or deduction
allocated to 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 to avoid liability for this penalty.
STATE, LOCAL AND OTHER TAX CONSIDERATIONS
In addition to federal income taxes, you will be subject to other taxes,
including state and local 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. Although an analysis of
those various taxes is not presented here, each prospective unitholder should
consider his or her potential impact on his or her investment in us. We
currently own property or do business in Ohio, Oklahoma, Texas, Pennsylvania
and New York. Each of these states, except Texas, currently imposes a personal
income tax. We may also own property or do business in other states in the
future. A unitholder will be required to file state income tax returns and to
pay state income taxes in some or all of these states in which we do business
or own property
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and may be subject to penalties for failure to comply with those requirements.
In some states, tax losses may not produce a tax benefit in the year incurred
and also may not be available to offset income in subsequent taxable years.
Some of the states 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 state. Withholding, the amount of which may be greater or less than a
particular unitholder's income tax liability to the state, generally does not
relieve a nonresident unitholder from the obligation to file an income tax
return. Amounts withheld may be treated as if distributed to unitholders for
purposes of determining the amounts distributed by us. See "--Tax Consequences
of Ownership--Entity-Level Collections." Based on current law and our
anticipated 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 states and localities, of his or her
investment in us. Accordingly, each prospective unitholder should consult, and
must depend upon, his or her own tax counsel or other advisor with regard to
those matters. Further, it is the responsibility of each unitholder to file
all state and local, as well as United States federal tax returns that may be
required of him or her. Ledgewood has not rendered an opinion on the state or
local tax consequences of an investment in us.
INVESTMENT 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
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:
o whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
o whether, in making the investment, the plan will satisfy the
diversification requirements of Section 404(a)(1)(C) of ERISA; and
o whether the investment will result in recognition of unrelated
business taxable income by the plan and, if so, the potential
after-tax investment return.
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 also IRAs that are not considered part of an
employee benefit plan, from engaging in specified transactions involving "plan
assets" with parties that are "parties in interest" under ERISA or
"disqualified persons" under the Internal Revenue Code with respect to the
plan.
In addition to considering whether the purchase of common units is a
prohibited transaction, a fiduciary of an employee benefit plan 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 general partner
also would be a fiduciary of the plan and 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
the assets of an entity in which employee benefit plans acquire equity
interests would be deemed "plan assets" under some circumstances. Under these
regulations, an entity's assets would not be considered to be "plan assets"
if, among other things,
o the equity interests acquired by employee benefit plans are publicly
offered securities, i.e., the equity interests are widely held by 100
or more investors independent of the issuer and each other, freely
transferable and registered under some provisions of the federal
securities laws;
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o 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
o 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, disregarding some interests held by our general
partner, its affiliates, and some other persons, 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 we satisfy the first requirement above.
Plan fiduciaries contemplating a purchase of common units should consult
with their own counsel regarding the consequences under ERISA and the Internal
Revenue Code in light of the serious penalties imposed on persons who engage
in prohibited transactions or other violations.
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UNDERWRITING
Under the underwriting agreement related to this common unit offering that
will be filed as an exhibit to a current report on Form 8-K and incorporated
by reference into the registration statement of which this prospectus
supplement is a part, each of the underwriters named below has severally
agreed to purchase from us, and we have agreed to sell to the underwriters,
the number of common units opposite its name below:
UNDERWRITERS NUMBER OF
------------ COMMON UNITS
------------
Friedman, Billings, Ramsey & Co., Inc. .......................... 1,035,000
A.G. Edwards & Sons, Inc. ....................................... 517,500
Wachovia Capital Markets, LLC ................................... 402,500
KeyBanc Capital Markets, a division of McDonald Investments Inc. 230,000
Sanders Morris Harris, Inc. ..................................... 115,000
Total ........................................................ 2,300,000
=========
The underwriting agreement provides that the underwriters are obligated to
purchase, subject to certain conditions, all of the common units in the
offering if any are purchased, other than those covered by the over-allotment
option described below. The conditions contained in the underwriting agreement
include the requirements that:
o all the representations and warranties made by us to the underwriters
are true;
o there has been no material adverse change in our condition or in the
financial markets; and
o we deliver to the underwriters customary closing documents.
OVER-ALLOTMENT OPTION
We have granted the underwriters a 30-day option after the date of the
underwriting agreement to purchase, in whole or part, up to an aggregate of
345,000 additional common units at the public offering price less the
underwriting discounts and commissions. This option may be exercised to cover
over-allotments, if any, made in connection with the common unit offering. To
the extent that the option is exercised, each underwriter will be obligated,
subject to certain conditions, to purchase a number of additional common units
approximately proportionate to that underwriter's initial purchase commitment.
COMMISSION AND EXPENSES
We have been advised by the underwriters that the underwriters propose to
offer the common units directly to the public at the price set forth on the
cover page of this prospectus supplement and to selected dealers, who may
include the underwriters, at the offering price less a selling concession not
in excess of $1.13 per unit. The underwriters may allow, and the selected
dealers may reallow, a discount from the concession not in excess of $0.10 per
unit to other dealers. After the offering, the underwriters may change the
offering price and other selling terms.
The following table summarizes the underwriting discounts and commissions we
will pay to the underwriters. These amounts are shown assuming both no
exercise and full exercise of the underwriters' over-allotment option to
purchase up to 345,000 additional common units. The underwriting fee is the
difference between the public offering price per unit and the amount per unit
the underwriters pay us to purchase the common units.
NO EXERCISE FULL EXERCISE
----------- -------------
Per unit ........................................ $ 1.89 $ 1.89
Total......................................... 4,341,825 4,993,099
========== ==========
We estimate that our total expenses for this offering, including
registration, filing and listing fees, printing fees and our legal and
accounting expenses but excluding underwriting discounts and commissions, will
be approximately $550,000.
S-73
STABILIZATION, SHORT POSITIONS AND PENALTY BIDS
In connection with this offering, the underwriters may engage in stabilizing
transactions, over-allotment transactions, syndicate covering transactions and
penalty bids or purchases for the purpose of pegging, fixing or maintaining
the price of the common units in accordance with Regulation M under the
Securities Exchange Act of 1934.
o Over-allotment transactions involve sales by the underwriters of the
common units in excess of the number of common units the underwriters
are obligated to purchase, which creates a syndicate short position.
The short position may be either a covered short position or a naked
short position. In a covered short position, the number of common
units over-allotted by the underwriters is not greater than the number
of common units that they may purchase in the over-allotment option.
In a naked short position, the number of common units involved is
greater than the number of common units in the over-allotment option.
The underwriters may close out any short position by either exercising
their over-allotment option and/or purchasing the common units in the
open market.
o Stabilizing transactions permit bids to purchase the underlying
security so long as the stabilizing bids do not exceed a specified
maximum.
o Syndicate covering transactions involve purchases of the common units
in the open market after the distribution has been completed in order
to cover syndicate short positions. In determining the source of the
common units to close out the short position, the underwriters will
consider, among other things, the price of common units available for
purchase in the open market as compared to the price at which they may
purchase common units through the over-allotment option. If the
underwriters sell more common units than could be covered by the
over-allotment option, a naked short position, the position can only
be closed out by buying common units in the open market. A naked short
position is more likely to be created if the underwriters are
concerned that there could be downward pressure on the price of the
common units in the open market after pricing that could adversely
affect investors who purchase in the offering.
o Penalty bids permit the underwriters to reclaim a selling concession
from a syndicate member when the common units originally sold by the
syndicate member are purchased in a stabilizing or syndicate covering
transaction to cover a syndicate short position.
These stabilizing transactions, syndicate covering transactions and penalty
bids may have the effect of raising or maintaining the market price of our
common units or preventing or retarding a decline in the market price of the
common units. As a result, the price of the common units may be higher than
the price that might otherwise exist in the open market. These transactions
may be effected on the New York Stock Exchange or otherwise and, if commenced,
may be discontinued at any time.
Neither we nor any of the underwriters makes any representation or
prediction as to the direction or magnitude of any effect that the
transactions described above may have on the price of the common units. In
addition, neither we nor any of the underwriters makes any representation that
the underwriters will engage in these stabilizing transactions or that any
transaction, once commenced, will not be discontinued without notice.
LISTING
Our common units are traded on the New York Stock Exchange under the symbol
"APL."
INDEMNIFICATION
We, our general partner and our operating companies have agreed to indemnify
the underwriters against certain liabilities, including liabilities under the
Securities Act of 1933, or to contribute to payments the underwriters may be
required to make in respect of any of those liabilities.
S-74
AFFILIATIONS
Some of the underwriters have engaged in transactions with, and, from time
to time, have performed services for, Resource America, Atlas America and us
in the ordinary course of business and have received customary fees for
performing these services. Friedman, Billings, Ramsey & Co., Inc. and KeyBanc
Capital Markets, a division of McDonald Investments Inc., acted as the
managing underwriters of our initial public offering and our follow-on
offerings in May 2003 and April 2004, and, along with A.G. Edwards and Sanders
Morris Harris, our follow-on offering in July 2004. Friedman, Billings, Ramsey
& Co., Inc. also provided advisory services to us in connection with our
acquisition of Elk City. In addition, affiliates of Wachovia Capital Markets,
LLC and KeyBanc Capital Markets are lenders under our credit facility and will
receive a portion of the net proceeds of this offering in partial prepayment
of amounts outstanding under the facility. See "Use of Proceeds." Because we
intend to use more than 10% of the net proceeds from this offering to reduce
indebtedness owed by us to affiliates of these underwriters, this offering is
being made in compliance with Rule 2710(h) of the NASD Conduct Rules.
ELECTRONIC DISTRIBUTION
A prospectus supplement and the accompanying prospectus in electronic format
may be made available on the Internet sites or through other online services
maintained by one or more of the underwriters and/or selling group members
participating in this common unit offering, or by their affiliates. In those
cases, prospective investors may view offering terms online and, depending
upon the particular underwriters or selling group members, prospective
investors may be allowed to place orders online. The underwriters may agree
with us to allocate a specific number of common units for sale to online
brokerage account holders. Any such allocation for online distributions will
be made by the underwriters on the same basis as other allocations.
Other than the prospectus in electronic format, the information on the
underwriters' or selling group members' website and any information contained
in any other website maintained by the underwriters or selling group members
is not part of the prospectus or the registration statement of which this
prospectus supplement forms a part, has not been approved and/or endorsed by
us or the underwriters or selling group members in their capacity as
underwriters or selling group members and should not be relied upon by
investors.
NATIONAL ASSOCIATION OF SECURITIES DEALERS CONDUCT RULES
Because the NASD views the common units offered hereby as interests in a
direct participation program, the offering is being made in compliance with
Rule 2810 of the NASD Conduct Rules. Investor suitability with respect to the
common units should be judged similarly to the suitability with respect to
other securities that are listed for trading on a national securities
exchange.
LEGAL MATTERS
The validity of the common units and tax matters will be passed upon for us
by Ledgewood, Philadelphia, Pennsylvania. Specific legal matters in connection
with the offering of the common units are being passed upon for the
underwriters by Dickstein Shapiro Morin & Oshinsky LLP, Washington, D.C.
EXPERTS
The financial statements included or incorporated by reference in this
prospectus supplement have been audited by Grant Thornton LLP, independent
registered public accountants, as indicated in their reports with respect
thereto, and are incorporated by reference herein in reliance upon the
authority of such firm as experts in giving such reports.
S-75
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-3 with respect
to this offering. This prospectus supplement and the accompanying prospectus
constitute only part of the registration statement and do not contain all of
the information set forth in the registration statement, its exhibits and its
schedules.
We file annual, quarterly and current reports, proxy statements and other
information with the SEC. Our SEC filings are available to the public over the
Internet at the SEC's web site at http://www.sec.gov. You may also read and
copy any document we file at the SEC's public reference rooms. Please call the
SEC at 1-800-SEC-0330 for additional information on the public reference
rooms.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The SEC allows us to "incorporate by reference" the information we file with
it. This means that we can disclose important information to you by referring
to these documents. The information incorporated by reference is an important
part of this prospectus supplement and the accompanying prospectus, and
information that we file later with the SEC under Sections 13(a), 13(c), 14 or
15(d) of the Securities Exchange Act of 1934 will automatically update and
supersede this information.
We are incorporating by reference the following documents that we have
previously filed with the SEC (other than information in such documents that
is deemed not to be filed):
o our Annual Report on Form 10-K for the fiscal year ended December 31,
2004;
o our Quarterly Report on Form 10-Q for the quarter ended March 31,
2005; and
o our Current Reports on Form 8-K filed March 14, 2005, March 22, 2005,
April 18, 2005, May 11, 2005 and May 23, 2005.
You may obtain a copy of these filings without charge by writing or calling
us at:
Investor Relations
Atlas Pipeline Partners, L.P.
311 Rouser Road
P.O. Box 611
Moon Township, Pennsylvania 15108
(412) 262-2830
S-76
INDEX TO FINANCIAL STATEMENTS
ELK CITY AUDITED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm ................ F-2
Balance Sheets as of August 31, 2004 and 2003 .......................... F-3
Income Statements for the Year Ended August 31, 2004 and Eleven Months
Ended 2003 ........................................................... F-4
Statements of Partners' Capital as of August 31, 2004 and 2003 ......... F-5
Statements of Cash Flows for Year Ended August 31, 2004 and Eleven
Months Ended August 31, 2003 ......................................... F-6
Notes to Financial Statements .......................................... F-7
ELK CITY UNAUDITED FINANCIAL STATEMENTS
Balance Sheet as of February 28, 2005 .................................. F-13
Income Statements for the Six Months Ended February 28, 2005 and
February 29, 2004 .................................................... F-14
Statements of Cash Flows for the Six Months Ended February 28, 2005 and
February 29, 2004 .................................................... F-15
Notes to Financial Statements .......................................... F-16
AQUILA GAS PROCESSING CORPORATION AUDITED CARVE-OUT FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm ................ F-19
Statement of Income and Changes in Parent's Equity in Division for the
Year Ended September 30, 2002 ........................................ F-20
Statement of Cash Flows for the Year Ended September 30, 2002 .......... F-21
Notes to Carve-out Financial Statements ................................ F-22
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and
Atlas Pipeline Partners, L.P.
We have audited the accompanying balance sheets of ETC Oklahoma Pipeline,
Ltd. (a Texas limited partnership) as of August 31, 2004 and 2003, and the
related statements of income, partners' capital, and cash flows for the year
ended August 31, 2004 and the period from the beginning of operations
(October 1, 2002) through August 31, 2003. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable assurance about
whether the financial statements are free of material misstatement. The
Partnership is not required to have, nor were we engaged to perform an audit
of its internal control over financial reporting. Our audits included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the
Partnership's internal control over financial reporting. Accordingly, we
express no such opinion. An audit also 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, as well as evaluating the overall financial statement
presentation. We believe that our audits provides a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of ETC Oklahoma Pipeline,
Ltd. as of August 31, 2004 and 2003, and the results of its operations and its
cash flows for the year ended August 31, 2004 and the period from inception
(September 24, 2002) through August 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Cleveland, Ohio
April 25, 2005
F-2
ETC OKLAHOMA PIPELINE, LTD.
BALANCE SHEETS
August 31, 2004 and 2003
(In thousands)
ASSETS
------ 2004 2003
------- -------
CURRENT ASSETS:
Cash ..................................................... $ -- $ --
Receivables--
Trade................................................... 1,773 1,098
Related parties......................................... 22,305 7,121
Exchanges............................................... 213 730
Materials and supplies ................................... 63 63
Other current assets ..................................... -- 49
------- -------
Total current assets .................................. 24,354 9,061
PROPERTY, PLANT AND EQUIPMENT ............................. 47,492 40,305
ACCUMULATED DEPRECIATION .................................. (3,938) (1,589)
------- -------
PROPERTY, PLANT AND EQUIPMENT, NET ........................ 43,554 38,716
------- -------
Total assets .......................................... $67,908 $47,777
======= =======
LIABILITIES AND PARTNERS' CAPITAL
---------------------------------
CURRENT LIABILITIES:
Payables--
Trade exchanges......................................... $19,825 $ 7,694
Exchanges............................................... 188 576
Accrued expenses ......................................... 577 640
------- -------
Total current liabilities ............................. 20,590 8,910
COMMITMENTS AND CONTINGENCIES (See Note H)
PARTNERS' CAPITAL
Limited partner .......................................... 47,271 38,828
General partner .......................................... 47 39
------- -------
Total partners' capital ............................... 47,318 38,867
------- -------
Total liabilities and partners' capital ............... $67,908 $47,777
======= =======
The accompanying notes are an integral part of these financial statements.
F-3
ETC OKLAHOMA PIPELINE, LTD.
INCOME STATEMENTS
(In thousands)
ELEVEN
YEAR ENDED MONTHS ENDED
AUGUST 31, 2004 AUGUST 31, 2003
--------------- ---------------
OPERATING REVENUES:
Third party .............................. $ 11,977 $ 7,607
Related party ............................ 123,320 84,834
-------- -------
Total revenues.......................... 135,297 92,441
COSTS AND EXPENSES:
Cost of products sold .................... 119,495 79,055
Operating ................................ 4,726 2,914
General and administrative ............... 2,664 2,887
Depreciation and amortization ............ 2,249 1,591
-------- -------
Total costs and expenses................ 129,134 86,447
-------- -------
NET INCOME ................................ $ 6,163 $ 5,994
======== =======
The accompanying notes are an integral part of these financial statements.
F-4
ETC OKLAHOMA PIPELINE, LTD.
STATEMENTS OF PARTNERS' CAPITAL
August 31, 2004 and 2003
(In thousands)
LIMITED GENERAL TOTAL
PARTNER'S PARTNER'S PARTNERS'
CAPITAL CAPITAL CAPITAL
--------- --------- ---------
Balance, October 1, 2002..................................................................... $ -- $-- $ --
Capital contribution........................................................................ 32,840 33 32,873
Net income.................................................................................. 5,988 6 5,994
------- --- -------
Balance, August 31, 2003..................................................................... 38,828 39 38,867
Capital contribution........................................................................ 2,286 2 2,288
Net income.................................................................................. 6,157 6 6,163
------- --- -------
Balance, August 31, 2004..................................................................... $47,271 $47 $47,318
======= === =======
The accompanying notes are an integral part of these financial statements.
F-5
ETC OKLAHOMA PIPELINE, LTD.
STATEMENTS OF CASH FLOWS
(In thousands)
ELEVEN
YEAR ENDED MONTHS ENDED
AUGUST 31, 2004 AUGUST 31, 2003
--------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................... $ 6,163 $ 5,994
Adjustments to reconcile net income to
net cash provided by
operating activities--
Depreciation and amortization........... 2,249 1,591
Other, net.............................. 1 --
Changes in operating assets and
liabilities--
Receivables ........................... (157) (1,829)
Related party receivables ............. (7,181) (18,289)
Other current assets .................. 49 (49)
Payables .............................. 11,743 8,269
Accrued expenses ...................... (63) 380
------- --------
Net cash provided by (used in)
operating activities................. 12,804 (3,933)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and
equipment................................ (4,873) (7,321)
Proceeds from sale of assets ............. 72 86
------- --------
Net cash used in investing activities (4,801) (7,235)
CASH FLOWS FROM FINANCING ACTIVITIES:
Working capital from (to) parent ......... (8,003) 11,168
------- --------
Net change in cash ....................... -- --
Cash beginning of year ................... -- --
------- --------
Cash end of year ......................... $ -- $ --
======= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Non-cash asset contribution .............. $ 2,288 $ 32,873
======= ========
Cash paid for interest ................... $ -- $ --
======= ========
Cash paid for income taxes ............... $ -- $ --
======= ========
The accompanying notes are an integral part of these financial statements.
F-6
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO FINANCIAL STATEMENTS
As of August 31, 2004 and 2003
(Dollar amounts in thousands)
A - ORGANIZATION AND BUSINESS
ETC Oklahoma Pipeline, Ltd. (Elk City or the Company) is a Texas limited
partnership, which began operations in October 2002. LG PL, LLC, a
wholly-owned subsidiary of La Grange Acquisition, L.P. (La Grange) owns a
0.1% general partner interest and La Grange Acquisition, L.P. owns a
99.9% limited partner interest. Elk City owns a natural gas gathering
pipeline system and gas processing plant in Oklahoma. La Grange acquired
the Oklahoma natural gas gathering and gas processing assets of Aquila
Gas Pipeline Corporation (Aquila), a subsidiary of Aquila, Inc., in
October 2002. These assets are referred to herein as "the Elk City
system."
The Elk City system is a 318-mile gathering system located in western
Oklahoma that gathers, compresses, treats and processes natural gas from
the Anadarko Basin. The Elk City system also includes the Elk City
processing plant and one treating facility. The Elk City system is
connected, either directly or indirectly, to six major interstate and
intrastate natural gas pipelines providing access to natural gas markets
throughout the United States. The Elk City system has a processing
capacity of approximately 130 million cubic feet per day (MMcf/d).
B - SIGNIFICANT ACCOUNTING POLICIES
1. Basis of Presentation
Financial statements are presented for the year ended August 31, 2004 and
for the eleven months ended August 31, 2003.
The financial statements of the Company have been prepared in accordance
with accounting principles generally accepted in the United States of
America.
2. Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period.
Some of the other more significant estimates made by management include,
but are not limited to the useful lives for depreciation and amortization
and general business reserves. Actual results could differ from those
estimates.
3. Cash
La Grange provides cash to the Company for working capital and capital
expenditures. Cash transfers are recorded through related party
receivables and payables. Cash receipts of the Company are immediately
transferred to La Grange to reduce the intercompany balance with La
Grange.
4. Accounts Receivable
Elk City deals with counter parties that are typically either investment
grade (Standard & Poors BBB or higher) or are otherwise secured with a
letter of credit or other form of security (corporate guaranty or
prepayment). Management reviews accounts receivable balances each week.
Credit limits are assigned and monitored for all counter parties. The
majority of payments are due on the 25th of the month following delivery.
Management closely monitors credit exposure for potential doubtful
accounts. Management believes that an occurrence of bad debt is unlikely;
therefore, an allowance for doubtful accounts was not deemed necessary at
August 31, 2004 and 2003, respectively. Bad debt expense is recognized at
the time an
F-7
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
As of August 31, 2004 and 2003
(Dollar amounts in thousands)
B - SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
account is deemed uncollectible. An account receivable will be written
off in the event a counter party files for bankruptcy protection or the
account is turned over for collection and the collector deems the account
uncollectible. No bad debt expense was recorded during the year ended
August 31, 2004 or the eleven months ended August 31, 2003.
5. Materials and Supplies
Materials and supplies are stated at the lower of cost (determined on a
first-in, first-out basis) or market value.
6. Inventories and Exchanges
Inventories and exchanges consist of natural gas liquids (NGLs) on hand
or natural gas and NGL delivery imbalances with others and are presented
net by customer/supplier. These amounts turn over monthly and management
believes the cost approximates market value. Accordingly, these volumes
are valued at market prices.
7. Property, Plant and Equipment
Pipeline, property, plant, and equipment are stated at cost less
accumulated depreciation. The cost of property additions includes labor
and materials, applicable overhead and payroll-related costs. Additions
and improvements that add to the productive capacity or extend the useful
life of the asset are capitalized. Expenditures for maintenance and
repairs that do not add capacity or extend the useful life are charged to
expense as incurred. Upon disposition or retirement of pipeline
components or gas plant components, any gain or loss is recorded to
accumulated depreciation. When entire pipeline systems, gas plants or
other property and equipment are retired or sold, any gain or loss is
included in operations.
Depreciation of the gathering pipeline systems, gas plants, and
processing equipment is provided using the straight-line method based on
an estimated useful life of primarily 20 years.
8. Federal and State Income Taxes
The Company is organized under the provisions of the Texas Revised
Limited Partnership Act. Accordingly, taxable income or loss, which may
vary substantially from the net income or loss reported for financial
reporting purposes is generally included in the federal and state income
tax returns of each partner.
9. Revenue Recognition
Revenue for sales of natural gas and NGLs is recognized upon delivery.
Service revenues, including transportation, treating, compression and gas
processing, are recognized at the time service is performed. Elk City
contracts consist primarily of transportation contracts and keep-whole
arrangements. Under transportation contracts, the Company receives a fee
for transporting gas through its system. The revenue earned from
transportation contracts is directly related to volume of natural gas
transported through the system and is not directly dependent on commodity
prices. Under keep-whole arrangements, the Company gathers natural gas
from the producer, processes the natural gas and sells the resulting NGLs
at market prices to an affiliated company.
10. Shipping and Handling Costs
In accordance with the Emerging Issues Task Force Issue 00-10,
"Accounting for Shipping and Handling Fees and Costs", the Company
classified fees deducted from payments to producers for compression and
treating of gas as revenue.
F-8
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
As of August 31, 2004 and 2003
(Dollar amounts in thousands)
B - SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
11. Asset Retirement Obligation
The Company accounts for its asset retirement obligations in accordance
with Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the
Company to record the fair value of an asset retirement obligation as a
liability in the period in which it incurs a legal obligation for the
retirement of tangible long-lived assets, typically at the time the
assets are placed into service. A corresponding asset is also recorded
and depreciated over the life of the asset. After the initial
measurement, any changes in the amount of the liability resulting from
the passage of time and revisions to either the timing or amount of
estimated cash flows would be recognized prospectively.
