UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
SCHEDULE 14A
Proxy Statement Pursuant to Section 14(a) of the Securities
Exchange Act of 1934 (Amendment No. ___)
Filed by the Registrant |X|
Filed by a Party other than the Registrant |_|
Check the appropriate box:
|X| Preliminary Proxy Statement
|_| Confidential, for Use of the Commission Only (as permitted by
Rule 14a-6(e)(2))
|_| Definitive Proxy Statement
|_| Definitive Additional Materials
|_| Soliciting Material Pursuant to ss. 240.14a-12
Atlas Pipeline Partners, L.P.
(Name of Registrant as Specified in its Charter)
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
|_| No fee required
|X| Fee computed on table below per Exchange Act Rules 14a-6(i)(l) and 0-11
1) Title of each class of securities to which transaction applies:
Membership interests
2) Aggregate number of securities to which transaction applies:
N/A
3) Per unit price or other underlying value of transaction computed
pursuant to Exchange Act Rule 0-11 (set forth the amount on which
the filing fee is calculated and state how it was determined):
$95,000,000 based on the cash consideration for the acquisition
4) Proposed maximum aggregate value of transaction:
$95,000,000
5) Total fee paid:
$19,000
|_| Fee paid previously with preliminary materials.
|_| Check box if any part of the fee is offset as provided by Exchange
Act Rule 0-11(a)(2) and identify the filing for which the offsetting
fee was paid previously. Identify the previous filing by
registration statement number, or the Form or Schedule and the date
of its filing.
1) Amount Previously Paid:
____________________________________________________________________
2) Form, Schedule or Registration Statement No.:
____________________________________________________________________
3) Filing Party:
____________________________________________________________________
4) Date Filed:
____________________________________________________________________
ATLAS PIPELINE PARTNERS, L.P.
311 Rouser Road
Moon Township, PA 15108
(412) 262-2830
Dear Unitholder:
We cordially invite you to a special meeting of our unitholders to be
held at [_____________________________] on [__________________, 2004] at 9:00
a.m., local time.
I am writing to ask your support for proposals we are submitting for
your consideration and approval.
o In September 2003 we agreed to acquire Alaska Pipeline Company. Alaska
Pipeline collects natural gas from producers in the Anchorage area and
delivers it to gas utility serving customers in the south-central
region of Alaska, including the city of Anchorage, and to other
industrial customers in the region. We believe that this acquisition,
for a total price of $95 million, will provide a significant and
reliable additional source of income to our partnership, and that it
will also moderate the inherent volatility from our current income
sources.
We have structured this acquisition so that we can fund it with outside
investors and existing sources of cash available to us. In Proposal I,
we are asking you to approve our issuance of common units in an
offering designed to eliminate the need for outside investors and
reduce the amount of debt we will otherwise incur. We believe that this
offering will serve to reduce on-going debt service and financing
payments.
o In Proposal II, we are asking for your approval of amendments to
sections of our partnership agreement that limit our ability to issue
further common units and to incur debt to finance our activities. These
provisions are scheduled to expire on January 1, 2005 if we continue to
pay a minimum quarterly distribution of $.42 per unit. We have paid in
excess of the minimum quarterly distribution in the 14 full quarters
since our inception, averaging $.57 per quarter. Accordingly, we
believe that the principal effect of these changes will be to advance
the expiration date by approximately [___] months.
We believe that these amendments are in our best interest. Currently
these restrictions hamper our efforts to take advantage of an active
acquisitions market. In particular, these limitations inhibit our
ability to raise funds in advance of a specific acquisition. It's
therefore difficult for us to accommodate a seller's desire to complete
a transaction quickly and to use equity or debt financing to make
significant acquisitions, such as the Alaska Pipeline transaction. We
believe that the resultant delays may cause us to be unable to make
acquisitions that are otherwise in our best interest.
We ask for your approval of Proposal II in order to be able to compete
successfully against others in our industry.
o We are also proposing to establish a long term incentive plan for
employees of our general partner and others who perform services for us
which we believe is essential to attract and retain the quality
individuals that we will need to significantly build the size and
profitability of our partnership.
Again, we need your approval and hope for your support.
We think the proposals that I have briefly discussed above and that are
presented in much greater detail in the proxy statement accompanying this letter
will provide us with the tools to continue building on the success that we have
achieved since our initial public offering in 2000. On behalf of the board of
managers of our general partner, I thank you for all of your support and urge
you to vote "FOR" the proposals.
Sincerely,
-----------------------------------
Edward E. Cohen
Chairman of the Board of Managers
of Atlas Pipeline Partners GP, LLC,
General Partner
_______________, 2004
ATLAS PIPELINE PARTNERS, L.P.
311 Rouser Road
Moon Township, PA 15108
(412) 262-2830
NOTICE OF SPECIAL MEETING OF UNITHOLDERS
To be held on _______________, 2004
To our Unitholders:
Notice is hereby given that a special meeting of the unitholders of
Atlas Pipeline Partners, L.P. will be held at [______________________],
Philadelphia, Pennsylvania on [__________________] at 9:00 a.m., local time, for
the purposes of:
1. Approving our issuance of up to 2.0 million common units of
limited partner interest in connection with our acquisition of
Alaska Pipeline Company and to fund anticipated capital
expenditures for the maintenance and expansion of the Alaska
Pipeline system;
2. Approving amendments to Sections 5.7 and 7.7 of our First Amended
and Restated Agreement of Limited Partnership that would remove
the limitations on our ability to issue common units and incur
debt, thereby effectively advancing their scheduled expiration
date by [___] months from January 1, 2005 to _______________,
2004, the date of the special meeting; and
3. Approving our Long-Term Incentive Plan.
The managing board of our general partner unanimously recommends that you vote
"FOR" the proposals.
Any action may be taken on the proposals at the meeting on the date
specified above, or on any date or dates to which the meeting may be adjourned.
Only unitholders of record at the close of business on _________________, 2003
are entitled to vote at the meeting or any adjournments or postponements of the
meeting.
To ensure that your units are voted at the meeting, please sign, date
and promptly mail the accompanying proxy card in the enclosed envelope. Any
unitholder of record present at the meeting or at any adjournments or
postponements of the meeting may revoke his or her proxy and vote personally on
each matter brought before the meeting.
Please review the proxy statement accompanying this notice for more
complete information regarding the matters proposed for your consideration at
the meeting. Should you have any questions or require assistance, please call
D.F. King & Co., Inc., our information agent, at: banks and brokers, call
collect: (212) 269-5550; all others, call toll free: (800) 758-5880.
BY ORDER OF THE MANAGING BOARD OF
ATLAS PIPELINE PARTNERS GP, LLC,
GENERAL PARTNER
Moon Township, Pennsylvania
________________, 2004
ATLAS PIPELINE PARTNERS, L.P.
311 Rouser Road
Moon Township, PA 15108
------------------------------------------------------------------------
PROXY STATEMENT
SPECIAL MEETING OF UNITHOLDERS
------------------------------------------------------------------------
We are furnishing this proxy statement to you in connection with our
solicitation of your proxy for use at the special meeting of unitholders called
for the purposes of:
1. Approving our issuance of up to 2.0 million common units of
limited partner interest in connection with our acquisition of
Alaska Pipeline Company and to fund anticipated capital
expenditures for the maintenance and expansion of the Alaska
Pipeline system;
2. Approving amendments to Sections 5.7 and 7.7 of our First
Amended and Restated Agreement of Limited Partnership that
would remove the limitations on our ability to issue common
units and incur debt, thereby effectively advancing their
scheduled expiration date by [___] months from January 1, 2005
to _________________, the date of the special meeting; and
3. Approving our Long-Term Incentive Plan.
This proxy statement is dated as of ____, 2004. It and the accompanying
proxy card are being sent on or about ___, 2004 to unitholders of record as of
____________, 2003. Only persons who are holders of record of units on
__________, 2003 may vote on the proposals.
If you have any questions about this proxy solicitation, please call
D.F. King & Co., Inc., our information agent at:
Banks and brokers, call collect: (212) 269-5550
All others, call toll free: (800) 758-5880
1
PROPOSAL I: ISSUANCE OF COMMON UNITS
On September 16, 2003, we entered into a purchase and sale agreement
with SEMCO Energy, Inc. (NYSE: SEN) pursuant to which we, or our designee, will
purchase all of the outstanding equity of Alaska Pipeline for $95.0 million.
Alaska Pipeline is the owner of an intrastate transmission system which delivers
natural gas to metropolitan Anchorage. The purchase and sale agreement is an
exhibit to our Current Report on Form 8-K, filed with the Securities and
Exchange Commission on September 16, 2003.
We are acquiring Alaska Pipeline because we believe it will provide a
significant and reliable source of additional income based on the gas
transmission agreements Alaska Pipeline will have with ENSTAR Natural Gas
Company, the division of SEMCO Energy which conducts its Alaska gas distribution
business. These agreements are described below under "--Additional Information
Concerning the Alaska Pipeline Acquisition--Gas Transmission Agreements."
We do not require and are not seeking unitholder approval of our
acquisition of Alaska Pipeline. Rather, we are seeking unitholder approval to
issue up to 2.0 million common units in order to finance the acquisition and
make capital improvements to the Alaska Pipeline system as described below under
"--Proposed Offering of Common Units." While the terms of our partnership
agreement permit us to acquire Alaska Pipeline, and to issue common units in
connection with the acquisition and related capital improvements, without the
approval of our unitholders, American Stock Exchange rules require us to seek
unitholder approval because our proposed issuance of up to 2.0 million common
units would increase our outstanding common equity by more than 20%.
We have obtained financing commitments for the entire Alaska Pipeline
purchase price. Therefore, we are able to, and intend to, complete the
acquisition whether or not our unitholders approve this proposal. However, if
our unitholders do not approve this proposal, we will not be able to retire a
substantial portion of the debt incurred in connection with the acquisition and
will likely need to raise capital through a smaller offering of common units or
incur additional indebtedness in order to make capital improvements to the
Alaska Pipeline system.
Alaska Pipeline
Alaska Pipeline is a wholly-owned subsidiary of SEMCO Energy, an energy
and infrastructure services company headquartered in southeastern Michigan.
Alaska Pipeline owns and operates SEMCO Energy's Alaska transmission system
which delivers natural gas from producing fields in south-central Alaska to
ENSTAR's Anchorage-based gas distribution system. ENSTAR is and will likely
continue to be for the foreseeable future Alaska Pipeline's only customer.
2
Alaska Pipeline's transmission system is composed of approximately 277
miles of 12- to 20-inch diameter pipeline and approximately 77 miles of smaller
diameter pipeline. Its present design delivery capacity is approximately 410
million cubic feet, or mmcf, per day, with an average throughput in 2002 of 130
mmcf per day. The gas transmission system consists of two pipeline networks. The
Kenai Pipeline System serves the east side of Cook Inlet and enters Anchorage
from the south. The Beluga Pipeline System serves the west side of Cook Inlet
and enters Anchorage from the north. The two pipeline systems are interconnected
in Anchorage, allowing ENSTAR's distribution system to serve all customers from
either pipeline system. The origination points of the two pipeline systems are
also interconnected by means of producer-owned pipelines. The Beluga and Kenai
pipeline systems form a complete loop around the Cook Inlet, and are the only
pipelines delivering gas to the Anchorage area.
At December 31, 2002, the ENSTAR delivery system to which the Alaska
Pipeline system connects consisted of 2,402 miles of gas distribution pipelines,
serving 111,000 customers in the Anchorage area or approximately 90% of the
city's population. For the year 2002, gas usage by customer was 34% residential,
26% commercial and 40% power and industrial.
We believe that the steady growth of Anchorage's population (an average
of 1.6% annually since 1990 according to statistics compiled by the Alaska
Department of Labor and Workforce Development and the U.S. Bureau of the Census)
will increase demand for gas and, accordingly, Alaska Pipeline's transportation
services. In addition, we believe Alaska Pipeline can grow through the
acquisition of producer-owned pipelines that connect gas fields to the Alaska
Pipeline system and to gas consumers. We believe that the acquisition of the
producer-owned pipelines may provide cost efficiencies and enhanced
opportunities for oil and gas transportation to end users.
Material Terms of the Alaska Pipeline Acquisition
The material terms of the Alaska Pipeline acquisition include the
following:
o We will pay SEMCO Energy $95.0 million for Alaska Pipeline,
including payments for certain licenses and services.
o At closing, Alaska Pipeline will enter into a Special Contract for
Gas Transportation with ENSTAR pursuant to which ENSTAR will pay a
reservation fee for use of all of the pipeline's transportation
capacity for 10 years. The reservation fee is $943,000 per month,
plus $.075 per thousand cubic feet, or mcf, of gas transported. In
addition, because the Regulatory Commission of Alaska has the
power to reduce the transportation rates payable by ENSTAR under
the Special Contract for Gas Transportation, SEMCO Energy will
enter into a Gas Transmission Agreement with Alaska Pipeline
pursuant to which SEMCO Energy will make up any difference between
the contract rate and the regulatory rate if the Regulatory
Commission of Alaska reduces the transportation rates during the
term of the Special Contract. We describe these agreements at
"--Additional Information Concerning the Alaska Pipeline
Acquisition--Gas Transmission Agreements."
3
o At closing Alaska Pipeline will enter into an Operation and
Maintenance and Administrative Services Agreement with ENSTAR
under which ENSTAR will continue to operate and maintain the
pipeline for at least 5 years. During the first 3 years of the
agreement, Alaska Pipeline will pay ENSTAR $334,000 per month for
these services; after that, ENSTAR's fee will be adjusted for
inflation. We describe this agreement at "--Additional Information
Concerning the Alaska Pipeline Acquisition--Operation and
Maintenance and Administrative Services Agreement."
o Completion of the acquisition is contingent upon receipt of the
approval of the Regulatory Commission of Alaska and the
expiration, without adverse action, of the waiting period under
the Hart-Scott-Rodino Antitrust Improvements Act of 1976. We have
a right to terminate the acquisition without penalty if these
approvals are not obtained on or before June 16, 2004.
Alaska Pipeline's principal executive offices are located at 3000
Spenard Road, Anchorage, Alaska 99519; its telephone number is: (907) 277-5551.
Financing the Alaska Pipeline Acquisition
Acquisition Entity. We have formed a new Delaware limited liability
company, APC Acquisition, LLC, to be the purchaser of Alaska Pipeline. APC
Acquisition will have no material operations until we complete the acquisition
of Alaska Pipeline. APC Acquisition will finance the $95.0 million purchase
price of Alaska Pipeline, plus estimated expenses of $4.4 million, as follows:
o $50.0 million revolving credit facility loan, administered by
Wachovia Bank, National Association. We describe this loan in
"--Wachovia Bank Credit Facilities."
o $25.0 million preferred equity "mezzanine" investment by Friedman,
Billings, Ramsey Group, Inc., representing 100% of the preferred
equity and 50% of the voting rights in APC Acquisition. The
preferred equity will be entitled to receive distributions at an
annual rate of 12% for the 12 months following the completion of
the Alaska Pipeline acquisition and at an annual rate of 18% after
that, which we refer to as the "preferred yield." For its
commitment to provide this funding, we have paid FBR $375,000, and
at the closing of the Alaska Pipeline acquisition will pay an
additional $875,000. We have the right to buy the preferred equity
interest and, if we do not do so, FBR has the right to require
Resource America, Inc., the parent of our general partner, to
purchase the interest as described in "--Right to Purchase FBR's
Preferred Equity Interest." Resource America has the right to
require us to purchase the preferred equity interest from it as
described in "--Resource America's Put Right to Us."
o $24.4 million common equity investment by us, representing 100% of
the common equity and 50% of the voting rights in APC Acquisition.
We will fund this investment through our existing $20 million
revolving credit facility administered by Wachovia Bank and
through $4.4 million of advances from our general partner or its
parent, Atlas America, Inc.
4
APC Acquisition will be managed by four managers, two designated by FBR
and two designated by us; however, the managers we appoint will be responsible
for supervising the day-to-day operations of Alaska Pipeline. If neither we nor
Resource America purchases FBR's interest, FBR may designate an additional
manager, as described in "--Right to Purchase FBR's Preferred Equity Interest."
If our unitholders approve this proposal, we may be able to minimize,
or entirely avoid, the use of the FBR mezzanine financing and minimize the use
of credit facility debt for the Alaska Pipeline acquisition, thereby reducing
our debt to equity ratio and saving significant financing costs.
Wachovia Bank Credit Facilities. We currently have $20.0 million
available under our credit facility administered by Wachovia Bank. We intend to
draw down all of the credit available under this facility in order to fund a
portion of our investment in APC Acquisition. Borrowings under the facility are
secured by a lien on and security interest in all of our property and that of
our subsidiaries, but will not include a lien on the property of APC Acquisition
or Alaska Pipeline. The revolving credit facility terminates in December 2005
and 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 .5%
or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided by 1 minus the
percentage prescribed by the Federal Reserve Board for determining the reserve
requirement for euro currency funding. The applicable margin is as follows:
o where our leverage ratio, that is, the ratio of our debt to
EBITDA, as defined in the credit facility agreement, is less than
or equal to 1.5, the applicable margin is 0% for base rate loans
and 1.5% for LIBOR loans;
o where our leverage ratio is greater than 1.5 but less than or
equal to 2.5, the applicable margin is 0.25% for base rate loans
and 1.75% for LIBOR loans;
o where our leverage ratio is greater than 2.5 but less than or
equal to 3.0, the applicable margin is 0.50% for base rate loans
and 2% for LIBOR loans; and
o where our leverage ratio is greater than 3.0, the applicable
margin is 0.75% for base rate loans and 2.50% for LIBOR loans.