The Company has determined that it is obligated by contractual
requirements to remove facilities or perform other remediation upon
retirement of certain of its assets. Determination of the amounts to be
recognized is based upon numerous estimates and assumptions, including
expected settlement dates, future retirement costs, future inflation
rates and the credit-adjusted risk-free interest rates. However, the
Company is not able to reasonably determine the fair value of the asset
retirement obligations as of August 31, 2004, because the settlement
dates are indeterminable. An asset retirement obligation will be recorded
in the periods the settlement dates can reasonably determined.
12. Impairment of Long-lived Assets
Long-lived assets, including property, plant and equipments are reviewed
for impairment whenever facts and circumstances indicate impairment may
be present. When impairment indicators are present, the Company evaluates
whether the assets in question are able to generate sufficient cash flows
to recover their carrying value on an undiscounted basis. If an asset is
deemed to be impaired, the amount of impairment is determined as the
amount by which the net carrying value exceeds discounted estimated net
cash flows.
C - ACQUISITION
In October 2002, La Grange purchased certain operating assets from
Aquila, primarily consisting of natural gas gathering, treating and
processing assets in Texas and Oklahoma, for $264 million in cash. At the
closing of the acquisition, approximately $33 million of the purchase
price was allocated to the Elk City assets based on the relative fair
value of all assets acquired.
The assets acquired and purchase price allocation were as follows:
ELK CITY ASSETS
---------------
Materials and supplies ....................................... $ 63
Property, plant and equipment ................................ 33,070
Accrued expenses ............................................. (260)
-------
$32,873
=======
F-9
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
As of August 31, 2004 and 2003
(Dollar amounts in thousands)
D - PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost, consisted of the following:
ESTIMATED BALANCE AT BALANCE AT
USEFUL AUGUST 31, AUGUST 31,
LIVES (YEARS) 2004 2003
------------- ---------- ----------
Midstream pipelines and equipment.................................................. 20 $45,445 $36,574
Midstream right of way............................................................. 20 903 103
Linepack........................................................................... N/A 48 48
Construction in progress........................................................... N/A 901 3,443
Other.............................................................................. 5 195 137
---------- ----------
Total.............................................................................. 47,492 40,305
Accumulated depreciation and amortization.......................................... (3,938) (1,589)
------- -------
Property, plant and equipment, net................................................. $43,554 $38,716
======= =======
E - RELATED PARTY TRANSACTIONS
The Company entered into various types of transactions with La Grange, or
its subsidiaries, for the year ended August 31, 2004 and eleven months
ended August 31, 2003. The Company sold the majority of natural gas
gathered and NGLs produced by the Company to La Grange or its
subsidiaries. La Grange purchased the gas and NGLs at an index based
price. Additionally, the Company reimbursed La Grange for certain
employees who provided services to the Company and for other costs
(primarily general and administrative expense) related to the Company's
operations. La Grange also provided working capital necessary for the
operations of the Company.
The following table summarizes transactions for the periods presented:
ELEVEN MONTHS
YEAR ENDED ENDED
AUGUST 31, AUGUST 31,
2004 2003
---------- -------------
Natural gas sales to affiliated companies ........ $77,169 $ 60,380
NGLs sales to affiliated companies ............... 46,151 24,454
Compression services from affiliated company ..... 91 --
Allocated costs from affiliated companies ........ 2,663 2,887
Working capital from affiliated companies ........ (3,185) (11,168)
Transfers of property, plant and equipment from
affiliated companies ........................... 2,288 32,873
The related party receivable due from La Grange was $22,305 and $7,121 at
August 31, 2004 and August 31, 2003, respectively.
F - MAJOR CUSTOMERS AND SUPPLIERS
The Company sold 91.1% and 91.8% of natural gas and NGLs produced to ETC
Marketing, Ltd., a subsidiary of La Grange, for the year ended August 31,
2004 and for the eleven months ended August 31, 2003, respectively.
F-10
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
As of August 31, 2004 and 2003
(Dollar amounts in thousands)
F - MAJOR CUSTOMERS AND SUPPLIERS -- (CONTINUED)
For the year ended August 31, 2004 and the eleven months ended August 31,
2003, the Company had gross purchases as a percentage of cost of sales
from nonaffiliated major suppliers as follows:
ELEVEN MONTHS
YEAR ENDED ENDED
AUGUST 31, AUGUST 31,
2004 2003
---------- -------------
St. Mary Operating Company ....................... 22.8% 14.1%
Samson Resources Company ......................... 18.2% 23.4%
Stephens Production Company ...................... 12.8% 8.8%
Management believes that the diversification of suppliers is sufficient
to enable the Company to purchase all of its supply needs at market
prices without a material disruption of operations if supplies are
interrupted from any of the Company's existing sources. Although no
assurances can be given that supplies will be readily available in the
future, we expect a sufficient supply to continue to be available.
G - RETIREMENT AND BENEFITS
La Grange has a defined contribution plan for virtually all employees
with discretionary matching. Pursuant to the plan, employees of the
Company can defer a portion of their compensation and contribute it to a
deferred account. La Grange did not elect to match contributions to this
plan during the year ended August 31, 2004 and the eleven months ended
August 31, 2003. Therefore, no expense related to the plan is recorded in
the accompanying financial statements.
H - COMMITMENTS AND CONTINGENCIES
1. Lease Obligations
The Company has operating leases for compressors under noncancelable
agreements. Future annual minimum lease payments for each of the next
five years and thereafter as of August 31, 2004 are as follows:
Year ending August 31:
2005 .................................................................. $ 522
2006 .................................................................. 522
2007 .................................................................. 522
2008 .................................................................. 522
2009 .................................................................. 500
After 2009 ............................................................ 72
------
$2,660
======
Rental expense relating to operating leases was $675 and $555 for the
year ended August 31, 2004 and eleven months ended August 31, 2003,
respectively.
2. Litigation
The Company is involved in various lawsuits, claims and regulatory
proceedings incidental to its business. In the opinion of management, the
outcome of such matters will not have a material adverse effect on the
Company's financial position or results of operations.
F-11
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
As of August 31, 2004 and 2003
(Dollar amounts in thousands)
H - COMMITMENTS AND CONTINGENCIES -- (CONTINUED)
3. Environmental
The Company's operations are subject to extensive federal, state and
local environmental laws and regulations that require expenditures for
remediation at operating facilities and waste disposal sites. Although
the Company believes its operations are in substantial compliance with
applicable environmental laws and regulations, risks of additional costs
and liabilities are inherent in the natural gas pipeline and processing
business, and there can be no assurance that significant costs and
liabilities will not be incurred. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws,
regulations and enforcement policies thereunder, and claims for damages
to property or persons resulting from the operations, could result in
substantial costs and liabilities. Accordingly, the Company has adopted
policies, practices, and procedures in the areas of pollution control,
product safety, occupational health, and the handling, storage, use, and
disposal of hazardous materials to prevent material environmental or
other damage, and to limit the financial liability, which could result
from such events. However, some risk of environmental or other damage is
inherent in the natural gas pipeline and processing business, as it is
with other entities engaged in similar businesses.
In conjunction with the acquisition of the Texas and Oklahoma natural gas
gathering and gas processing assets from Aquila, Aquila, Inc. agreed to
indemnify La Grange Acquisition, L.P. for any environmental liabilities
from those operations prior to October 1, 2002.
Environmental exposures and liabilities are difficult to assess and
estimate due to unknown factors such as the magnitude of possible
contamination, the timing and extent of remediation, the determination of
the Company's liability in proportion to other parties, improvements in
cleanup technologies and the extent to which environmental laws and
regulations may change in the future. Although environmental costs may
have a significant impact on the results of operations for any single
period, the Company believes that such costs will not have a material
adverse effect on its financial position. Elk City did not accrue for
environmental liabilities as of August 31, 2004 or 2003.
I - SUBSEQUENT EVENT
On April 14, 2005, Elk City's parent company completed the sale of the
Company to Atlas Pipeline Partners, L.P. for $190 million in cash,
subject to certain adjustments as defined in the purchase and sale
agreement.
F-12
ETC OKLAHOMA PIPELINE, LTD.
BALANCE SHEET
February 28, 2005
(Unaudited)
(In thousands)
ASSETS
------
CURRENT ASSETS:
Cash ................................................................ $ --
Receivables--
Trade ............................................................. 2,294
Related parties ................................................... 27,671
Exchanges ......................................................... 716
Materials and supplies .............................................. 63
Other current assets ................................................ 497
-------
Total current assets ............................................. 31,241
PROPERTY, PLANT AND EQUIPMENT ........................................ 50,004
ACCUMULATED DEPRECIATION ............................................. (5,243)
-------
PROPERTY, PLANT AND EQUIPMENT, net ................................... 44,761
-------
Total assets ..................................................... $76,002
=======
LIABILITIES AND PARTNERS' CAPITAL
---------------------------------
CURRENT LIABILITIES:
Payables--
Trade ............................................................. $23,206
Exchanges ......................................................... 209
Accrued expenses .................................................... 162
-------
Total current liabilities ........................................ 23,577
COMMITMENTS AND CONTINGENCIES (See Note D)
PARTNERS' CAPITAL:
Limited partner ..................................................... 52,373
General partner ..................................................... 52
-------
Total partners' capital .......................................... 52,425
-------
Total liabilities and partners' capital .......................... $76,002
=======
The accompanying notes are an integral part of this financial statement.
F-13
ETC OKLAHOMA PIPELINE, LTD.
INCOME STATEMENTS
(UNAUDITED)
(In thousands)
SIX MONTHS ENDED SIX MONTHS ENDED
FEBRUARY 28, 2005 FEBRUARY 29, 2004
----------------- -----------------
(UNAUDITED) (UNAUDITED)
OPERATING REVENUES:
Third party .......................... $ 6,841 $ 5,138
Related party ........................ 77,355 54,789
------- -------
Total revenues...................... 84,196 59,927
COSTS AND EXPENSES:
Cost of products sold ................. 74,330 52,757
Operating ............................. 2,624 2,297
General and administrative ............ 1,437 1,331
Depreciation and amortization ......... 1,236 1,076
------- -------
Total costs and expenses............ 79,627 57,461
------- -------
NET INCOME ............................ $ 4,569 $ 2,466
======= =======
The accompanying notes are an integral part of these financial statements.
F-14
ETC OKLAHOMA PIPELINE, LTD.
STATEMENTS OF CASH FLOWS
(UNAUDITED)
(In thousands)
SIX MONTHS ENDED SIX MONTHS ENDED
FEBRUARY 28, 2005 FEBRUARY 29, 2004
----------------- -----------------
(UNAUDITED) (UNAUDITED)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ........................... $ 4,569 $ 2,466
Adjustments to reconcile net income
to net cash provided by
operating activities--
Depreciation and amortization....... 1,236 1,076
Loss on disposal of assets.......... -- 3
Changes in operating assets and
liabilities--
Receivables ....................... (1,024) (521)
Related party receivables ......... (12,560) (21,586)
Other current assets .............. (497) 47
Payables .......................... 3,402 11,764
Accrued expenses .................. (415) (402)
-------- --------
Net cash used in operating
activities....................... (5,289) (7,153)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and
equipment............................ (1,905) (2,545)
Proceeds from sale of assets ......... -- 72
-------- --------
Net cash used in investing
activities...................... (1,905) (2,473)
CASH FLOWS FROM FINANCING ACTIVITIES:
Working capital from parent .......... 7,194 9,626
-------- --------
Net change in cash ................... -- --
Cash beginning of year ............... -- --
-------- --------
Cash end of year ..................... $ -- $ --
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Non-cash asset contribution .......... $ 538 $ 2,288
======== ========
Cash paid for interest ............... $ -- $ --
======== ========
Cash paid for income taxes ........... $ -- $ --
======== ========
The accompanying notes are an integral part of these financial statements.
F-15
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO UNAUDITED FINANCIAL STATEMENTS
Six months ended February 28, 2005
A - ORGANIZATION AND BUSINESS
ETC Oklahoma Pipeline, Ltd. (Elk City or the Company) is a Texas limited
partnership. LG PL, LLC, a wholly-owned subsidiary of La Grange
Acquisition, L.P. (La Grange) owns a 0.1% general partner interest and La
Grange Acquisition, L.P. owns a 99.9% limited partner interest. Elk City
owns a natural gas gathering pipeline system and gas processing plant in
Oklahoma. These assets are referred to herein as "the Elk City system."
The Elk City system is a 318-mile gathering system located in western
Oklahoma that gathers, compresses, treats and processes natural gas from
the Anadarko Basin. The Elk City system also includes the Elk City
processing plant and one treating facility. The Elk City system is
connected, either directly or indirectly, to six major interstate and
intrastate natural gas pipelines providing access to natural gas markets
throughout the United States. The Elk City system has a processing
capacity of approximately 130 million cubic feet per day (MMcf/d).
B - SIGNIFICANT ACCOUNTING POLICIES
1. Basis of Presentation
The interim financial statements of the Company have been prepared in
accordance with accounting principles generally accepted in the United
States ("US GAAP") and on the same basis as the audited financial
statements for the year ended August 31, 2004. Certain information and
footnote disclosures normally included in annual financial statements
prepared in accordance with US GAAP have been omitted pursuant to the
rules and regulations of the SEC. Because the interim financial
statements do not include all of the information and footnotes required
by US GAAP, they should be read in conjunction with the audited financial
statements and related notes for the year ended August 31, 2004. The
results of operations for an interim period may not give a true
indication of results for a full year. There are no other components of
comprehensive income other than net income.
2. Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. The natural
gas industry conducts its business by processing actual transactions at
the end of the month following the month of delivery. Consequently, the
most current month's financial results are estimated using volume
estimates and market prices. Any difference between estimated results and
actual results are recognized in the following month's financial
statements. Management believes that the operating results estimated for
the six months ending February 28, 2005 and February 29, 2004 represent
the actual results in all material respects.
Some of the other more significant estimates made by management include,
but are not limited to the useful lives for depreciation and
amortization, and general business reserves. Actual results could differ
from those estimates.
3. Cash
La Grange provides cash to the Company for working capital and capital
expenditures. Cash transfers are recorded through related party
receivables and payables. Cash receipts of the Company are immediately
transferred to La Grange to reduce the intercompany balance with La
Grange.
F-16
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO UNAUDITED FINANCIAL STATEMENTS -- (CONTINUED)
Six months ended February 28, 2005
B - SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
4. Accounts Receivable
Elk City deals with counter parties that are typically either investment
grade (Standard & Poors BBB or higher) or are otherwise secured with a
letter of credit or other form of security (corporate guaranty or
prepayment). Management reviews accounts receivable balances each week.
Credit limits are assigned and monitored for all counter parties. The
majority of payments are due on the 25th of the month following delivery.
Management closely monitors credit exposure for potential doubtful
accounts. Management believes that an occurrence of bad debt is unlikely;
therefore, an allowance for doubtful accounts was not deemed necessary at
February 28, 2005. Bad debt expense is recognized at the time an account
is deemed uncollectible. An account receivable will be written off in the
event a counter party files for bankruptcy protection or the account is
turned over for collection and the collector deems the account
uncollectible. No bad debt expense was recorded during the six months
ended February 28, 2005 or six months ended February 29, 2004.
C - RELATED PARTY TRANSACTIONS
The Company entered into various types of transactions with La Grange, or
its subsidiaries for the six months ended February 28, 2005 and
February 29, 2004.
The following table summarized transactions for the six month periods
February 28, 2005 and February 29, 2004:
2005 2004
------- -------
Natural gas sales to affiliated companies ................. $47,886 $33,957
NGLs sales to affiliated companies ........................ 29,469 20,832
Compression services from affiliated company .............. 207 --
Allocated costs from affiliated companies ................. 1,437 1,329
Working capital to (from) related companies ............... 4,009 (1,542)
Transfer of property, plant and equipment from related
parties .................................................. 539 2,288
The related party receivable due from La Grange was $27,671 as of
February 28, 2005.
D - COMMITMENTS AND CONTINGENCIES
1. Litigation
The Company is involved in various lawsuits, claims and regulatory
proceedings incidental to its business. In the opinion of management, the
outcome of such matters will not have a material adverse effect on the
Company's financial position or results of operations.
2. Environmental
The Company's operations are subject to extensive federal, state and
local environmental laws and regulations that require expenditures for
remediation at operating facilities and waste disposal sites. Although
the Company believes its operations are in substantial compliance with
applicable environmental laws and regulations, risks of additional costs
and liabilities are inherent in the natural gas pipeline and processing
business, and there can be no assurance that significant costs and
liabilities will not be incurred. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws,
regulations and enforcement policies thereunder, and claims for damages
to property
F-17
ETC OKLAHOMA PIPELINE, LTD.
NOTES TO UNAUDITED FINANCIAL STATEMENTS -- (CONTINUED)
Six months ended February 28, 2005
D - COMMITMENTS AND CONTINGENCIES -- (CONTINUED)
or persons resulting from the operations, could result in substantial
costs and liabilities. Accordingly, the Company has adopted policies,
practices, and procedures in the areas of pollution control, product
safety, occupational health, and the handling, storage, use, and disposal
of hazardous materials to prevent material environmental or other damage,
and to limit the financial liability, which could result from such
events. However, some risk of environmental or other damage is inherent
in the natural gas pipeline and processing business, as it is with other
entities engaged in similar businesses.
In conjunction with the acquisition of the Texas and Oklahoma natural gas
gathering and gas processing assets from Aquila, Aquila, Inc. agreed to
indemnify La Grange Acquisition, L.P. for any environmental liabilities
from those operations prior to October 1, 2002.
Environmental exposures and liabilities are difficult to assess and
estimate due to unknown factors such as the magnitude of possible
contamination, the timing and extent of remediation, the determination of
the Company's liability in proportion to other parties, improvements in
cleanup technologies and the extent to which environmental laws and
regulations may change in the future. Although environmental costs may
have a significant impact on the results of operations for any single
period, the Company believes that such costs will not have a material
adverse effect on its financial position. Elk City did not accrue for
environmental liabilities as of February 28, 2005.
E - SUBSEQUENT EVENT
On April 14, 2005, Elk City's parent company completed the sale of the
Company to Atlas Pipeline Partners, L.P. for $190 million in cash,
subject to certain adjustments as defined in the purchase and sale
agreement.
F-18
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and
Atlas Pipeline Partners, L.P.
We have audited the accompanying statements of income and changes in
parent's equity and cash flows of the Elk City System (a division of the
Aquila Gas Pipeline Corporation), for the year ended September 30, 2002. 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 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. The
Company is not required to have, nor were we engaged to perform an audit of
its internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the Company's
internal control over financial reporting. Accordingly, we express no such
opinion. An audit also 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,
as well as evaluating the overall financial statement presentation. We believe
that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the results of operations of the Elk City System of
Aquila Gas Pipeline Corporation for the year ended September 30, 2002, in
conformity with accounting principles generally accepted in the United States
of America.
/s/ Grant Thornton LLP
Cleveland, Ohio
April 25, 2005
F-19
THE ELK CITY SYSTEM
STATEMENT OF INCOME AND CHANGES IN PARENT'S EQUITY IN DIVISION
For the year ended September 30, 2002
(In thousands)
OPERATING REVENUES:
Third party ........................................................ $ 5,599
Related party ...................................................... 46,643
--------
Total revenues ................................................... 52,242
COSTS AND EXPENSES:
Cost of products sold .............................................. 41,610
Operating .......................................................... 3,881
General and administrative ......................................... 1,389
Depreciation and amortization ...................................... 3,811
Asset impairment ................................................... 12,850
--------
Total costs and expenses ......................................... 63,541
--------
LOSS FROM OPERATIONS ................................................ (11,299)
OTHER INCOME:
Gain on disposal of assets ......................................... 14
--------
LOSS BEFORE INCOME TAXES ............................................ (11,285)
INCOME TAX BENEFIT .................................................. (4,439)
--------
NET LOSS ............................................................ (6,846)
--------
Parent's beginning equity in division ............................... 11,763
--------
Parent's ending equity in division .................................. $ 4,917
========
The accompanying notes are an integral part of this financial statement.
F-20
THE ELK CITY SYSTEM
STATEMENT OF CASH FLOWS
For the year ended September 30, 2002
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss ............................................................ $(6,846)
Adjustments to reconcile net loss to net cash provided by operating
activities--
Depreciation and amortization ..................................... 3,811
Asset impairment .................................................. 12,850
Deferred income taxes ............................................. (4,864)
Other, net ........................................................ (15)
Changes in operating assets and liabilities--
Receivables ...................................................... (1,726)
Materials and supplies ........................................... 148
Other current assets ............................................. (34)
Payables ......................................................... 942
Related party payables ........................................... 5,167
Accrued expenses ................................................. 49
Income taxes payable ............................................. 425
-------
Net cash provided by operating activities ....................... 9,907
-------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment .......................... (5,045)
Proceeds from sale of assets ........................................ 115
-------
Net cash used in investing activities ........................... (4,930)
-------
CASH FLOWS FROM FINANCING ACTIVITIES:
Working capital from parent ......................................... (4,977)
-------
Net cash used in financing activities ........................... (4,977)
-------
Net change in cash and cash equivalents ............................. --
Cash and cash equivalents, beginning of year ........................ --
-------
Cash and cash equivalents, end of year .............................. $ --
=======
The accompanying notes are an integral part of this financial statement.
F-21
THE ELK CITY SYSTEM
NOTES TO CARVE-OUT FINANCIAL STATEMENTS
Year ended September 30, 2002
(Dollar amounts in thousands)
A - ORGANIZATION AND BUSINESS
Aquila Gas Processing Corporation (AGP), a Delaware Corporation and a
wholly-owned subsidiary of Aquila Gas Pipeline Corporation (Aquila),
owned the Elk City natural gas gathering pipeline system and gas
processing plant in Oklahoma. Collectively, those assets are referred to
herein as the Elk City System. The Elk City System is considered a
business as defined in the rules and regulations of the U.S. Securities
and Exchange Commission and is sometimes referred to herein as the
"Company".
The Elk City system, a 318-mile gathering system located in western
Oklahoma, gathers, compresses, treats and processes natural gas from the
Anadarko Basin. The Elk City System also includes the Elk City processing
plant and one treating facility. The Elk City System is connected, either
directly or indirectly, to six major interstate and intrastate natural
gas pipelines providing access to natural gas markets throughout the
United States. The Elk City System has a processing capacity of
approximately 130 million cubic feet per day (MMcf/d).
B - SIGNIFICANT ACCOUNTING POLICIES
1. Basis of Presentation
The financial statements of the Company have been prepared in accordance
with accounting principles generally accepted in the United States of
America. The accompanying financial statements present the operations and
cash flows of the Elk City System on a carve-out basis. Accordingly, the
carve-out financial statements reflect a reasonable allocation of the
costs historically incurred by AGP.
2. Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period.
Significant estimates made by management include, but are not limited to
the useful lives for depreciation and amortization, and general business
reserves. Actual results could differ from those estimates.
3. Impairment of Long-lived Assets
The Company evaluates the carrying value of long-lived assets to be held
and used when events and circumstances warrant such a review. The
carrying value of long-lived assets would be considered impaired when the
projected undiscounted cash flows are less than carrying value. In that
event, a loss would be recognized based on the amount by which the
carrying value exceeds the fair value. Fair value is determined primarily
by available market valuations, or, if applicable, discounted cash flows.
As a result of the sale to La Grange (See Note H), the Company recorded
an impairment of $12,850 for the year ended on September 30, 2002, to
write down the Elk City assets to their net realizable value.
4. Revenue Recognition
Revenue for sales of natural gas and natural gas liquids (NGLs) is
recognized upon delivery. Service revenues, including transportation,
treating, compression and gas processing, are recognized at the time
service is performed. Elk City System contracts consist primarily of
transportation contracts and keep-whole arrangements. Under
transportation contracts, the Company receives a fee for transporting gas
through its system. The revenue earned from transportation contracts is
directly related to volume of natural gas transported through the system
and is not directly dependent on commodity prices. Under keep-whole
arrangements, the Company gathers natural gas from the producer,
processing the natural gas and selling the resulting NGLs at market
prices to an affiliated company.
F-22
THE ELK CITY SYSTEM
NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)
Year ended September 30, 2002
(Dollar amounts in thousands)
B - SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
5. Shipping and Handling Costs
In accordance with the Emerging Issues Task Force Issue 00-10,
"Accounting for Shipping and Handling Fees and Costs," the Company
classifies fees deducted from payments to producers for compression and
treating of gas as revenue.
6. Commodity Risk Management
In 1999, Aquila Gas Pipeline transferred all of its energy trading
operations and management thereof to Aquila Energy Market (AEM), a wholly
owned subsidiary of Aquila, Inc. AEM enters into forward physical
contracts with third parties for the benefit of Aquila and where deemed
necessary entered into intercompany financial derivative positions (e.g.,
swaps, futures and options) with Aquila and other affiliates to assist
them in managing their exposures. Thus, Aquila has forward physical
contracts with third parties and financial derivative positions with AEM
and affiliates. This activity was not pushed down to the carve-out
financial statements of Elk City.