APC Acquisition has received a commitment from Wachovia Bank for a
$50.0 million credit facility to finance the purchase of Alaska Pipeline. The
facility is contingent upon the closing of the Alaska Pipeline acquisition on or
before June 16, 2004. Up to $25.0 million of borrowings under the facility will
be secured by a lien on and security interest in all of APC Acquisition's
property. In addition, upon the earlier to occur of the termination of our
subordination period or the amendment of the restrictions in our partnership
agreement on our incurrence of debt (see Proposal II below), we will guaranty
all borrowings under the facility, securing the guaranty with a pledge of our
interest in APC Acquisition. The revolving credit facility will terminate after
three years and will bear interest at the base rate described in the previous
paragraph plus the applicable margin or LIBOR plus the applicable margin. The
applicable margin will be as follows:
5
o where APC Acquisition's leverage ratio is less than or equal to
1.5, the applicable margin will be 0% for base rate loans and 1.5%
for LIBOR loans;
o where APC Acquisition's leverage ratio is greater than 1.5 but
less than or equal to 3, the applicable margin will be 0.75% for
base rate loans and 1.75% for LIBOR loans;
o where APC Acquisition's leverage ratio is greater than 3 but less
than or equal to 3.5, the applicable margin will be 1.5% for base
rate loans and 2.5% for LIBOR loans;
o where APC Acquisition's leverage ratio is greater than 3.5 but
less than or equal to 4, the applicable margin will be 2% for base
rate loans and 3% for LIBOR loans; and
o where APC Acquisition's leverage ratio is greater than 4, the
applicable margin will be 2.5% for base rate loans and 3.5% for
LIBOR loans.
Advances from Our General Partner or Atlas America. Our general partner
and its parent, Atlas America, have been advancing and will continue to advance,
funds to pay expenses related to our acquisition of Alaska Pipeline. These
advances are an open account and bear the same rate of interest as the Wachovia
Bank credit facilities. These advances are due upon demand and are unsecured.
Right to Purchase FBR's Preferred Equity Interest. We will have the
option, during the 18 months following the closing of the Alaska Pipeline
acquisition, which we refer to as the "acquisition closing date," to purchase
any portion or all of FBR's preferred equity interest in APC Acquisition on the
following terms:
----------------------------------------------- ----------------------------------------------------
Date of purchase Purchase price
---------------- --------------
----------------------------------------------- ----------------------------------------------------
----------------------------------------------- ----------------------------------------------------
Acquisition closing date to and including the The sum of (i) the initial capital contribution
following 90th day made by FBR with respect to the preferred equity
interest being purchased, plus (ii) an amount equal
to 2.0% of the amount set forth in clause (i) plus
(iii) the accrued but unpaid preferred yield through
and including the date of closing on the preferred
equity interests being purchased.
----------------------------------------------- ----------------------------------------------------
----------------------------------------------- ----------------------------------------------------
91st day following the acquisition closing The sum of (i) the initial capital contribution
date through the end of the following 18th made by FBR with respect to the preferred equity
month interests being purchased, plus (ii) an amount,
which we refer to as the "purchase premium," equal
to 1.0% of the amount of the initial capital
contribution made by FBR with respect to the
preferred equity interests being purchased,
multiplied by the whole number equal to the number
of whole or partial months that have elapsed since
the acquisition closing date minus one, plus (iii)
the accrued but unpaid preferred yield through and
including the date of closing on the preferred
equity interests being purchased.
----------------------------------------------- ----------------------------------------------------
6
We are not required to purchase FBR's preferred equity interest in APC
Acquisition. If we do not purchase all of FBR's preferred equity interest within
180 days of the acquisition closing date, FBR can require Resource America to
purchase its interest in three tranches, starting on the 181st day after the
acquisition closing date and then at two 180-day intervals after that, at the
same purchase price described in the table above. We paid Resource America a fee
of $70,750 for this standby commitment, and will pay it an additional fee of
$141,500 upon closing of the Alaska Pipeline acquisition.
In the event that neither we nor Resource America purchases all of
FBR's preferred equity interest in APC Acquisition on the terms described above
within 24 months of the acquisition closing date, then:
o FBR will have the right to designate an additional manager of APC
Acquisition so that it has management control and
o we will be deemed to have waived our right to object to actions
taken by FBR in managing APC Acquisition.
Resource America's Put Right to Us. Beginning 180 days after it
acquires any of the equity interests in APC Acquisition pursuant to the FBR put,
Resource America will have the right to require us to purchase the same
interests at a price equal to the price Resource America paid to FBR plus
purchase premium calculated in the same manner as the purchase premium payable
to FBR. The purchase premium begins accruing on the date Resource America
acquires the equity interest. We must pay the purchase price in common units
based on the closing price of common units on the dates Resource America
exercises its put right. If our unitholders approve this proposal, we may issue
a portion of the authorized common units to Resource America pursuant to this
obligation.
We will also have the option of purchasing the equity interests in APC
Acquisition that Resource America acquires, on the same terms described above,
at any time.
7
Proposed Offering of Common Units
Subject to unitholder approval, we intend to publicly offer up to 2.0
million common units for cash and use the net proceeds of the offering as
follows:
o $25.5 million to purchase FBR's preferred equity interest in APC
Acquisition.
o $10.0 million as a further investment in APC Acquisition so that
it may repay $10.0 million of the indebtedness outstanding under
its $50 million revolving credit facility.
o $20.0 million to repay indebtedness outstanding under our $20.0
million revolving credit facility.
o $4.4 million to repay advances to us by our general partner and
Atlas America for expenses we incur in connection with the
acquisition.
o $11.1 million to fund anticipated future capital expenditures
related to the maintenance and expansion of Alaska Pipeline
system, principally relating to expenditures in 2004 for repair of
that portion of the Beluga pipeline that runs under the Susitna
River.
Alternatively, if we do not purchase FBR's preferred equity interest in
APC Acquisition and FBR exercises its put right to Resource America described
above under "--Financing the Alaska Pipeline Acquisition--Right to Purchase
FBR's Preferred Equity Interest," we may issue up to $32.1 million of common
units to Resource America in connection with its put right described under
"--Resource America's Put Right to Us."
We anticipate that we will offer the common units at a price that will
be determined by us and our underwriters based on then existing market
conditions. Unitholders will not have preemptive rights to acquire any of the
common units.
Rule 712 of the American Stock Exchange, or AMEX, requires shareholder
approval of the issuance of shares as sole or partial consideration for an
acquisition of stock or assets of another company if the stock issuance could
result in an increase in outstanding common shares of 20% or more. The proposed
issuance of up to 2.0 million of common units will increase the number of our
outstanding common units by approximately 74%.
Additional Information Concerning the Alaska Pipeline Acquisition
Background of the Acquisition. Our business goal is to increase per
unit distributions to our unitholders. Our growth strategy is to add new wells
to our pipeline system and acquire additional mid-stream gas assets,
particularly pipelines.
8
In February 2003, McDonald Investments Inc., an investment banking
company that acted as a co-underwriter of our initial public offering in January
2000 and follow-on equity offering in May 2003, informed us and several other
potential bidders that SEMCO Energy intended to sell the equity of its wholly
owned subsidiary, Alaska Pipeline. In March 2003, we received a Confidential
Memorandum describing Alaska Pipeline. On March 28, 2003, we submitted a
preliminary proposal, based solely on the information provided in the
Confidential Memorandum, to acquire Alaska Pipeline, and on April 28, 2003 we
were informed that we had been selected as one of the final group of bidders.
On May 5 and 6, 2003, officers of our general partner attended a
briefing in Anchorage, Alaska by officers of SEMCO Energy and ENSTAR who
provided an additional overview of Alaska Pipeline, a field inspection of the
assets and an opportunity to ask questions. On May 23, 2003, we submitted a
final proposal to acquire Alaska Pipeline for $95.0 million to be paid in cash
at closing and were informed a few days later that our final proposal was
accepted subject to the negotiation of definitive agreements. On September 16,
2003, we executed the definitive purchase and sale agreement.
Gas Transmission Agreements. Alaska Pipeline's historic revenues have
been determined as a part of ENSTAR's overall rate determination by the
Regulatory Commission of Alaska and, because of agreements we will enter into
with SEMCO when we acquire Alaska Pipeline, are not indicative of its revenues
subsequent to our acquisition of Alaska Pipeline. We anticipate that
substantially all of Alaska Pipeline's revenues for the foreseeable future will
be derived from transmission of gas for ENSTAR pursuant to the gas transmission
agreements to be entered into with ENSTAR and SEMCO Energy at the closing. The
form of these agreements are attached as Exhibits B and C of the purchase and
sale agreement. The principal terms of these agreements are:
o ENSTAR will have the exclusive right to transport on Alaska
Pipeline's system a quantity of gas equal to the system's current
transportation capacity for an initial term of 10 years, subject
to automatic renewals of additional one-year periods unless either
party gives notice of its intention to terminate the agreement at
least one year before the end of the initial term and at least 180
days before the end of any renewal term.
o ENSTAR will pay Alaska Pipeline a monthly reservation charge of
$943,000 plus a commodities charge of $.075 per mcf of natural gas
transported. Based on 2002 throughput of 47.4 billion cubic feet,
or bcf, this would result in annual revenues of $14.9 million.
o SEMCO Energy will make up any difference if the Regulatory
Commission of Alaska reduces the transportation rates payable by
ENSTAR to Alaska Pipeline.
o ENSTAR will reimburse Alaska Pipeline for all user fees, taxes
(except income and ad valorem taxes) and similar charges levied
upon the transportation of the natural gas.
Operation and Maintenance and Administrative Services Agreement. To
provide operational stability for Alaska Pipeline, ENSTAR will operate the
pipeline system for at least 5 years following the closing (subject to
extensions on negotiated terms) pursuant to the Operation and Maintenance and
Administrative Services Agreement to be entered into at closing. The form of
this agreement is attached as Exhibit A of the purchase and sale agreement. The
principal terms of this agreement are:
9
o ENSTAR will provide Alaska Pipeline with all supplies, materials,
goods and services that are otherwise necessary for the physical
operation and maintenance of the pipeline system including:
o administration of the pipeline system and day to day customer
services;
o information systems services and information technology
services;
o regulatory, pipeline safety, occupational health and safety,
and environmental services; and
o tax, customer billing and collection, accounting, human
resources, legal, claims and other administrative services.
o ENSTAR will provide Alaska Pipeline with all services necessary
for the design, construction and placing in service of all capital
improvements in accordance with an annual capital improvement
budget approved by Alaska Pipeline. Except in the case of
emergencies, ENSTAR will not make unbudgeted capital expenditures
without Alaska Pipeline's prior consent.
o Alaska Pipeline will pay ENSTAR a fixed fee of $334,000 per
calendar month for the operations and maintenance services for the
first 3 years. After that, ENSTAR's fee will be adjusted for
inflation.
o All capital improvements services will be performed by ENSTAR on a
cost reimbursement basis, including direct and indirect costs.
Gas Control Services Agreement. ENSTAR will also provide gas control
services to Alaska Pipeline for at least 10 years following the closing (subject
to extensions on negotiated terms). The form of this agreement is attached as
Exhibit F of the purchase and sale agreement. The principal terms of this
agreement are:
o ENSTAR will monitor the compression of the pipeline system,
including, analyzing pressures for irregularities, maintaining
pressures at compressor stations, key line junctions and
regulating stations to divide the available gas during heavy
demand periods, maintaining proper compression ratios and
compressor stations and rerouting gas during emergencies and
planned shutdowns.
o Alaska Pipeline will make a single payment of $450,000 for
ENSTAR's services during the initial 10-year term. This payment is
included in the $95.0 million purchase price described in
"--Material Terms of the Alaska Pipeline Acquisition."
10
Tower License. At the closing, Alaska Pipeline will receive a
perpetual, non-exclusive license to use ENSTAR's radio tower facilities
necessary for the operation of the Alaska Pipeline system. Alaska Pipeline will
make a single payment of $250,000 for the license. This payment is included in
the $95.0 million purchase price described in "--Material Terms of the Alaska
Pipeline Acquisition."
Regulatory Approvals. Historically, Alaska Pipeline's revenues have
been included in the rate design and the actual rate that ENSTAR has been
authorized by the Regulatory Commission of Alaska to charge its customers. The
rate design is based on, among other factors, the cost of the gas, the cost of
operations and the capital structure of the regulated entity. It is a condition
to the completion of the Alaska Pipeline acquisition that the Regulatory
Commission approve the transportation fees stated in the Special Contract for
Gas Transportation and that the approval not contain a condition which is
reasonably likely to have a material adverse effect on ENSTAR's gas distribution
business. We and SEMCO Energy submitted an application for such approval with
the Regulatory Commission on October 10, 2003, which was deemed complete and
filed on November 14, 2003, and requested that the Regulatory Commission issue a
final order approving the transaction by April 16, 2004. Once the Regulatory
Commission issues its final order, there will be a 30-day appeal period.
In addition, the Alaska Pipeline acquisition is subject to review by
the Federal Trade Commission and the U.S. Department of Justice under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976. We and SEMCO Energy intend
to file HSR notification forms with these agencies before the end of the year.
Vote Required
The proposal to issue up to 2.0 million common units in connection with
the Alaska Pipeline acquisition must be approved by a majority of the aggregate
outstanding common units and subordinated units, voting as a single class. Our
general partner, which owns all of our 1,641,026 subordinated units, intends to
vote in favor of the proposal.
General Partner Recommendation
The managing board of our general partner unanimously recommends a vote
"FOR" approval of the proposal.
PROPOSAL II: AMENDMENTS TO PARTNERSHIP AGREEMENT
We believe that provisions in the partnership agreement that limit our
ability to issue additional common units and to incur debt without first
obtaining unitholder approval inhibit our ability to make additional material
purchases or acquisitions and severely hamper our ability to take advantage of
opportunities presented to us. We propose to amend our partnership agreement to
eliminate the restrictions on our ability to incur debt and to issue additional
common units. If approved, these amendments will be effective as of the date of
the special meeting.
11
Amendments Relating to Additional Common Unit Issuances
Currently, our partnership limits the amount of common units we may
issue during the subordination period. This provision is scheduled to expire on
January 1, 2005 provided we continue to pay a minimum quarterly distribution of
$.42 on our common and subordinated units until December 31, 2004, which we
expect to be able to do. We have paid in excess of the minimum quarterly
distribution in each of the 14 full quarters since our inception, averaging $.57
per quarter. If unitholders approve the proposed amendment, the termination of
the limitation would be advanced by approximately [___] months, to the
[_______________] special meeting date.
Under Section 5.7 of our partnership agreement, we may issue common
units during the subordination period only as follows:
o up to 150,000 common units for general purposes--we issued the
150,000 common units in our May 2003 offering and, accordingly, do
not now have authority to issue common units for general purposes
without unitholder approval until the subordination period ends;
o in connection with an "acquisition" or a "capital improvement;"
o to repay debt incurred in connection with an acquisition or
capital improvement, but only if we issue the common units within
365 days of the acquisition or capital improvement; or
o in connection with conversion of incentive distribution rights,
employee benefit plans, combination or subdivision of the common
units, or construction financing we elect to require Atlas America
to provide us.
As defined in our partnership agreement, an "acquisition" is a transaction where
we acquire control over assets, properties or a business for purposes of
increasing our operating capacity, while a "capital improvement" is the
acquisition or construction of capital assets if done to increase our operating
capacity or the revenues from our operating capacity.
Our partnership agreement further provides that, during the
subordination period, an acquisition or capital improvement can only be financed
through issuance of common units if we can demonstrate that it meets certain
financial tests prescribed by the partnership agreement. These tests generally
require that, on a pro forma basis, the acquisition or capital improvement may
not result in a diminution of per unit adjusted operating surplus (which is,
essentially, partnership cash flow).
The negative effect of these limitations is, we believe, four-fold:
o First, our ability to make acquisitions or capital improvements is
narrowly circumscribed. We are not, for example, permitted to make
an acquisition that will be accretive over a longer term but may
have dilutive effects on the pro forma basis prescribed by the
partnership agreement. As a further example, we are not presently
permitted to issue common units to repay debt we incur in
connection with an acquisition or capital improvement if the
issuance will occur more than 365 days after the acquisition or
capital improvement.
12
o Second, the necessity of ascertaining compliance with the pro
forma financial tests established by the partnership agreement has
the practical effect of prohibiting us from raising the funds
necessary to make the acquisition or capital improvement before we
have identified and negotiated the acquisition terms or identified
and quantified the cost of the capital improvement. In an
acquisition, the time constraints associated with seeking to raise
capital after a transaction has been identified and negotiated
puts us at a disadvantage relative to other bidders who may be
able to raise capital well before planning an acquisition (and are
thus able to offer a prospective seller the advantage of a rapid
consummation of the acquisition once it has been negotiated). With
respect to capital improvements, a transaction-by-transaction
process may cause delays in implementing a program that we believe
will enhance our transportation capabilities, our revenues or our
cash flow.
o Third, we cannot issue our common units at times when our general
partner believes that market conditions are favorable to us. As
described in the second bullet point, we can only issue common
units after we have identified an acquisition or capital
improvement. This may not occur in a period of market strength for
our sector or our common units, resulting in our having to issue
more units (and thus diluting the interest of existing
unitholders) in order to raise the necessary funds.
o Fourth, a transaction-by-transaction approval process will, we
believe, result in increased costs because each transaction would
require a separate consent and, as a result, a separate proxy
statement and solicitation process.
For these reasons, we believe that the ability to issue common units
without further unitholder approval is in our best interest. However, we have no
plan to issue any of these units at this time and expect to do so only at such
time as we have identified a purpose that we believe is in our best interest.
Unitholders will not have preemptive rights to acquire any common units we may
issue. In addition, the proposed amendment would have the following effects:
o The requirement that the issuance of additional units not result
in a decrease in our cash flow on a per unit basis pro forma for
the preceding four-quarter period will be eliminated. In other
words, we could issue additional common units even if the
immediate effect of the issuance was dilutive. However, until the
end of the subordination period, all common unitholders will
continue to benefit from the provisions of our partnership
agreement regarding minimum quarterly distributions and the
subordination of the priority of common units over subordinated
units in receiving distributions.
o Unless an issuance of common units is in connection with an
acquisition which will produce a ratio of distributable cash to
taxable income that is greater than that produced by our existing
assets (after giving effect to the special allocation of gross
income to our general partner through 2006), issuances of common
units may increase the ratio of federal taxable income to
distributions for the common units, thus decreasing the amount of
our distributions per common unit that is not subject to federal
income tax.
13
Amendments Relating to Elimination of Restrictions on Indebtedness
We are asking for your approval of an amendment to our partnership
agreement that would eliminate limitations on the amount of debt we may incur
without unitholder approval during the subordination period. Currently, under
Section 7.7 of our partnership agreement we may not incur debt during the
subordination period that will:
o result in our unconsolidated indebtedness exceeding 2 times EBITDA
for the immediately preceding four fiscal quarters, determined on
a pro forma basis giving effect to any contemplated acquisitions,
or
o result in our consolidated interest coverage ratio, on a pro forma
basis, being less than 4.0 to 1.0. Our partnership agreement
defines interest coverage ratio as being the ratio of EBITDA to
annual interest payments made. EBITDA means our income or losses
before interest, taxes, depreciation and amortization.
We believe that the principal effect of the proposed amendment would be
to advance the scheduled expiration date of the existing limitations by
approximately [___] months. We are proposing this advance in the scheduled
termination date because we believe that these provisions inhibit our ability to
take advantage of acquisition, capital improvement or other opportunities
presented to us.
Upon completion of our acquisition of Alaska Pipeline, and absent the
offering of our common units discussed in Proposal I, our interest coverage
ratio, on a pro forma basis, would be 4.17 to 1.0. See "-Unaudited Pro Forma
Financial Information." As a result, we could be materially limited in the
amount of further debt we will be able to incur during the subordination period.
We believe that the limitations imposed by Section 7.7 are unduly
restrictive and inhibit the potential growth of our business. By comparison, our
existing $20.0 million credit facility prohibits us from incurring debt that:
o causes the ratio of our consolidated debt to EBITDA to be more
than 3 to 1 or
o causes the ratio of our EBITDA to our consolidated interest
expense to be less than 3.5 to 1.
Current economic and industry conditions present many expansion and growth
opportunities which could be pursued within the limitations imposed by our
lenders but not under the existing provisions of our partnership agreement. We
believe that the obligation to obtain unitholder approval of an acquisition if
it results in our exceeding the debt thresholds in our partnership agreement
puts us at a significant disadvantage compared to other bidders who do not have
similar constraints on the amount of indebtedness they may incur. Moreover, we
believe that publicly-traded master limited partnerships engaged in businesses
similar to ours typically are not restricted under their partnership agreements
in the amount of debt they may incur. Further, with respect to capital
improvement programs, the need for unitholder approval in order to incur debt
over the threshold may cause delays in implementing a program we believe will
enhance our transportation capabilities and provide immediate benefits to our
unitholders.
14
Although we will, of course, remain subject to the debt limitations
imposed by our lenders, the elimination of the debt limitations may result in
our incurring increased debt and related debt service costs, which could impair
ability to make distributions to unitholders. The elimination of the debt
limitations will also result in the advance of the date on which we must
guaranty APC Acquisition's debt under the $50.0 million credit facility, as
described above in the "Financing the Alaska Pipeline Acquisition--Wachovia Bank
Credit Facilities" section of Proposal I to the [______________] special meeting
date.
Federal Income Tax Consequences of the Proposed Amendments
At the time of the original issuance of the common units, and based
upon certain representations of our general partner, our counsel rendered its
opinion that, under then current law and regulations, we and our operating
partnership would be classified as partnerships for federal income tax purposes.
Counsel to our general partner has delivered its opinion that the proposed
amendments will not cause either us or our operating subsidiary to be treated as
an association taxable as a corporation for federal income tax purposes.
Amendments will not Affect Limited Liability of Unitholders
As required by Section 13.3 of our partnership agreement, we have
obtained an opinion of counsel that the proposed amendments will not affect the
limited liability of any unitholders under Delaware law.
Vote Required
The proposed amendments to our partnership agreement will be voted upon
as a single proposal. The proposal to adopt the amendments must be approved by
holders of not less than a majority of the outstanding common units, voting as a
separate class, and a majority of the outstanding subordinated units, voting as
a separate class. Our general partner, which owns all of our 1,641,026
subordinated units, intends to vote in favor of the proposal.
General Partner Recommendation
The managing board of our general partner unanimously recommends a vote
"FOR" approval of the proposal.
15
PROPOSAL III: LONG-TERM INCENTIVE PLAN
Description of the Plan
The managing board of our general partner has approved the Atlas
Pipeline Partners, L.P. Long-Term Incentive Plan for officers, employees and
non-employee managers of our general partner and officers and employees of our
general partner's affiliates, consultants and joint venture partners who perform
services for us or in furtherance of our business. In accordance with AMEX
rules, we are asking unitholders to approve the plan at the special meeting. We
believe that the proposed plan is in our best interest because it will enhance
our general partner's ability to attract and retain the services of individuals
who are essential for our growth and profitability and will give them a longer
term stake in our continued success. The form of the proposed plan is attached
as Appendix B. The statements made in this proxy statement with respect to the
proposed plan should be read in conjunction with, and are qualified in their
entirety by reference to, the full text of the plan.
The plan will be administered by our general partner's managing board
or by a committee appointed by the board, which will set the terms of awards
under it. Under the plan, the managing board may make awards of either phantom
units or options covering an aggregate of 435,000 common units.
o A phantom unit entitles the grantee to receive a common unit upon
the vesting of the phantom unit or, at the discretion of the
managing board, cash equivalent to the value of a common unit. In
addition, the managing board may grant a participant the right,
which we refer to as a DER, to receive cash per phantom unit in an
amount equal to, and at the same time as, the cash distributions
we make on a common unit during the period the phantom unit is
outstanding.
o An option entitles the grantee to purchase our common units at an
exercise price determined by the managing board, which may be less
than, equal to or more than the fair market value of our common
units on the date of grant. The managing board will also have
discretion to determine how the exercise price may be paid.
Each non-employee manager of our general partner will be awarded the lesser of
500 phantom units, with DERs, or that number of phantom units, with DERs, equal
to $15,000 divided by the then fair market value of a common unit for each year
of service on the managing board beginning when the plan is adopted by our
unitholders. Up to 10,000 phantom units may be awarded to non-employee managers.
On ____________, 200__, the closing price per common unit on the AMEX was
$________.
Except for phantom units awarded to non-employee managers of our
general partner, the managing board will determine the vesting period for
phantom units and the exercise period for options. Phantom units awarded to
non-employee managers will vest over a 4-year period at the rate of 25% per
year. Both types of awards will automatically vest upon a change of control,
defined as follows:
16
o Atlas Pipeline GP (or an affiliate of Resource America) ceasing to
be our general partner;
o a merger, consolidation, share exchange, division or other
reorganization or transaction of us, Atlas Pipeline GP or a direct
or indirect parent of Atlas Pipeline GP with any entity, other
than a transaction which would result in the voting securities of
the us, Atlas Pipeline GP or the parent, as appropriate,
outstanding immediately prior thereto continuing to represent
(either by remaining outstanding or by being converted into voting
securities of the surviving entity) at least 60% of the combined
voting power immediately after such transaction of the surviving
entity's outstanding securities or, in the case of a division, the
outstanding securities of each entity resulting from the division;
o the equity holders of us or a direct or indirect parent of Atlas
Pipeline GP approve a plan of complete, liquidation or winding-up
or an agreement for the sale or disposition (in one transaction or
a series of transactions) of all or substantially all of the our
or such parent's assets; or
during any period of 24 consecutive months, individuals who at the
beginning of such period constituted the board of directors of Atlas
Pipeline GP or a direct or indirect parent of Atlas Pipeline GP
(including for this purpose any new director whose election or
nomination for election or appointment was approved by a vote of at
least 2/3 of the directors then still in office who were directors at
the beginning of such period) cease for any reason to constitute at
least a majority of the board or, in the case of a spin off of the
parent, if Edward E. Cohen and Jonathan Z. Cohen cease to be directors
of the parent.
If a grantee terminates employment, the grantee's award will be
automatically forfeited unless the managing board provides otherwise. However,
the award will automatically vest if the reason for the termination is the
participant's death or disability.
Common units to be delivered upon vesting of phantom units or upon
exercise of options may be newly issued units, units acquired in the open market
or from any of our affiliates, or any combination of these sources at the
discretion of the managing board. If we issue new common units upon vesting of
the phantom units or upon the exercise of options, the total number of common
units outstanding will increase. We intend to file a registration statement with
the SEC in order to permit participants to publicly re-sell any common units
received by them under the plan.
The managing board may terminate the plan at any time with respect to
any of the common units for which it has not made a grant. In addition, the
managing board will have the right to amend the plan from time to time,
including, subject to applicable law or the rules of the principal securities
exchange on which our common units are traded, increasing the number of common
units with respect to which it may grant awards, provided that, without the
participant's consent, no change may be made in any outstanding grant that would
materially impair the rights of the participant. AMEX rules would require us to
obtain unitholder approval for all material amendments to the plan, including
amendments to increase the number of common units issuable under the plan.
17
As of the date of this proxy statement, approximately 3 non-employee
managers and 9 officers of our general partner, and approximately 50 employees
of its affiliates, would be eligible to participate in the plan.
Income Tax Treatment
The Long-Term Incentive Plan is not eligible for treatment as a
qualified plan under the Internal Revenue Code. Therefore, all options granted
pursuant to the plan will be non-qualified options. A grantee will recognize
ordinary compensation income when a phantom unit vests, in an amount equal to
the fair market value of the underlying common unit. A grantee will not
recognize income at the time of the grant of an option or a phantom unit. Upon
exercise of an option, the grantee will recognize ordinary compensation income
equal to the difference, if any, between the option price paid and the fair
market value, as of the date of the option exercise, of the common units
purchased. The tax basis to a grantee of common units obtained by the exercise
of an option equals the option price paid plus ordinary compensation income
recognized. The grantee's capital holding period for the common units acquired
begins on the option exercise date.
We will generally be entitled to a federal income tax deduction in
connection with the grant of a phantom unit, at the time a grantee receives a
common unit in exchange for the phantom unit, in an amount equal to the fair
market value of the common unit at the time of vesting. We will generally be
entitled to an income tax deduction upon exercise of an option in an amount
equal to the ordinary or compensation income recognized by the grantee.
Vote Required
The proposal to adopt the Long-Term Incentive Plan must be approved by
a majority of the aggregate outstanding common units and subordinated units. Our
general partner intends to vote all of the subordinated units in favor of the
proposal.
General Partner Recommendation
The managing board of our general partner unanimously recommends a vote
"FOR" approval of the proposal.
OUR SELECTED FINANCIAL INFORMATION
The selected financial data set forth below as of and for the three
years ended December 31, 2002, 2001 and 2000 have been derived from our
financial statements for those periods, which have been audited by Grant
Thornton LLP, independent accountants. The selected financial data set forth
below as of and for the periods ended September 30, 2003 and 2002 have been
derived from our unaudited financial statements for those periods incorporated
by reference in this proxy statement. You should read the selected financial
data in this table together with, and such financial data is qualified by
reference to, our financial statements, the notes to our financial statements
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations" incorporated by reference in this proxy statement.
18
Period from
Nine months ended September 30, Years ended December 31, inception through
------------------------------- --------------------------- December 31,
2003 2002 2002 2001 2000
(unaudited) (unaudited)
------------ ----------- ---------- ---------- ----------
Revenues:
Transportation and compression... $ 11,816 $ 7,857 $ 10,660 $ 13,095 $ 9,441
Depreciation and amortization.... 61 6 7 35 25
---------- -------- ---------- ---------- ----------
Total revenues................. 11,877 7,863 10,667 13,130 9,466
---------- -------- ---------- ---------- ----------
Costs and expenses:
Transportation and compression... 1,831 1,481 2,062 1,929 1,224
General and administrative....... 1,301 1,158 1,482 1,113 589
Depreciation and amortization.... 1,266 1,084 1,475 1,356 1,020
Interest......................... 212 140 250 176 8
---------- -------- ---------- ---------- ----------
Total costs and expenses....... 4,610 3,863 5,269 4,574 2,841
Net income.......................... $ 7,267 $ 4,000 $ 5,398 $ 8,556 $ 6,625
========== ======== ========== ========== ==========
Net income - limited partners....... $ 6,611 $ 3,725 $ 5,022 $ 7,499 $ 6,492
========== ======== ========== ========== ==========
Net income - general partner........ $ 656 $ 275 $ 376 $ 1,057 $ 133
========== ======== ========== ========== ==========
Basic and diluted net income per
limited partner unit............. $ 1.72 $ 1.14 $ 1.54 $ 2.30 $ 2.07
========== ======== ========== ========== ==========
Weighted average limited partner
units outstanding................ $ 3,854 $ 3,262 $ 3,262 $ 3,255 $ 3,141
========== ======== ========== ========== ==========
Cash distributions per common unit.. $ 1.76 $ 1.60 $ 2.14 $ 2.50 $ 1.84
========== ======== ========== ========== ==========
September 30, December 31,
--------------------------- ---------------------------------------------
2003 2002 2002 2001 2000
----------- --------- --------- ----------- -----------
Balance sheet data:
Total assets..................... $ 50,832 $ 27,983 $ 28,515 $ 26,002 $ 22,092
Long-term debt................... - 5,605 6,500 2,089 -
Common unitholders' capital...... 43,976 19,394 19,164 20,129 18,122
Subordinated unitholder capital.. 611 918 684 1,661 2,074
General partner's capital........ 359 (150) (161) (116) (89)
---------- -------- ---------- ---------- -----------
Total capital.................. $ 44,946 $ 20,162 $ 19,687 $ 21,674 $ 20,107
========== ======== ========== ========== ==========
19
ALASKA PIPELINE SELECTED FINANCIAL INFORMATION
The selected financial data set forth below as of and for the three
years ended December 31, 2002, 2001 and 2000 have been derived from Alaska
Pipeline's financial statements for those periods, which have been audited by
Grant Thornton LLP, independent accountants. The selected financial data set
forth below as of and for the periods ended September 30, 2003 and 2002 have
been derived from Alaska Pipeline's unaudited financial statements for those
periods included in this proxy statement. You should read the selected financial
data in this table together with, and such financial data is qualified by
reference to, Alaska Pipeline's financial statements, the notes to financial
statements and "Alaska Pipeline Management's Discussion and Analysis of
Financial Condition and Results of Operations" included in this proxy statement.
Nine months ended September 30, Years ended December 31,
------------------------------- ----------------------------------------------
2003 2002
(unaudited) (unaudited) 2002 2001 2000
---------- ---------- ---------- --------- ----------
Revenues:
Gas sales and transportation..... $ 43,098 $ 47,381 $ 67,853 $ 69,083 $ 50,330
Pipeline management services..... 2,352 320 562 - -
---------- ---------- ---------- --------- ----------
Total revenues................. 45,450 47,701 68,415 69,083 50,330
---------- ---------- ---------- --------- ----------
Costs and expenses:
Costs of gas sold................ 35,467 39,087 56,149 56,620 38,223
Operations and maintenance....... 983 955 1,273 1,233 1,155
General and administrative....... 5,278 2,914 3,808 3,105 3,278
Depreciation and amortization.... 2,452 2,514 3,349 4,591 4,744
---------- ---------- ---------- --------- ----------
Total costs and expenses....... 44,180 45,470 64,579 65,549 47,400
---------- ---------- ---------- --------- ----------
Operating income.................... 1,270 2,231 3,836 3,534 2,930
Other income (deductions)
Interest expense................. (2,173) (2,260) (3,013) (3,587) (5,059)
Amortization of debt expense..... (31) - (45) (55) (243)
Other............................ 263 3 4 26 23
---------- ---------- ---------- --------- ----------
(1,941) (2,257) (3,054) (3,616) (5,279)
Income (loss) before income taxes .. (671) (26) 782 (82) (2,349)
Provision (benefit) for income
taxes............................ (283) (7) 314 30 (966)
---------- ---------- ---------- --------- ----------
Net income (loss).............. $ (388) $ (19) $ 468 $ (112) $ (1,383)
========== ========== ========== ========= ==========
Cash flow data:
Cash (used in) provided by
operating activities........... $ (2,574) $ (3,622) $ 4,081 $ 10,387 $ 5,069
Cash flow used in investing
activities..................... $ (342) $ (282) $ (554) $ (989) $ (1,514)
Cash flow provided by (used in)
financing activities........... $ 2,816 $ 4,207 $ (3,428) $ (9,398) $ (3,662)
September 30, December 31,
--------------------------- ----------------------------------------------
2003 2002 2002 2001 2000
---------- ---------- ---------- --------- -----------
Balance sheet data:
Total assets..................... $ 96,297 $ 95,214 $ 100,871 $ 100,005 $ 110,229
Long-term debt................... $ 35,900 $ 35,900 $ 35,900 $ 35,900 $ 51,900
Stockholder's equity............. $ 51,469 $ 51,369 $ 51,857 $ 51,389 $ 51,501
20
UNAUDITED PRO FORMA FINANCIAL INFORMATION
Following are our unaudited pro forma financial statements as of and
for the nine months ended September 30, 2003 and for the year ended December 31,
2002. The unaudited pro forma balance sheet is prepared as though the
acquisition of Alaska Pipeline described in this proxy statement occurred as of
September 30, 2003, and the unaudited pro forma statements of operations are
prepared as though the acquisition occurred as of January 1, 2002. The
acquisition and offering 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 and Alaska Pipeline's
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and historical financial statements and related notes included
elsewhere, or incorporated by reference, in this proxy statement.