7. Stock Compensation
Some of the Company's employees received stock options in Aquila. As
permitted under accounting principles generally accepted in the United
States of America, Aquila elected to account for the options under
Accounting Principles Board Opinion No. 25, and because the options
strike price was equal to or greater than the fair value at the date of
the grant, no compensation expense was recognized for the year ended
September 30, 2002. As these were Aquila options, the Company does not
have full access to the information necessary to disclose what
compensation expense would have been, had Aquila accounted for the
options under Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation, which requires compensation
expense be recognized for the fair value of the options at the date of
grant. La Grange Acquisition does not have a stock option plan in place
for its employees.
8. Federal and State Income Taxes
The Elk City System was included in the consolidated federal income tax
returns filed by Aquila. Accordingly, all tax balances were ultimately
settled through Aquila. The Company had generally accounted for its taxes
on a stand-alone or separate return basis (see Note D). Periodically,
taxes payable were settled through the intercompany accounts with Aquila
and were not funded in cash.
The Company provides for income taxes in accordance with Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes
(Statement No. 109). Statement No. 109 requires that deferred tax assets
and liabilities be established for the basis differences between the
reported amounts of assets and liabilities for financial reporting
purposes and income tax purposes.
9. Asset Retirement Obligation
The Company accounts for its asset retirement obligations in accordance
with Statement of Financial Accounting Standards No. 143, Accounting for
Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the
Company to record the fair value of an asset retirement obligation as a
liability in the period in which it incurs a legal obligation for the
retirement of tangible long-lived assets, typically at the time the
assets are placed into service. A corresponding asset is also recorded
and depreciated over the life of the asset. After the initial
measurement, any changes in the amount of the liability resulting from
the passage of time and revisions to either the timing or amount of
estimated cash flows would be recognized prospectively.
The Company has determined that it is obligated by contractual
requirements to remove facilities or perform other remediation upon
retirement of certain of our assets. Determination of the amounts to be
recognized is based upon numerous estimates and assumptions, including
expected settlement dates,
F-23
THE ELK CITY SYSTEM
NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)
Year ended September 30, 2002
(Dollar amounts in thousands)
B - SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
future retirement costs, future inflation rates and the credit-adjusted
risk-free interest rates. However, the Company is not able to reasonably
determine the fair value of the asset retirement obligations as of
September 30, 2002, because the settlement dates are indeterminable. An
asset retirement obligation will be recorded in the periods in which the
settlement dates can reasonably be determined.
C - RELATED PARTY TRANSACTIONS
The Company entered into various types of transactions with Aquila for
the year ended September 30, 2002. The Company sold the majority of
natural gas and NGLs produced to Aquila. Additionally, the Company
reimbursed Aquila for certain employees who provided services to the
Company and for other costs (primarily general and administrative
expense) related to the Company's operations. Aquila also provided the
working capital necessary for the operations of the Company.
The following table summarized transactions for the year ended
September 30, 2002:
Natural gas sales to affiliated companies............................ $16,391
NGLs sales to affiliated companies................................... 30,252
Allocated costs from affiliated companies............................ 1,389
Working capital to affiliated companies.............................. 3,732
D - INCOME TAXES
A reconciliation between the expected tax computed using the US federal
statutory income tax rate and the provision for income taxes is as
follows:
2002
--------
Statutory federal income tax (35%).................................. $ (3,950)
State and local income taxes -- net of federal income tax effect
(4.3%)............................................................. (489)
--------
Total............................................................... $(4,439)
========
E - RETIREMENT AND BENEFITS
For the year ended September 30, 2002, certain Aquila employees received
stock options to purchase Aquila's common stock. As permitted under
generally accepted accounting principles, Aquila elected to account for
the options under Accounting Principles Board Opinion No. 25, and because
the options strike price was equal to or greater than the fair value at
the date of grant, no compensation expense was recognized. As these were
Aquila, Inc. options, the Company does not have full access to the
information necessary to disclose what compensation would have been, had
Aquila accounted for the options under Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation", which
requires compensation expense be recognized for the fair value of the
options at the date of grant. The Company does not have a stock option
plan in place for its employees.
Aquila had a defined contribution plan for virtually all employees.
Pursuant to the plan, employees of the Company can defer a portion of
their compensation and contribute it to a deferred account. Aquila's
matching contribution to the plan for the Company employees was $34 for
the year ended September 30, 2002.
Aquila had a stock contribution plan under which eligible employees
received a Company contribution of 3% of their base income in Aquila's
common stock. The Company's expense associated with this plan for the
Company employees for the year ended September 30, 2002 was $19.
F-24
THE ELK CITY SYSTEM
NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)
Year ended September 30, 2002
(Dollar amounts in thousands)
F - COMMITMENTS AND CONTINGENCIES
1. Litigation
The Company is involved in various lawsuits, claims and regulatory
proceedings incidental to its business. In the opinion of management, the
outcome of such matters will not have a material adverse effect on the
Company's financial position or results of operations.
2. Environmental
The Company's operations are subject to extensive federal, state and
local environmental laws and regulations that require expenditures for
remediation at operating facilities and waste disposal sites. Although
the Company believes its operations are in substantial compliance with
applicable environmental laws and regulations, risks of additional costs
and liabilities are inherent in the natural gas pipeline and processing
business, and there can be no assurance that significant costs and
liabilities will not be incurred. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws,
regulations and enforcement policies thereunder, and claims for damages
to property or persons resulting from the operations, could result in
substantial costs and liabilities. Accordingly, the Company has adopted
policies, practices, and procedures in the areas of pollution control,
product safety, occupational health, and the handling, storage, use, and
disposal of hazardous materials to prevent material environmental or
other damage, and to limit the financial liability, which could result
from such events. However, some risk of environmental or other damage is
inherent in the natural gas pipeline and processing business, as it is
with other entities engaged in similar businesses.
Environmental exposures and liabilities are difficult to assess and
estimate due to unknown factors such as the magnitude of possible
contamination, the timing and extent of remediation, the determination of
the Company's liability in proportion to other parties, improvements in
cleanup technologies and the extent to which environmental laws and
regulations may change in the future. Although environmental costs may
have a significant impact on the results of operations for any single
period, the Company believes that such costs will not have a material
adverse effect on its financial position. Elk City did not accrue for
environmental liabilities as of September 30, 2002.
G - MAJOR CUSTOMERS AND SUPPLIERS
The Company sold 89.3% of natural gas and NGLs produced to Aquila for the
year ended September 30, 2002.
For the year ended September 30, 2002, the Company had gross purchases as
a percentage of cost of sales from nonaffiliated major suppliers as
follows:
St. Mary Operating Company...................................... 19.8%
Exxon Company, U.S.A............................................ 10.7%
Management believes that the diversification of suppliers is sufficient
to enable the Company to purchase all of its supply needs at market
prices without a material disruption of operations if supplies are
interrupted from any of the Company's existing sources. Although no
assurances can be given that supplies will be readily available in the
future, we expect a sufficient supply to continue to be available.
H - SUBSEQUENT EVENT
In October 2002, La Grange Acquisition, L.P. purchased the Elk City System
from Aquila.
F-25
$250,000,000
ATLAS PIPELINE PARTNERS, L.P.
Common Units
Subordinated Units
Debt Securities
Warrants
We may offer from time to time the following types of securities:
o our common units representing limited partner interests;
o our subordinated units representing limited partner interests;
o our debt securities, in one or more series, which may be senior debt
securities or subordinated debt securities, in each case consisting of
notes or other evidences of indebtedness;
o warrants to purchase any of the other securities that may be sold under
this prospectus; or
o any combination of these securities, individually or as units.
The securities will have an aggregate initial offering price of up to
$250,000,000. The securities may be offered separately or together in any
combination and as a separate series. This prospectus also covers guarantees, if
any, of our payment obligations under any debt securities, which may be given by
certain of our subsidiaries on terms to be determined at the time of the
offering.
We will provide specific terms of these securities in supplements to this
prospectus. You should read this prospectus and any prospectus supplement, as
well as the documents incorporated or deemed to be incorporated by reference in
this prospectus, carefully before you invest. This prospectus may not be used to
consummate sales of securities unless accompanied by the applicable prospectus
supplement.
Our common units are quoted on the American Stock Exchange under the symbol
"APL."
You should read "Risk Factors" beginning on page 14 of this prospectus, as
well as those which may be contained in any supplement to this prospectus, for a
discussion of important factors that you should consider before you invest.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
We may sell these securities directly, through agents, dealers or
underwriters as designated from time to time, or through a combination of these
methods. We reserve the sole right to accept, and together with our agents,
dealers and underwriters reserve the right to reject, in whole or in part, any
proposed purchase of securities to be made directly or through agents, dealers
or underwriters. If any agents, dealers or underwriters are involved in the sale
of any securities, the relevant prospectus supplement will set forth any
applicable commissions or discounts. Our net proceeds from the sale of
securities also will be set forth in the relevant prospectus supplement.
Prospectus dated April 5, 2004
PROSPECTUS SUMMARY
About this Prospectus
This prospectus is part of a registration statement that we filed with
the Securities and Exchange Commission using a "shelf" registration process.
Under this shelf process, we may, from time to time, offer any combination of
the securities described in this prospectus in one or more offerings up to a
total dollar amount of $250,000,000. This prospectus provides you with a general
description of the securities we may offer. Each time we use this prospectus to
offer these securities, we will provide a prospectus supplement that will
contain specific information about the terms of that offering. The prospectus
supplement may also add, update or change information contained in this
prospectus. Please carefully read this prospectus and the prospectus supplement
together with the additional information described under the heading "Where You
Can Find More Information."
Atlas Pipeline
We own and operate natural gas pipeline gathering systems through our
operating partnership and its operating subsidiaries. Our primary assets consist
of approximately 1,380 miles of intrastate gathering systems located in eastern
Ohio, western New York and western Pennsylvania. In September 2003, we entered
into a purchase and sale agreement with SEMCO Energy, Inc. (NYSE: SEN) under
which we or our designee will purchase all of the outstanding equity of SEMCO's
wholly-owned subsidiary, Alaska Pipeline Company, which owns a 354-mile
intrastate natural gas transmission pipeline that delivers gas to metropolitan
Anchorage. The total consideration, payable in cash at closing, will be
approximately $95 million, subject to an adjustment based on the amount of
working capital that Alaska Pipeline has at closing.
Currently, our gathering systems serve approximately 4,500 wells with
an average daily throughput for the year ended December 31, 2003 of 52.5 million
cubic feet, or mmcf, of natural gas. Our gathering systems provide a means
through which well owners and operators can transport the natural gas produced
by their wells to public utility pipelines for delivery to customers. To a
lesser extent, our gathering systems transport natural gas directly to
customers. Our gathering systems currently connect with public utility pipelines
operated by Peoples Natural Gas Company, National Fuel Gas Supply, Tennessee Gas
Pipeline Company, National Fuel Gas Distribution Company, East Ohio Gas Company,
Columbia of Ohio, Consolidated Natural Gas Co., Texas Eastern Pipeline, Columbia
Gas Transmission Corp. and Equitable Utilities. We do not engage in storage or
gas marketing programs, nor do we currently engage in the purchase and resale
for our own account of natural gas transported through our gathering systems.
We originally acquired the gathering systems of Atlas America, Inc. and
its affiliates, all of which are subsidiaries of Resource America, Inc. (NASDAQ:
REXI), when we commenced operations in January 2000. Throughout this prospectus,
we refer to the Resource America energy subsidiaries with which we have
contractual relationships, including Atlas America, collectively as "Atlas
America," unless specifically stated otherwise. Atlas America and its affiliates
sponsor limited and general partnerships to raise funds from investors to
explore for natural gas, and produce natural gas and, to a lesser extent, oil
from locations in eastern Ohio, western New York and western Pennsylvania. Our
gathering systems are connected to 4,100 of those wells. Atlas America drilled
and connected 270 wells to our gathering systems during the year ended December
31, 2003, 195 wells during the year ended December 31, 2002 and 196 wells during
the year ended December 31, 2001.
We are party to an omnibus agreement with Atlas America that is
intended to maximize the use and expansion of our gathering systems and the
amount of natural gas they transport. Among other things, the omnibus agreement
requires Atlas America to install required flow lines and connect wells it
operates that are located within 2,500 feet of one of our gathering systems.
2
We are also party to natural gas gathering agreements with Atlas
America under which it pays us gathering fees generally equal to a percentage,
generally 16%, of the gross or weighted average sales price of the natural gas
we transport subject, in certain cases, to minimum prices of $.35 or $.40 per
thousand cubic feet, or mcf. Our business, therefore, depends in large part on
the prices at which the natural gas we transport is sold. Due to the volatility
of natural gas prices, our gross revenues can vary materially from period to
period. During the year ended December 31, 2003, we received gathering fees
averaging $.82 per mcf, while during the previous year, our average gathering
fee was $.58 per mcf.
Objectives and Strategy
Our objective is to increase cash flow, earnings and returns to our
unitholders by:
o expanding our revenue base through:
o construction of extensions necessary to service additional
wells drilled by Atlas America and others and
o accretive acquisitions of mid-stream energy assets such as
natural gas gathering, transmission, processing and storage
facilities and liquid gathering, transmission and storage
facilities;
o limiting operating costs through achievement of economies of
scale as a result of expanding our operations through extensions
and acquisitions; and
o continuing to strengthen our balance sheet by financing our
growth with a combination of long-term debt and equity to provide
the financial flexibility to fund future opportunities.
Since commencing operations in January 2000, we have pursued these
objectives by:
o adding 372 miles of pipeline to our original system;
o connecting 829 wells to our pipeline, 770 of which were drilled
by Atlas America;
o acquiring gathering systems in Ohio and Pennsylvania, aggregating
120 miles of pipeline, with approximately 433 wells connected to
those systems;
o agreeing in September 2003 to acquire Alaska Pipeline, which we
believe will add a significant source of stable income and
distributable cash flow; and
o upgrading our system and substantially expanding our capacity.
Partnership Information
We were formed in May 1999 as a Delaware limited partnership and, under
our partnership agreement, will be required to dissolve no later than December
31, 2098. We own a 98.9899% limited partnership interest in Atlas Pipeline
Operating Partnership, L.P., also a Delaware limited partnership, which owns our
current gathering systems through subsidiaries. We recently formed APC
Acquisition, LLC, in which we currently own 100% of the membership interests, in
order to acquire Alaska Pipeline. We have no significant assets other than our
limited partnership interest in the operating partnership. Our general partner
has sole responsibility for conducting our business and managing our operations.
As is commonly the case with publicly traded limited partnerships, we do not
directly employ any of the persons responsible for our management or operation.
Rather, Atlas America personnel manage and operate our business. Our general
partner also acts as general partner of the operating partnership. As a
consequence, the affairs of the operating partnership are controlled by our
general partner and not by us. However, our general partner may not, without the
consent of all of our limited partners, consent to any act that would make it
impossible to carry on our ordinary business and may not, without the consent of
limited partners holding a majority of the outstanding common units and
subordinated units, voting as separate classes, dispose of all or substantially
all of our assets or the assets of the operating partnership.
3
Our common units are entitled to receive cash distributions of $.42 per
quarter, or $1.68 on an annualized basis, before any distributions are paid on
our existing subordinated units. We expect this priority to continue until
January 1, 2005. Our general partner owns all of our outstanding 1,641,026
subordinated units.
Our principal executive offices are located at 311 Rouser Road, Moon
Township, Pennsylvania 15108 and our telephone number is (412) 262-2830.
Summary of Conflicts of Interest and Fiduciary Responsibilities
Our general partner has a fiduciary duty to manage us in a manner
beneficial to us and our unitholders. However, because our general partner is a
corporate subsidiary of Atlas America, its officers and directors have fiduciary
duties to manage its business in a manner beneficial to Atlas America. As a
result, conflicts of interest may arise in the future between us and our
unitholders, on the one hand, and Atlas America and its affiliates, on the other
hand.
The following situations, among others, could give rise to conflicts of
interest:
o our general partner determines the amount and timing of asset
purchases and sales, capital expenditures, issuances of additional
common units, borrowings and reserves, which can impact the amount of
distributions to unitholders;
o our general partner may take actions on our behalf that have the
effect of enabling our general partner to receive distributions on
its subordinated units;
o some of the officers of our general partner who provide services to
us also devote significant time to the businesses of our general
partner's affiliates, and competition for their services may develop;
o the officers of our general partner may make decisions on behalf of
Atlas America, as the operator of natural gas wells connected to our
gathering systems, as to the volume of gas produced by these wells,
and these decisions may affect the volume of natural gas transported
by us and, thus, our revenues; and
o our general partner makes decisions that affect the obligations of
Atlas America to us in constructing gathering systems, providing
financing for that construction and identifying gathering systems for
possible acquisition.
Our general partner has a conflicts committee, consisting of three
independent members of its managing board, that is available to review matters
involving conflicts of interest.
Our partnership agreement limits the liability and reduces the
fiduciary duties of our general partner to our unitholders. Our partnership
agreement also restricts the remedies available to unitholders for actions that
might otherwise constitute breaches of its fiduciary duty. By purchasing a
common unit, you are treated as having consented to these restrictions, and to
various actions contemplated in the partnership agreement and to conflicts of
interest that might otherwise be considered a breach of fiduciary or other
duties under applicable state law.
4
Distributions and Payments to Our General Partner and Its Affiliates
The following summarizes the distributions and payments we make to our
general partner and its affiliates in connection with our operation and
liquidation. These distributions and payments were determined by and among
affiliated entities and, consequently, are not the result of arm's length
negotiations.
Cash distributions to our general partner........... Cash distributions are generally made 98% to the
unitholders, including to our general partner as
holder of our existing subordinated units, and 2% to
our general partner. If distributions exceed specified
target levels, our general partner will receive from
15% to 50% of the excess distributions. We refer to
these distributions as our general partner's
"incentive distribution rights." For the year ended
December 31, 2003, our general partner received
distributions of $4,561,100, including $594,000 of
incentive distributions, $192,700 on its general
partner interest and $3,774,400 on its subordinated
units.
Payments to our general partner..................... Our general partner does not receive management fees or other
compensation for managing us. We reimburse our general partner
for all direct, indirect and capital expenditures it incurs on
our behalf. For the year ended December 31, 2003, we reimbursed
$11,715,600 to our general partner, consisting of $2,420,500 in
transportation and compression costs, $1,660,900 in general and
administrative costs and $7,634,200 in capital expenditures.
Withdrawal or removal of our general
partner............................................. If our general partner withdraws or is removed, its general partner
interest and 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.
Liquidation......................................... Upon our liquidation and after payment of our creditors, the
partners, including our general partner, will be entitled to
receive liquidating distributions according to their
particular capital account balances. For a description of how
capital account balances are determined and adjusted upon
liquidation, see "Cash Distribution Policy--Distributions of
Cash Upon Liquidation."
Our Partnership Agreement
Cash distributions.................................. We must distribute all of our cash on hand at the end of each
quarter, less reserves established by our general partner in its
discretion. The amount of this cash may be greater than or less
than the minimum quarterly distribution referred to in the next
paragraph. We generally make cash distributions within 45 days
after the end of each quarter.
5
In general, we make cash distributions each quarter based on the
following priorities:
o first, 98% to the common units and 2% to our general partner until
each common unit has received a minimum quarterly distribution of
$.42, plus any arrearages in the payment of the minimum quarterly
distribution from prior quarters;
o second, 98% to our existing subordinated units and 2% to our
general partner until each subordinated unit has received a
minimum quarterly distribution of $.42;
o third, 85% to all units and 15% to our general partner until each unit has
received a total distribution of $.52 in that quarter;
o fourth, 75% to all units and 25% to our general partner until each
unit has received a total distribution of $.60 in the quarter; and
o after that, 50% to all units and 50% to our general partner.
The distributions to our general partner in the third through fifth
distribution levels are incentive distributions and are
disproportionate to its 2% interest in us as our general partner.
If we make a distribution from capital surplus, which generally
means distributions from cash generated other than from operations
or from working capital reserves, it is treated as if it were
repayment of the unit price from our initial public offering of
common units, which was $13.00 per common unit. To reflect
repayment, distribution levels, including the minimum quarterly
distributions, will be adjusted downward by multiplying each
distribution amount by a fraction. This fraction is determined as
follows:
o the numerator is the unrecovered initial unit price of the common
unit immediately after giving effect to the repayment, and
o the denominator is the unrecovered initial unit price of the
common units immediately before the repayment.
The unrecovered initial unit price is the initial public offering
price per common unit of $13.00 less any distributions from capital
surplus. Distributions from capital surplus will not reduce the
minimum quarterly distribution or target or other distribution
levels for the quarter in which they are distributed. We do not
anticipate that there will be significant distributions from capital
surplus.
6
Upon liquidation, we will distribute any cash remaining, after we
have paid our creditors, to unitholders and our general partner in
accordance with their capital account balances. To the extent
proceeds of liquidation are available, we will adjust the capital
accounts of our general partner and the common unitholders to give
our general partner amounts representing incentive distributions.
Existing subordinated units;
subordination period................................ Our existing subordinated units are a separate class of interest in
us whose rights to distributions are subordinate to those of the
common units during the subordination period. The subordination
period will end on January 1, 2005 unless the financial tests in the
partnership agreement are not met. When the subordination period
ends, all of these subordinated units will convert into common units
on a one-for-one basis. The subordinated units will similarly
convert to common units if our general partner is removed without
cause. Converted subordinated units will have the same rights as
common units and will thus participate equally with the other common
units in distributions.
Issuance of additional units........................ We are permitted to issue common units, subordinated units, debt and
other securities without restriction under our partnership agreement
except that, during the subordination period for our existing
subordinated units, we cannot issue securities having rights to
distribution or in liquidation ranking prior or senior to our common
units without unitholder consent.
Amendment of our partnership
agreement........................................... Our partnership agreement may generally be amended by a vote of
persons holding a majority of the common units and existing
subordinated units, voting as separate classes, provided that we
obtain an opinion of counsel that the amendment will not materially
adversely affect the limited liability of the limited partners.
Amendments may be proposed only by or with the consent of our
general partner, which may withhold its consent in its sole
discretion. Our general partner may, without the consent of
unitholders, amend our partnership agreement to accommodate
administrative functions such as admission, withdrawal or
substitution of limited partners, to effect our qualification to do
business in a jurisdiction or to prevent us from being deemed an
investment company. No amendment may be made that would enlarge the
obligations of any limited partner without that partner's consent;
enlarge, restrict or reduce the rights, obligations, or amounts
distributable or reimbursable to our general partner; change our
term or modify the nature of those events causing our dissolution.
7
Limited liability of limited partners............... The liability of a person purchasing common units or subordinated
units will be limited to the amount of the purchaser's investment
plus the purchaser's share of any of our undistributed profits or
assets, so long as the purchaser does not participate in the control
of our business within the meaning of Delaware law and otherwise
acts in conformity with our partnership agreement.
Limited voting rights............................... Holders of common units and subordinated units do not have voting
rights except with respect to the following matters, for which the
partnership agreement requires unitholder approval:
o a sale or exchange of all or substantially all of our
assets;
o the removal or withdrawal of our general partner;
o the election of a successor general partner;
o our dissolution or reconstitution;
o a merger;
o termination or material modification of the master natural gas
gathering agreement and omnibus agreement with Atlas America;
o approval of the transfer by our general partner of its general
partner interest or incentive distribution rights, except in a
merger or to an affiliate; and
o in general, amendments to the partnership agreement.
Change of control................................... Any person or group, other than our general partner and its
affiliates or a direct transferee of our general partner or its
affiliates, that acquires beneficial ownership of 20% or more of our
common units will lose its voting rights with respect to all of its
common units.
Removal or withdrawal of our general
partner............................................. Our general partner may be removed by the vote of at least 66 2/3%
of our outstanding common units and the election of a successor
general partner by the vote of a majority of the outstanding common
units, excluding in both cases common units held by our general
partner and its affiliates.
Our general partner may not withdraw as our general partner without
the vote of at least a majority of the outstanding common units,
excluding common units held by our general partner and its
affiliates. However, our general partner may withdraw without
approval of our common units if at least 50% of our common units are
held or controlled by one person or its affiliates other than our
general partner and its affiliates.
8
Consequences of removal of our general
partner............................................. If our general partner is removed other than for cause, all of our
existing subordinated units will immediately convert into common
units on a one-for-one basis. Any existing arrearages in the payment
of the minimum quarterly distribution to the common units will be
extinguished, and our general partner will have the right to convert
its general partner interest and its right to receive incentive
distributions into common units or to receive cash in exchange for
such interests. In addition, the omnibus agreement will terminate
and the master natural gas gathering agreement will terminate with
respect to future wells drilled and completed by Atlas America.
9
Summary Financial Data
We derived the financial data set forth below as of and for the three
years ended December 31, 2003 from our consolidated financial statements for
those periods, which have been audited by Grant Thornton LLP, independent
accountants. You should read the financial data in this table together with, and
such financial data is qualified by reference to, our consolidated financial
statements, the notes to our consolidated financial statements and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included elsewhere or incorporated by reference in this prospectus.