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.
21
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA BALANCE SHEET (UNAUDITED)
SEPTEMBER 30, 2003
Historical Historical Acquisition Pro forma Offering Pro forma
APL APC adjustments consolidated adjustment consolidated
---------- ---------- ----------- ------------ ---------- ------------
ASSETS
Current assets:
Cash and cash
equivalents........... $ 20,098 $ - $ - $ 20,098 $ 12,545 (k) $ 32,643
Accounts receivable..... - 388 (388) (a) - - -
Accounts receivable -
affiliates............ - 3,530 (3,530) (a) - - -
Prepaid expenses........ 81 170 (170) (a) 81 - 81
---------- ---------- ----------- ------------ ---------- ------------
Total current assets.. 20,179 4,088 (4,088) 20,179 12,545 32,724
Property and equipment:
Gas gathering and
transmission
facilities............ 33,527 58,677 37,096 (b) 129,300 - 129,300
Less - accumulated
depreciation.......... (6,885) (13,216) 13,216 (b) (6,885) - (6,885)
---------- ---------- ----------- ------------ ---------- ------------
Net property and
equipment........... 26,642 45,461 50,312 122,415 - 122,415
Goodwill .................. 2,305 46,472 (46,472) (a) 2,305 - 2,305
Other assets............... 1,707 276 3,306 (a)(b)(c) 5,289 - 5,289
---------- ---------- ----------- ------------ ---------- ------------
$ 50,833 $ 96,297 $ 3,058 $ 150,188 $ 12,545 $ 162,733
========== ========== =========== ============ ========== ============
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and
accrued liabilities... 973 3,488 (3,488) (a) 973 - 973
Accounts payable -
affiliates............ 1,885 - 4,355 (a)(b)(c) 6,240 (4,355) (k) 1,885
Distribution payable.... 3,029 - - 3,029 - 3,029
---------- ---------- ----------- ------------ ---------- ------------
Total current
liabilities......... 5,887 3,488 867 10,242 (4,355) 5,887
Long-term debt............. - 35,900 34,100 (a)(b) 70,000 (30,000) (k) 40,000
Deferred income taxes...... - 5,440 (5,440) (a) - - -
Preferred equity
subject to
redemption.............. - - 25,000 (b) 25,000 (25,000) (k) -
Stockholder's equity....... - 51,469 (51,469) (a) - - -
Members' equity............ - - - (a)(b) - - -
Partners' capital (deficit):
Common unitholders...... 43,976 - - 43,976 70,467 (k) 114,443
Subordinated
unitholders........... 611 - - 611 - 611
General partner......... 359 - - 359 1,433 (k) 1,792
---------- ---------- ----------- ------------ ---------- ------------
Total partners'
capital............. 44,946 - - 44,946 71,900 116,846
---------- ---------- ----------- ------------ ---------- ------------
$ 50,833 $ 96,297 $ 3,058 $ 150,188 $ 12,545 $ 162,733
========== ========== =========== ============ ========== ============
See notes to pro forma financial statements
22
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA STATEMENT OF OPERATIONS (UNAUDITED)
FOR THE YEAR ENDED DECEMBER 31, 2002
(in thousands, except per unit data)
Historical Historical Acquisition Pro forma Offering Pro forma
APL APC adjustments consolidated adjustment consolidated
---------- ---------- ----------- ------------ ---------- ------------
Revenues:
Transportation and
compression........... $ 10,660 $ 67,853 $ (52,982) (d) $ 25,531 $ - $ 25,531
Pipeline management
services.............. - 562 (562) (d) - - -
---------- ---------- ----------- ------------ ---------- ------------
10,660 68,415 (53,544) 25,531 - 25,531
Costs and expenses:
Transportation and
compression........... 2,062 - - 2,062 - 2,062
Cost of gas sold........ - 56,149 (56,149) (d) - - -
General and
administrative........ 1,482 3,808 (2,337) (e) 2,953 - 2,953
Operations and
maintenance ......... - 1,273 1,264 (e) 2,537 - 2,537
Depreciation and
amortization ......... 1,475 3,349 (377) (g)(h) 4,447 - 4,447
---------- ---------- ----------- ------------ ---------- ------------
5,019 64,579 (57,599) 11,999 - 11,999
---------- ---------- ----------- ------------ ---------- ------------
Operating income........ 5,641 3,836 4,055 13,532 - 13,532
---------- ---------- ----------- ------------ ---------- ------------
Other income
(deductions):
Interest expense...... (250) (3,058) (5,069) (f)(i) (8,377) 3,983 (l) (4,394)
Other................. 7 4 (4) (d) 7 - 7
---------- ---------- ----------- ------------ ---------- ------------
(243) (3,054) (5,073) (8,370) 3,983 (4,387)
---------- ---------- ----------- ------------ ---------- ------------
Income (loss) before
Income taxes............ 5,398 782 (1,018) 5,162 3,983 9,145
Provision for income taxes. - 314 (314) (j) - - -
---------- ---------- ----------- ------------ ---------- ------------
Net income.............. $ 5,398 $ 468 $ (704) $ 5,162 $ 3,983 $ 9,145
---------- ---------- ----------- ------------ ---------- ------------
Net income - limited
partners................ $ 5,022 $ - $ - $ 3,773 $ - $ 7,944
========== ========== =========== ============ ========== ============
Net income - general
partner................. $ 376 $ - $ - $ 1,389 $ - $ 1,201
========== ========== =========== ============ ========== ============
Basic and diluted net
income per limited
partner unit........... $ 1.54 $ - $ - $ 1.16 $ - $ 1.51
========== ========== =========== ============ ========== ============
Weighted average units
outstanding............. $ 3,262 $ - $ - $ 3,262 $ - $ 5,262
========== ========== =========== ============ ========== ============
Per unit distributions -
limited partner unit.... $ 2.14 $ - $ - $ 2.64 (m) $ - $ 2.43(m)
========== ========== =========== ============ ========== ============
See notes to pro forma financial statements
23
ATLAS PIPELINE PARTNERS, L.P.
PRO FORMA STATEMENT OF OPERATIONS (UNAUDITED)
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003
(in thousands, except per unit data)
Historical Historical Acquisition Pro forma Offering Pro forma
APL APC adjustments consolidated adjustment consolidated
---------- ---------- ----------- ------------ ---------- ------------
Revenues:
Transportation and
compression........... $ 11,816 $ 43,098 $ (31,671) (d) $ 23,243 $ - $ 23,243
Pipeline
management
services.............. - 2,352 (2,352) (d) - - -
---------- ---------- ----------- ------------ ---------- ------------
11,816 45,450 (34,023) 23,243 - 23,243
Costs and expenses:
Transportation and
compression........... 1,831 - - 1,831 - 1,831
Cost of gas sold........ - 35,467 (35,467) (d) - - -
General and
administrative........ 1,301 5,278 (4,175) (e) 2,404 - 2,404
Operations and
maintenance........... 983 920 (e) 1,903 - 1,903
Depreciation and
amortization.......... 1,266 2,452 (223) (g) 3,495 - 3,495
---------- ---------- ----------- ------------ ---------- ------------
4,398 44,180 (38,945) 9,633 - 9,633
---------- ---------- ----------- ------------ ---------- ------------
Operating income........ 7,418 1,270 4,922 13,610 - 13,610
---------- ---------- ----------- ------------ ---------- ------------
Other income
(deductions):
Interest expense...... (212) (2,204) (3,524) (f)(i) (5,940) 2,694 (l) (3,246)
Other................. 61 263 (263) (d) 61 - 61
---------- ---------- ----------- ------------ ---------- ------------
(151) (1,941) (3,787) (5,879) 2,694 (3,185)
---------- ---------- ----------- ------------ ---------- ------------
Income (loss) before
income taxes............ 7,267 (671) 1,135 7,731 2,694 10,425
Provision for income
taxes .................. - (283) 283 (j) - - -
---------- ---------- ----------- ------------ ---------- ------------
Net income.............. $ 7,267 $ (388) $ 852 $ 7,731 $ 2,694 $ 10,425
========== ========== =========== ============ ========== ============
Net income - limited
partners................ $ 6,611 $ - $ - $ 4,692 $ - $ 7,672
========== ---------- ----------- ============ ---------- ============
Net income - general
partner................. $ 656 $ - $ - $ 3,039 $ - $ 2,753
========== ---------- ----------- ============ ---------- ============
Basic and diluted net
income per limited
partner unit........... $ 1.72 $ - $ - $ 1.22 $ - $ 1.31
========== ---------- ----------- ============ ---------- ============
Weighted average units
outstanding............. $ 3,854 $ - $ - $ 3,854 $ - $ 5,854
========== ---------- ----------- ============ ---------- ============
Per unit distributions -
limited partner......... $ 1.76 $ - $ - $ 2.43 (m) $ - $ 2.11(m)
========== ---------- ----------- ============ ---------- ============
See notes to pro forma financial statements
24
Atlas Pipeline Partners, L.P.
Notes to Unaudited Pro Forma Financial Statements
A. Immediately prior to the closing, Alaska Pipeline Company ("APC") 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 Energy, Inc.
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
$700,000 for the tower license and gas control services fees. The
acquisition will be financed by a $25.0 million preferred equity
mezzanine investment, a $50.0 million revolving credit facility and
$20.0 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 in connection with the acquisition
and the elimination of APC's pipeline management services and other
income. The adjustment also reflects the elimination of APC's cost of
gas sold. The revenue APC 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 APC 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 in connection with the acquisition.
F. Reflects the adjustment to interest expense resulting from the $25.0
million preferred equity (treated as debt for financial reporting
purposes) bearing a fixed interest rate of 12%, the $50.0 million of
new borrowings bearing an interest rate of LIBOR plus 350 basis points,
assumed to be 5.37% for the six months ended June 30, 2002, 5.39% for
the six months ended December 31, 2002, 4.82% for the six months ended
June 30, 2003 and 4.55% for the three months ended September 30, 2003.
The additional borrowings under our existing credit facility and
inter-company line with our parent bear an interest rate of LIBOR plus
200 basis points, assumed to be 3.87% for the six months ended June 30,
2002, 3.89% for the six months ended December 31, 2002, 3.32% for the
six months ended June 30, 2003 and 3.05% for the three months ended
September 30, 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.
25
H. Reflects the amortization of the gas control services fee 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 APC to LLC and its acquisition by us, a master
limited partnership not subject to income taxes.
K. To reflect net proceeds of $71.0 million after offering costs of $4.9
million from the issuance of 2.0 million common units at a price of
$37.95 per unit used to repay the $25.5 million preferred equity
mezzanine investment including a 2% purchase premium, the $20.0 million
of bank borrowings under our credit facility, $10.0 million of the
acquisition credit facility and $4.4 million of borrowings from our
parent. The remaining funds appear as an increase to cash. The
adjustment also reflects a 2% capital contribution from our general
partner in accordance with the terms of our partnership agreement.
L. Reflects the adjustment to interest expense resulting from the issuance
of new common units and the repayment of debt provided to finance the
acquisition.
M. Reflects the impact to limited partner distributions from adjusting our
distributable cash flow.
ALASKA PIPELINE MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
Historically, Alaska Pipeline's operations have consisted of three
related activities:
o The transportation of natural gas from producers in the Cook
Inlet area of south-central Alaska to Alaska Pipeline's
affiliate, ENSTAR Natural Gas Company, the gas distribution
utility serving Anchorage, Alaska, and to other industrial and
commercial users in the Anchorage area.
o The purchase of the natural gas Alaska Pipeline transports
from producers and its resale to ENSTAR.
o Since April 2002, the provision of pipeline management
services to third parties.
Alaska Pipeline's transportation and gas purchase and sale operations
are subject to regulation by the Regulatory Commission of Alaska, which we refer
to as the RCA. The RCA has jurisdiction over rates for natural gas
transportation and sales, construction of new facilities, pipeline extensions,
abandonment of services and related matters. Historically, Alaska Pipeline has
been regulated in combination with ENSTAR as a single entity. Rates and charges
established by the RCA are generally designed to permit the recovery of the cost
of providing a service and a return on investment.
26
On September 16, 2003, Alaska Pipeline's parent, SEMCO Energy, Inc.,
which we refer to as SEMCO, agreed to sell its equity interest in Alaska
Pipeline to Atlas Pipeline. Under the terms of the transaction, Alaska Pipeline
will continue to transport natural gas from producers to ENSTAR, but will no
longer purchase natural gas from producers and resell it to ENSTAR nor provide
pipeline management services. In addition, following approval of the terms of
the transaction by the RCA and Alaska Pipeline's acquisition by Atlas Pipeline,
Alaska Pipeline's financial performance will be governed by three principal
agreements with ENSTAR and SEMCO, as follows:
o Revenues will be governed by both a Special Contract for Gas
Transportation with ENSTAR and a Gas Transmission Agreement with
SEMCO:
o Under the Special Contract for Gas Transportation, ENSTAR will
pay Alaska Pipeline a monthly capacity reservation fee of
$943,000 plus $.075 per mcf of natural gas transported. During
2002, Alaska Pipeline transported an average of 130,000 mcf
per day.
o Under the Gas Transmission Agreement, if the RCA approves
rates and charges for Alaska Pipeline that are less than
those called for under the Special Contract for Gas
Transportation, SEMCO will pay Alaska Pipeline the
difference.
o Expenses, to a significant extent, will be affected by the
Operation and Maintenance and Administrative Services Agreement
under which ENSTAR will operate and maintain Alaska Pipeline's
pipeline system for at least five years. Alaska Pipeline will pay
ENSTAR $334,000 per month for its services, subject to an
inflation-based adjustment in the fourth and fifth contract years.
This fee includes normal maintenance expenditures, but excludes
expenditures that are capitalized costs.
Since its acquisition by SEMCO in 1999, Alaska Pipeline has generated
its cash resources from operations. It has typically used its cash to fund
working capital deficits, maintenance costs and long-term capital expenditures.
In addition, because SEMCO allocated to Alaska Pipeline a portion of the
borrowings SEMCO used to acquire it in 1999, cash has also been used to pay debt
service. Alaska Pipeline will have no obligation for SEMCO's borrowings
following its acquisition by Atlas Pipeline.
As a result of Alaska Pipeline's post-acquisition concentration on
natural gas transportation, the post-acquisition agreements with ENSTAR and
SEMCO, and the release of Alaska Pipeline from its obligations with respect to
SEMCO's borrowings, Alaska Pipeline believes that its historical financial
condition and results of operations, which are discussed in the remainder of
this section, will not be indicative of its post-acquisition financial
performance. For financial data for Alaska Pipeline for the nine months ended
September 30, 2003 and the year ended December 31, 2002, as adjusted to give
effect to its acquisition by us as if the acquisition had occurred on the dates
indicated, see "Unaudited Pro Forma Financial Information."
27
General
Revenues. ENSTAR is Alaska Pipeline's only gas transportation customer
and, as a result, the sole source of its gas sale and transportation revenues.
Alaska Pipeline recognizes gas sales and transportation revenue at the time the
natural gas it purchases for sale to ENSTAR is transported through Alaska
Pipeline's system to ENSTAR's system. Alaska Pipeline has earned revenue from
ENSTAR under an intercompany gas sales agreement that compensates Alaska
Pipeline for the cost and transportation of the purchased gas. This agreement
will be terminated upon completion of Alaska Pipeline's acquisition by Atlas
Pipeline. Under the terms of the current agreement, Alaska Pipeline earns
revenue only on the volume of gas sold to ENSTAR and, as a result, Alaska
Pipeline is not compensated for volumes transported to ENSTAR's system that do
not involve a sale of gas directly to ENSTAR. These volumes have been
transported principally for sale by ENSTAR to two industrial customers and one
electric utility. Following Alaska Pipeline's acquisition by Atlas Pipeline, all
of the gas Alaska Pipeline transports will be subject to the transportation and
transmission agreements with ENSTAR and SEMCO referred to in "-Overview," above.
Because Alaska Pipeline and ENSTAR are viewed as one entity by the RCA for
purposes of rate making, regulatory review of the revenue from ENSTAR to
compensate Alaska Pipeline for transportation service has not been necessary.
Alaska Pipeline also receives revenues from its pipeline services
subsidiary, NORSTAR, which began business in April 2002. NORSTAR generates all
its revenue from unaffiliated customers. Under the terms of Alaska Pipeline's
acquisition by Atlas Pipeline, ENSTAR will retain NORSTAR.
Costs and Expenses. Alaska Pipeline's principal expenses have been the
cost of the natural gas it purchases and, since the formation of NORSTAR, the
cost of producing its pipeline services. Alaska Pipeline has gas purchase
contracts with several entities, which are all approved by the RCA. The price of
gas Alaska Pipeline purchases under these contracts is adjusted annually based
on factors such as the price of certain traded oil futures, certain natural gas
futures and other inflationary measures. ENSTAR will assume these contracts
following Atlas Pipeline's acquisition of Alaska Pipeline, and Alaska Pipeline
will have no further obligations under them.
Seasonality. Alaska Pipeline's business is seasonal in nature; it
depends on the winter months for the majority of its operating revenue. As a
result, a substantial portion of Alaska Pipeline's annual income is earned
during the first and fourth quarters of the year. Therefore, the results of
operations for the nine months ended September 30, 2003 and 2002 are not
necessarily indicative of results for a full year.
Growth of Customer Base. ENSTAR and, as a result, Alaska Pipeline, are
affected by the number of residential, commercial, industrial and electric
utility customers served by ENSTAR. Since 1990, the Anchorage area has
experienced an average annual population growth of 1.6%. Alaska Pipeline
believes that this growth will positively affect ENSTAR's gas demand and,
consequently, the volume of gas Alaska Pipeline transports for ENSTAR and the
revenue Alaska Pipeline can earn.
28
Results of Operations
--------------------------------------------------- -------------------------------- ---------------------------------------------
Nine months ended Years ended
September 30, December 30,
-------------------------------- ---------------------------------------------
--------------------------------------------------- -------------- ----------------- -------------- --------------- --------------
2003 2002 2002 2001 2000
------------ ------------ ------------ ------------ ------------
--------------------------------------------------- -------------- ----------------- -------------- --------------- --------------
--------------------------------------------------- -------------- ----------------- -------------- --------------- --------------
Gas sales and transportation revenues................ $43,097,681 $47,381,481 $67,852,910 $69,083,247 $50,330,051
--------------------------------------------------- -------------- ----------------- -------------- --------------- --------------
Average daily throughput volumes (mcf) (1)........... 144,309 129,927 130,495 129,141 128,841
--------------------------------------------------- -------------- ----------------- -------------- --------------- --------------
Percent colder (warmer) than normal (2) ............. (10.5%) (0.7%) (7.8%) (3.0%) (5.4%)
--------------------------------------------------- -------------- ----------------- -------------- --------------- --------------
Number of degree days (2) ........................... 5,811 6,492 9,392 10,033 9,753
-------------------------- ------------------------ -------------- ----------------- -------------- --------------- --------------
(1) Includes fuel used in operations and unaccounted line loss, both of which
were allocated to ENSTAR.
(2) Alaska Pipeline determines the percent that weather is warmer or colder
than normal for a particular period by computing the deviation of actual
degree days for that period from the average of degree days during the same
periods in the prior 15 years and dividing the deviation by such 15-year
average. Degree days are a measure of coldness determined daily as the
number of degrees the average temperature during the day in question is
below 65 degrees Fahrenheit. Degree days for a particular period are
determined by adding the degree days incurred during each day of that
period.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30,
2002
Alaska Pipeline's gas sales and transportation revenue decreased to
$43,097,681 in the nine months ended September 30, 2003 from $47,381,481 in the
nine months ended September 30, 2002. The decrease of $4,283,800 (9.0%) resulted
primarily from a decrease in the volume of gas sales to ENSTAR as a result of
warmer temperatures during the nine months ended September 30, 2003, compared to
the nine months ended September 30, 2002, and a $0.07 per mcf decrease in the
average cost of gas purchased by Alaska Pipeline and passed through to ENSTAR.
Total volumes transported increased, however, due to increased usage by the
industrial and electric utility customers referred to in "--General--Revenues,"
above.
Alaska Pipeline's NORSTAR subsidiary had pipeline management service
revenue of $2,352,365 for the nine months ended September 30, 2003, compared to
$319,598 for the nine months ended September 30, 2002. The increase was
principally because NORSTAR had a full nine months of operations in the 2003
period as compared to five months operations in the prior year period following
its commencement of operations in April 2002. NORSTAR's revenues were
substantially offset by its costs in providing service, referred to in "--Cost
and Expenses," below.
Costs and Expenses. Alaska Pipeline's cost of gas sold decreased to
$35,466,112 in the nine months ended September 30, 2003 as compared to
$39,086,921 in the nine months ended September 30, 2002, a decrease of
$3,620,809 (9.3%). During the nine months ended September 30, 2003, Alaska
Pipeline purchased 14,577,450 mcf of gas at an average cost of $2.44 per mcf as
compared to 15,608,164 mcf purchased at an average cost of $2.52 per mcf during
the nine months ended September 30, 2002. The decrease in the cost of gas sold
was due primarily to a decrease in the oil futures index used to price the
natural gas Alaska Pipeline purchased under its RCA-approved gas supply
contracts.
29
Alaska Pipeline's operations and maintenance expense increased to
$982,803 in the nine months ended September 30, 2003, compared to $955,142 in
the prior year period. The increase of $27,661 (2.9%) was primarily due to
normal cost increases and increases in the level of its maintenance activities.
Alaska Pipeline's general and administrative expenses increased to
$5,278,201 in the nine months ended September 30, 2003, as compared to
$2,914,125 in the nine months ended September 30, 2002, an increase of
$2,364,076 (81.1%). However, $2,225,860 of the increase were expenses incurred
by NORSTAR, which relate to the pipeline management service revenue referred to
above. The remainder of the increase, $138,216, was due primarily to an increase
in insurance costs and property taxes.
Alaska Pipeline's depreciation expense decreased to $2,452,390 in the
nine months ended September 30, 2003 as compared to $2,514,239 in the nine
months ended September 30, 2002, a decrease of $61,849 (2.5%). This decrease was
primarily caused by certain assets reaching the end of their depreciable lives
and, to a lesser extent, the retirement of certain assets.
Alaska Pipeline's interest expense decreased to $2,172,848 in the nine
months ended September 30, 2003 as compared to $2,259,900 in the nine months
ended September 30, 2002. This decrease of $87,052 (3.9%) resulted from lower
interest rates on the $35.9 million of SEMCO's long-term debt allocated to
Alaska Pipeline, from which Alaska Pipeline will be released following its
acquisition by Atlas Pipeline. Alaska Pipeline's average interest rate for the
nine months ended September 30, 2003 was 8.07% as compared to an average rate of
8.39% during the comparable prior period.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Revenues. Alaska Pipeline's gas sales and transportation revenue
decreased to $67,852,910 in the year ended December 31, 2002 from $69,083,247 in
the year ended December 31, 2001. The decrease of $1,230,337 (1.8%) resulted
from a decrease in volumes of gas sold to ENSTAR due to warmer weather in Alaska
Pipeline's operating area reducing the heating demand for natural gas, partially
offset by increased demand due to ENSTAR's growing customer base, and a $0.09
per mcf increase in the average cost of gas Alaska Pipeline purchased and passed
through to ENSTAR. Volumes transported increased, however, due to increased
usage by the industrial and electric utility customers referred to in
"--General--Revenues," above.
In the year ended December 31, 2002, Alaska Pipeline's NORSTAR
subsidiary began operations and generated pipeline management service revenue of
$562,109. This revenue was more than offset by the costs of providing its
services, referred to in "--Cost and Expenses," below.
Costs and Expenses. Alaska Pipeline's cost of gas sold decreased to
$56,148,644 in the year ended December 31, 2002 as compared to $56,620,021 in
the year ended December 31, 2001, a decrease of $471,377 (0.8%). During the year
ended December 31, 2002, Alaska Pipeline purchased and sold 22,381,547 mcf of
gas at an average cost of $2.50 per mcf as compared to 23,226,437 mcf purchased
and sold at an average cost of $2.43 per mcf during the year ended December 31,
2001. The increase was due primarily to an increase in the oil futures index
used to price the natural gas Alaska Pipeline purchases under its RCA-approved
gas supply agreements.
30
Alaska Pipeline's operations and maintenance expense increased to
$1,273,348 in 2002 as compared to $1,232,789 in 2001. The increase of $40,557
(3.3%) was due to the increased cost of providing system maintenance and an
increased level of maintenance activity.
Alaska Pipeline's general and administrative expenses increased to
$3,808,055 in the year ended December 31, 2002 as compared to $3,105,009 in the
year ended December 31, 2001, an increase of $703,046 (22.6%). However, $589,961
of the increase were expenses incurred by NORSTAR which relate to the pipeline
management service revenue discussed above. The remainder of the increase,
$113,085, was due primarily to an increase in employee benefit costs.
Alaska Pipeline's depreciation and amortization expense decreased to
$3,349,051 in the year ended December 31, 2020 as compared to $4,591,050 in the
year ended December 31, 2001, a decrease of $1,241,999 (27.1%). This decrease
was primarily the result of ceasing the amortization of goodwill during the year
ended December 31, 2002 because of the adoption of SFAS No. 142 as further
discussed in Note 1 of the Notes to the Financial Statements.
Alaska Pipeline's interest expense decreased to $3,013,200 in the year
ended December 31, 2002 as compared to $3,586,510 in the year ended December 31,
2001. This decrease of $573,310 (16.0%) resulted from a reduction in average
long-term debt owed to SEMCO as a result of a $16.0 million paydown during 2001,
partially offset by an increase in interest rates on such debt. Alaska
Pipeline's average interest rate for the year ended December 31, 2002 was 8.39%
on an average outstanding debt balance of $35.9 million as compared to an
average rate of 8.17% on an average outstanding debt balance of $43.9 million
during the comparable prior period.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Revenues. Alaska Pipeline's gas sales and transportation revenue
increased to $69,083,247 in the year ended December 31, 2002 from $50,330,051 in
the year ended December 31, 2001. The increase of $18,753,196 (37.3%) was due
primarily to a $0.74 per mcf increase in the cost of gas Alaska Pipeline
purchased and passed through to ENSTAR and an increase in the volume of gas
sales to ENSTAR as a result of ENSTAR's growing customer base and slightly
colder temperatures.
Costs and Expenses. Alaska Pipeline's cost of gas sold increased to
$56,620,021 in the year ended December 31, 2001 as compared to $38,222,548 in
the year ended December 31, 2000, an increase of $18,397,473 (48.1%). During the
year ended December 31, 2001, Alaska Pipeline purchased and sold 23,226,437 mcf
of gas at an average cost of $2.43 per mcf as compared to 22,543,972 mcf
purchased and sold at an average cost of $1.69 per mcf during the year ended
December 31, 2000. The increase in the cost of gas sold was due primarily to an
increase in the oil futures index used to price the natural gas Alaska Pipeline
purchases under its RCA-approved gas supply agreements.
31
Alaska Pipeline's operations and maintenance expense increased to
$1,232,789 in 2001 as compared to $1,155,438 in 2000. The increase of $77,351
(6.7%) was primarily due to normal cost increases and an increase level of
system maintenance, oil recovery and system control activities.
Alaska Pipeline's general and administrative expenses decreased to
$3,105,009 in the year ended December 31, 2001 as compared to $3,278,097 in the
year ended December 31, 2000, a decrease of $173,088 (5.3%). This decrease was
due primarily to an increase in the level of general and administrative expenses
allocated to capital projects.
Alaska Pipeline's depreciation and amortization expense decreased to
$4,591,050 in the year ended December 31, 2001 as compared to $4,743,636 in the
year ended December 31, 2000, a decrease of $152,586 (3.2%). This decrease was
due primarily to certain assets reaching the end of their depreciable lives.
Alaska Pipeline's interest expenses decreased to $3,586,510 in the year
ended December 31, 2001 as compared to $5,058,543 in the year ended December 31,
2000. This decrease of $1,472,033 (29.1%) resulted from a reduction in average
long-term debt allocated to Alaska Pipeline following a $16.0 million paydown
during 2001 and a decrease in interest rates on such debt. Alaska Pipeline's
average interest rate for the year ended December 31, 2001 was a 8.17% on an
average outstanding debt balance of $43.9 million as compared to an average rate
of 9.75% on an average outstanding debt balance of $51.9 million during the
comparable prior period.
Liquidity and Capital Resources
Since its acquisition by SEMCO in 1999, Alaska Pipeline's principal
cash requirement, in addition to operating, maintenance and capital expenses,
has been payment of debt service on Alaska Pipeline's allocation of SEMCO's
acquisition debt. SEMCO will satisfy this debt from proceeds of Atlas Pipeline's
acquisition of Alaska Pipeline and, accordingly, Alaska Pipeline will have no
outstanding debt immediately following its acquisition by Atlas Pipeline.
Alaska Pipeline incurred capital expenditures of $654,740 in the nine
months ended September 30, 2003 and $553,805 in the year ended December 31,
2002, as compared to $282,428 in the nine months ended September 30, 2002, and
$989,108 and $1,513,756 in the years ended December 31, 2001 and 2000,
respectively. These capital expenditures generally consisted of maintenance,
upgrades and expansion of Alaska Pipeline's system. As of September 30, 2003,
Alaska Pipeline had no capital expense commitments; however, it anticipates an
expenditure of $5.2 million during the fourth quarter of 2004 or the first
quarter of 2005 for the replacement of a section of its system underneath the
Susitna River. Alaska Pipeline's capital expenditures could increase materially
if unforeseen or uninsured deterioration of its system occurs.
32
Inflation and Changes in Prices
Historically, inflation has affected Alaska Pipeline's operating
expenses. Increases in those expenses have not necessarily been offset by
increases in Alaska Pipeline's transportation fees although, due to relatively
moderate inflation rates generally experienced in its operating area, the effect
of inflation on Alaska Pipeline has not been material during the past three
years. Although Alaska Pipeline's operating cost structure is fixed for at least
the first three years following the Atlas Pipeline acquisition under its
agreement with ENSTAR, its capital expenditure costs and its costs of operation
once the ENSTAR agreement expires could be affected by inflation. Moreover,
ENSTAR's fee under the operation, maintenance and administrative services
agreement to be entered into with Alaska Pipeline provides for an
inflation-based adjustment in the fourth and fifth contract years. Alaska
Pipeline cannot predict the future effect that inflation may have on it. In
addition, the value of Alaska Pipeline's system has been and will continue to be
affected by changes in the demand and availability of natural gas in its
operating area which are subject to fluctuations which Alaska Pipeline is unable
to control or accurately predict.
Environmental Regulation
A continuing trend to greater environmental and safety awareness and
increasing environmental regulation has generally resulted in higher operating
costs for the oil and gas industry. Alaska Pipeline monitors environmental and
safety laws and believes it is in compliance with applicable environmental laws
and regulations. To date, compliance with environmental laws and regulations has
not had a material impact on Alaska Pipeline's capital expenditures, earnings or
competitive position. However, compliance with environmental laws and
regulations may, in the future, materially adversely affect Alaska Pipeline's
operations through increased costs of doing business or restrictions on the
manner in which Alaska Pipeline conducts its operations.
Contractual Obligations and Commercial Commitments
In addition to the allocation of the debt SEMCO incurred in acquiring
Alaska Pipeline, Alaska Pipeline currently has purchase obligations under its
gas supply contracts. As previously discussed, upon Atlas Pipeline's acquisition
of Alaska Pipeline, it will be released from the debt and ENSTAR will assume its
gas supply contracts. Post-acquisition, Alaska Pipeline's sole commitment will
be its five-year commitment to ENSTAR under the previously discussed operation,
maintenance and administrative services agreement. While ENSTAR is obligated to
provide any capital maintenance or expansion services requested by Alaska
Pipeline and will be reimbursed at ENSTAR's cost for those services, Alaska
Pipeline has the right to use other companies for those projects.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires Alaska
Pipeline 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 actual revenues
and expenses during the reporting period. Although Alaska Pipeline believes its
estimates are reasonable, actual results could differ from those estimates.
Alaska Pipeline has summarized its significant accounting policies in Note 2 to
its consolidated financial statements. The critical accounting policies and
estimates that it has identified are discussed below.
33
Revenue and Expenses
Alaska Pipeline routinely makes accruals for both revenues and expenses
due to the timing of receiving information from third parties and reconciling
its records with those of third parties. Alaska Pipeline has determined these
estimates using available market data and valuation methodologies. Alaska
Pipeline believes its estimates for these items are reasonable; however, actual
amounts may vary from estimated amounts.
Depreciation and Amortization
Alaska Pipeline calculates its depreciation based on the estimated
useful lives and salvage values of its assets. However, factors such as usage,
equipment failure, competition, regulation or environmental matters could cause
it to change its estimates, thus impacting the future calculation of
depreciation and amortization.
Impairment of Assets
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," whenever events or changes in circumstances
indicate that the carrying amount of long-lived assets may not be recoverable,
Alaska Pipeline determines if its long-lived assets are impaired by comparing
the carrying amount of an asset or group of assets with the estimated future
cash flows associated with such asset or group of assets. If the carrying amount
is greater than the estimated future cash flows, Alaska Pipeline recognizes an
impairment loss in the amount of the excess, if any, of carrying amount over the
fair value of the asset or group assets.
Goodwill
At September 30, 2003, Alaska Pipeline had $46.5 million of goodwill,
all of which relates to the acquisition of its pipeline assets on November 1,
1999, net of $2.7 million in accumulated amortization. In accordance with SFAS
No. 144, since January 1, 2002, Alaska Pipeline has not amortized its goodwill.
Alaska Pipeline tests its goodwill for impairment each year. Alaska Pipeline's
test during 2002 resulted in a determination that goodwill had not been
impaired. This goodwill will be extinguished upon acquisition by Atlas Pipeline.
Recently Issued Financial Accounting Standards
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS
143 requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long-lived asset. The adoption of
SFAS 143 as of January 1, 2003 did not have a material impact on Alaska
Pipeline's results of operations or financial position.
34
In April 2002, SFAS 145, "Rescission of FASB Statements No. 4, 44, and
64, Amendment of FASB Statement No. 13, and Technical Corrections" was issued.
SFAS 145 rescinds the automatic treatment of gains and losses from
extinguishments of debt as extraordinary unless they meet the criteria for
extraordinary items as outlined in Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations, Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." SFAS 145 also requires sale-leaseback accounting for
certain lease modifications that have economic effects similar to a
sale-leaseback transaction and makes various corrections to existing
pronouncements. The provisions of this statement are effective for financial
statements issued by us in 2003. The adoption of SFAS 145 as of January 1, 2003
did not have a material impact on Alaska Pipeline's results of operations or
financial position.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 addresses significant
issues relating to the recognition, measurement, and reporting of costs
associated with exit and disposal activities, including restructuring
activities, and nullifies the guidance in Emerging Issues Task Force Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." The provisions of this statement are effective for exit and
disposal activities that are initiated after December 31, 2002. The adoption of
SFAS 146 did not have a material impact on Alaska Pipeline's results of
operations or financial position.