For the years ended December 31,
-----------------------------------
2003 2002 2001
------- ------- -------
(in thousands, except per unit data)
Income statement data:
Revenues............................................. $15,749 $10,667 $13,129
======= ======= =======
Total transportation and compression, general and
administrative expenses........................... $ 4,081 $ 3,544 $ 3,042
======= ======= =======
Depreciation and amortization........................ $ 1,770 $ 1,476 $ 1,356
======= ======= =======
Net income........................................... $ 9,639 $ 5,398 $ 8,556
======= ======= =======
Net income per limited partner unit - basic and $ 2.17 $ 1.54 $ 2.30
diluted............................................ ======= ======= =======
Distributions declared per common unit............... $ 2.39 $ 2.14 $ 2.50
======= ======= =======
At December 31,
-----------------------------------
2003 2002 2001
------- ------- -------
(in thousands)
Balance sheet data:
Total assets......................................... $49,512 $28,515 $26,002
======= ======= =======
Long-term debt....................................... $ - $ 6,500 $ 2,089
======= ======= =======
Common unitholders' capital.......................... $43,551 $19,164 $20,129
Subordinated unitholder's capital.................... 354 684 1,661
General partner's capital (deficit).................. 340 (161) (116)
------- ------- -------
Total partners' capital.............................. $44,245 $19,687 $21,674
======= ======= =======
10
Summary Operating Data
The following table summarizes information concerning the volumes of
natural gas we transported during the years ended December 31, 2003, 2002 and
2001 as well as the average transportation rate we received during those
periods.
For the years ended December 31,
---------------------------------------
2003 2002 2001
----------- ----------- -----------
Total volume of natural gas transported (in
mcf).......................................... 19,152,300 18,382,600 17,125,000
=========== =========== ===========
Average daily volume of natural gas transported
(in mcf)...................................... 52,472 50,363 46,918
=========== =========== ===========
Average transportation rate per mcf.............. $ .82 $ .58 $ .76
=========== =========== ===========
Available cash from operating surplus(1)......... $10,800,000 $ 7,385,300 $ 9,284,600
=========== =========== ===========
-----------------
(1) We define available cash from operating surplus under "Our Partnership
Agreement--Cash Distribution Policy--Distributions of Available Cash from
Operating Surplus." Available cash from operating surplus is not a measure
of cash flow as determined by generally accepted accounting principles. We
have included information concerning available cash from operating surplus
because it provides investors and management additional information as to
our ability to pay distributions to common unitholders and fixed charges
and is presented solely as a supplemental financial measure. Available cash
from operating surplus should not be considered as an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with generally accepted accounting principles or as an indicator of our
operating performance or liquidity. Available cash from operating surplus
is not necessarily comparable to a similarly titled measure of another
company. The table below shows how we calculated available cash from
operating surplus.
For the years ended December 31,
--------------------------------
2003 2002 2001
-------- ------- -------
(in thousands)
Net cash provided by operating activities........... $ 13,702 $ 8,138 $10,268
Net borrowings less capital expenditures
and acquisitions................................. (14,134) (820) (1,039)
Capital contributions and net proceeds from
offering......................................... 25,720 - 45
Increase in other assets............................ (2,468) (61) (38)
(Increase) decrease in cash reserves................ (12,020) 128 49
-------- ------- -------
Available cash from operating surplus............... $ 10,800 $7,385 $ 9,285
======== ======= =======
11
RISK FACTORS
Limited partner interests are inherently different from the capital
stock of a corporation, although many of the business risks we encounter are
similar to those that would be faced by a corporation engaged in a similar
business. You should consider the following risk factors together with all of
the other information included in this prospectus in evaluating an investment in
our securities. If any of the following risks actually occurs, our business,
financial condition or results of operations could be materially adversely
affected. In that case, the trading price of our securities could decline and
you may lose some or all of your investment.
Our cash distributions are not assured and may fluctuate with our performance.
The amounts of cash that we generate may not be sufficient to pay the
minimum quarterly distributions established in our partnership agreement or any
other level of distributions. The actual amounts of cash we generate will depend
upon numerous factors relating to our business which may be beyond our control,
including:
o the demand for and price of natural gas;
o the volume of natural gas we transport;
o continued development of wells for connection to our gathering
systems;
o the expenses we incur in providing our gathering services;
o the cost of acquisitions and capital improvements;
o our issuance of equity securities;
o required principal and interest payments on our debt;
o fluctuations in working capital;
o prevailing economic conditions;
o fuel conservation measures;
o alternate fuel requirements;
o government regulations; and
o technical advances in fuel economy and energy generation devices.
Our ability to make cash distributions depends primarily on our cash
flow. Cash distributions do not depend directly on our profitability, which is
affected by non-cash items. Therefore, cash distributions may be made during
periods when we record losses and may not be made during periods when we record
profits.
The failure of Atlas America to perform its obligations under the natural gas
gathering agreements may adversely affect our revenues.
Our revenues currently consist of the fees we receive under the master
natural gas gathering agreement and other transportation agreements we have with
Atlas America and its affiliates. While Atlas America receives gathering fees
from the well owners, it is contractually obligated to pay our fees even if the
gathering fees paid to it by well owners are less than the fees it must pay us.
Our cash flow could be materially adversely affected if Atlas America failed to
discharge its obligations to us.
The amount of natural gas we transport will decline over time unless new wells
are connected to our gathering systems.
Production of natural gas from a well generally declines over time
until the well can no longer economically produce natural gas and is plugged and
abandoned. Failure to connect new wells to our gathering systems could,
therefore, result in the amount of natural gas we transport reducing
substantially over time and could, upon exhaustion of the current wells, cause
us to abandon one or more of our gathering
12
systems and, possibly, cease operations. As a consequence, our revenues and,
thus, our ability to make distributions to unitholders would be materially
adversely affected.
We entered into the omnibus agreement with Atlas America to, among
other things, increase the number of natural gas wells connected to our
gathering systems. However, well connections resulting from that agreement
depend principally upon the success of Atlas America in sponsoring drilling
investment partnerships and completing wells for these partnerships in areas
where our gathering systems are located. If Atlas America cannot or does not
continue to organize these partnerships, if the amount of money raised by these
partnerships decreases, or if the number of wells actually drilled and completed
as commercial producing wells decreases, our revenues and ability to make cash
distributions will be materially adversely affected.
The amount of natural gas we transport may be reduced if the public utility
pipelines to which we deliver gas cannot or will not accept the gas.
Our gathering systems principally serve as intermediate transportation
facilities between sales lines from wells connected to our systems and the
public utility pipelines to which we deliver natural gas. If one or more of
these public utility pipelines has service interruptions, capacity limitations
or otherwise does not accept the natural gas we transport, and we cannot arrange
for delivery to other public utility pipelines, local distribution companies or
end users, the amount of natural gas we transport may be reduced. Since our
revenues depend upon the volumes of natural gas we transport, this could result
in a material reduction in our revenues.
We may not be able to complete the acquisition of Alaska Pipeline.
Completion of the acquisition of Alaska Pipeline is subject to a number
of conditions, including receipt of governmental and non-governmental consents
and approvals and the absence of a material adverse change in Alaska Pipeline's
business. Among the required governmental authorizations are approval of the
Regulatory Commission of Alaska. The purchase and sale agreement may be
terminated by either SEMCO or us if the transaction is not completed by June 16,
2004.
We will incur substantial indebtedness to acquire Alaska Pipeline which may
restrict our liquidity and, if interest rates increase, affect cash flow from
the acquisition.
We intend to finance the Alaska Pipeline acquisition in part through
borrowing all of the $20 million available under our existing credit facility.
Unless the borrowing is paid down, or the amount of availability increased, we
will not have further borrowing capacity to finance future acquisitions, capital
expenditures or other liquidity needs. Moreover, since this borrowing, and the
$50 million borrowing that APC Acquisition will also make to finance the
acquisition, are at variable interest rates, any increase in interest rates will
adversely affect the cash flow we expect to derive from the acquisition. We
intend to use the proceeds of one or more offerings of our securities pursuant
to this prospectus to reduce some of these borrowings. However, we cannot assure
you that we and Alaska Pipeline will generate sufficient cash flow from
operations to satisfy our and its future liquidity needs.
Governmental regulation of our pipelines could increase our operating costs.
Currently our gathering of natural gas from wells is exempt from
regulation under the Natural Gas Act. However, the implementation of new laws or
policies could subject us to regulation by the Federal Energy Regulatory
Commission under the Natural Gas Act. We expect that any such regulation would
increase our costs, decrease our revenues, or both.
Gas gathering operations are subject to regulation at the state level.
Matters subject to regulation include rates, service and safety. We have been
granted an exemption from regulation as a public utility in Ohio. Presently, our
rates are not regulated in New York and Pennsylvania. Changes in state
regulations, or our status under these regulations that subject us to further
regulation, could increase our operating costs or require material capital
expenditures.
13
Litigation or governmental regulation relating to environmental protection and
operational safety may result in substantial costs and liabilities.
Our operations are subject to federal and state environmental laws
under which owners of natural gas pipelines can be liable for clean-up costs and
fines in connection with any pollution caused by their pipelines. We may also be
held liable for clean-up costs resulting from pollution which occurred before
our acquisition of the gathering systems. In addition, we are subject to federal
and state safety laws that dictate the type of pipeline, quality of pipe
protection, depth, methods of welding and other construction-related standards.
Any violation of environmental, construction or safety laws could impose
substantial liabilities and costs on us.
We are also subject to the requirements of the Occupational Health and
Safety Act, or OSHA, and comparable state statutes. Any violation of OSHA could
impose substantial costs on us.
We cannot predict whether or in what form any new legislation or
regulatory requirements might be enacted or adopted, nor can we predict our
costs of compliance. In general, we expect that new regulations would increase
our operating costs and, possibly, require us to obtain additional capital to
pay for improvements or other compliance action necessitated by those
regulations.
We may not be able to fully execute our growth strategy.
Our strategy contemplates substantial growth through both the
acquisition of other gathering systems and the development of our existing
system. Typically, we have paid for system development in cash and have made
acquisitions either for cash or a combination of cash and common units. As a
result, limitations on our access to capital or on the market for our common
units will impair our ability to execute our growth strategy. In addition, our
strategy of growth through acquisitions involves numerous risks, including:
o we may not be able to identify suitable acquisition candidates;
o we may not be able to make acquisitions on economically
acceptable terms;
o our costs in seeking to make acquisitions may be material, even
if we cannot complete any acquisition we have pursued;
o irrespective of estimates at the time we make an acquisition, the
acquisition may prove to be dilutive to earnings and operating
surplus;
o we may encounter difficulties in integrating operations and
systems; and
o we may acquire assets located outside of our core geographic
area of operations or acquire businesses or operations that
differ in nature from traditional gas pipeline or gathering
activities, and we may incur difficulties or delays in
successfully operating such new businesses;
A decline in natural gas prices could adversely affect our revenues.
Our gathering fees are generally equal to a percentage of either the
gross or weighted average sales price of the natural gas we transport, although
in some cases we receive a flat fee per mcf of gas transported. Our income
therefore depends upon the prices at which the natural gas we transport is sold.
Historically, the price of natural gas has been volatile; as a result, our
income may vary widely from period to period.
Gathering system operations are subject to operational hazards and unforeseen
interruptions.
The operations of our gathering systems are subject to hazards and
unforeseen interruptions, including natural disasters, adverse weather,
accidents or other events beyond our control. A casualty occurrence might result
in injury and extensive property or environmental damage. Our insurance coverage
may not be sufficient for any casualty loss we may incur.
14
USE OF PROCEEDS
Unless we indicate otherwise in an accompanying prospectus supplement,
we intend to use the net proceeds from the sale of the securities offered by
this prospectus for general partnership purposes, which may include, but not be
limited to, refinancing of indebtedness, working capital, capital expenditures,
acquisitions and repurchases and redemptions of securities.
RATIO OF EARNINGS TO FIXED CHARGES
The following table shows our ratio of earnings to fixed charges for
the periods indicated.
Inception
through
Year ended December 31, December 31,
---------------------------- ------------
2003 2002 2001 2000
---- ---- ---- -----
Ratio of earnings to fixed
charges..................... 29.2 18.0 36.9 753.8
PRO FORMA FINANCIAL DATA
Following are our unaudited pro forma financial statements as of and
for the year ended December 31, 2003. The unaudited pro forma balance sheet is
prepared as though the acquisition of Alaska Pipeline described in this
prospectus occurred as of December 31, 2003, and the unaudited pro forma
statement of operations is prepared as though the acquisition occurred as of
January 1, 2003. The acquisition adjustments are described in the notes to the
unaudited pro forma financial statements. The unaudited pro forma financial
statements and accompanying notes should be read together with our "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our and Alaska Pipeline's historical financial statements and related notes
included elsewhere, or incorporated by reference, in this prospectus.
We accounted for the acquisition of Alaska Pipeline in the unaudited
pro forma financial statements using the purchase method in accordance with the
guidance of Statement of Financial Accounting Standards No. 141, "Business
Combinations." For purposes of developing the unaudited pro forma financial
information, we have allocated the purchase price to Alaska Pipeline's gas
gathering and transmission facilities based on fair market value.
The unaudited pro forma financial statements are for informational
purposes only and are based upon available information and assumptions that we
believe are reasonable under the circumstances. You should not construe the
unaudited pro forma financial statements as indicative of the combined financial
position or results of operations that we and Alaska Pipeline would have
achieved had the transaction been consummated on the dates assumed. Moreover,
they do not purport to represent our and Alaska Pipeline's combined financial
position or results of operations for any future date or period or a
representation that we will complete the Alaska Pipeline acquisition. See "Risk
Factors--We may not be able to complete the acquisition of Alaska Pipeline."
15
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA BALANCE SHEET (UNAUDITED)
DECEMBER 31, 2003
(in thousands)
Historical Historical
Atlas Alaska Acquisition Pro forma
Pipeline Pipeline adjustments consolidated
---------- ---------- ----------- ------------
ASSETS
Current assets:
Cash and cash
equivalents............ $ 15,078 $ - $ - $ 15,078
Accounts receivable...... - 714 (714) (a) -
Accounts receivable -
affiliates............. 12 11,555 (11,555) (a) 12
Prepaid expenses......... 67 124 (124) (a) 67
-------- --------- ------------ ------------
Total current assets... 15,157 12,393 (12,393) 15,157
Property and equipment:
Gas gathering and
transmission
facilities............. 37,018 58,888 36,885 (b) 132,791
Less - accumulated
depreciation........... (7,390) (12,212) 12,212 (b) (7,390)
--------- ---------- ----------- -------------
Net property and
equipment............ 29,628 46,676 49,097 125,401
Goodwill.................... 2,305 46,472 (46,472) (a) 2,305
Other assets................ 2,422 267 3,315 (a)(b)(c) 6,004
-------- --------- ----------- ------------
$ 49,512 $ 105,808 $ (6,453) $ 148,867
======== ========= =========== ============
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and
accrued liabilities.... $ 521 $ 8,245 $ (8,245) (a) $ 521
Accounts payable -
affiliates............. 1,673 - 4,355 (a)(b)(c) 6,028
Distribution payable..... 3,073 - - 3,073
-------- --------- ----------- ------------
Total current
liabilities.......... 5,267 8,245 (3,890) 9,622
Long-term debt.............. - 35,900 34,100 (a)(b) 70,000
Regulatory liability........ - 1,819 (1,819) (b) -
Deferred income taxes....... - 6,947 (6,947) (a) -
Preferred equity
subject to
redemption............... - - 25,000 (b) 25,000
Stockholder's equity........ - 52,897 (52,897) (a) -
Members equity.............. - - - (a)(b) -
Partners' capital:
Common unitholders....... 43,551 - - 43,551
Subordinated
unitholders............ 354 - - 354
General partner.......... 340 - - 340
-------- --------- ----------- ------------
Total partners'
capital.............. 44,245 - - 44,245
-------- --------- ----------- ------------
$ 49,512 $ 105,808 $ (6,453) $ 148,867
======== ========= =========== ============
See notes to pro forma financial statements
16
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA STATEMENT OF OPERATIONS (UNAUDITED)
FOR THE YEAR ENDED DECEMBER 31, 2003
(in thousands, except per unit data)
Historical Historical
Atlas Alaska Acquisition Pro forma
Pipeline Pipeline adjustments consolidated
--------- ---------- ----------- ------------
Revenues:
Transportation and
compression............ $ 15,651 $ 67,733 $ (52,581) (d) $ 30,803
Pipeline management
services............... - 3,110 (3,110) (d) -
--------- --------- ----------- ---------
15,651 70,843 (55,691) 30,803
Costs and expenses:
Transportation and
compression............ 2,421 - - 2,421
Cost of gas sold......... - 55,549 (55,549) (d) -
General and
administrative......... 1,661 3,575 (2,104) (e) 3,132
Operations and
maintenance............ - 4,007 (1,470) (e) 2,537
Depreciation and
amortization........... 1,770 3,265 (293) (g)(h) 4,742
--------- --------- ------------ ---------
5,852 66,396 (59,416) 12,832
--------- --------- ------------ ---------
Operating income......... 9,799 4,447 3,725 17,971
--------- --------- ----------- ---------
Other income
(deductions):
Interest expense....... (258) (2,937) (4,674) (f)(i) (7,869)
Other.................. 98 263 (263) (d) 98
--------- --------- ------------ ---------
(160) (2,674) (4,937) (7,771)
--------- --------- ----------- ---------
Income before
income taxes............. 9,639 1,773 (1,212) 10,200
Provision for income taxes.. - 733 (733) (j) -
--------- --------- ------------ ---------
Net income............... $ 9,639 $ 1,040 $ (479) $ 10,200
========= ========= =========== =========
Net income - limited
partners................. $ 8,651 $ 7,593
========= =========
Net income - general
partner.................. $ 988 $ 2,607
========= =========
Basic and diluted net
income per limited
partner ................. $ 2.17 $ 1.91
========= =========
Weighted average units
outstanding.............. 3,981 3,981
========= =========
Per unit distributions -
limited partner.......... $ 2.39 $ 2.84 (k)
========== =========
See notes to pro forma financial statements
17
Atlas Pipeline Partners, L.P.
Notes to Unaudited Pro Forma Financial Statements
a. Immediately prior to the closing, Alaska Pipeline will convert from a
corporation to a Delaware limited liability company ("LLC"), transfer
its pipeline assets to the newly formed LLC, and dividend all of its
remaining net assets to SEMCO.
b. To reflect our purchase of 100% of the interest in the LLC for $96.5
million including estimated transaction costs and the payment of
$250,000 for the tower license fee and $450,000 for the gas control
services fee. The acquisition will be financed by a $25 million
preferred equity mezzanine investment, a $50 million revolving credit
facility and $20 million from bank borrowings under our existing credit
facility. The remaining $1.5 million is funded through borrowings from
our parent, which appear as an increase to accounts payable -
affiliates.
c. To reflect the payment of $2.9 million of estimated financing costs
which appear in the pro forma balance sheet as an increase in accounts
payable - affiliates.
d. Reflects the adjustment to gas sales and transportation and compression
revenue in accordance with the terms of the Special Contract for Gas
Transportation to be entered into with ENSTAR Natural Gas Company (the
division of SEMCO which conducts its Alaska distribution business) in
connection with the acquisition and the elimination of Alaska
Pipeline's pipeline management services and other income. The
adjustment also reflects the elimination of Alaska Pipeline's cost of
gas sold. The revenue Alaska Pipeline earned for gas sales and the
expense it recognized for the cost of gas sold are the result of an
intercompany gas sales agreement with ENSTAR that requires Alaska
Pipeline to sell ENSTAR the gas volumes it purchases from gas producing
entities.
e. Reflects the general and administrative costs in accordance with the
terms of the Operation and Maintenance and Administrative Services
Agreement to be entered into with ENSTAR in connection with the
acquisition.
f. Reflects the adjustment to interest expense resulting from the $25
million preferred equity (treated as debt for financial reporting
purposes) bearing a fixed interest rate of 12% and the $50 million of
new borrowings bearing an interest rate of LIBOR plus 350 basis points,
assumed to be 4.82% for the six months ended June 30, 2003 and 4.55%
for the six months ended December 31, 2003. In addition, reflects
borrowings under our existing credit facility and inter-company line
with our parent bearing an interest rate of LIBOR plus 200 basis
points, assumed to be 3.32% for the six months ended June 30, 2003 and
3.05% for the six months ended December 31, 2003.
g. Reflects the adjustment to depreciation expense based upon the cost of
the acquired gas gathering and transmission facilities using a 33 year
depreciable life and using the straight-line method.
h. Reflects the amortization of the gas control services and tower license
fees on a straight line basis over the 10 year term of the contract.
i Reflects the amortization of deferred financing costs related to the
various borrowing facilities to finance the acquisition over their
respective terms.
j. Reflects the elimination of federal and state income taxes following
the conversion of Alaska Pipeline to a LLC and its acquisition by us, a
master limited partnership not subject to income taxes.
k. Reflects the impact to limited partner distributions from adjusting our
distributable cash flow as a result of the acquisition of Alaska
Pipeline.
18
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
Conflicts of Interest
General
Conflicts of interest exist and may arise in the future as a result of
the relationships between our general partner and Atlas America and its
affiliates, on the one hand, and us and our limited partners, on the other hand.
The managing board members and officers of our general partner have fiduciary
duties to manage our general partner in a manner beneficial to Atlas America and
its affiliates as members. At the same time, our general partner has a fiduciary
duty to manage us in a manner beneficial to us and our unitholders.
Our partnership agreement contains provisions that allow our general
partner to take into account the interests of parties in addition to ours in
resolving conflicts of interest. In effect, these provisions limit our general
partner's fiduciary duty to the unitholders. The partnership agreement also
restricts the remedies available to unitholders for actions taken that might,
without those limitations, constitute breaches of fiduciary duty.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us or any partner, on the other, our general
partner has the responsibility to resolve that conflict. A conflicts committee
of our general partner's managing board will, at the request of our general
partner, review conflicts of interest. The conflicts committee consists of the
independent managing board members, currently William R. Bagnell, Donald W.
Delson and Murray S. Levin. Our general partner will not be in breach of its
obligations under the partnership agreement or its duties to us or our
unitholders if the resolution of the conflict is considered to be fair and
reasonable to us. Any resolution is considered to be fair and reasonable to us
if that resolution is:
o approved by the conflicts committee, although no party is
obligated to seek approval and our general partner may adopt a
resolution or course of action that has not received approval;
o on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
o fair to us, taking into account the totality of the
relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
In resolving a conflict, our general partner may, unless the resolution
is specifically provided for in the partnership agreement, consider:
o the relative interest of the parties involved in the conflict or
affected by the action;
o any customary or accepted industry practices or historical
dealings with a particular person or entity; and
o generally accepted accounting practices or principles and other
factors as it considers relevant, if applicable.
Conflicts of interest could arise in the situations described below,
among others:
Actions taken by our general partner may affect the amount of cash available for
distribution to unitholders or accelerate the conversion of subordinated units.
The amount of cash that is available for distribution to unitholders is
affected by decisions of our general partner regarding various matters,
including:
o amount and timing of asset purchases and sales;
o cash expenditures;
o borrowings;
o issuances of additional units; and
19
o the creation, reduction or increase of reserves in any quarter.
In addition, our borrowings do not constitute a breach of any duty owed
by our general partner to the unitholders, including borrowings that have the
purpose or effect of:
o enabling our general partner and its affiliates to receive
distributions on any subordinated units held by them or the
incentive distribution rights or
o hastening the expiration of the subordination period.
Our partnership agreement provides that we and the operating
partnership may borrow funds from our general partner and its affiliates. Our
general partner and its affiliates may not borrow funds from us or the operating
partnership. The partnership agreement limits the amount of debt we may incur,
including amounts borrowed from our general partner.
We do not have any employees and rely on the employees of our general partner
and its affiliates.
We do not have any officers or employees and rely solely on officers
and employees of our general partner and its affiliates. Affiliates of our
general partner conduct business and activities of their own in which we have no
economic interest. If these separate activities are significantly greater than
our activities, there could be material competition between us, our general
partner and affiliates of our general partner for the time and effort of the
officers and employees who provide services to our general partner. The officers
of our general partner who provide services to us are not required to work full
time on our affairs. These officers may devote significant time to the affairs
of our general partner's affiliates and be compensated by these affiliates for
the services rendered to them. There may be significant conflicts between us and
affiliates of our general partner regarding the availability of these officers
to manage us.
We must reimburse our general partner and its affiliates for expenses.
We must reimburse our general partner and its affiliates for costs
incurred in managing and operating us, including costs incurred in rendering
corporate staff and support services properly allocable to us.
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 other party has recourse only as to all or particular
assets of ours and not against our general partner or its assets. The
partnership agreement provides that any action taken by our general partner to
limit our or its liability is not a breach of our general partner's fiduciary
duties, even if we could have obtained more favorable terms without the
limitation on liability.
Common unitholders have no right to enforce obligations of our general partner
and its affiliates under agreements with 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
those affiliates in favor of us.
Determinations by our general partner may affect its obligations and the
obligations of Atlas America.
We have agreements with Atlas America regarding, among other things,
transporting natural gas from wells controlled by it and its affiliates,
construction of expansions to our gathering systems, financing that construction
and identification of other gathering systems for acquisition. Determinations
made by our general partner will significantly affect the obligations of Atlas
America under these agreements. For example, a determination by our general
partner to seek outside financing to expand our gathering systems would reduce
the amount of additional investment Atlas America would be required to make in
us. A determination not to acquire a gathering system identified by Atlas
America could result in the acquisition of that system by Atlas America.
20
Contracts between us, on the one hand, and our general partner and Atlas America
and its affiliates, on the other, will not be the result of arm's-length
negotiations.