Quantitative and Qualitative Disclosures About Market Risk
All of Alaska Pipeline's assets and liabilities are denominated in U.S.
dollars, and as a result, it does not have exposure to currency exchange risks.
Alaska Pipeline does not engage in any interest rate, foreign currency
exchange rate or commodity price-hedging transactions, and as a result, it does
not have exposure to derivatives risk.
Alaska Pipeline's major market risk exposure is in the volume of gas
that it transports. That volume is a function of the demand from ENSTAR's
residential, industrial and commercial customers. Additionally, availability of
gas from producers connected to Alaska Pipeline's system may, from time to time,
be a limiting factor in the amount of gas it transports. Alaska Pipeline's
revenue is ultimately dependent on the volume of gas it transports.
Market risk inherent in Alaska Pipeline's debt is the potential change
arising from increases or decreases in interest rates in the general market
place and the rates SEMCO, Alaska Pipeline's parent company, charges it. Changes
in interest rates usually do not affect the fair value of variable rate debt,
but may affect Alaska Pipeline's earnings and cash flows. At September 30, 2003,
Alaska Pipeline had $35.9 million in total debt outstanding, which bore interest
at an average effective rate of 6.05%. At September 30, 2003, the interest rate
was 8.07%. At September 30, 2003 and 2002, respectively, a hypothetical 10%
change in the average interest rate applicable to this debt would result in a
change of approximately $122,000 and $91,000 in Alaska Pipeline's annual net
income and would not affect the market value of this debt. Alaska Pipeline will
not be obligated on this debt following its acquisition by Atlas Pipeline.
35
THE SPECIAL MEETING
Location and Time
The special meeting of the unitholders of Atlas Pipeline Partners, L.P.
will be held at _____________________ Philadelphia, Pennsylvania, on
____________________ at 9:00 a.m., local time. We do not expect representatives
of our independent public accountants, Grant Thornton, LLP, to be present at the
meeting.
Outstanding Units
As of the record date, we had 2,713,659 common units outstanding, held
of record by approximately ___ persons, and 1,641,026 subordinated units held of
record by our general partner. Each record holder has one vote for each unit
held.
Voting of Proxies
You may vote in person at the special meeting or by proxy. To ensure
your representation at the meeting, we recommend you vote by proxy even if you
plan to attend the meeting. You can always change your vote at the meeting;
however, mere attendance at the meeting will not revoke your proxy.
Voting instructions are included on the proxy card. If you properly
give your proxy and submit it to us in time to vote, the persons named as your
proxies will vote your units as you have directed. You may vote for or against
the proposals set forth on the proxy card and described in this document or
abstain from voting. If you sign and return a proxy card but do not make a
specific choice as to how to vote, the persons named in the proxy will vote
"FOR" each of the proposals. Not returning a completed proxy card, or otherwise
abstaining, and broker non-votes will have the same effect as a vote against the
proposals.
Revocability of Proxies
You may revoke your proxy before it is voted by:
o submitting a new proxy with a later date,
o notifying the secretary of our general partner in writing before
the special meeting that you have revoked your proxy, or
o voting in person at the special meeting.
If you plan to attend the special meeting and wish to vote in person,
we will give you a ballot at the meeting.
36
Solicitation of Proxies
We may solicit proxies through managing board members or officers of
our general partner or its affiliates either personally, by letter or by
telephone. We will not compensate any of these persons specifically for
soliciting proxies. We have retained D.F. King & Co., Inc. to act as information
agent. The information agent may contact unitholders by mail, telephone and
personal interviews and may request brokers, dealers and other nominee
unitholders to forward materials relating to the offer to beneficial owners. We
will pay the information agent reasonable and customary compensation for its
services, reimburse it for reasonable out-of-pocket expenses and will indemnify
it against certain liabilities in connection with the proxy solicitation,
including liabilities under federal securities laws. We do not expect the cost
of the independent agent to exceed $35,000. We expect to reimburse banks,
brokers, and other persons for their reasonable out-of-pocket expenses in
handling proxy solicitation materials for beneficial owners of common units.
No Appraisal Rights
Common unitholders who object to the proposals will not have appraisal,
dissenters' or similar rights under Delaware law or our partnership agreement,
nor will such rights be voluntarily accorded to common unitholders by us. These
rights would permit a common unitholder to seek a judicial determination of the
fair value of his or her common units and to compel the purchase of his or her
common units for cash in that amount. If the proposals described in this proxy
statement are approved as described in this proxy statement, that approval will
be binding on all unitholders, and objecting common unitholders will have no
alternative other than selling their units if they dissent from them.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the number and percentage of common or
subordinated units beneficially owned, as of ______, 2003, by:
o each person who, to our knowledge, beneficially owns 5% or more of
either our common or subordinated units,
o each of the present managing board members of our general partner,
o each of the executive officers of our general partner, and
o all of the present executive officers and managing board members of
our general partner as a group.
The subordinated units listed opposite the name of each managing board member
and executive officer of our general partner represent subordinated units owned
by our general partner. By reason of their position as managing board members or
executive officers of our general partner, such persons may be deemed to have
shared voting and investment power over the subordinated units. The address of
our general partner, its executive officers and managing board members is 311
Rouser Road, Moon Township, Pennsylvania 15108.
37
Percentage of Subordinated Percentage of
common units units subordinated units
Common units beneficially beneficially beneficially
beneficially owned owned owned owned
------------------ ------------ ------------- ------------------
Name of beneficial owner
------------------------
Atlas Pipeline Partners GP - - 1,641,026 100%
Edward E. Cohen - - 1,641,026 100%
Steven J. Kessler - - 1,641,026 100%
Jonathan Z. Cohen 1,277 * 1,641,026 100%
Michael L. Staines - - 1,641,026 100%
William R. Bagnell - - 1,641,026 100%
Donald W. Delson - - 1,641,026 100%
Tony C. Banks - - 1,641,026 100%
Murray S. Levin - - 1,641,026 100%
Executive officers and managing
board members as a group (8 persons) 1,277 * 1,641,026 100%
---------------------------
* Less than 1%.
EXECUTIVE COMPENSATION
Executive Compensation
We do not directly compensate the executive officers of our general
partner. Rather, Resource America and its affiliates allocate the compensation
of the executive officers between activities on behalf of our general partner
and us and activities on behalf of itself and its affiliates based upon an
estimate of the time spent by such persons on activities for us and for Resource
America and its affiliates, and we reimburse our general partner for the
compensation allocated to us. The compensation allocation was $301,066 and
$299,821 for the years ended December 31, 2002 and 2001, respectively. The
following table sets forth the compensation allocation since we commenced
operations for our general partner's Chief Executive Officer and President. No
other executive officer of the general partner received an allocation of
aggregate salary and bonus in excess of $100,000 during the periods indicated.
Summary Compensation Table
-------------------------------------------------------------- ---------- ------------ ---------------------
-------------------------------------------------------------- ---------- ------------ ---------------------
Name and principal position Year Salary Bonus
--------------------------- ---- ---------- -----------------
-------------------------------------------------------------- ---------- ------------ ---------------------
Edward E. Cohen, Chairman of the Managing Board and 2002 $ 0 $ 0
Chief Executive Officer 2001 0 0
2000 0 0
-------------------------------------------------------------- ---------- ------------ ---------------------
Michael L. Staines, President, Chief Operating Officer and 2002 $ 169,979 $28,058
Managing Board Member
-------------------------------------------------------------- ---------- ------------ ---------------------
2001 193,500 0
-------------------------------------------------------------- ---------- ------------ ---------------------
2000 114,000 0
-------------------------------------------------------------- ---------- ------------ ---------------------
38
Compensation of Managing Board Members
Our general partner does not pay additional remuneration to officers or
employees of Resource America who also serve as managing board members. Each
non-employee managing board member receives an annual retainer of $6,000
together with $1,000 for each board meeting attended, $1,000 for each committee
meeting attended where he is chairman of the committee and $500 for each
committee meeting attended where he is not chairman. In addition, our general
partner reimburses each non-employee board member for out-of-pocket expenses in
connection with attending meetings of the board or committees. We reimburse our
general partner for these expenses and indemnify our general partner's managing
board members for actions associated with being managing board members to the
extent permitted under Delaware law.
Compensation Committee Interlocks and Insider Participation
Neither we nor the managing board of our general partner has a
compensation committee. Compensation of the personnel of Resource America and
its affiliates who provide us with services is set by Resource America and such
affiliates. The independent members of the managing board of our general
partner, however, do review the allocation of the salaries of such personnel for
purposes of reimbursement.
PERFORMANCE GRAPH
The following graph compares the cumulative total
unitholder return on our common units with the cumulative
total return of two other stock market indices: AMEX U.S.
and AMEX Natural Resources.
39
Comparison of cumulative total return since commence trading on January 28,
2000 including reinvestment of all distributions
[GRAPHIC OMITTED][GRAPHIC OMITTED]
UNITHOLDER PROPOSALS AT FUTURE MEETINGS
We do not hold annual or other regular meetings of unitholders. Special
meetings of unitholders may be called by our general partner or by limited
partners owning 20% or more of the outstanding limited partner interests.
Limited partner proposals to be presented at any future meeting of the limited
partners must be received by us at a reasonable time before our solicitation of
proxies for the meeting in order for such proposals to be considered for
inclusion in the proxy materials related to that meeting. Pursuant to Section
13.2 of our partnership agreement, amendments to our partnership agreement may
be proposed only by our general partner or with the consent of our general
partner, which consent may be given or withheld in our general partner's sole
discretion. Furthermore, limited partners are not permitted to vote on matters
that would cause the limited partners to be deemed to be taking part in the
management and control of our business and affairs so as to jeopardize the
limited partners' limited liability under Delaware law or the law of any other
state in which we are qualified to do business.
INCORPORATION OF 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 proxy statement.
We incorporate the following documents by reference in this proxy
statement:
o our Annual Report on Form 10-K for the fiscal year ended December
31, 2002;
40
o our Quarterly Reports on Form 10-Q for the three months ended March
31, 2003, June 30, 2003 and September 30, 2003; and
o our Current Report on Form 8-K filed on September 16, 2003.
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
We will respond to your request by mailing the requested materials by first
class mail within one business day.
WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and current reports, proxy statements and
other information with the SEC. You may read and copy any reports, statements or
other information that we file with the SEC at the SEC's public reference room
at 450 Fifth Street, N.W., Washington, D.C. 20549. You may request copies of
these documents, upon payment of a copying fee, by writing to the SEC. Please
call the SEC at 1-800-SEC-0330 for information on the operation of the public
reference room. Our SEC filings are also available to the public on the SEC
internet site at http://www.sec.gov.
Please direct questions and requests for assistance regarding this
proxy solicitation to:
D.F. King & Co., Inc.
77 Water Street
New York, New York 10005
Banks and brokers call collect: (212) 269-5550
All others call toll free: (800) 758-5880
41
APPENDIX A
ALASKA PIPELINE COMPANY FINANCIAL STATEMENTS
A-1
INDEX TO ALASKA PIPELINE COMPANY FINANCIAL STATEMENTS
Alaska Pipeline Company Consolidated Financial Statements:
Report of Independent Certified Public Accountants .................................. A-3
Consolidated Balance Sheets as of December 31, 2002 and 2001 ........................ A-4
Consolidated Statements of Operations for the years ended December 31,
2002, 2001 and 2000 ............................................................. A-5
Consolidated Statements of Shareholders' Equity for the years ended
December 31, 2002, 2001 and 2000 ................................................ A-6
Consolidated Statements of Cash Flows for the years ended December 31,
2002, 2001 and 2000 ............................................................. A-7
Notes to Consolidated Financial Statements........................................... A-8
Alaska Pipeline Company Unaudited Consolidated Financial Statements:
Introduction ........................................................................ A-18
Consolidated Balance Sheet as of September 30, 2003 and 2002 ........................ A-19
Consolidated Statements of Income for the nine months ended
September 30, 2003 and 2002 ..................................................... A-20
Consolidated Statements of Changes in Shareholders' Equity for the
nine months ended September 30, 2003 and 2002 ................................... A-21
Consolidated Statements of Cash Flows for the nine months ended
September 30, 2003 and 2002 ..................................................... A-22
A-2
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, 2002 and 2001, and the related
consolidated statements of income, shareholder's equity, and cash flows for each
of the three years in the period ended December 31, 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 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, 2002 and 2001, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2002 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
October 31, 2003
A-3
Alaska Pipeline Company
CONSOLIDATED BALANCE SHEETS
December 31,
---------------------------------
2002 2001
-------------- ----------
ASSETS
Current assets:
Cash............................................................ $ 99,407 $ -
Notes receivable - affiliates................................... 6,346,451 2,918,666
Accounts receivable - trade..................................... 203,019 -
Prepaid expenses................................................ 131,691 155,130
--------------- --------------
Total current assets...................................... 6,780,568 3,073,796
--------------- --------------
Property, plant and equipment:
Plant in service, at cost....................................... 58,152,685 57,598,880
Less - accumulated depreciation................................. 10,841,245 7,492,194
--------------- --------------
Net property and equipment................................ 47,311,440 50,106,686
--------------- --------------
Deferred charges and other assets:
Goodwill (net of accumulated amortization of $2,661,605)........ 46,472,348 46,472,348
Unamortized debt expense, net................................... 306,940 352,031
--------------- --------------
46,779,288 46,824,379
--------------- --------------
Total Assets....................................................... $ 100,871,296 $ 100,004,861
=============== ==============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities........................ $ 7,674,537 $ 9,299,154
Deferred credit and other liabilities
Accumulated deferred income taxes............................... 5,440,065 3,416,862
Long-term debt - affiliate......................................... 35,900,000 35,900,000
Shareholders' 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 (deficit)..................................... 114,897 (352,952)
--------------- --------------
Total shareholders' equity................................... 51,856,694 51,388,845
--------------- --------------
Total liabilities and shareholders' equity............... $ 100,871,296 $ 100,004,861
=============== ==============
The accompanying notes to the consolidated financial statements are an integral part of these statements.
A-4
Alaska Pipeline Company
CONSOLIDATED STATEMENTS OF OPERATIONS
For the years ended December 31,
---------------------------------------------------------
2002 2001 2000
-------------- -------------- ---------
Operating revenues:
Gas sales and transportation............ $ 67,852,910 $ 69,083,247 $ 50,330,051
Pipeline management services............ 562,109 - -
-------------- ------------- --------------
68,415,019 69,083,247 50,330,051
------------- ------------- --------------
Operating expenses:
Cost of gas sold.................................... 56,148,644 56,620,021 38,222,548
Operations and maintenance.............. 1,273,348 1,232,789 1,155,438
General and administrative.......................... 3,808,055 3,105,009 3,278,097
Depreciation and amortization........... 3,349,051 4,591,050 4,743,636
------------- ------------- --------------
64,579,098 65,548,869 47,399,719
------------- ------------- --------------
Operating income.......................... 3,835,921 3,534,378 2,930,332
------------- ------------- --------------
Other income (deductions):
Interest expense........................ (3,013,200) (3,586,510) (5,058,543)
Amortization of debt expense............ (45,091) (54,984) (242,906)
Other................................... 4,098 25,233 22,266
------------- ------------- --------------
(3,054,193) (3,616,261) (5,279,183)
------------- ------------- --------------
Income (loss) before income taxes......... 781,728 (81,883) (2,348,851)
Income tax (benefit).................................. 313,879 30,431 (966,061)
------------- ------------- --------------
Net income (loss)..................................... $ 467,849 $ (112,314) $ (1,382,790)
============= ============= ==============
The accompanying notes to the consolidated financial statements are an integral part of these statements.
A-5
Alaska Pipeline Company
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
For the years ended December 31, 2002, 2001 and 2000
Common stock Additional Retained Total
----------------------------------- paid-in earnings shareholders'
Shares Amount capital (deficit) equity
--------------- ------------------- ------------------ ----------------- ----------------
Balance at January 1, 2000 1,900,500 $ 1,900,500 $ 49,841,297 $ 1,142,152 $ 52,883,949
Net loss........................ - - - (1,382,790) (1,382,790)
--------------- ------------------- ------------------ ----------------- ----------------
Balance at December 31, 2000 1,900,500 1,900,500 49,841,297 (240,638) 51,501,159
Net loss........................ - - - (112,314) (112,314)
--------------- ------------------- ------------------ ----------------- ----------------
Balance at December 31, 2001 1,900,500 1,900,500 49,841,297 (352,952) 51,388,845
Net income...................... - - - 467,849 467,849
--------------- ------------------- ------------------ ----------------- ----------------
Balance at December 31, 2002 1,900,500 1,900,500 49,841,297 114,897 51,856,694
=============== =================== ================== ================= ================
The accompanying notes to the consolidated financial statements are an integral part of these statements.
A-6
Alaska Pipeline Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
----------------------------------------------------
2002 2001 2000
--------------- --------------- ----------------
Cash flows from operating activities:
Net income (loss).............................. $ 467,849 $ (112,314) $ (1,382,790)
Adjustments to reconcile net income
(loss) to net cash (used in)
provided by operating activities:
Depreciation and amortization.................. 3,394,142 4,646,034 4,986,542
Deferred income tax expense.. 2,023,203 1,636,048 1,635,333
Changes in operating assets and liabilities:
Accounts receivable............................ (203,019) - -
Prepaid expenses............................... 23,439 (34,967) (29,655)
Accounts payable and accrued liabilities....... (1,624,617) 4,252,384 (98,306)
Other.......................................... - - (42,334)
----------- ------------- --------------
Net cash (used in) provided by operating
Activities................................ 4,080,997 10,387,185 5,068,790
----------- ------------- -------------
Cash flows from investing activities:
Property additions............................. (553,805) (989,108) (1,513,756)
----------- ------------- -------------
Net cash used in investing
activities................................ (553,805) (989,108) (1,513,756)
----------- ------------- -------------
Cash flows from financing activities:
Increase (decrease) in notes
receivable/payable -
affiliates.................................. (3,427,785) 6,601,923 (3,662,487)
Repayments on long term debt. - (16,000,000) -
----------- -------------- -------------
Net cash provided by (used in) financing
activities................................ (3,427,785) (9,398,077) (3,662,487)
------------- -------------- -------------
Cash:
Net increase (decrease)........................ 99,407 - (107,453)
Beginning of period............................ - - 107,453
---------- ------------- -------------
End of period............................... $ 99,407 $ - $ -
=========== ============= =============
The accompanying notes to the consolidated financial statements are an integral part of these statements
A-7
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
NOTE 1 - NATURE OF BUSINESS
Company Description. 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 begun 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.
A-8
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Financial Instruments
For cash, notes receivable, accounts receivables, and accounts
payables and accrued liabilities, the carrying amounts
approximates 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.
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 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 and $1,228,572
in 2000.
A-9
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
The Company completed the transitional impairment and annual tests
required by SFAS 142, which involve the use of estimates related
to the fair market value of the business operations associated
with the goodwill. These tests did not indicate an impairment
loss. The Company will continue to evaluate its goodwill at least
annually 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 (loss) for the periods presented in the financial
statements exclusive of amortization expense (including any
related tax effects) related to goodwill:
Years Ended December 31,
------------------------------------------
2002 2001 2000
-------- --------- -----------
Net income (loss) $467,849 $(112,314) $(1,382,790)
Add back: Goodwill amortization, net of
income taxes - 798,424 798,572
-------- --------- -----------
Adjusted net income (loss) $467,849 $ 686,110 $ (584,218)
======== ========= ===========
The following table presents the components of the Company's goodwill:
As of December 31,
----------------------------------
2002 2001
------------ ------------
Goodwill, net of accumulated amortization:
Beginning balance $46,472,348 $47,700,692
Amortization - (1,228,344)
----------- -----------
Ending balance $46,472,348 $46,472,348
=========== ===========
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
A-10-
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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 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, 2002, 2001, and 2000.
Additionally, since all debt is owed to affiliates, the interest expensed
was recorded as an affiliate transaction and credited to notes receivable -
affiliates, thus no cash was specifically paid for interest for the years
ended December 31, 2002, 2001, and 2000.
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. Over time, the liability
is accreted to its present value each period, 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.
A-11
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities ("SFAS 146"). SFAS 146 requires that the
liability for costs associated with exit or disposal activities be
recognized when incurred, rather than at the date of a commitment to exit
or disposal plan. SFAS 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. The adoption of SFAS
146 is not expected to have a material impact on the Company's financial
statements.
NOTE 3 - RELATED PARTY TRANSACTIONS
Notes Receivable - Affiliate
As of December 31, 2002 and 2001, the Company had non-interest bearing
notes receivable from SEMCO of $6,346,451 and $2,918,666, respectively.
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 working directly on the
operations and maintenance of the Company's pipelines and related equipment
who charge their time directly to the Company. 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 administrative and general expenses to the
Company, which amounted to $2,301,948 in 2002, $2,122,433 in 2001, and
$2,305,132 in 2000.
Interest Expense
Since all long-term debt is owed to SEMCO, all interest expense is a
related party transaction.
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.
A-12
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
The Company and ENSTAR have undergone a rate review with the RCA, which
began in 2000. They received an Order dated August 8, 2002 from the RCA on
its review of rates based on normalized data for the year 2000. In its
Order, the RCA established a revenue requirement of $107.6 million and a
12.55% return on equity. In response to a petition by ENSTAR, the RCA
issued an additional Order dated September 16, 2002 which revised the
indicated annual revenue reduction from $2.1 million to $2.0 million, which
was 1.84% of ENSTAR's revenue in the normalized 2000 test year. The Order
required ENSTAR to implement the rate reduction by September 27, 2002 on an
across-the-board basis. The RCA also required ENSTAR to file an updated
cost of service study and a rate design, with a hearing on the rate design
filing scheduled for May 2003. See Note 8 for the subsequent matters
regarding ENSTAR's rate design.
A-13
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
NOTE 5 - INCOME TAXES
SFAS No. 109
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.
Provision for Income Taxes
The table below summarizes the components of the Company's provision for
income taxes:
Years Ended December 31,
-----------------------------------------------------
2002 2001 2000
----------------- ------------------ -------------
Federal income taxes:
Currently refundable $ (1,520,436) $(1,454,496) $ (2,086,398)
Deferred to future periods 1,764,531 1,492,138 1,344,633
State income taxes:
Currently refundable (188,888) (151,121) (514,996)
Deferred to future periods 258,672 143,910 290,700
------------ ----------- -------------
Total income tax provision (benefit) $ 313,879 $ 30,431 $ (966,061)
============ =========== =============
Deferred Income Taxes
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,
------------------------------------
2002 2001
-------------- --------------
Deferred tax liability components:
Property $ 3,629,226 $ 2,627,805
Goodwill 1,096,267 333,157
Other 714,572 455,900
------------ ------------
Total deferred tax liability $ 5,440,065 $ 3,416,862
============ ============
A-14
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
NOTE 6 - DEBT
Long-Term Debt - Affiliate
The long-term debt - affiliate is owed to SEMCO. Interest on the note is
recorded monthly through an intercompany transaction. The weighted average
interest rate charged to the Company by SEMCO was 8.17% in 2002 and 8.39%
in 2001 and 9.75% in 2000.
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 future minimum lease payments that have initial or remaining
non-cancelable lease terms in excess of one year for the years ended
December 31, 2003 through 2007 total $103,000. Total lease expense
approximated $107,000, $103,000 and $98,000 in 2002, 2001 and 2000,
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 threatening 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 - SUBSEQUENT EVENTS
Definitive Agreement to Sell the 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. At September 30, 2003, the book value of APC's assets that are
expected to be sold was approximately $89 million. 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.
A-15
ALASKA PIPELINE COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
As part of the sale, APC will enter into a Special Contract for Gas
Transportation with ENSTAR pursuant to which ENSTAR will pay a reservation
fee for use of all of APC's transportation capacity of $943,000 per month,
plus $0.075 per Mcf of gas transported, for ten years. 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 will be transferred to ENSTAR prior to the sale
and the intercompany gas sales agreement between APC and ENSTAR discussed
in Notes 2 and 4 will be terminated. NORSTAR is not part of the sale.
Rate Matters
As described in Note 4, 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.
A-16
ALASKA PIPELINE COMPANY UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
These unaudited consolidated financial statements as of September 30, 2003
and 2002 and for the nine-month periods then ended were prepared by the
Company and should be read in conjunction with audited consolidated
financial statements contained herein, which include the Company's audited
consolidated balance sheets as of December 31, 2002 and 2001 and the
consolidated statements of income, consolidated statements of cash flows,
and consolidated statements of changes in shareholder's equity for the
years ended December 31, 2002, 2001, and 2000. The information in the
accompanying unaudited financial statements reflect, in the opinion of the
Company's management, all adjustments (which include only normal recurring
adjustments) necessary for a fair statement of the information shown,
subject to year-end and other adjustments, as later information may
require.
A-18
ALASKA PIPELINE COMPANY
CONSOLIDATED BALANCE SHEET
September 30,
---------------------------------------
2003 2002
---------- ------------
Current assets
Cash......................................................... $ - $ 302,956
Notes receivable - affiliates................................ 3,530,074 -
Accounts receivable - trade.................................. 388,181 52,500
Prepaid expenses............................................. 170,119 159,524
------------ -----------
Total current assets...................................... 4,088,374 514,980
------------ -----------
Utility plant
Plant in service, at cost.................................... 58,676,852 57,881,311
Less - accumulated depreciation.............................. 13,215,657 10,006,433
------------ -----------
45,461,195 47,874,878
------------ -----------
Deferred charges and other assets
Goodwill, net of accumulated amortization of $2,661,605..... 46,472,348 46,472,348
Unamortized debt expense.................................... 275,436 352,031
------------ -----------
46,747,784 46,824,379
------------ -----------
Total assets..................................................... $ 96,297,353 $95,214,237
============ ===========
Current liabilities
Notes payable - affiliates.................................. $ - $ 1,288,733
Accounts payable and accrued liabilities.................... 3,488,697 3,239,305
------------ -----------
Total current liabilities................................ 3,488,697 4,528,038
------------ -----------
Deferred credits and other liabilities
Accumulated deferred income taxes........................... 5,440,065 3,416,862
Long-term debt - affiliate....................................... 35,900,000 35,900,000
Shareholders' 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 (deficit)................................. (273,206) (372,460)
------------ -----------
Total shareholders' equity............................... 51,468,591 51,369,337
------------ -----------
Total liabilities and shareholders' equity....................... $ 96,297,353 $95,214,237
============ ===========
A-19
ALASKA PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the nine months
ended September 30,
2003 2002
---------------- ---------------
Operating revenues
Gas sales and transportation.......... $ 43,097,681 $ 47,381,481
Engineering services.................. 2,352,365 319,598
------------- ------------
45,450,046 47,701,079
------------- ------------
Operating expenses
Cost of gas sold...................... $ 35,466,112 $ 39,086,921
Operations and maintenance............ 982,803 955,142
General and administrative............ 5,278,201 2,914,125
Depreciation and amortization......... 2,452,390 2,514,239
------------- ------------
44,179,506 45,470,427
------------- ------------
Operating income............................ 1,270,540 2,230,652
------------- ------------
Other income (deductions)
Interest expense...................... (2,172,848) (2,259,900)
Amortization of debt expense.......... (31,504) -
Other................................. 262,891 2,758
------------- ------------
(1,941,461) (2,257,142)
------------- ------------
Income (loss) before income taxes............... (670,921) (26,490)
Income tax (benefit)............................ (282,818) (6,982)
------------- ------------
Net income (loss)............................... $ (388,103) $ (19,508)
============= ===========
A-20
ALASKA PIPELINE COMPANY
CONSOLIDATED STATEMENT OF
CHANGES IN SHAREHOLDERS' EQUITY
For the mine months
ended September 30,
----------------------------------------
2003 2002
------------ -------------
Common stock........................ $ 1,900,500 $ 1,900,500
Capital surplus..................... 49,841,297 49,841,297
Retained earnings (deficit)
Beginning balance.............. 114,897 (352,952)
Net income (loss).............. (388,103) (19,508)
------------ ------------
Ending balance................. (273,206) (372,460)
------------ ------------
Total shareholders' equity.......... $ 51,468,591 $ 51,369,337
============ ============
A-21
ALASKA PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the nine months
ended September 30,
---------------------------------------
2003 2002
-------------- --------------
Cash flow from operating activities
Net income (loss).................................................. $ (388,103) $ (19,508)
Adjustments to reconcile net income (loss) to net cash used in
operating activities:
Depreciation and amortization................................... 2,483,894 2,514,239
Gain on the sale of assets...................................... (260,292) -
Changes in assets and liabilities, net of effects of
other changes as shown below:................................. (4,409,429) (6,116,746)
----------- ------------
Net cash used in operating activities.................. (2,573,930) (3,622,015)
----------- ------------
Cash flows from investing activities
Property additions................................................. (654,740) (282,428)
Proceeds from property sales, net of retirement costs.............. 312,886 -
----------- ------------
Net cash used in investing activities.................. (341,854) (282,428)
----------- ------------
Cash flows from financing activities
Increase (decrease) in notes receivable/payable - affiliates....... 2,816,377 4,207,399
----------- ------------
Net cash provided by financing activities.............. 2,816,377 4,207,399
----------- ------------
Cash
Net increase (decrease)............................................ (99,407) 302,956
Beginning of period................................................ 99,407 -
----------- ------------
End of period...................................................... - 302,956
=========== ============
Changes in assets and liabilities, net of effects of
other changes:
Accounts receivable............................................ (185,162) (52,500)
Prepaid expenses............................................... (38,428) (4,394)
Accounts payable and accrued liabilities....................... (4,185,839) (6,059,852)
----------- ------------
$(4,409,429) $ (6,116,746)
=========== ============
A-22
APPENDIX B
ATLAS PIPELINE PARTNERS LONG-TERM INCENTIVE PLAN
B-1
ATLAS PIPELINE PARTNERS, L.P.
LONG-TERM INCENTIVE PLAN
SECTION 1: PURPOSE OF THE PLAN.
The Atlas Pipeline Partners, L.P. Long-Term Incentive Plan (the "Plan") is
intended to promote the interests of Atlas Pipeline Partners, L.P., a Delaware
limited partnership (the "Partnership"), by providing to officers, employees and
managing board members of Atlas Pipeline Partners GP, LLC, a Delaware limited
liability company (the "Company"), and employees of its Affiliates, consultants
and joint venture partners who perform services for the Partnership incentive
awards for superior performance that are based on Units. It is also contemplated
that the Plan will enhance the ability of the Company and its Affiliates to
attract and retain the services of individuals who are essential for the growth
and profitability of the Partnership and to encourage them to devote their best
efforts to the business of the Partnership, thereby advancing the interests of
the Partnership and its partners.
SECTION 2: DEFINITIONS.
As used in the Plan, the following terms shall have the meanings set forth
below:
"Affiliate" means, with respect to any Person, any other Person that directly or
indirectly through one or more intermediaries controls, is controlled by or is
under common control with, the Person in question. As used herein, the term
"control" means the possession, direct or indirect, of the power to direct or
cause the direction of the management and policies of a Person, whether through
ownership of voting securities, by contract or otherwise.
"Award" means an Option or Phantom Unit granted under the Plan, and shall
include any tandem DERs granted with respect to a Phantom Unit.
"Board" means the Managing Board of the Company.
"Change in Control" means the occurrence of any of the following:
(1) the Company, or an Affiliate of the Parent, ceases to be the
general partner of the Partnership;
(2) a merger, consolidation, share exchange, division or other
reorganization or transaction of the Partnership, the Company, the Parent or any
Affiliate of the Parent that is a direct or indirect parent of the Company with
any entity, other than a transaction which would result in the voting securities
of the Partnership, the Company or Parent, as appropriate, outstanding
immediately prior thereto continuing to represent (either by remaining
outstanding or by being converted into voting securities of the surviving
entity) at least 60% of the combined voting power immediately after such
transaction of the surviving entity's outstanding securities or, in the case of
a division, the outstanding securities of each entity resulting from the
division;
(3) the equity holders of the Partnership, the Parent or any Affiliate
of the Parent that is a direct or indirect parent of the Company approve a plan
of complete, liquidation or winding-up or an agreement for the sale or
disposition (in one transaction or a series of transactions) of all or
substantially all of the Partnership's, the Parent's or any such Affiliate's
assets; or
B-2
(4) during any period of 24 consecutive months, individuals who at the
beginning of such period constituted the board of directors of the Company, the
Parent or any Affiliate of the Parent that is a direct or indirect parent of the
Company (including for this purpose any new director whose election or
nomination for election or appointment was approved by a vote of at least 2/3 of
the directors then still in office who were directors at the beginning of such
period) cease for any reason to constitute at least a majority of the board or,
in the case of a spin off of the Parent, if Edward E. Cohen and Jonathan Z.
Cohen cease to be directors of the Parent.
"Committee" means the Board or such committee of the Board appointed by the
Board to administer the Plan.
"DER" means a right, granted in tandem with a specific Phantom Unit, to receive
an amount in cash equal to, and at the same time as, the cash distributions made
by the Partnership with respect to a Unit during the period such Phantom Unit is
outstanding.
"Disability" means an illness or injury that lasts at least 6 months, is
expected to be permanent and renders the Participant unable to carry out his or
her duties to the Company or any of its Affiliates.
"Employee" means any officer or employee of the Company, its Affiliates,
consultants or joint venture partners who performs services for the Partnership
or in furtherance of the Partnership's business.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Fair Market Value" means the closing sales price of a Unit on the applicable
date (or if there is no trading in the Units on such date, the closing sales
price on the last date Units were traded). In the event Units are not publicly
traded at the time a determination of fair market value is required to be made
hereunder, the determination of fair market value shall be made in good faith by
the Committee.
"Manager" means a "non-employee director" of the Company as defined in Rule
16b-3 under the Exchange Act.
"Option" means an option to purchase Units granted under the Plan.
"Parent" means Resource America, Inc., a Delaware corporation, or, from and
after the date that Atlas America, Inc., a Delaware corporation, is not a
subsidiary of Resource America, Inc., Atlas America, Inc. provided that the
transaction pursuant to which Atlas America, Inc. ceased to be a subsidiary of
Resource America, Inc. was approved by the board of directors of Resource
America, Inc.
"Participant" means any Employee or Manager granted an Award under the Plan.
"Partnership Agreement" means the Agreement of Limited Partnership of Atlas
Pipeline Partners, L.P., as amended from time to time.
B-3
"Person" means an individual or a corporation, limited liability company,
partnership, joint venture, trust, unincorporated organization, association,
government agency or political subdivision thereof or other entity.
"Phantom Unit" means a phantom (notional) unit granted under the Plan which upon
vesting entitles the Participant to receive a Unit or its then Fair Market Value
in cash, as determined by the Committee.
"Restricted Period" means the period established by the Committee with respect
to an Award during which the Award remains subject to forfeiture or is not
exercisable by the Participant.
"Rule 16b-3" means Rule 16b-3 promulgated by the SEC under the Exchange Act, or
any successor rule or regulation thereto as in effect from time to time.
"SEC" means the Securities and Exchange Commission, or any successor thereto.
"Securities Act" means the Securities Act of 1933, as amended.
"Unit" means a common unit of limited partner interest of the Partnership.
SECTION 3: ADMINISTRATION.