The partnership agreement allows our general partner to pay itself or
its affiliates for any services rendered, provided these services are on terms
fair and reasonable to us. Our general partner may also enter into additional
contractual arrangements with any of its affiliates on our behalf. Neither the
partnership agreement nor any of the other agreements, contracts and
arrangements between us, on the one hand, and our general partner and its
affiliates on the other, are or will be the result of arm's length negotiations.
In addition, our general partner will negotiate the terms of any acquisitions
from Atlas America subject to the approval of the conflicts committee consisting
of persons unaffiliated with Atlas America.
We may not retain separate counsel or other professionals.
Attorneys, independent public accountants and others who perform
services for us are selected by our general partner or the conflicts committee
and may also perform services for our general partner and Atlas America and its
affiliates. We may retain separate counsel in the event of a conflict of
interest arising 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 that conflict. We do not intend to do so in most cases.
Fiduciary Duties
State Law Fiduciary Duty Standards
Fiduciary duties are generally considered to include an obligation to
act with due care and loyalty. The duty of care, in the absence of a provision
in a partnership agreement providing otherwise, would generally require a
general partner to 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
prohibit a general partner of a Delaware limited partnership from taking any
action or engaging in any transaction where a conflict of interest is present.
The Delaware Revised Uniform Limited Partnership Act provides that a
limited partner may institute legal action on our behalf to recover damages from
a third party where our general partner has refused to institute the action or
where an effort to cause our general partner to do so is not likely to succeed.
In addition, the statutory or case law 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.
Partnership Agreement Modified Standards; Limitations on Remedies of Unitholders
Our partnership agreement contains provisions that waive or consent to
conduct by our general partner and its affiliates that might otherwise raise
issues as to compliance with fiduciary duties or applicable law. For example,
the partnership agreement permits our general partner to make a number of
decisions in its "sole discretion." This entitles our general partner to
consider only the interests and factors that it desires; it has no duty or
obligation to give any consideration to any interest of, or factors affecting,
us, our affiliates or any limited partner. Other provisions of the partnership
agreement provide that our general partner's actions must be made in its
reasonable discretion. These standards reduce the obligations to which our
general partner would otherwise be held and limit the remedies that would
otherwise be available to unitholders for actions by our general partner that,
in the absence of those standards, might constitute breaches of fiduciary duty
to unitholders.
Our partnership agreement generally provides that affiliated
transactions and resolutions of conflicts of interest not involving a required
vote of unitholders must be "fair and reasonable" to us under the factors
previously described. In determining whether a transaction or resolution is
"fair and reasonable," our general partner may consider interests of all parties
involved, including its own. Unless our general partner has acted in bad faith,
the action taken by our general partner will not constitute a breach of its
fiduciary duty. These standards reduce the obligations to which our general
partner would otherwise be held and limit the remedies
21
that would otherwise be available to unitholders for actions by our general
partner that, in the absence of those standards, might constitute breaches of
fiduciary duty to unitholders.
Our partnership agreement specifically provides that, subject only to
the obligations of Atlas America and its affiliates to us under the omnibus
agreement, the master natural gas gathering agreement or similar agreements, it
will not be a breach of our general partner's fiduciary duty if its affiliates
engage in business interests and activities in preference to or to the exclusion
of us. Also, our general partner and its affiliates have no obligation to
present business opportunities to us except for the obligation of Atlas America
to us in connection with the identification of potential acquisitions of
existing gathering systems. These standards reduce the obligations to which our
general partner would otherwise be held and limit the remedies that would
otherwise be available to unitholders for actions by our general partner that,
in the absence of those standards, might constitute breaches of fiduciary duty
to unitholders.
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 managing board members will not be
liable for monetary damages to us, our limited partners or assignees for errors
of judgment or for any acts or omissions if our general partner and those other
persons acted in good faith.
In order to become a limited partner, a unitholder is required to agree
to be bound by the provisions of our partnership agreement, including the
provisions discussed above. This is in accordance with the policy of the
Delaware Revised Uniform Limited Partnership Act favoring the principle of
freedom of contract and the enforceability of partnership agreements. The
failure of a limited partner or assignee to sign a partnership agreement does
not render the partnership agreement unenforceable against that person.
We are required to indemnify our general partner and its officers,
managing board members, employees, affiliates, partners, members, agents and
trustees, to the fullest extent permitted by law, against liabilities, costs and
expenses incurred by our general partner or these other persons. This
indemnification is required if our general partner or the other persons acted in
good faith and in a manner they reasonably believed to be in, or not opposed to,
our best interests. Indemnification is required for criminal proceedings if our
general partner or these other persons had no reasonable cause to believe their
conduct was unlawful. See "Our Partnership Agreement--Indemnification."
22
GENERAL DESCRIPTION OF SECURITIES THAT WE MAY SELL
We, directly or through agents, dealers or underwriters that we may
designate, may offer and sell, from time to time, up to $250,000,000 aggregate
initial offering price of:
o our common units representing limited partner interests;
o our subordinated units representing limited partner interests;
o our debt securities, in one or more series, which may be senior debt
securities or subordinated debt securities, in each case consisting
of notes or other evidences of indebtedness;
o warrants to purchase any of the other securities that may be sold
under this prospectus; or
o any combination of these securities, individually or as units.
We may offer and sell these securities either individually or as units
consisting of one or more of these securities, each on terms to be determined at
the time of sale. We may issue debt securities that are exchangeable for and/or
convertible into common units or any of the other securities that may be sold
under this prospectus. When particular securities are offered, a supplement to
this prospectus will be delivered with this prospectus, which will describe the
terms of the offering and sale of the offered securities.
DESCRIPTION OF COMMON UNITS
We describe our common units under the heading "Our Partnership
Agreement." The prospectus supplement relating to the common units offered will
state the number of units offered, the initial offering price and the market
price, distribution information and any other relevant information. Rules of the
American Stock Exchange, on which our common units trade, may limit the amount
of common units we may issue. Current AMEX rules require us to seek unitholder
approval if a proposed issuance of common units as consideration for an
acquisition of assets or stock of another company would increase our outstanding
common equity by more than 20%.
DESCRIPTION OF SUBORDINATED UNITS
The subordinated units will be a separate class of limited partner
interest. We currently have outstanding 1,641,026 subordinated units which we
expect will convert into common units on January 1, 2005, as described under
"Our Partnership Agreement." The rights of holders of new subordinated units to
participate in distributions to partners will differ from, and be subordinated
to, the rights of the holders of common units. The prospectus supplement
relating to the new subordinated units offered will state the number of units
offered, the initial offering price and the market price, the terms of the
subordination, any ways in which the new subordinated units will differ from
common units, distribution information and any other relevant information.
DESCRIPTION OF DEBT SECURITIES
We may issue debt securities either separately, or together with, or
upon the conversion of or in exchange for, other securities. The debt securities
may be our unsubordinated obligations, which we refer to as "senior debt
securities," or our subordinated obligations, which we refer to as "subordinated
debt securities." The subordinated debt securities of any series may be our
senior subordinated obligations, subordinated obligations, junior subordinated
obligations or may have such other ranking as will be described in the relevant
prospectus supplement. We may issue any of these types of debt securities in one
or more series.
Our senior debt securities may be issued from time to time under a
senior debt securities indenture. Our subordinated debt securities may be issued
from time to time under a subordinated debt securities indenture. Each of the
senior debt securities indenture and the subordinated debt securities indenture
is referred to individually as an "indenture" and they are referred to
collectively as the "indentures." Each trustee is referred to individually as a
"trustee" and the trustees are collectively referred to as the "trustees."
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This section summarizes selected terms of the debt securities that we
may offer. The applicable prospectus supplement and the form of applicable
indenture relating to any particular debt securities offered will describe the
specific terms of that series, which may be in addition to or different from the
general terms summarized in this section. If any particular terms of the debt
securities described in a prospectus supplement differ from any of the terms
described in this prospectus, then the terms described in the applicable
prospectus supplement will supersede the terms described in this prospectus. The
following summary and any description of our debt securities contained in an
applicable prospectus supplement do not describe every aspect of the applicable
indenture or the debt securities. When evaluating the debt securities, you also
should refer to all provisions of the applicable indenture and the debt
securities. The forms of indentures have been filed as exhibits to the
registration statement of which this prospectus is a part.
General
We can issue an unlimited amount of debt securities under the
indentures. However, certain of our existing or future debt agreements may limit
the amount of debt securities we may issue. We can issue debt securities from
time to time and in one or more series as determined by us. In addition, we can
issue debt securities of any series with terms different from the terms of debt
securities of any other series and the terms of particular debt securities
within any series may differ from each other, all without the consent of the
holders of previously issued series of debt securities.
The applicable prospectus supplement relating to the series of debt
securities will describe the specific terms of the debt securities being
offered, including, where applicable, the following:
o the title and series designation of the series of debt securities
and whether the debt securities of the series will be senior debt
securities or subordinated debt securities;
o any limit on the aggregate principal amount of debt securities of
the series;
o the price or prices at which the debt securities of the series
will be issued;
o whether the debt securities of the series will be guaranteed and
the terms of any such guarantees;
o the date or dates on which the principal amount and premium, if
any, are payable;
o the interest rate or rates or the method for calculating the
interest rate, which may be fixed or variable, at which the debt
securities of the series will bear interest, if any, the date or
dates from which interest will accrue and the interest payment
date on which interest will be payable, subject to our right, if
any, to defer or extend an interest payment date and the duration
of that deferral or extension;
o the date or dates on which interest, if any, will be payable and
the record dates for payment of interest;
o the place or places where the principal and premium, if any, and
interest, if any, will be payable and where the debt securities
of the series can be surrendered for transfer, conversion or
exchange;
o our right, if any, to redeem the debt securities and the terms
and conditions upon which the debt securities of the series may
be redeemed, in whole or in part;
o any mandatory or optional sinking fund or analogous provisions;
o if the debt securities of the series will be secured, any
provisions relating to the security provided;
o whether the debt securities of the series are convertible or
exchangeable into other debt or equity securities, and, if so,
the terms and conditions upon which such conversion or exchange
will be effected;
o whether any portion of the principal amount of the debt
securities of the series will be payable upon declaration or
acceleration of the maturity thereof pursuant to an event of
default;
o whether the debt securities of the series, in whole or any
specified part, will not be defeasible pursuant to the applicable
indenture and, if other than by an officers' certificate, the
manner in which any election by us to defease the debt securities
of the series will be evidenced;
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o any deletions from, modifications of or additions to the events
of default or our covenants pertaining to the debt securities of
the series;
o any terms applicable to debt securities of any series issued at
an issue price below their stated principal amount, including the
issue price thereof and the rate or rates at which the original
issue discount will accrue;
o whether the debt securities of the series are to be issued or
delivered (whether at the time of original issuance or at the
time of exchange of a temporary security of such series or
otherwise), or any installment of principal or any premium or
interest is to be payable only, upon receipt of certificates or
other documents or satisfaction of other conditions in addition
to those specified in the applicable indenture;
o whether the debt securities of the series are to be issued in
fully registered form without coupons or are to be issued in the
form of one or more global securities in temporary global form or
permanent global form;
o whether the debt securities of the series are to be issued in
registered or bearer form, the terms and conditions relating the
applicable form, including, but not limited to, tax compliance,
registration and transfer procedures and, if in registered form,
the denominations in which we will issue the registered
securities if other than $1,000 or a multiple thereof and, if in
bearer form, the denominations in which we will issue the bearer
securities;
o any special United States federal income tax considerations
applicable to the debt securities of the series;
o any addition to or change in the covenants set forth in the
indenture which apply to the debt securities of the series; and
o any other terms of the debt securities of the series not
inconsistent with the provisions of the applicable indenture.
The prospectus supplement relating to any series of subordinated debt
securities being offered also will describe the subordination provisions
applicable to that series, if different from the subordination provisions
described in this prospectus. In addition, the prospectus supplement relating to
a series of subordinated debt will describe our rights, if any, to defer
payments of interest on the subordinated debt securities by extending the
interest payment period.
Debt securities may be issued as original issue discount securities to
be sold at a discount below their principal amount or at a premium above their
principal amount. In the event of an acceleration of the maturity of any
original issue discount security, the amount payable to the holder upon
acceleration will be determined in the manner described in the applicable
prospectus supplement.
The above is not intended to be an exclusive list of the terms that may
be applicable to any debt securities and we are not limited in any respect in
our ability to issue debt securities with terms different from or in addition to
those described above or elsewhere in this prospectus, provided that the terms
are not inconsistent with the applicable indenture. Any applicable prospectus
supplement also will describe any special provisions for the payment of
additional amounts with respect to the debt securities.
Guarantees
Debt securities may be guaranteed by certain of our subsidiaries, if so
provided in the applicable prospectus supplement. The prospectus supplement will
describe the terms of any guarantees, including, among other things, the method
for determining the identity of the guarantors and the conditions under which
guarantees will be added or released. Any guarantees will be joint and several
obligations of the guarantors. The obligations of each guarantor under its
guarantee will be limited as necessary to prevent that guarantee from
constituting a fraudulent conveyance or fraudulent transfer under applicable
law.
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Subordination Provisions Relating to Subordinated Debt
Debt securities may be subject to contractual subordination provisions
contained in the subordinated debt securities indenture. These subordination
provisions may prohibit us from making payments on the subordinated debt
securities in certain circumstances before a defined class of "senior
indebtedness" is paid in full or during certain periods when a payment or other
default exists with respect to certain senior indebtedness. If we issue
subordinated debt securities, the applicable prospectus supplement relating to
the subordinated debt securities will include a description of the subordination
provisions and the definition of senior indebtedness that apply to the
subordinated debt securities.
If the trustee under the subordinated debt indenture or any holder of
the series of subordinated debt securities receives any payment or distribution
that is prohibited under the subordination provisions, then the trustee or the
holders will have to repay that money to the holders of senior indebtedness.
Even if the subordination provisions prevent us from making any payment
when due on the subordinated debt securities of any series, we will be in
default on our obligations under that series if we do not make the payment when
due. This means that the trustee under the subordinated debt indenture and the
holders of that series can take action against us, but they will not receive any
money until the claims of the holders of senior indebtedness have been fully
satisfied.
Unless otherwise indicated in an applicable prospectus, if any series
of subordinated debt securities is guaranteed by certain of our subsidiaries,
then the guarantee will be subordinated to the senior indebtedness of such
guarantor to the same extent as the subordinated debt securities are
subordinated to the senior indebtedness.
Conversion and Exchange Rights
The debt securities of a series may be convertible into or exchangeable
for any of our other securities, if at all, according to the terms and
conditions of an applicable prospectus supplement. Such terms will include the
conversion or exchange price and any adjustments thereto, the conversion or
exchange period, provisions as to whether conversion or exchange will be
mandatory, at our option or at the option of the holders of that series of debt
securities and provisions affecting conversion or exchange in the event of the
redemption of that series of debt securities.
Form, Exchange, Registration and Transfer
The debt securities of a series may be issued as registered securities,
as bearer securities (with or without coupons attached) or as both registered
securities and bearer securities. Debt securities of a series may be issuable in
whole or in part in the form of one or more global debt securities, as described
below under "-Global Debt Securities." Unless otherwise indicated in an
applicable prospectus supplement, registered securities will be issuable in
denominations of $1,000 and integral multiples thereof.
Registered securities of any series will be exchangeable for other
registered securities of the same series of any authorized denominations and of
a like aggregate principal amount and tenor. Debt securities may be presented
for exchange as provided above, and unless otherwise indicated in an applicable
prospectus supplement, registered securities may be presented for registration
of transfer, at the office or agency designated by us as registrar or
co-registrar with respect to any series of debt securities, without service
charge and upon payment of any taxes, assessments or other governmental charges
as described in the applicable indenture. The transfer or exchange will be
effected on the books of the registrar or any other transfer agent appointed by
us upon the registrar or transfer agent, as the case may be, being satisfied
with the documents of title and identity of the person making the request. We
intend to initially appoint the trustee as registrar and the name of any
different or additional registrar designated by us with respect to the debt
securities of any series will be included in the applicable prospectus
supplement. If a prospectus supplement refers to any transfer agents (in
addition to the registrar) designated by us with respect to any series of debt
securities, we may at any time rescind the designation of any transfer agent or
approve a change in the location through which any transfer agent acts, except
that, if debt securities of a series are issuable only as
26
registered securities, we will be required to maintain a transfer agent in each
place of payment for that series. We may at any time designate additional
transfer agents with respect to any series of debt securities.
In the event of any redemption of debt securities of any series, we
will not be required to:
o issue, register the transfer of or exchange debt securities of
that series during a period beginning at the opening of business
15 days before any selection of debt securities of that series to
be redeemed and ending at the close of business on the day of
mailing of the relevant notice of redemption; or
o register the transfer of or exchange any registered security, or
portion thereof, called for redemption, except the unredeemed
portion of any registered security being redeemed in part.
Payment and Paying Agents
Unless otherwise indicated in an applicable prospectus supplement,
payment of principal of, premium, if any, and interest, if any, on registered
securities will be made at the office of the paying agent or paying agents
designated by us from time to time, except that at our option, payment of
principal and premium, if any, or interest also may be made by wire transfer to
an account maintained by the payee. Unless otherwise indicated in an applicable
prospectus supplement, payment of any installment of interest on registered
securities will be made to the person in whose name the registered security is
registered at the close of business on the regular record date for the interest
payment.
Unless otherwise indicated in an applicable prospectus supplement, the
trustee will be designated as our sole paying agent for payments with respect to
debt securities which are issuable solely as registered securities. We may at
any time designate additional paying agents or rescind the designation of any
paying agent or approve a change in the office through which any paying agent
acts, except that, if debt securities of a series are issuable only as
registered securities, we will be required to maintain a paying agent in each
place of payment for that series.
All monies paid by us to a paying agent for the payment of principal
of, premium, if any, or interest, if any, on any debt security which remains
unclaimed at the end of two years after that principal or interest will have
become due and payable will be repaid to us, and the holder of the debt security
or any coupon will thereafter look only to us for payment of those amounts.
Global Debt Securities
The debt securities of a series may be issued in whole or in part in
global form. A global debt security will be deposited with, or on behalf of, a
depositary, which will be identified in an applicable prospectus supplement. A
global debt security may be issued in either registered or bearer form and in
either temporary or permanent form. A global debt security may not be
transferred except as a whole to the depositary for the debt security or to a
nominee or successor of the depositary. If any debt securities of a series are
issuable in global form, the applicable prospectus supplement will describe the
circumstances, if any, under which beneficial owners of interests in a global
debt security may exchange their interests for definitive debt securities of
that series of like tenor and principal amount in any authorized form and
denomination, the manner of payment of principal of, premium, if any, and
interest, if any, on the global debt securities and the specific terms of the
depositary arrangement with respect to any global debt security.
Covenants
Reports. Except as otherwise set forth in an applicable prospectus
supplement, so long as any debt securities of a series are outstanding, we will
furnish to the holders of debt securities of that series, within the time
periods specified in the rules and regulations of the SEC:
o our reports on Forms 10-Q and 10-K, including a "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and, with respect to the annual information only, a
report on the audited financial statements by our certified
independent accountants; and
o all current reports on Form 8-K.
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We also will file a copy of all of the foregoing information and
reports with the SEC for public availability within the time periods specified
in the SEC's rules and regulations (unless the SEC will not accept such a
filing) and make such information available to securities analysts and
prospective investors upon request.
Any additional covenants with respect to any series of debt securities
will be set forth in the applicable prospectus supplement. Unless otherwise
indicated in an applicable prospectus supplement, the indentures do not include
covenants restricting our ability to enter into a highly leveraged transaction,
including a reorganization, restructuring, merger or similar transaction
involving us that may adversely affect the holders of the debt securities, if
the transaction is a permissible consolidation, merger or similar transaction.
In addition, unless otherwise specified in an applicable prospectus supplement,
the indentures do not afford the holders of the debt securities the right to
require us to repurchase or redeem the debt securities in the event of a highly
leveraged transaction. See "-Merger, Consolidation and Sale of Assets."
Merger, Consolidation and Sale of Assets
Except as otherwise set forth in an applicable prospectus supplement,
we may not, directly or indirectly:
o consolidate with or merge into any other person (whether or not
we are the surviving corporation); or
o sell, assign, transfer, convey or otherwise dispose of all or
substantially all of our properties and assets, unless
o either
o we are the continuing corporation; or
o the person formed by or surviving any such consolidation or
merger (if other than us) or to which such sale, assignment,
transfer, conveyance or disposition will have been made is a
corporation organized and existing under the laws of the
United States, any state thereof or the District of Columbia
and that person assumes all of our obligations under the debt
securities of such series and the indenture relating thereto
pursuant to agreements reasonably satisfactory to the
applicable trustee; and
o any other conditions specified in the applicable prospectus
supplement have been satisfied.
In addition, we may not, directly or indirectly, lease all or
substantially all of our properties or assets in one or more related
transactions to any other person. This covenant will not apply to a sale,
assignment, transfer, conveyance or other disposition of assets between or among
us and any guarantors, if applicable.
Events of Default and Remedies
Under each indenture, unless otherwise specified with respect to a
series of debt securities, the following events will constitute an event of
default with respect to any series of debt securities:
o default for 30 days in the payment when due of any interest on
any debt securities of that series;
o default in payment when due of the principal of, or premium, if
any, on any debt security of that series;
o failure to comply with the provisions described under the caption
"-Merger, Consolidation and Sale of Assets";
o failure for 60 days after notice to comply with any of the other
agreements in the indenture;
o except as permitted by the indenture, if debt securities of a
series are guaranteed, any guarantee shall be held in any final,
non-appealable judicial proceeding to be unenforceable or invalid
or shall cease for any reason to be in full force and effect or
any guarantor, or any person acting on behalf of any guarantor,
shall deny, or disaffirm its obligations under its guarantee
(unless such guarantor could be released from its guarantee in
accordance with the applicable terms of the indenture);
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o certain events of bankruptcy or insolvency described in the
indenture with respect to us or any of our significant
subsidiaries, as defined below; and
o any other event of default applicable to the series of debt
securities and set forth in the applicable prospectus supplement.
For purposes of this section, "significant subsidiary" means any
subsidiary that would be a "significant subsidiary" as defined in Article 1,
Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act.
Each indenture provides that in the case of an event of default arising
from certain events of bankruptcy or insolvency relating to us with respect to a
series of debt securities, all outstanding debt securities of that series will
become due and payable immediately without further action or notice. If any
other event of default occurs and is continuing, the trustee or the holders of
at least 25% in principal amount of the then outstanding debt securities of that
series may declare all the debt securities of that series to be due and payable
immediately.
Holders of the debt securities of a series may not enforce the
indenture or the debt securities of that series except as provided in the
indenture. Subject to certain limitations, holders of a majority in principal
amount of the then outstanding debt securities of a series may direct the
trustee in its exercise of any trust or power. The trustee may withhold from
holders of the debt securities of a series notice of any continuing default or
event of default if it determines that withholding notice is in their interest,
except a default or event of default relating to the payment of principal or
interest.
Each indenture provides that we are required to deliver to the trustee
annually a statement regarding compliance with the indenture. Upon becoming
aware of any default or event of default, we are required to deliver to the
trustee a statement specifying such default or event of default.
The holders of a majority in aggregate principal amount of the debt
securities of a series then outstanding by notice to the trustee may on behalf
of the holders of all of the debt securities of that series waive any existing
default or event of default and its consequences under the indenture except a
continuing default or event of default in the payment of interest or premium on,
or the principal of, the debt securities of that series.
Such limitations do not apply, however, to a suit instituted by a
holder of any debt security for the enforcement of the payment of the principal
of, premium, if any, and interest in respect of a debt security on the date
specified for payment in the debt security. Unless otherwise specified with
respect to a series of debt securities, the holders of at least a majority in
aggregate principal amount of the then outstanding debt securities of that
series may, on behalf of the holders of the debt securities of any series, waive
any past defaults under the applicable indenture, other than:
o a default in any payment of the principal of, and premium, if
any, or interest on, any debt security of the series; or
o any default in respect of the covenants or provisions in the
applicable indenture which may not be modified without the
consent of the holder of each outstanding debt security of the
series affected.
Amendment, Supplement and Waiver
Each indenture permits us and the applicable trustee, with the consent
of the holders of at least a majority in aggregate principal amount of the
outstanding debt securities of the series affected by the supplemental
indenture, to execute a supplemental indenture to add provisions to, or change
in any manner or eliminate any provisions of, the indenture with respect to that
series of debt securities or modify in any manner the rights of the holders of
the debt securities of that series and any related coupons under the applicable
indenture. However, the supplemental indenture will not, without the consent of
the holder of each outstanding debt security of that series affected thereby:
o change the stated maturity of the principal of, or any
installment of principal or interest on, the debt securities of
that series or any premium payable upon redemption thereof;
29
o reduce the principal amount of, or premium, if any, or the rate
of interest on, the debt securities of that series;
o change the place or currency of payment of principal and premium,
if any, or interest, if any, on the debt securities of that
series;
o impair the right to institute suit for the enforcement of any
payment after the stated maturity date on any debt securities of
that series, or in the case of redemption, on or after the
redemption date;
o reduce the principal amount of outstanding debt securities of
that series necessary to modify or amend or waive compliance with
any provisions of the indenture;
o release any applicable guarantor from any of its obligations
under its guarantee or the indenture, except in accordance with
the indenture;
o modify the foregoing amendment and waiver provisions, except to
increase the percentage in principal amount of outstanding debt
securities of any series necessary for such actions or to provide
that certain other provisions of the indenture cannot be modified
or waived without the consent of the holder of each debt security
of a series affected thereby; and
o change such other matters as may be specified in an applicable
prospectus supplement for any series of debt securities.
The indentures also permit us, the guarantors, if any, and the
applicable trustee to execute a supplemental indenture without the consent of
the holders of the debt securities:
o to cure any ambiguity, defect or inconsistency;
o to provide for uncertificated debt securities in addition to or
in place of certificated debt securities;
o to provide for the assumption of our obligations or, if
applicable, a guarantor's obligations to holders of debt
securities of a series in the case of a merger or consolidation
or sale of all or substantially all of our assets or, if
applicable, a guarantor's assets;
o to make any change that would provide any additional rights or
benefits to the holders of debt securities of a series or that
does not adversely affect the legal rights under the indenture of
any such holder;
o to comply with the requirements of the SEC in order to effect or
maintain the qualification of the indenture under the Trust
Indenture Act;
o to add a guarantor under the indenture;
o to evidence and provide the acceptance of the appointment of a
successor trustee under the applicable indenture;
o to mortgage, pledge, hypothecate or grant a security interest in
favor of the trustee for the benefit of the holders of debt
securities of any series as additional security for the payment
and performance of our or any applicable guarantor's obligations
under the applicable indenture, in any property or assets;
o to add to, change or eliminate any provisions of the applicable
indenture (which addition, change or elimination may apply to one
or more series of debt securities), provided that, any such
addition, change or elimination:
o shall neither:
o apply to any debt security of any series created prior to the
execution of such supplemental indenture and entitled to the
benefit of such provision nor
o modify the rights of the holders of such debt securities with
respect to such provisions or
o shall become effective only when there is no such outstanding
debt securities of such series; and
o to establish the form and terms of debt securities of any series
as permitted by the indenture.
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The holders of a majority in principal amount of outstanding debt
securities of any series may waive compliance with certain restrictive covenants
and provisions of the applicable indenture.
Discharge
Unless otherwise indicated in an applicable prospectus supplement, each
indenture provides that we may satisfy and discharge our obligations thereunder
with respect to the debt securities of any series, when either:
o all debt securities of that series that have been authenticated,
except lost, stolen or destroyed debt securities of that series
that have been replaced or paid and debt securities of that
series for whose payment money has been deposited in trust and
thereafter repaid to us, have been delivered to the trustee for
cancellation; or
o all debt securities of that series that have not been delivered
to the trustee for cancellation have become due and payable by
reason of the mailing of a notice of redemption or otherwise or
will become due and payable within one year and we or, if
applicable, any guarantor has irrevocably deposited or caused to
be deposited with the trustee as trust funds in trust solely for
the benefit of the holders of debt securities of that series,
cash, non-callable U.S. government securities, or a combination
thereof, in amounts as will be sufficient without consideration
of any reinvestment of interest, to pay and discharge the entire
indebtedness on the debt securities of that series not delivered
to the trustee for cancellation for principal, premium, if any,
and accrued interest to the date of maturity or redemption.
Defeasance
Unless otherwise indicated in an applicable prospectus supplement, each
indenture provides that we may, at our option and at any time, elect to have all
of our obligations discharged with respect to the outstanding debt securities of
a series and, if applicable, all obligations of the guarantors discharged with
respect to their guarantees ("legal defeasance") except for:
o the rights of holders of the outstanding debt securities of that
series to receive payments in respect of the principal of, or
premium or interest, if any, on the debt securities of that
series when such payments are due from the trust referred to
below;
o our obligations with respect to the debt securities of that
series concerning issuing temporary securities, registration of
securities, mutilated, destroyed, lost or stolen securities and
the maintenance of an office or agency for payment and money for
security payments held in trust;
o the rights, powers, trusts, duties and immunities of the
applicable trustee, our obligations and, if applicable, the
guarantor's obligations in connection therewith; and
o the legal defeasance provisions of the indenture.
In addition, we may, at our option and at any time, elect to have our
obligations and, if applicable, the guarantors' obligations released with
respect to certain covenants in respect of the debt securities of any series
that are described in the indenture ("covenant defeasance") and thereafter any
omission to comply with those covenants will not constitute a default or event
of default with respect to the debt securities of that series. In the event
covenant defeasance occurs, certain events (not including non-payment,
bankruptcy, receivership, rehabilitation and insolvency events) described under
"--Events of Default and Remedies" will no longer constitute an event of default
with respect to the debt securities of that series.
In order to exercise either legal defeasance or covenant defeasance we
are required to meet specified conditions, including:
o we must irrevocably deposit with the trustee, in trust, for the
benefit of the holders of the debt securities of that series,
cash, non-callable U.S. government securities, or a combination
thereof, in amounts as will be sufficient to pay the principal
of, or premium and interest, if any, on the outstanding debt
securities of that series on the stated maturity or on the
applicable redemption date, as the case may be;
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o in the case of legal defeasance, we have delivered to the
applicable trustee an opinion of counsel reasonably acceptable to
the trustee confirming that (a) we have received from, or there
has been published by, the Internal Revenue Service a ruling or
(b) since the date of the indenture, there has been a change in
the applicable federal income tax law, in either case to the
effect that, and based thereon such opinion of counsel will
confirm that, the holders of the outstanding debt securities of
that series will not recognize income, gain or loss for federal
income tax purposes as a result of such legal defeasance and will
be subject to federal income tax on the same amounts, in the same
manner and at the same times as would have been the case if such
legal defeasance had not occurred; and
o in the case of covenant defeasance, we have delivered to the
trustee an opinion of counsel reasonably acceptable to the
trustee confirming that the holders of the outstanding debt
securities of that series will not recognize income, gain or loss
for federal income tax purposes as a result of such covenant
defeasance and will be subject to federal income tax on the same
amounts, in the same manner and at the same times as would have
been the case if such covenant defeasance had not occurred.
The Trustees under the Indentures
If a trustee becomes a creditor of ours or any guarantor, the indenture
limits its right to obtain payment of claims in certain cases, or to realize on
certain property received in respect of any such claim as security or otherwise.
Each trustee will be permitted to engage in other transactions with us and/or
the guarantors, if any; however, if any trustee acquires any conflicting
interest it must eliminate such conflict within 90 days, apply to the SEC for
permission to continue or resign.
The holders of a majority in principal amount of the then outstanding
debt securities of a series will have the right to direct the time, method and
place of conducting any proceeding for exercising any remedy available to the
trustee, subject to certain exceptions. The indenture provides that in case an
event of default occurs and is continuing, a trustee will be required, in the
exercise of its power, to use the degree of care of a prudent person in the
conduct of its own affairs. Subject to such provisions, a trustee will be under
no obligation to exercise any of its rights or powers under the indenture at the
request of any holder of debt securities, unless such holder has offered to the
trustee security and indemnity satisfactory to it against any loss, liability or
expense.
Applicable Law
The debt securities and the indentures will be governed by and
construed in accordance with the laws of the State of Delaware.
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DESCRIPTION OF WARRANTS
We may issue, either separately or together with other securities,
warrants for the purchase of any of the other types of securities that we may
sell under this prospectus.
This section summarizes the general terms of the warrants that we may
offer. The warrants will be issued under warrant agreements to be entered into
between us and a bank or trust company, as warrant agent. The prospectus
supplement relating to a particular series of warrants will describe the
specific terms of that series, which may be in addition to or different from the
general terms summarized in this section. The summaries in this section and the
prospectus supplement do not describe every aspect of the warrants. If any
particular terms of a series of warrants described in a prospectus supplement
differ from any of the terms described in this prospectus, then the terms
described in the applicable prospectus supplement will be deemed to supersede
the terms described in this prospectus. When evaluating the warrants, you also
should refer to all the provisions of the applicable warrant agreement, the
certificates representing the warrants and the specific descriptions in the
applicable prospectus supplement. The applicable warrant agreement and warrant
certificates will be filed as exhibits to or incorporated by reference in the
registration statement.
General
The prospectus supplement will describe the terms of the warrants in
respect of which this prospectus is being delivered as well as the related
warrant agreement and warrant certificates, including the following, where
applicable:
o the principal amount of, or the number of securities, as the case
may be, purchasable upon exercise of each warrant and the initial
price at which the principal amount or number of securities, as
the case may be, may be purchased upon such exercise;
o the designation and terms of the securities, if other than common
units, purchasable upon exercise thereof and of any securities,
if other than common units, with which the warrants are issued;
o the procedures and conditions relating to the exercise of the
warrants;
o the date, if any, on and after which the warrants, and any
securities with which the warrants are issued, will be separately
transferable;
o the offering price of the warrants, if any;
o the date on which the right to exercise the warrants will
commence and the date on which that right will expire;
o a discussion of any special United States federal income tax
considerations applicable to the warrants;
o whether the warrants represented by the warrant certificates will
be issued in registered or bearer form, and, if registered, where
they may be transferred and registered;
o call provisions of the warrants, if any;
o antidilution provisions of the warrants, if any; and
o any other material terms of the warrants.
Exercise of Warrants
Each warrant will entitle the holder to purchase for cash that
principal amount of or number of securities, as the case may be, at the exercise
price set forth in, or to be determined as set forth in, the applicable
prospectus supplement relating to the warrants. Unless otherwise specified in
the applicable prospectus supplement, warrants may be exercised at the corporate
trust office of the warrant agent or any other office indicated in the
applicable prospectus supplement at any time up to 5:00 p.m. Eastern Standard
Time on the expiration date set forth in the applicable prospectus supplement.
After 5:00 p.m. Eastern Standard Time on the expiration date, unexercised
warrants will become void. Upon receipt of payment and the warrant certificate
properly completed and duly executed, we will, as soon as practicable, issue the
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securities purchasable upon exercise of the warrant. If less than all of the
warrants represented by the warrant certificate are exercised, a new warrant
certificate will be issued for the remaining amount of warrants.
No Rights of Security Holder Prior to Exercise
Prior to the exercise of their warrants, holders of warrants will not
have any of the rights of holders of the securities purchasable upon the
exercise of the warrants and will not be entitled to:
o in the case of warrants to purchase debt securities, payments of
principal of, premium, if any, or interest, if any, on the debt
securities purchasable upon exercise; or
o in the case of warrants to purchase equity securities, the right
to vote or to receive dividend payments or similar distributions
on the securities purchasable upon exercise.
Exchange of Warrant Certificates
Warrant certificates will be exchangeable for new warrant certificates
of different denominations at the corporate trust office of the warrant agent or
any other office indicated in the applicable prospectus supplement.
OUR PARTNERSHIP AGREEMENT
The following is a summary of our current partnership agreement which
relates to our common units and our existing subordinated units. Accordingly,
references to "subordinated units" and the "subordination period" are to the
existing subordinated units and the subordination period relating to those
units. Pursuant to our partnership agreement and this prospectus we may issue
additional limited partner interests having different rights and
characteristics. These rights and characteristics will be set forth in a
prospectus supplement with respect to the issuance of any of these securities.
Organization and Duration
We were formed in May 1999. We will dissolve on December 31, 2098,
unless sooner dissolved under the terms of our partnership agreement.
Purpose
Our purpose under our partnership agreement is limited to serving as
the limited partner of our operating partnership and engaging in any business
activity that may be engaged in by our operating partnership or that is approved
by our general partner. The operating partnership agreement provides that our
operating partnership may, directly or indirectly, engage in:
o operations as conducted on February 2, 2000, including the
ownership and operation of our gathering systems;
o any other activity approved by our general partner, but only to
the extent that our general partner reasonably determines that,
as of the date of the acquisition or commencement of the
activity, the activity generates "qualifying income" as that term
is defined in Section 7704 of the Internal Revenue Code; or
o any activity that enhances the operations described above.
The Units
Our common units and the subordinated units represent 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 and subordinated units to
partnership distributions, together with a description of the circumstances
under which subordinated units may convert into common units, see "--Cash
Distribution Policy" and "--Description of the Subordinated Units."
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Description of the Subordinated Units
The subordinated units are a separate class of interest and the rights
of holders to participate in distributions to partners differ from, and are
subordinated to, the rights of the holders of common units. For any given
quarter, any available cash is first distributed to our general partner and to
the holders of common units, plus any arrearages on the common units, and then
distributed to the holders of subordinated units.
The subordination period will extend until the first day of any quarter
beginning after December 31, 2004 that each of the following three events
occurs:
o distributions of available cash from operating surplus on the
common units and the subordinated units equal or exceed the sum
of the minimum quarterly distributions on all of the outstanding
common units and the subordinated units for each of the 12
consecutive quarters immediately preceding that date;
o the adjusted operating surplus generated during each of the 12
immediately preceding quarters equals or exceeds the sum of the
minimum quarterly distributions on all of the outstanding common
units and the subordinated units during those periods on a fully
diluted basis and the related distributions on the general
partner interests during those periods; and
o there are no arrearages in the payment of the minimum quarterly
distribution on the common units.
Once the subordination period ends, all existing subordinated units
will convert into common units on a one-for-one basis and will participate, pro
rata, with the other common units in distributions of available cash.
Limited Voting Rights
Holders of common units generally vote as a class separate from the
holders of subordinated units and have similarly limited voting rights. During
the subordination period, common units and subordinated units vote separately as
a class on the following matters:
o a sale or exchange of all or substantially all of our assets;
o our dissolution or reconstitution;
o our merger;
o termination or material modification of the omnibus agreement or
master natural gas gathering agreement; and
o substantive amendments to our partnership agreement, including
any amendment that would cause us to become taxable as a
corporation.
Only the common units are entitled to vote on approval of the removal
or voluntary withdrawal of our general partner or the transfer by our general
partner of its general partner interest or incentive distribution rights during
the subordination period, except that our general partner may transfer all of
its general partner interest and incentive distribution rights to an affiliate
or in connection with a merger of our general partner without approval of the
common unitholders. Removal of our general partner requires a two-thirds vote of
all outstanding common units, excluding those held by our general partner and
its affiliates. Our partnership agreement permits our general partner generally
to make amendments to it that do not materially adversely affect unitholders
without the approval of any unitholders.
Cash Distribution Policy
Quarterly Distributions of Available Cash. Our operating partnership is
required by the operating partnership agreement to distribute to us, within 45
days of the end of each fiscal quarter, all of its available cash for that
quarter. We, in turn, distribute to our partners all of the available cash
received from our operating partnership for that quarter.
Available cash generally means, for any of our fiscal quarters, all
cash on hand at the end of the quarter less cash reserves that our general
partner determines are appropriate to provide for our operating costs,
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including potential acquisitions, and to provide funds for distributions to the
partners for any one or more of the next four quarters. We generally make
distributions of all available cash within 45 days after the end of each quarter
to holders of record on the applicable record date.
For each quarter during the subordination period, to the extent there
is sufficient available cash, the holders of common units have the right to
receive the minimum quarterly distribution of $.42 per unit, plus any arrearages
on the common units, before any distribution is made to the holders of
subordinated units. This subordination feature enhances our ability to
distribute the minimum quarterly distribution on the common units during the
subordination period.
We make distributions of available cash to unitholders regardless of
whether the amount distributed is less than the minimum quarterly distribution.
If distributions from available cash on the common units for any quarter during
the subordination period are less than the minimum quarterly distribution of
$.42 per common unit, holders of common units will be entitled to arrearages.
Common unit arrearages will accrue and be paid in a future quarter after the
minimum quarterly distribution is paid for that quarter. Subordinated units will
not accrue any arrearages on distributions for any quarter.
The holders of subordinated units will have the right to receive the
minimum quarterly distribution only after the common units have received the
minimum quarterly distribution plus any arrearages in payment of the minimum
quarterly distribution. Upon expiration of the subordination period, the
subordinated units will convert into common units on a one-for-one basis, and
will then participate pro rata with the other common units in distributions of
our available cash.
Distributions of Available Cash from Operating Surplus. Cash
distributions are characterized as distributions from either operating surplus
or capital surplus. This distinction affects the amounts distributed to
unitholders relative to our general partner, and also determines whether holders
of subordinated units receive any distributions.
Operating surplus means:
o our cash balance, excluding cash constituting capital surplus, less
o all of our operating expenses, debt service payments, maintenance
costs, capital expenditures and reserves established for future
operations.
Capital surplus means capital generated only by borrowings other than
working capital borrowings, sales of debt and equity securities and sales or
other dispositions of assets for cash, other than inventory, accounts receivable
and other assets disposed of in the ordinary course of business.
We treat all available cash distributed from any source as distributed
from operating surplus until the sum of all available cash distributed since we
began operations equals our total operating surplus from the date we began
operations until the end of the quarter that immediately preceded the
distribution. This method of cash distribution avoids the difficulty of trying
to determine whether available cash is distributed from operating surplus or
capital surplus. We treat any excess available cash, irrespective of its source,
as capital surplus, which would represent a return of capital, and we will
distribute it accordingly. For a discussion of distributions of capital surplus,
see "--Distributions of Capital Surplus" below.
We distribute available cash from operating surplus for any quarter
during the subordination period in the following manner:
o first, 98% to the common units, pro rata, and 2% to our general
partner, until we have distributed for each outstanding common unit
an amount equal to the minimum quarterly distribution for that
quarter;
o second, 98% to the common units, pro rata, and 2% to our general
partner, until we have distributed for each outstanding common unit
an amount equal to any arrearages in payment of the minimum quarterly
distribution on the common units;
o third, 98% to the subordinated units, pro rata, and 2% to our general
partner, until we have distributed for each outstanding subordinated
unit an amount equal to the minimum quarterly distribution for that
quarter; and
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o after that, in the manner described in "-Incentive Distribution
Rights" below.
The 2% allocation of available cash from operating surplus to our
general partner includes our general partner's percentage interest in
distributions from us and our operating partnership on a combined basis,
exclusive of its interest as a subordinated unitholder.
We distribute available cash from operating surplus for any quarter
after the subordination period in the following manner:
o first, 98% to all units, pro rata, and 2% to our general partner,
until we have distributed for each unit an amount equal to the
minimum quarterly distribution for that quarter;
o second, 98% to the common units, pro rata, and 2% to our general
partner, until we have distributed for each outstanding common unit
an amount equal to any arrearages in payment of the minimum quarterly
distribution on the common units; and
o after that, in the manner described in "-Incentive Distribution
Rights" below.
Adjusted operating surplus for any period generally means operating
surplus generated during that period, less:
o any net increase in working capital borrowings during that period and
o any net reduction in cash reserves for operating expenditures during
that period not relating to an operating expenditure made during that
period,
and plus:
o any net decrease in working capital borrowings during that period and
o any net increase in cash reserves for operating expenditures during
that period required by any debt instrument for the repayment of
principal, interest or premium.
Operating surplus generated during a period is equal to the difference
between:
o the operating surplus determined at the end of that period and
o the operating surplus determined at the beginning of that period.
Incentive Distribution Rights. By "incentive distribution rights" we
mean the general partner's right to receive an increasing percentage of
quarterly distributions of available cash from operating surplus after we have
made the minimum quarterly distributions and we have met specified target
distribution levels, as described below. Our general partner may transfer its
incentive distribution rights separately from its general partner interest
subject, during the subordination period, to the consent of a majority of the
common units and the subordinated units voting as separate classes. After the
subordination period no consent is required.
We make incentive distributions to our general partner for any quarter
in which each of the following occurs:
o we have distributed available cash from operating surplus to the
common and subordinated unitholders in an amount equal to the minimum
quarterly distribution and
o we have distributed available cash from operating surplus on the
common units in an amount necessary to eliminate any cumulative
common unit arrearages.
If these conditions have been satisfied, the remaining available cash
will be distributed as follows:
o first, 85% to all units, pro rata, and 15% to our general partner,
until each unitholder has received a total of $.52 per unit for that
quarter, in addition to any distributions to common unitholders to
eliminate any cumulative arrearages in payment of the minimum
quarterly distribution on the common units;
o second, 75% to all units, pro rata, and 25% to our general partner,
until each unitholder has received a total of $.60 per unit for that
quarter, in addition to any distributions to common unitholders to
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eliminate any cumulative arrearages in payment of the minimum
quarterly distribution on the common units; and
o after that, 50% to all units, pro rata, and 50% to our general
partner.
The distributions to our general partner that exceed its aggregate 2%
general partner interest represent the incentive distribution rights.
Distributions from Capital Surplus. We distribute available cash from
capital surplus in the following manner:
o first, 98% to all units, pro rata, and 2% to our general partner,
until each common unit has received distributions equal to $13.00 per
unit;
o second, 98% to the common units, pro rata, and 2% to our general
partner, until each common unit has received an aggregate amount
equal to any unpaid arrearages in payment of the minimum quarterly
distribution on the common units; and
o after that, we will distribute all available cash from capital
surplus, as if it were from operating surplus.
When we make a distribution from capital surplus, we will treat it as
if it were a repayment of your investment in your common units. For these
purposes, the partnership agreement deems the investment to be $13.00 per common
unit, which is the unit price from our initial public offering, regardless of
the price you actually pay for your common units in this offering. To reflect
this repayment, we will reduce the amount of the minimum quarterly distribution
and the distribution levels at which our general partner's incentive
distribution rights begin, which we refer to in this prospectus as "target
distribution levels," by multiplying each amount by a fraction, determined as
follows:
o the numerator is $13.00 less all distributions from capital surplus
including the distribution just made, and
o the denominator is $13.00 less all distributions from capital surplus
excluding the distribution just made.
We refer to the initial public offering price of $13.00 per common
unit, less any distributions from capital surplus, as the "unrecovered unit
price." This adjustment to the minimum quarterly distribution may accelerate the
dates at which the subordinated units convert into common units.
After the minimum quarterly distribution and the target distribution
levels have been reduced to zero, we will treat all distributions of available
cash from all sources as if they were from operating surplus. Because the
minimum quarterly distribution and the target distribution levels will have been
reduced to zero, our general partner will then be entitled to receive 50% of all
distributions of available cash in its capacity as general partner and holder of
the incentive distribution rights, in addition to any distributions to which it
may be entitled as a holder of units.
Distributions from capital surplus will not reduce the minimum
quarterly distribution or target distribution levels for the quarter in which
they are distributed.
Adjustment of Minimum Quarterly Distribution and Target Distribution
Levels. In addition to adjustments made upon a distribution of available cash
from capital surplus, we will proportionately adjust each of the following
upward or downward, as appropriate, if any combination or subdivision of units
occurs:
o the minimum quarterly distribution,
o the target distribution levels,
o the unrecovered unit price,
o the number of common units issuable upon conversion of the
subordinated units, and
o other amounts calculated on a per unit basis.
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For example, if a two-for-one split of the common units occurs, we will
reduce the minimum quarterly distribution, the target distribution levels and
the unrecovered initial unit price of the common units to 50% of their initial
levels.
We will not make any adjustment for the issuance of additional common
units for cash or property.
We may also adjust the minimum quarterly distribution and the target
distribution levels if legislation is enacted or if existing law is modified or
interpreted in a manner that causes us or our operating partnership to become
taxable as a corporation or otherwise subject to taxation as an entity for
federal, state or local income tax purposes. In this event, we will reduce the
minimum quarterly distribution and the target distribution levels for each
quarter after that time to amounts equal to the product of:
o the minimum quarterly distribution and each of the target
distribution levels multiplied by
o one minus the sum of:
o the highest marginal federal income tax rate which could apply to
the partnership that is taxed as a corporation plus
o any increase in the effective overall state and local income tax
rate that would have been applicable in the preceding calendar year
as a result of the new imposition of the entity level tax, after
taking into account the benefit of any deduction allowable for
federal income tax purposes for the payment of state and local
income taxes, but only to the extent of the increase in rates
resulting from that legislation or interpretation.
For example, assuming we are not previously subject to state and local income
tax, if we became taxable as a corporation for federal income tax purposes and
subject to a maximum marginal federal, and effective state and local, income tax
rate of 40%, then we would reduce the minimum quarterly distribution and the
target distribution levels to 60% of the amount immediately before the
adjustment.
Distributions of Cash Upon Liquidation. When we commence dissolution
and liquidation, we will sell or otherwise dispose of our assets and adjust the
partners' capital account balances to reflect any resulting gain or loss. We
will first apply the proceeds of liquidation to the payment of our creditors in
the order of priority provided in our partnership agreement and by law. After
that, we will distribute the proceeds to the unitholders and our general partner
in accordance with their capital account balances, as so adjusted.
We maintain capital accounts in order to ensure that the partnership's
allocations of income, gain, loss and deduction are respected under the Internal
Revenue Code. The balance of a partner's capital account also determines how
much cash or other property the partner will receive on liquidation of the
partnership. A partner's capital account is credited with (increased by) the
following items:
o the amount of cash and fair market value of any property (net of
liabilities) contributed by the partner to the partnership, and
o the partner's share of "book" income and gain (including income and
gain exempt from tax).
A partner's capital account is debited with (reduced by) the following items:
o the amount of cash and fair market value (net of liabilities) of
property distributed to the partner, and
o the partner's share of loss and deduction (including some items not
deductible for tax purposes).
Partners are entitled to liquidating distributions in accordance with
their capital account balances. The allocations of gains and losses upon
liquidation are intended, to the extent possible, to entitle common unitholders
to a preference over the subordinated unitholders upon our liquidation to the
extent required to permit common unitholders to receive the unrecovered initial
public offering unit price described in "-Distributions from Capital Surplus,"
above, plus any unpaid arrearages in payment of the minimum quarterly
distributions. Thus, we will allocate net losses recognized upon our liquidation
to the holders of the subordinated units to the extent of their capital account
balances before we allocate any loss to the holders of the common units. Also we
will allocate net gains recognized upon our liquidation first to restore
negative balances in the capital account of our general partner and any
unitholders and then to the common
39
unitholders until their capital account balances equal the unrecovered initial
unit price plus unpaid arrearages in payment of the minimum quarterly
distributions. However, we cannot assure you that there will 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.
If our liquidation occurs before the end of the subordination period,
any gain, or unrealized gain attributable to assets distributed in kind, will be
allocated to the partners in the following manner:
o 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;
o second, 98% to the common units, pro rata, and 2% to our general
partner, until the capital account for each common unit is equal to
the sum of:
o the unrecovered unit price,
o the amount of the minimum quarterly distribution for the quarter
during which our liquidation occurs, and
o any unpaid arrearages in payment of the minimum quarterly
distribution;
o third, 98% to the subordinated units, pro rata, and 2% to our general
partner, until the capital account for each subordinated unit is
equal to the sum of:
o the unrecovered capital on that subordinated unit and
o the amount of the minimum quarterly distribution for the quarter
during which our liquidation occurs;
o fourth, 85% to all units, pro rata, and 15% to our general partner,
until there has been allocated under this paragraph an amount per
unit equal to:
o the excess of the $.52 target distribution per unit over the
minimum quarterly distribution per unit for each quarter of our
existence less
o the cumulative amount per unit of any distribution of available
cash from operating surplus in excess of the minimum quarterly
distribution per unit that was distributed 85% to the units, pro
rata, and 15% to our general partner for each quarter of our
existence;
o fifth, 75% to all units, pro rata, and 25% to our general partner,
until there has been allocated under this paragraph an amount per
unit equal to:
o the excess of the $.60 target distribution per unit over the $.52
target distribution per unit for each quarter of our existence less
o the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the first target
distribution per unit that was distributed 75% to the units, pro
rata, and 25% to our general partner for each quarter of our
existence; and
o after that, 50% to all units, pro rata, and 50% to our general
partner.
If our liquidation occurs after the end of the subordination period,
the distinction between common units and subordinated units will disappear, so
that the second and third priorities above will no longer be applicable.
Upon our liquidation, any loss will generally be allocated to our
general partner and the unitholders in the following manner:
o first, 98% to holders of subordinated units in proportion to the
positive balances in their capital accounts and 2% to our general
partner, until the capital accounts of the holders of the
subordinated units have been reduced to zero;
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o second, 98% to the holders of common units in proportion to the
positive balances in their capital accounts and 2% to our general
partner, until the capital accounts of the common unitholders have
been reduced to zero; and
o after that, 100% to our general partner.
If our liquidation occurs after the subordination period, the distinction
between common units and subordinated units will disappear, so that all of the
first priority above will no longer be applicable.
In addition, we will make interim adjustments to the capital accounts
at the time we issue additional equity interests or make distributions of
property. We will base these adjustments on the fair market value of the
interests or the property distributed and we will allocate any gain or loss
resulting from the adjustments to the unitholders and our general partner in the
same manner as we allocate gain or loss upon liquidation. In the event that we
make positive interim adjustments to the capital accounts, we will allocate any
later negative adjustments to the capital accounts resulting from the issuance
of additional equity interests, our distributions of property, or upon our
liquidation, in a manner which results, to the extent possible, in the capital
account balances of our general partner equaling the amount which would have
been our general partner's capital account balances if we had not made any
earlier positive adjustments to the capital accounts.
Power of Attorney
Each limited partner, and each person who acquires a unit from a
unitholder and executes and delivers a transfer application, 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 and the amendment of our partnership agreement, and
to make consents and waivers under our partnership agreement.
Capital Contributions
Unitholders are not obligated to make additional capital contributions,
except as described below under "--Limited Liability."
Limited Liability
So long as a limited partner does not participate in the control of our
business within the meaning of the Delaware Revised Uniform Limited Partnership
Act and otherwise acts in conformity with the provisions of our partnership
agreement, the limited partner's liability under the Delaware Act will be
limited 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. If it were
determined that a limited partner participated in the control of our business,
then the limited partner could be held personally liable for our obligations
under Delaware law to the same extent as our general partner. This liability
would extend only to persons who transact business with us who reasonably
believe that the limited partner is a general partner. However, what constitutes
participating in the control of a limited partnership's business has not been
clearly established in all states. If it were determined, for example, that the
right, or exercise of a right, by the limited partners to:
o remove our general partner,
o approve some amendments to our partnership agreement, or
o take other action under our partnership agreement
constituted participation in the control of our business, then limited partners
could be held liable for our obligations to the same extent as our general
partner.
Under the Delaware Act, we cannot make a distribution to a partner if,
after the distribution, all our liabilities, other than liabilities to partners
on account of their partnership interests and liabilities for which the recourse
of creditors is limited to specific property, exceed the fair value of our
assets. 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
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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 is liable to the
limited partnership for the amount of the distribution for three years. Under
the Delaware Act, an assignee who becomes a substituted limited partner is
liable for the obligations of his assignor to make contributions to the
partnership, except the assignee is not obligated for liabilities unknown to him
at the time he became a limited partner and which he could not ascertain from
our partnership agreement.
Our operating partnership currently conducts business in New York, Ohio
and Pennsylvania. The limitations on the liability of limited partners for the
obligations of a limited partnership have not been clearly established in many
jurisdictions. If it were determined that we were, by virtue of our limited
partner interest in our operating partnership or otherwise, conducting business
in any state under the applicable limited partnership 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. We operate in a manner our general partner considers reasonable and
appropriate to preserve the limited liability of the limited partners.
Transfer Agent and Registrar
American Stock Transfer and Trust Company is our registrar and transfer
agent for the common units. We pay all fees charged by the transfer agent for
transfers of common units, except that the following fees must be paid by
unitholders:
o surety bond premiums to replace lost or stolen certificates, taxes
and other governmental charges,
o special charges for services requested by a holder of a common unit,
and
o other similar fees or charges.
There is no charge to unitholders for disbursements of cash distributions.
We will indemnify the transfer agent, its agents and each of their
particular shareholders, directors, officers and employees against all claims
and losses that may arise out of acts performed or omitted in its capacity as
our transfer agent, except for any liability due to any negligence, gross
negligence, bad faith or intentional misconduct of the indemnified person or
entity.
Transfer of Common Units
The transfer agent will not record a transfer of common units, and we
will not recognize the transfer, unless the transferee executes and delivers a
transfer application. The form of transfer application appears on the reverse
side of the certificates representing the common units. By executing and
delivering a transfer application, the transferee of common units:
o becomes the record holder of the common units and is an assignee
until admitted as a substituted limited partner;
o automatically requests admission as a substituted limited partner;
o agrees to be bound by the terms and conditions of our partnership
agreement;
o represents that the transferee has the capacity, power and authority
to enter into our partnership agreement;
o grants powers of attorney to officers of our general partner and our
liquidator, as specified in our partnership agreement; and
o makes the consents and waivers contained in our partnership
agreement.
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An assignee will become a substituted limited partner as to the
transferred common units upon the consent of our general partner and the
recordation of the name of the assignee on our books and records. Our general
partner may withhold its consent in its sole discretion.
A transferee's broker, agent or nominee may complete, execute and
deliver the transfer applications. We are entitled to 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.
Common units are securities and are transferable according to the laws
governing transfer of securities. In addition to the rights acquired upon
transfer, the transferor gives the transferee the right to request admission as
a substituted limited partner. A purchaser or transferee of common units who
does not execute and deliver a transfer application will have only
o the right to assign the common units to a purchaser or other
transferee and
o the right to transfer the right to seek admission as a substituted
limited partner.
Thus, a purchaser or transferee of common units who does not execute and deliver
a transfer application will not receive
o cash distributions or federal income tax allocations unless the
common units are held in a nominee or "street name" account and the
nominee or broker has executed and delivered a transfer application
and
o may not receive federal income tax information or reports furnished
to record holders of common units.
The transferor of common units must provide the transferee with all
information necessary to transfer the common units. The transferor will not be
required to insure the execution of the transfer application by the transferee
and will have no liability or responsibility if the transferee neglects or
chooses not to execute and forward the transfer application to the transfer
agent. See "-Status as Limited Partner or Assignee."
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,
even if either of us has notice of an attempted transfer.
Issuance of Additional Securities
Our partnership agreement generally authorizes us to issue an unlimited
number of additional limited partner interests, debt and other securities for
the consideration and on the terms and conditions established by our general
partner in its sole discretion without the approval of any limited partners.
During the subordination period, we cannot issue securities having rights to
distribution or in liquidation ranking prior or senior to our common units
without the approval of our unitholders.
We have funded, and will likely continue to fund, acquisitions through
the issuance of additional common units or other equity 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 partnership interests 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, in the sole
discretion of our general partner, may have special voting rights to which the
common units are not entitled.
Upon issuance of additional partnership securities, our general partner
must make additional capital contributions to the extent necessary to maintain
its combined 2% general partner interest in us and in our operating partnership.
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, subordinated units or other equity securities whenever, and on the same
terms that, we issue those securities to persons other than our
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general partner and its affiliates, to the extent necessary to maintain its
percentage interest that existed immediately before each issuance. The holders
of common units will not have preemptive rights to acquire additional common
units or other partnership interests.
Amendment of Our Partnership Agreement
Amendments to our partnership agreement may be proposed only by or with
the consent of our general partner, which it may withhold in its sole
discretion. In order to adopt a proposed amendment, other than the amendments
discussed in "--No Unitholder Approval" below, our general partner must seek
written approval of the holders of the number of units required to approve the
amendment or call a meeting of the limited partners to consider and vote upon
the proposed amendment.
Prohibited Amendments. No amendment may be made that would:
o change the percentage of outstanding units required to take
partnership action, unless approved by the affirmative vote of
unitholders constituting at least the voting requirement sought to be
reduced;
o 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;
o 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 its consent, which may be given or withheld
in its sole discretion;
o change our term;
o provide that we are not dissolved upon the expiration of our term or
upon an election to dissolve us by our general partner that is
approved by holders of a majority of the units of each class; or
o give any person the right to dissolve us other than our general
partner's right to dissolve us with the approval of holders of a
majority of the units of each class.
The provision of our partnership agreement preventing the amendments
having the effects described above can be amended upon the approval of the
holders of at least 90% of the outstanding units voting together as a single
class.
No Unitholder Approval. Our general partner may amend our partnership
agreement, without the approval of the unitholders, to:
o change our name, the location of our principal place of business, our
registered agent or registered office;
o reflect the admission, substitution, withdrawal or removal of
partners in accordance with our partnership agreement;
o qualify us or continue our qualification as a limited partnership
under the laws of any state or to ensure that neither we nor our
operating partnership will be taxed as a corporation or otherwise
taxed as an entity for federal income tax purposes;
o prevent us or our general partner, or its directors, officers, agents
or trustees, from being subject to the provisions of the Investment
Advisers Act of 1940 or "plan asset" regulations adopted under the
Employee Retirement Income Security Act of 1974;
o authorize additional limited or general partner interests;
o reflect changes required by a merger agreement that has been approved
under the terms of our partnership agreement;
o permit us to form or invest in any entity, other than the operating
partnership, permitted by our partnership agreement;
o change our fiscal year or taxable year; and
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o make other changes substantially similar to any of the matters
described above.
In addition, our general partner may amend our partnership agreement,
without the approval of the unitholders, if those amendments:
o do not adversely affect the limited partners in any material respect;
o are necessary to satisfy any requirements 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;
o are necessary to facilitate the trading of limited partner interests
or to comply with any rule or guideline of any securities exchange or
interdealer quotation system on which the limited partner interests
are or will be listed for trading;
o are necessary for any action taken by our general partner relating to
splits or combinations of units; or
o 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. Except in the case of the
amendments described above under "--No Unitholder Approval," amendments to our
partnership agreement will not become effective without the approval of holders
of at least 90% of the units unless we obtain an opinion of counsel to the
effect that the amendment will not affect the limited liability under applicable
law of any limited partner or cause us or our operating partnership to be
taxable as a corporation or otherwise to be taxed as an entity for federal
income tax purposes (to the extent not previously taxed as such). Subject to
obtaining the opinion of counsel, 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.
Merger, Sale or Other Disposition of Our Assets
Our general partner may not, without the prior approval of holders of a
majority of the outstanding units of each class, cause us to sell, exchange or
otherwise dispose of all of substantially all of our assets, including by way of
merger, consolidation or other combination, or approve on our behalf the sale,
exchange or other disposition of all or substantially all of the assets of our
operating partnership. However, our general partner may mortgage or otherwise
grant a security interest in all or substantially all of our assets or sell all
or substantially all of our assets under a foreclosure without that approval.
Furthermore, provided that conditions specified in our partnership agreement are
satisfied, our general partner may merge us or any of our subsidiaries into, or
convey some or all of our and their assets to, a newly formed entity if the sole
purpose of that merger or conveyance changes our legal form into another limited
liability entity.
The unitholders are not entitled to dissenters' rights of appraisal in
the event of a merger, consolidation, sale of substantially all of our assets or
any other transaction or event.
Termination and Dissolution
We will continue until December 31, 2098, unless terminated sooner upon:
o the election of our general partner to dissolve us, if approved by
the holders of a majority of the outstanding units of each class;
o the sale, exchange or other disposition of all or substantially all
of our assets and those of our operating partnership;
o the entry of a decree of judicial dissolution of us; or
o the withdrawal or removal of our general partner or any other event
that results in its ceasing to be our general partner other than the
transfer of its general partner interest in accordance with our
partnership agreement or withdrawal or removal following approval and
admission of a successor.
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Upon a dissolution under the last item above, the holders of a majority
of the units of each class may also elect, within specific time limitations, to
reconstitute us by forming a new limited partnership on terms identical to those
in our partnership agreement and having as general partner an entity approved by
the holders of a majority of the units of each class subject to our receipt of
an opinion of counsel to the effect that:
o the action would not result in the loss of limited liability of any
limited partner and
o we, the reconstituted limited partnership, and the operating
partnership would not be taxed as a corporation or otherwise be taxed
as an entity for federal income tax purposes upon the exercise of
that right to continue.
Liquidation and Distribution of Proceeds
Unless we are reconstituted and continue as a new limited partnership,
upon our liquidation the liquidator will liquidate our assets and apply the
proceeds of the liquidation as described in "--Cash Distribution
Policy--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 the partners.
Withdrawal or Removal of Our General Partner
Except as described below, our general partner will not withdraw
voluntarily either as our general partner or as general partner of our operating
partnership during the subordination period 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 furnishing an
opinion of counsel regarding limited liability and tax matters. At the end of
the subordination period, our general partner may withdraw as our general
partner without first obtaining approval from the unitholders by giving 90 days'
written notice. In addition, our general partner may withdraw at any time
without unitholder approval upon 90 days' notice 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. Our general partner may also
sell or otherwise transfer all of its general partner interests in us without
the approval of the unitholders as described below under "-Transfer of General
Partner Interest and Incentive Distribution Rights." Upon withdrawal, we must
reimburse our general partner for all expenses incurred by it on our behalf or
allocable to us in connection with operating our business.
If our general partner withdraws, other than as a result of a transfer
of all or a part of its general partner interests in us, the holders of a
majority of the common units may elect a successor to the 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 and liquidated, unless within 180 days after that withdrawal the
holders of a majority of the units of each class agree in writing to continue
our business and to appoint a successor general partner. See "--Termination and
Dissolution."
Our general partner may not be removed except by the vote of the
holders of at least 66 2/3% of the outstanding common units, excluding common
units held by our general partner and its affiliates, and we receive an opinion
of counsel regarding limited liability and tax matters. Any removal is also
subject to the approval of a successor general partner by the vote of the
holders of a majority of the common units, excluding common units held by our
general partner and its affiliates. If our general partner is removed under
circumstances where cause does not exist and does not consent to that removal:
o the subordination period will end and all outstanding subordinated
units will immediately convert into common units on a one-for-one
basis;
o the agreement of Atlas America to connect wells to our gathering
systems will terminate;
o the master natural gas gathering agreement with Atlas America will
not apply to any future wells drilled by Atlas America although it
will continue as to wells connected to the gathering system at the
time of removal;
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o the obligations of Atlas America to provide financing and other
assistance for the extension of our gathering systems and to provide
assistance in the identification and acquisition of gathering systems
from third parties will terminate;
o any existing arrearages in payment of the minimum quarterly
distributions will be extinguished; and
o our general partner will have the right to convert its general
partner interests and incentive distribution rights into common units
or to receive cash in exchange for those interests from the successor
general partner.
Our partnership agreement defines "cause" as existing where a court has
rendered a final, non-appealable judgment that our general partner has committed
fraud, gross negligence or willful or wanton misconduct in its capacity as
general partner.
Withdrawal or removal of our general partner as our general partner
also constitutes its withdrawal or removal as the general partner of our
operating partnership.
In the event of removal of our general partner under circumstances
where cause exists or a withdrawal of our general partner that violates our
partnership agreement, a successor general partner will have the option to
purchase the general partner interests 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, the departing general partner will have the option to
require the successor general partner to purchase those interests for their fair
market value. In each case, fair market value will be determined by agreement
between the departing general partner and the successor general partner. If they
cannot reach an agreement, an independent expert selected by the departing
general partner and the successor general partner will determine the fair market
value. If the departing general partner and the successor general partner cannot
agree on an expert, then an expert chosen by agreement of the experts selected
by each of them will determine the fair market value. If the purchase option is
not exercised by either the departing general partner or the successor general
partner, the general partner interests and incentive distribution rights will
automatically convert into common units equal to the fair market value of those
interests. The successor general partner must indemnify the departing general
partner (or its transferee) from all of our debt and liability arising on or
after the date on which the departing general partner becomes a common
unitholder as a result of the conversion. Except for this limited indemnity
right and the right of the departing general partner to receive distributions on
its common units, no other payments will be made to our general partner after
withdrawal.
Transfer of General Partner Interest and Incentive Distribution Rights
Except for a transfer by our general partner of all, but not less than
all, of its general partner interests in us and our operating partnership to:
o an affiliate of our general partner or
o another person as part of the merger or consolidation of the general
partner with or into another person or the transfer by the general
partner of all or substantially all of its assets to another person,
our general partner may not transfer any part of its general partner interest in
us and our operating partnership to another person during the subordination
period without the approval of the holders of at least a majority of the
outstanding common units, excluding those held by our general partner and its
affiliates. After the subordination period ends, our general partner may
transfer all or any part of its general partner interest without obtaining the
consent of the common unitholders. As a condition to the transfer of a general
partner interest, either before or after the subordination period ends, the
transferee must assume the rights and duties of the general partner to whose
interest it has succeeded, furnish an opinion of counsel regarding limited
liability and tax matters, agree to acquire all of the general partner's
interest in our operating partnership and agree to be bound by the provisions of
the partnership agreement of our operating partnership. Our general partner may
at any time, however, transfer its subordinated units without unitholder
approval. In addition, the members of our general partner may sell or transfer
all or part of their interest in our general partner to an affiliate without the
approval of the unitholders.
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Our general partner or a later holder may transfer its incentive
distribution rights to an affiliate or another person as part of its merger or
consolidation with or into, or sale of all or substantially all of its assets
to, that person without the prior approval of the unitholders. However, the
transferee must agree to be bound by the provisions of our partnership
agreement. Before the end of the subordination period, other transfers of the
incentive distribution rights will require the affirmative vote of holders of a
majority of the outstanding common units, excluding those held by our general
partner and its affiliates. After the subordination period ends, the incentive
distribution rights will be freely transferable.
Atlas America and its affiliates have agreed that they will not divest
their interest in our general partner without also divesting to the same
acquiror their ownership interest in subsidiaries which act as the general
partner of oil and gas investment partnerships sponsored by them.
Change of Management Provisions
Our partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to remove Atlas
Pipeline Partners GP, LLC as our general partner or otherwise change 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 will lose voting rights on all of its units and the units will not be
considered outstanding for the purposes of noticing meetings, determining the
presence of a quorum, calculating required votes and other similar matters. In
addition, the removal of our general partner under circumstances where cause
does not exist and our general partner does not consent to that removal has the
adverse consequences described under "--Withdrawal or Removal of Our General
Partner."
Limited Call Right
If at any time not more than 20% of the outstanding limited partner
interests of any class are held by persons other than our general partner and
its affiliates, 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 remaining limited partner interests of the class held by
unaffiliated persons as of a record date selected by our general partner on at
least 10 but not more than 60 days' notice. The purchase price is the greater
of:
o the highest cash 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
o the current market price as of the date three days before the date
the notice is mailed.
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 an undesirable time or price. 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.
Meetings; Voting
Except as described above under "-Change of Management Provisions,"
unitholders or assignees who are record holders of units on a 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. Common units that are
owned by an assignee who is a record holder, but who has not yet been admitted
as a substituted limited partner, will be voted by our general partner at the
written direction of the record holder. Absent direction of this kind, the
common units will not be voted, except that, in the case of common units held by
our general partner on behalf of non-citizen assignees, our general partner
shall distribute the votes on those common units in the same ratios as the votes
of limited partners on other units are cast.
Any action 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 same number of units
as would be necessary to take the action. 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
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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.
Except as described above under "--Change of Management Provisions,"
each record holder will have a vote in accordance with his percentage interest,
although additional limited partner interests having different voting rights
could be issued. See "--Issuance of Additional Securities." 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. Except as otherwise
provided in our partnership agreement, subordinated units will vote together
with common units as a single class.
We or the transfer agent will deliver any notice, report or proxy
material required or permitted to be given or made to record holders of common
units under our partnership agreement to the record holder.
Status as Limited Partner or Assignee
An assignee of a common unit, after executing and delivering a transfer
application, but pending its admission as a substituted limited partner, is
entitled to an interest equivalent to that of a limited partner sharing in
allocations and distributions, including liquidating distributions. Our general
partner will vote and exercise other powers attributable to common units owned
by an assignee who has not become a substituted limited partner at the written
direction of the assignee. See "--Meetings; Voting." We will not treat
transferees who do not execute and deliver a transfer application as assignees
or as record holders of common units, and they will not receive cash
distributions, federal income tax allocations or reports furnished to record
holders. See "-Transfer of Common Units."
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 in which we
have an interest because of the nationality, citizenship or related status of
any limited partner or assignee, we may redeem the units held by the limited
partner or assignee at their current market price. In order to avoid any
cancellation or forfeiture, our general partner may require each limited partner
or assignee to furnish information about his nationality, citizenship or related
status. If a limited partner or assignee fails to furnish this information
within 30 days after a request for it, or our general partner determines after
receipt of the information that the limited partner or assignee is not an
eligible citizen, then the limited partner or assignee may be treated as a
non-citizen assignee. In addition to other limitations on the rights of an
assignee who is not a substituted limited partner, 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.
Indemnification
Under the partnership agreement, we will indemnify the following
persons, by reason of their status as such, to the fullest extent permitted by
law, from and against all losses, claims or damages arising out of or incurred
in connection with our business:
o our general partner;
o any departing general partner;
o any person who is or was an affiliate of our general partner or any
departing general partner;
o any person who is or was a member, partner, officer, director,
employee, agent or trustee of our general partner, any departing
general partner or the operating partnership or any affiliate of a
general partner, any departing general partner or the operating
partnership; or
o any person who is or was serving at the request of a general partner
or any departing general partner or any affiliate of a general
partner or any departing general partner as an officer, director,
employee, member, partner, agent, fiduciary or trustee of another
person.
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Our indemnification obligation arises only if the indemnified person
acted in good faith and in a manner the person reasonably believed to be in, and
not opposed to, our best interests. With respect to criminal proceedings, the
indemnified person must not have had reasonable cause to believe that the
conduct was unlawful.
Any indemnification under these provisions will be only out of our
assets. Our general partner will not be personally liable for the
indemnification obligations and will not have any obligation to contribute or
loan funds to us in connection with it. The partnership agreement permits us to
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 the partnership agreement.
Books and Reports
Our general partner keeps appropriate books on our business at our
principal offices. The books are maintained for both tax and financial reporting
purposes on an accrual basis. For tax and financial reporting purposes, our
fiscal year is the calendar year.
We furnish or make available to record holders of common units, within
120 days after the close of each fiscal year, an annual report containing
audited financial statements and a report on those financial statements by our
independent public accountants. Except for our fourth quarter, we also furnish
or make available summary financial information within 90 days after the close
of each quarter.
We furnish each record holder information reasonably required for tax
reporting purposes within 90 days after the close of each calendar year. We
expect to furnish information in summary form so that some complex calculations
normally required of partners can be avoided. Our ability to furnish this
summary information to unitholders depends on the cooperation of unitholders in
supplying us with specific information. We will furnish every unitholder with
information to assist him in determining his federal and state tax liability and
filing his federal and state income tax returns, regardless of whether he
supplies us with 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
demand and at his own expense, have furnished to him:
o a current list of the name and last known address of each partner;
o a copy of our tax returns;
o 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 became a
partner;
o copies of our partnership agreement, the certificate of limited
partnership and related amendments and powers of attorney under which
they have been executed;
o information regarding the status of our business and financial
condition; and
o other information regarding our affairs that is just and reasonable.
Our general partner intends to keep confidential from the limited
partners trade secrets or other information the disclosure of which our general
partner believes in good faith is not in our best interests or which we are
required by law or by agreements with third parties to keep confidential.
Registration Rights
Under the 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 if an exemption from the registration
requirements is not otherwise available. We are obligated to pay all expenses
incidental to the registration, excluding underwriting discounts and
commissions.
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EXPERTS
The financial statements included or incorporated by reference in this
prospectus have been so included or incorporated in reliance upon the reports of
Grant Thornton LLP, independent certified public accountants, upon the authority
of such firm as experts in accounting and auditing.
LEGAL MATTERS
The validity of the securities offered hereby and tax matters will be
passed upon for us by Ledgewood Law Firm, P.C., Philadelphia, Pennsylvania.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-3 with
respect to this offering. This prospectus only constitutes part of the
registration statement and does not contain all of the information set forth in
the registration statement, its exhibits, and its schedules.
We file annual, quarterly and current reports, proxy statements and
other information with the SEC. Our SEC filings are available to the public over
the Internet at the SEC's web site at http://www.sec.gov. You may also read and
copy any document we file at the SEC's public reference rooms. Please call the
SEC at 1-800-SEC-0330 for additional information on the public reference rooms.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The SEC allows us to "incorporate by reference" the information we file
with it. This means that we can disclose important information to you by
referring to these documents. The information incorporated by reference is an
important part of this prospectus, and information that we file later with the
SEC under Sections 13(a) or 15(d) of the Securities Exchange Act of 1934 will
automatically update and supersede this information.
We are incorporating by reference the following documents that we have
previously filed with the SEC (other than information in such documents that is
deemed not to be filed):
o our Annual Report on Form 10-K for the fiscal year ended December
31, 2003, and
o our Proxy Statement on Schedule 14A for the special meeting of
unitholders held on February 11, 2004.
You may obtain a copy of these filings without charge by writing or
calling us at:
Investor Relations
Atlas Pipeline Partners, L.P.
311 Rouser Road
P.O. Box 611
Moon Township, Pennsylvania 15108
(412) 262-2830
You should rely only on the information incorporated by reference or
provided in this prospectus. We have not authorized anyone else to provide you
with different information. We are not making an offer to sell these securities
or soliciting an offer to buy these securities in any state where the offer or
sale is not permitted. You should not assume that the information in this
prospectus or the documents we have incorporated by reference is accurate as of
any date other than the date on the front of those documents.
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PLAN OF DISTRIBUTION
We may distribute the securities from time to time in one or more
transactions at a fixed price or prices. We may change these prices from time to
time. We may also distribute our securities at market prices prevailing at the
time of sale, at prices related to prevailing market prices or at negotiated
prices. We will describe the distribution method for each offering in a
prospectus supplement.
We may sell our securities in any of the following ways:
o through underwriters or dealers,
o through agents who may be deemed to be underwriters as defined in the
Securities Act, or
o directly to one or more purchasers.
The prospectus supplement for a particular offering will set forth the
terms of the offering, purchase price, the proceeds we will receive from the
offering, any delayed delivery arrangements, and any underwriting arrangements,
including underwriting discounts and other items constituting underwriters'
compensation and any discounts or concessions allowed or reallowed or paid to
dealers. We may have agreements with the underwriters, dealers and agents who
participate in the distribution to indemnify them against certain civil
liabilities, including liabilities under the Securities Act, or to contribute to
payments which they may be required to make.
Securities offered may be a new issue of securities with no established
trading market. Any underwriters to whom or agents through whom these securities
are sold by us for public offering and sale may make a market in these
securities, but such underwriters or agents will not be obligated to do so and
may discontinue any market making at any time without notice. No assurance can
be given as to the liquidity of or the trading market for any such securities.
If we use underwriters in the sale, the securities we offer will be
acquired by the underwriters for their own account and may be resold from time
to time in one or more transactions, including negotiated transactions, at a
fixed public offering price or at varying prices determined at the time of sale.
Our securities may be offered to the public either through underwriting
syndicates represented by one or more managing underwriters or directly by one
or more firms acting as underwriters. The underwriter or underwriters with
respect to a particular underwritten offering of securities will be named in the
prospectus supplement relating to that offering, and if an underwriting
syndicate is used, the managing underwriter or underwriters will be set forth on
the cover of that prospectus supplement.
If we use dealers in an offering, we will sell the securities to the
dealers as principals. The dealers may then resell the securities to the public
at varying prices to be determined by those dealers at the time of resale. The
names of the dealers and the terms of the transaction will be set forth in a
prospectus supplement. Any initial public offering price and any discounts or
concessions allowed or reallowed or paid to dealers may be changed from time to
time.
We may also offer our securities directly, or though agents we
designate, from time to time at fixed prices, which we may change, or at varying
prices determined at the time of sale. We will name any agent we use and
describe the terms of the agency, including any commissions payable by us to the
agent, in a prospectus supplement. Unless otherwise indicated in the prospectus
supplement, any agent we use will act on a reasonable best efforts basis for the
period of its appointment.
52
Report of Independent Certified Public Accountants
Shareholder
Alaska Pipeline Company
We have audited the accompanying consolidated balance sheets of Alaska
Pipeline Company and subsidiary as of December 31, 2003 and 2002, and the
related consolidated statements of income, changes in shareholder's equity,
and cash flows for each of the three years in the period ended December 31,
2003. 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 in accordance with auditing standards generally
accepted in the United States of America. 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. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Alaska
Pipeline Company and subsidiary as of December 31, 2003 and 2002, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 2003 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, effective January 1,
2002, Alaska Pipeline Company changed its method of accounting related to
goodwill in accordance with the adoption of Statement of Financial Accounting
Standard No. 142, Goodwill and Other Intangible Assets.
/s/ GRANT THORNTON LLP
------------------------
Cleveland, Ohio
March 26, 2004
F-1
ALASKA PIPELINE COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 2003 and 2002
2003 2002
------------ ------------
Current Assets
Cash ........................................... $ -- $ 99,407
Notes receivable - affiliates .................. 11,554,502 6,346,451
Accounts receivable - trade .................... 714,392 203,019
Prepaid expenses ............................... 123,545 131,691
------------ ------------
Total current assets.......................... 12,392,439 6,780,568
Property, Plant and Equipment
Plant in service, at cost ...................... 58,887,932 58,152,685
Less - accumulated depreciation ................ 12,211,960 9,463,050
------------ ------------
46,675,972 48,689,635
Deferred Charges and Other Assets
Goodwill, net of accumulated amortization of
$2,661,605..................................... 46,472,348 46,472,348
Unamortized debt expense, net .................. 267,141 306,940
------------ ------------
46,739,489 46,779,288
------------ ------------
Total Assets ................................... $105,807,900 $102,249,491
============ ============
Current Liabilities
Accounts payable and accrued liabilities ....... $ 8,245,102 $ 7,674,537
Deferred Credits and Other Liabilities
Deferred income taxes .......................... 6,946,939 5,440,065
Regulatory Liability ............................ 1,818,788 1,378,195
Long-Term Debt - Affiliate ...................... 35,900,000 35,900,000
Shareholder's Equity
Common stock, 2,850,000 shares authorized;
1,900,500 shares issued and outstanding,
$1 par value.................................. 1,900,500 1,900,500
Capital surplus ................................ 49,841,297 49,841,297
Retained earnings .............................. 1,155,274 114,897
------------ ------------
Total shareholder's equity ..................... 52,897,071 51,856,694
------------ ------------
Total Liabilities and Shareholder's Equity ...... $105,807,900 $102,249,491
============ ============
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-2
ALASKA PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2003, 2002 and 2001
2003 2002 2001
----------- ----------- -----------
Operating revenues
Gas sales and transportation - affiliate....................................... $67,732,859 $67,852,910 $69,083,247
Pipeline management services................................................... 3,109,996 562,109 --
----------- ----------- -----------
70,842,855 68,415,019 69,083,247
Operating expenses
Cost of gas sold............................................................... 55,548,942 56,148,644 56,620,021
Operations and maintenance..................................................... 4,006,898 1,273,348 1,232,789
General and administrative..................................................... 3,575,399 3,808,055 3,105,009
Depreciation and amortization.................................................. 3,265,221 3,349,051 4,591,050
----------- ----------- -----------
66,396,460 64,579,098 65,548,869
----------- ----------- -----------
Operating income............................................................. 4,446,395 3,835,921 3,534,378
Other income (expense)
Interest expense - affiliate................................................... (2,897,130) (3,013,200) (3,586,510)
Amortization of debt expense................................................... (39,799) (45,091) (54,984)
Other.......................................................................... 263,733 4,098 25,233
----------- ----------- -----------
(2,673,196) (3,054,193) (3,616,261)
----------- ----------- -----------
Income (loss) before income taxes............................................ 1,773,199 781,728 (81,883)
Income tax provision............................................................ 732,822 313,879 30,431
----------- ----------- -----------
NET INCOME (LOSS)............................................................... $ 1,040,377 $ 467,849 $ (112,314)
=========== =========== ===========
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-3
ALASKA PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2003, 2002 and 2001
2003 2002 2001
----------- ----------- -----------
Common stock.................................................................... $ 1,900,500 $ 1,900,500 $ 1,900,500
Capital surplus................................................................. 49,841,297 49,841,297 49,841,297
Retained earnings (deficit)
Beginning balance.............................................................. 114,897 (352,952) (240,638)
Net income (loss).............................................................. 1,040,377 467,849 (112,314)
----------- ----------- -----------
Ending balance................................................................. 1,155,274 114,897 (352,952)
----------- ----------- -----------
Total Shareholder's Equity...................................................... $52,897,071 $51,856,694 $51,388,845
=========== =========== ===========
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-4
ALASKA PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002 and 2001
2003 2002 2001
----------- ----------- ------------
Cash flow from operating activities
Net income (loss).............................................................. $ 1,040,377 $ 467,849 $ (112,314)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation and amortization................................................ 3,305,020 3,394,142 4,646,034
Deferred income tax expense.................................................. 1,506,874 2,023,203 1,636,048
Gain on sale of property..................................................... (260,292) -- --
Changes in operating assets and liabilities:
Accounts receivable......................................................... (511,373) (203,019) --
Prepaid expenses............................................................ 8,146 23,439 (34,967)
Accounts payable and accrued liabilities.................................... 570,565 (1,624,617) 4,252,384
----------- ----------- ------------
Net cash provided by operating activities.................................. 5,659,317 4,080,997 10,387,185
Cash flows from investing activities
Property additions............................................................. (863,559) (553,805) (989,108)
Proceeds from sale of property................................................. 312,886 -- --
----------- ----------- ------------
Net cash used in investing activities...................................... (550,673) (553,805) (989,108)
Cash flows from financing activities
(Increase) decrease in notes receivable - affiliates........................... (5,208,051) (3,427,785) 6,601,923
Repayment of long-term debt - affiliate........................................ -- -- (16,000,000)
----------- ----------- ------------
Net cash used in financing activities...................................... (5,208,051) (3,427,785) (9,398,077)
----------- ----------- ------------
NET (DECREASE) INCREASE.................................................... (99,407) 99,407 --
Cash - Beginning of period...................................................... 99,407 -- --
----------- ----------- ------------
Cash - End of period............................................................ $ -- $ 99,407 $ --
=========== =========== ============
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-5
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
NOTE 1 -- NATURE OF BUSINESS
Alaska Pipeline Company ("APC"), a wholly owned subsidiary of SEMCO Energy,
Inc. ("SEMCO"), is an intrastate natural gas transmission company which owns
and operates the high-pressure gas pipelines that transport gas from Alaska's
Cook Inlet gas fields to ENSTAR Natural Gas Company's ("ENSTAR") distribution
system and various commercial customers of ENSTAR. ENSTAR, a division of
SEMCO, is a natural gas distribution company. NORSTAR Pipeline Company, Inc.
("NORSTAR") is a 100% owned subsidiary of APC, and its primary business is
pipeline management services. APC and NORSTAR have no employees and ENSTAR is
APC's only customer. SEMCO is a publicly traded company (trading under the
symbol SEN on the NYSE) operating in the energy, construction, and information
technology service industries.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies consistently applied in the
preparation of the accompanying consolidated financial statements follows.
Principles of Consolidation
The consolidated financial statements include the accounts of APC, and its
wholly owned subsidiary, NORSTAR, collectively ("the Company"). NORSTAR was
incorporated in 2001 and began operating in April 2002. All material
intercompany transactions have been eliminated.
Basis of Presentation
The financial statements of the Company were prepared in conformity with
accounting principles generally accepted in the United States of America. In
connection with the preparation of the financial statements, management was
required to make estimates and assumptions that affect the reported amounts of
assets and liabilities and 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. Actual results could differ from those
estimates.
Financial Instruments
For cash, notes receivable, accounts receivable, and accounts payable and
accrued liabilities, the carrying amounts approximate fair values because of
the short maturity of those instruments. The carrying value of long-term debt
from an affiliate approximates fair market value since interest rates
approximate current market rates.
Reclassifications
Certain reclassifications have been made to the 2002 financial statements to
conform to the 2003 presentation.
Property, Plant, Equipment and Depreciation
The Company's property, plant and equipment, consisting primarily of
pipeline assets, are recorded at cost. The Company provides for depreciation
on a straight-line basis over 33 years, the estimated useful life of the
assets. Expenditures for routine maintenance and repairs are charged to
expense as incurred.
On January 1, 2002, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-
Lived Assets ("SFAS 144"). SFAS 144 requires the cost of long-lived assets be
tested for recoverability whenever events or changes in circumstances indicate
that their carrying amounts may not be recoverable. The carrying amount 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. In that circumstance, an impairment loss shall be measured as the
amount by which
F-6
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
December 31, 2003, 2002 and 2001
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (Continued)
the carrying amount of the asset exceeds it fair value. The adoption of SFAS 144
did not have a material effect on the Company's financial position or results of
operations.
Goodwill
Goodwill represents the excess of purchase price and related costs over the
value assigned to the net tangible assets of businesses acquired. On January
1, 2002, the Company adopted SFAS No. 141, Business Combinations ("SFAS 141")
and SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS 142"). SFAS 141
addresses financial accounting and reporting for all business combinations and
requires that all business combinations entered into subsequent to June 30,
2001 be recorded under the purchase method. This Statement also addresses
financial accounting and reporting for goodwill and other intangible assets
acquired in a business combination at the date of acquisition. SFAS 142
addresses financial accounting and reporting for intangible assets acquired
individually or with a group of other assets at the date of acquisition. This
Statement also addresses financial accounting and reporting for goodwill and
other intangible assets subsequent to their acquisition.
As of January 1, 2002, the date of adoption of SFAS 142, the Company had
unamortized goodwill in the amount of $46.5 million. Prior to the adoption,
goodwill was being amortized on a straight-line basis over a period of 40
years. Amortization expense related to goodwill was $1,228,344 in 2001.
The Company will continue to evaluate its goodwill at least annually as
required by SFAS 142 and will reflect the impairment of goodwill, if any, in
operating income in the income statement in the period in which the impairment
is indicated.
The following table presents what would have been reported as net income for
the periods presented in the financial statements exclusive of amortization
expense (net of any related tax effects) related to goodwill:
Years Ended December 31,
----------------------------------
2003 2002 2001
---------- -------- ---------
Net income (loss)............................................................... $1,040,377 $467,849 $(112,314)
Add back: Goodwill amortization, net of income taxes............................ -- -- 798,424
---------- -------- ---------
Adjusted net income............................................................ $1,040,377 $467,849 $ 686,110
========== ======== =========
Revenue Recognition
ENSTAR is APC's only gas transportation customer and, thus, all gas sales
and transportation revenue relates to ENSTAR. Gas sales and transportation
revenue is recognized at the time the natural gas purchased for sale to ENSTAR
is transported through the Company's system to ENSTAR's system. The Company
earns revenue from ENSTAR under an intercompany gas sales agreement that
compensates the Company for the cost of purchased gas and transporting the
purchased gas. Under the terms of the agreement, the Company earns revenue
only on the volume of gas sold to ENSTAR. Volumes that are transported by the
Company to ENSTAR's system that do not involve a sale of gas by the Company to
ENSTAR do not provide revenue to the Company. The gas sold to ENSTAR is sold
by ENSTAR to its gas sales service customers. Because the Company and ENSTAR
are viewed as one entity by the Regulatory Commission of Alaska ("RCA") for
purposes of rate making, regulatory review of the revenue from ENSTAR to
compensate the Company for transportation service has not been necessary.
Cost of Gas
The cost of gas is based upon contracts entered into between the Company and
several gas producing entities. Furthermore, these contracts have been
approved by the RCA. The base price of gas purchased under
F-7
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
December 31, 2003, 2002 and 2001
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (Continued)
these contracts can be adjusted annually based on factors such as the price of
certain traded oil futures, certain natural gas futures and other inflationary
measures.
Income Taxes
The Company is included in SEMCO's consolidated federal income tax return
and income taxes are allocated to the Company based upon its separate taxable
income.
Supplemental Disclosure of Cash Flow Information
All taxes are paid by SEMCO, and accordingly, the Company made no income tax
payments for the years ended December 31, 2003, 2002, and 2001. Additionally,
since all debt is owed to affiliates, the interest expense represents an
affiliate transaction and was recorded as a reduction to notes receivable --
affiliates, thus no cash was specifically paid for interest for the years
ended December 31, 2003, 2002, or 2001.
New Accounting Standards
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). The Standard
required entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When the liability
is initially recorded by an entity, it also increases the carrying amount of the
related long-lived asset. The liability is accreted each period to its present
value and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement. The
Company has determined that it does not have any asset retirement obligations
required to be recorded in accordance with SFAS 143. However, the Company is
subject to the provisions of SFAS 71, Accounting for the Effects of Certain
Types of Regulation. The provisions of SFAS 71 allow the Company to defer
expenses and income as regulatory assets and liabilities in the Consolidated
Balance Sheets when it is probable that those expenses and income will be
allowed in the rate setting process in a period different from the period in
which they would have been reflected in the Consolidated Statements of Income by
an unregulated company. These deferred regulatory assets and liabilities are
then included in the Consolidated Statements of Income in the periods in which
the same amounts are reflected in rates. In prior years, negative salvage value
was recorded in the accumulated depreciation of the Company in accordance with
industry practice. Negative salvage value has been reclassified to regulatory
liabilities in accordance with SFAS 143, Accounting for Asset Retirement
Obligations, which was adopted by the Company on January 1, 2003.
Notes Receivable -- Affiliate
As of December 31, 2003 and 2002, the Company had non-interest bearing notes
receivable from SEMCO of $11,554,502 and $6,346,451, respectively.
NOTE 3 -- RELATED PARTY TRANSACTIONS
Operations and Maintenance Expenses
Since the Company has no employees, all functions relating to the Company
are conducted by ENSTAR and SEMCO employees. ENSTAR charges the Company for
the payroll and related costs of the employees who work directly on the
operations and maintenance of the Company's pipelines and related equipment.
Any purchased items or services relating to the Company, although processed by
ENSTAR, are also directly charged to the Company at cost. Additionally, ENSTAR
and SEMCO allocate a portion of their
F-8
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
December 31, 2003, 2002 and 2001
NOTE 3 -- RELATED PARTY TRANSACTIONS -- (Continued)
administrative and general expenses to the Company, which amounted to $2,700,503
in 2003, $2,301,948 in 2002, and $2,122,433 in 2001.
Interest Expense
Since all long-term debt is owed to SEMCO, all interest expense incurred is
with a related party.
NOTE 4 -- REGULATORY MATTERS
The Company is subject to regulation by the RCA. The Company and ENSTAR are
viewed together as one entity by the RCA for purposes of rate making and other
regulatory matters. The RCA has jurisdiction over, among other things, rates,
accounting procedures, and standards of service.
The Company and ENSTAR have undergone a rate review with the RCA, which
began in 2000. The Company and ENSTAR received a rate order in August 2002,
which set the combined revenue requirement for the Company and ENSTAR and
included a 12.55% authorized return on equity. After receiving the order,
the Company and ENSTAR filed the rate design portion of the case. The Company
and ENSTAR stipulated with all parties to a rate design and an order on the
rate design was issued on May 21, 2003 providing for decreases to residential,
power plant and industrial customers and an increase to commercial customers.
The design also increases the monthly customer service charges over a 3-year
period.
NOTE 5 -- INCOME TAXES
The Company accounts for income taxes in accordance with SFAS No. 109,
Accounting For Income Taxes ("SFAS 109"). SFAS 109 requires an annual
measurement of deferred tax assets and deferred tax liabilities based upon the
estimated future tax effects of temporary differences and carryforwards.
The table below summarizes the components of the Company's provision for
income taxes:
Years Ended December 31,
---------------------------------------
2003 2002 2001
---------- ----------- -----------
Federal income taxes:
Currently refundable........................................................... $ (677,544) $(1,520,436) $(1,454,496)
Deferred to future periods..................................................... 1,243,504 1,764,531 1,492,138
State income taxes:
Currently refundable........................................................... (96,508) (188,888) (151,121)
Deferred to future periods..................................................... 263,370 258,672 143,910
---------- ----------- -----------
Total income tax provision...................................................... $ 732,822 $ 313,879 $ 30,431
========== =========== ===========
Deferred income taxes arise from temporary differences between the tax bases
of assets and liabilities and their reported amounts in the financial
statements. The table below shows the principal components of the Company's
deferred tax liability.
December 31,
-----------------------
2003 2002
---------- ----------
Deferred tax liability components:
Property ........................................... $4,109,653 $3,629,226
Goodwill ........................................... 1,859,344 1,096,267
Other .............................................. 977,942 714,572
---------- ----------
Total deferred tax liability ........................ $6,946,939 $5,440,065
========== ==========
F-9
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
December 31, 2003, 2002 and 2001
NOTE 6 -- DEBT
Long-Term Debt -- Affiliate
The long-term debt -- affiliate is payable to SEMCO. Interest on the note is
recorded monthly as an intercompany transaction. The weighted average interest
rate charged to the Company by SEMCO was 8.07% in 2003, 8.17% in 2002 and
8.39% in 2001.
NOTE 7 -- COMMITMENTS AND CONTINGENCIES
Lease Commitments
The Company leases right of way access from various companies and
governmental agencies. The resulting leases are classified as operating leases
in accordance with SFAS 13, "Accounting for Leases." The
terms of these agreements range from one to thirty-three years. Management
anticipates renewing these leases as they become due.
The Company's annual future minimum lease payments under leases that have
initial or remaining non-cancellable terms in excess of one year for the years
ended December 31, 2004 through 2008 total approximately $123,000. Total lease
expense approximated $115,000, $107,000 and $103,000 in 2003, 2002 and 2001,
respectively.
Other Contingencies
In the normal course of business, the Company is party to certain lawsuits
and administrative proceedings before various courts and government agencies.
These lawsuits and proceedings may involve personal injury, property damage,
contractual issues and other matters. Management cannot predict the ultimate
outcome of any pending or threatened litigation or of actual or possible
claims; however, management believes resulting liabilities, if any, will not
have a material adverse impact upon the Company's financial position or
results of operations.
NOTE 8 -- PROPOSED SALE OF COMPANY
In September 2003, SEMCO entered into a definitive sales agreement to sell
APC to Atlas Pipeline Partners, L.P. for approximately $95 million, subject to
an adjustment based on the amount of working capital that APC has at closing.
The sale is subject to approval under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976, approval by the RCA, and consents under various
contracts. In regard to the RCA approval process, a stipulation on a final
order was reached with all interveners in the case and filed with the RCA on
March 26, 2004. A hearing on the stipulation is scheduled for April 7 and 8,
2004. A full hearing is scheduled for the week of April 26, 2004, if required.
As part of the sale, APC will enter into a ten-year Special Contract with
ENSTAR for gas transportation pursuant to which ENSTAR will pay a reservation
fee for use of all of APC's transportation capacity of $943,000 per month plus
a volumetric rate of $0.075 per Mcf of gas transported. The Special Contract
is subject to RCA approval. Additionally, SEMCO will execute a gas
transmission agreement with APC under which SEMCO will be obligated to make up
any difference if the RCA reduces the transportation rates payable by ENSTAR
pursuant to the Special Contract.
Furthermore, APC will enter into an Operations and Maintenance and
Administrative Services Agreement with ENSTAR under which ENSTAR will continue
to operate and maintain the pipeline for at least five years for a fee of
$334,000 per month for the first three years. Thereafter, ENSTAR's fees will
be adjusted for inflation.
All gas purchase contracts discussed in Note 2 will be assigned to ENSTAR
prior to the sale and the intercompany gas sales agreement between APC and
ENSTAR discussed in Note 2 will be terminated. NORSTAR is not part of the
sale.
F-10
[GRAPHIC OMITTED]
2,300,000 COMMON UNITS
REPRESENTING LIMITED PARTNER INTERESTS
----------------
PROSPECTUS SUPPLEMENT
May 27, 2005
----------------
FRIEDMAN BILLINGS RAMSEY
A.G. EDWARDS
WACHOVIA SECURITIES
----------------
KEYBANC CAPITAL MARKETS
SANDERS MORRIS HARRIS