The Plan shall be administered by the Committee. A majority of the Committee
shall constitute a quorum, and the acts of a majority of the members of the
Committee who are present at any meeting thereof at which a quorum is present,
or acts unanimously approved by the members of the Committee in writing, shall
be the acts of the Committee. Subject to the following and any applicable law,
the Committee, in its sole discretion, may delegate any or all of its powers and
duties under the Plan, including the power to grant Awards under the Plan, to
the Chief Executive Officer of the Company, subject to such limitations on such
delegated powers and duties as the Committee may impose, if any; provided,
however, that such delegation shall not limit the Chief Executive Officer's
right to receive Awards under the Plan. Notwithstanding the foregoing, the Chief
Executive Officer may not grant Awards to, or take any action with respect to
any Award previously granted to, himself or a Person who is an Employee or
Manager subject to Rule 16b-3. Subject to the terms of the Plan and applicable
law, and in addition to other express powers and authorizations conferred on the
Committee by the Plan, the Committee shall have full power and authority to: (i)
designate Participants; (ii) determine the type or types of Awards to be granted
to a Participant; (iii) determine the terms and conditions of any Award; (iv)
determine whether, to what extent, and under what circumstances Awards may be
settled, exercised, canceled, or forfeited; (v) interpret and administer the
Plan and any instrument or agreement relating to an Award made under the Plan;
(vi) establish, amend, suspend, or waive such rules and regulations and appoint
such agents as it shall deem appropriate for the proper administration of the
Plan; and (vii) make any other determination and take any other action that the
Committee deems necessary or desirable for the administration of the Plan.
Unless otherwise expressly provided in the Plan, all designations,
determinations, interpretations, and other decisions under or with respect to
the Plan or any Award shall be within the sole discretion of the Committee, may
be made at any time and shall be final, conclusive, and binding upon all
Persons, including the Company, the Partnership, any Affiliate, any Participant,
and any beneficiary of any Award.
B-4
SECTION 4: UNITS.
(a) Units Available. Subject to adjustment as provided in Section 4(c), the
number of Units with respect to which Phantom Units and Options may be granted
under the Plan is 435,000; provided that the maximum number of Phantom Units
that may be awarded to Managers is 10,000. If any Option or Phantom Unit is
forfeited or otherwise terminates or is canceled without the delivery of Units,
then the Units covered by such Award, to the extent of such forfeiture,
termination or cancellation, shall again be Units with respect to which Awards
may be granted.
(b) Sources of Units Deliverable under Awards. Any Units delivered pursuant to
an Award shall consist, in whole or in part, of Units newly issued by the
Partnership, Units acquired in the open market or from any Affiliate of the
Partnership or the Company, or any other Person, or any combination of the
foregoing, as determined by the Committee in its discretion.
(c) Adjustments. In the event that the Committee determines that any
distribution (whether in the form of cash, Units, other securities or other
property), recapitalization, split, reverse split, reorganization, merger,
consolidation, split-up, spin-off, combination, repurchase, or exchange of Units
or other securities of the Partnership, issuance of warrants or other rights to
purchase Units or other securities of the Partnership, or other similar
transaction or event affects the Units such that an adjustment is appropriate in
order to prevent dilution or enlargement of the benefits or potential benefits
intended to be made available under the Plan, then the Committee shall, in such
manner as it may deem equitable, adjust any or all of (i) the number and type of
Units (or other securities or property) with respect to which Awards may be
granted, (ii) the number and type of Units (or other securities or property)
subject to outstanding Awards, and (iii) the grant or exercise price with
respect to any Award or, if deemed appropriate, make provision for a cash
payment to the holder of an outstanding Award; provided, that the number of
Units subject to any Award shall always be a whole number.
SECTION 5: ELIGIBILITY.
Any Employee or Manager shall be eligible to be designated a Participant and
receive an Award under the Plan.
SECTION 6: AWARDS.
(a) Options. The Committee shall have the authority to determine the Employees
to whom Options shall be granted, the number of Units to be covered by each
Option, the exercise price therefor, the Restricted Period and the conditions
and limitations applicable to the exercise of the Option, as the Committee shall
determine, that are not inconsistent with the provisions of the Plan.
(i) Exercise Price. The exercise price per Unit purchasable under an
Option shall be determined by the Committee at the time the Option is granted
and may be more or less than its Fair Market Value as of the date of grant.
(ii) Time and Method of Exercise. The Committee shall determine the
Restricted Period and the method or methods by which payment of the exercise
price may be made or deemed to have been made, which may include, without
limitation, cash, check acceptable to the Board, a "cashless-broker" exercise
through procedures approved by the Board, a recourse note from the Participant
in a form acceptable to the Board, or any combination thereof, having a fair
market value on the exercise date equal to the relevant exercise price.
B-5
(b) Phantom Units.
(i) Awards to Employees. The Committee shall have the authority
to determine the Employees to whom Phantom Units shall be granted, the number of
Phantom Units to be granted to each such Participant, the Restricted Period, the
conditions under which the Phantom Units may become vested or forfeited, whether
DERs are granted with respect to an Award and such other terms and conditions,
as the Committee may determine, that are not inconsistent with the provisions of
the Plan.
(ii) Awards to Managers. Each Manager who is a member of the Board as
of the effective date of the Plan shall be awarded Phantom Units with DERs as of
that date in an amount equal to the lesser of (A) 500 or (B) that number of
Phantom Units equal to $15,000 divided by the Fair Market Value of a Unit as of
that date. Each Manager who is first appointed to the Board on or after the
effective date of the Plan shall be awarded Phantom Units with DERs as of the
date of first appointment in an amount equal to the lesser of (A) 500 or (B)
that number of Phantom Units equal to $15,000 divided by the Fair Market Value
of a Unit as of that date. Thereafter, on each anniversary of the date on which
a Manager is first awarded Phantom Units during the term of the Plan, the
Manager shall be awarded Phantom Units with DERs as of that date in an amount
equal to the lesser of (A) 500 or (B) that number of Phantom Units equal to
$15,000 divided by the Fair Market Value of a Unit as of that date. Except as
provided in Section 6(b)(iii), a Manager shall vest in 25% of his or her Phantom
Units on each anniversary of the original Award for such Phantom Units such that
each Award shall fully vest on the fourth anniversary of the Award.
(c) General.
(i) Forfeiture. Except as otherwise provided in the terms of the Award,
upon termination of a Participant's employment with the Company or its
Affiliates or membership on the Board during the applicable Restricted Period,
all Options and unvested Phantom Units shall be forfeited by the Participant;
provided, however, that if the reason for the termination is the Participant's
death or Disability, all Options awarded to the Participant shall become
exercisable and all Phantom Units shall vest automatically. The Committee may,
in its discretion, waive in whole or in part any forfeiture.
(ii) Awards May Be Granted Separately or Together. Awards may, in the
discretion of the Committee, be granted either alone or in addition to, in
tandem with, or in substitution for any other Award granted under the Plan or
any award granted under any other plan of the Company or any Affiliate.
(iii) Limits on Transfer of Awards. (A) Except as provided in (C)
below, each Option shall be exercisable only by the Participant during the
Participant's lifetime, or by the person to whom the Participant's rights shall
pass by will or the laws of descent and distribution.
B-6
(B) Except as provided in (C) below, no Award and no right under any
such Award may be assigned, alienated, pledged, attached, sold or otherwise
transferred or encumbered by a Participant and any such purported assignment,
alienation, pledge, attachment, sale, transfer or encumbrance shall be void and
unenforceable against the Partnership, the Company or any Affiliate thereof.
(C) To the extent specifically provided by the Committee with respect
to an Option grant, an Option may be transferred by a Participant without
consideration to immediate family members or related family trusts, limited
partnerships or similar entities or on such terms and conditions as the
Committee may from time to time establish. In addition, Awards may be
transferred by will and the laws of descent and distribution.
(iv) Unit Certificates. All certificates for Units or other securities
of the Partnership delivered under the Plan pursuant to any Award or the
exercise thereof shall be subject to such stop transfer orders and other
restrictions as the Committee may deem advisable under the Plan or the rules,
regulations, and other requirements of the SEC, any stock exchange upon which
such Units or other securities are then listed, and any applicable federal or
state laws, and the Committee may cause a legend or legends to be put on any
such certificates to make appropriate reference to such restrictions.
(v) Delivery of Units or Other Securities and Payment by Participant of
Consideration. Notwithstanding anything in the Plan or any grant agreement to
the contrary, delivery of Units pursuant to the exercise or vesting of an Award
may be deferred for any period during which, in the good faith determination of
the Committee, the Partnership is not reasonably able to obtain or issue Units
pursuant to such Award without violating the rules or regulations of any
applicable law or securities exchange. No Units or other securities shall be
delivered pursuant to any Award until payment in full of any amount required to
be paid pursuant to the Plan or the applicable Award grant agreement (including,
without limitation, any exercise price or tax withholding) is received by the
Partnership.
(vi) RULE 16b-3. It is intended that the Plan and any Award made to a
Participant subject to Section 16 of the Exchange Act meet all of the
requirements of Rule 16b-3. If any provision of the Plan or any such Award would
disqualify the Plan or such Award under, or would otherwise not comply with Rule
16b-3, such provision or Award shall be construed or deemed amended to conform
to Rule 16b-3
(vii) Status of Original Issue Units. The Partnership intends, but
shall not be obligated, to register for sale under the Securities Act the Units
acquirable pursuant to Awards, and to keep such registration effective
throughout the period any Awards are in effect. In the absence of such effective
registration or an available exemption from registration under the Securities
Act, delivery of Units acquirable pursuant to Awards shall be delayed until
registration of such Units is effective or an exemption from registration under
the Securities Act is available. In the event exemption from registration under
the Securities Act is available, a Participant (or a Participant's estate or
personal representative in the event of the Participant's death or incapacity),
if requested by the Partnership to do so, will execute and deliver to the
Partnership in writing an agreement containing such provisions as the
Partnership may require to assure compliance with applicable securities laws. No
sale or disposition of Units acquired pursuant to an Award by a Participant
shall be made in the absence of an effective registration statement under the
Securities Act with respect to such Units unless an opinion of counsel
satisfactory to the Partnership that such sale or disposition will not
constitute a violation of the Securities Act or any other applicable securities
laws is first obtained.
B-7
(viii) Change in Control. Upon a Change in Control, all Awards shall
automatically vest and become payable or exercisable, as the case may be, in
full. In this regard, all Restricted Periods shall terminate and all performance
criteria, if any, shall be deemed to have been achieved at the maximum level. To
the extent an Option is not exercised upon a Change in Control, the Committee
may, in its discretion, cancel such Award without payment or provide for a
replacement grant with respect to such property and on such terms as it deems
appropriate.
SECTION 7: AMENDMENT AND TERMINATION.
Except to the extent prohibited by applicable law:
(a) Amendments to the Plan. Except as required by the rules of the principal
securities exchange on which the Units are traded and subject to Section 7(b)
below, the Board or the Committee may amend, alter, suspend, discontinue, or
terminate the Plan in any manner without the consent of any partner,
Participant, other holder or beneficiary of an Award, or other Person.
(b) Amendments to Awards. Subject to Section 7(a), the Committee may waive any
conditions or rights under, amend any terms of, or alter any Award theretofore
granted, provided no change, other than pursuant to Section 7(c), in any Award
shall materially reduce the benefit to a Participant without the consent of such
Participant.
(c) Adjustment of Awards upon the Occurrence of Certain Unusual or Nonrecurring
Events. The Committee is hereby authorized to make adjustments in the terms and
conditions of, and the criteria included in, Awards in recognition of unusual or
nonrecurring events (including, without limitation, the events described in
Section 4(c) of the Plan) affecting the Partnership or the financial statements
of the Partnership, or of changes in applicable laws, regulations, or accounting
principles, whenever the Committee determines that such adjustments are
appropriate in order to prevent dilution or enlargement of the benefits or
potential benefits intended to be made available under the Plan.
SECTION 8: GENERAL PROVISIONS.
(a) No Rights to Award. No Person shall have any claim to be granted any Award
under the Plan, and there is no obligation for uniformity of treatment of
Participants. The terms and conditions of Awards need not be the same with
respect to each Participant.
(b) Withholding. The Company or any Affiliate is authorized to withhold from any
Award, from any payment due or transfer made under any Award or from any
compensation or other amount owing to a Participant the amount (in cash, Units,
other securities, Units that would otherwise be issued pursuant to such Award or
other property) of any applicable taxes payable in respect of the grant of an
Award, its exercise, the lapse of restrictions thereon, or any payment or
transfer under an Award or under the Plan and to take such other action as may
be necessary in the opinion of the Company or Affiliate to satisfy its
withholding obligations for the payment of such taxes.
B-8
(c) No Right to Employment. The grant of an Award shall not be construed as
giving a Participant the right to be retained in the employ of the Company or
any Affiliate or to remain on the Board. Further, the Company or an Affiliate
may at any time dismiss a Participant from employment, free from any liability
or any claim under the Plan, unless otherwise expressly provided in the Plan or
in any Award agreement.
(d) Governing Law. The validity, construction, and effect of the Plan and any
rules and regulations relating to the Plan shall be determined in accordance
with the laws of the State of Delaware and applicable federal law.
(e) Severability. If any provision of the Plan or any Award is or becomes or is
deemed to be invalid, illegal, or unenforceable in any jurisdiction or as to any
Person or Award, or would disqualify the Plan or any Award under any law deemed
applicable by the Committee, such provision shall be construed or deemed amended
to conform to the applicable laws, or if it cannot be construed or deemed
amended without, in the determination of the Committee, materially altering the
intent of the Plan or the Award, such provision shall be stricken as to such
jurisdiction, Person or Award and the remainder of the Plan and any such Award
shall remain in full force and effect.
(f) Other Laws. The Committee may refuse to issue or transfer any Units or other
consideration under an Award if, in its sole discretion, it determines that the
issuance or transfer or such Units or such other consideration might violate any
applicable law or regulation, the rules of the principal securities exchange on
which the Units are then traded, or entitle the Partnership or an Affiliate to
recover the same under Section 16(b) of the Exchange Act, and any payment
tendered to the Partnership by a Participant, other holder or beneficiary in
connection with the exercise of such Award shall be promptly refunded to the
relevant Participant, holder or beneficiary.
(g) No Trust or Fund Created. Neither the Plan nor any Award shall create or be
construed to create a trust or separate fund of any kind or a fiduciary
relationship between the Partnership, the Company or any participating Affiliate
and a Participant or any other Person.
(h) No Fractional Units. No fractional Units shall be issued or delivered
pursuant to the Plan or any Award, and the Committee shall determine whether
cash, other securities, or other property shall be paid or transferred in lieu
of any fractional Units or whether such fractional Units or any rights thereto
shall be canceled, terminated, or otherwise eliminated.
(i) Headings. Headings are given to the sections and subsections of the Plan
solely as a convenience to facilitate reference. Such headings shall not be
deemed in any way material or relevant to the construction or interpretation of
the Plan or any provision thereof.
(j) Facility Payment. Any amounts payable hereunder to any Person under legal
disability or who, in the judgment of the Committee, is unable to properly
manage his financial affairs, may be paid to the legal representative of such
Person, or may be applied for the benefit of such Person in any manner which the
Committee may select, and the Company shall be relieved of any further liability
for payment of such amounts.
B-9
SECTION 9: TERM OF THE PLAN.
The Plan shall be effective on the date of its approval by the Unit holders and
shall continue until the date terminated by the Board or Units are no longer
available for the grant of Awards under the Plan, whichever occurs first.
However, unless otherwise expressly provided in the Plan or in an applicable
Award agreement, any Award granted prior to such termination, and the authority
of the Board or the Committee to amend, alter, adjust, suspend, discontinue, or
terminate any such Award or to waive any conditions or rights under such Award,
shall extend beyond such termination date.
B-10
ATLAS PIPELINE PARTNERS, L.P.
PROXY
THIS PROXY IS SOLICITED ON BEHALF OF THE MANAGING BOARD
OF ATLAS PIPELINE PARTNERS GP, LLC
The undersigned hereby constitutes and appoints Edward E. Cohen and Jonathan Z.
Cohen, or either of them, as and for his or her proxies, each with the power to
appoint such proxy's substitute, and hereby authorizes them, or either of them,
to vote all of the units of limited partner interest in Atlas Pipeline Partners,
L.P. held of record by the undersigned on ______________, 2003 at the Special
Meeting of Unitholders of Atlas Pipeline Partners, L.P. to be held
[______________] and at any and all adjournments thereof as follows:
I plan to attend
the meeting
+-+
+-+
1. PROPOSAL TO APPROVE THE ISSUANCE OF UP TO ________ COMMON UNITS OF
LIMITED PARTNER INTEREST
+-+ +-+ +-+
+-+ FOR +-+ AGAINST +-+ ABSTAIN
2. PROPOSAL TO APPROVE THE AMENDMENTS TO THE AGREEMENT OF LIMITED
PARTNERSHIP OF ATLAS PIPELINE PARTNERS, L.P.
+-+ +-+ +-+
+-+ FOR +-+ AGAINST +-+ ABSTAIN
3. PROPOSAL TO APPROVE THE ATLAS PIPELINE PARTNERS, L.P. LONG-TERM
INCENTIVE PLAN.
+-+ +-+ +-+
+-+ FOR +-+ AGAINST +-+ ABSTAIN
This proxy, when properly executed, will be voted in the manner
specified above by the named proxies. If no direction is made, this proxy will
be voted FOR each of the proposals. Please sign exactly as your name appears on
this proxy card. When units are held by joint tenants, both should sign. When
signing as an attorney, executor, administrator, trustee, or guardian, please
give full title as such. If a corporation, please sign in full corporate name by
President or other authorized officer. If a partnership, please sign in
partnership name by authorized person.
Dated:________________, 2004
_______________________
Signature of unitholder
_________________________
Signature if held jointly
PLEASE MARK, SIGN, DATE AND RETURN THE PROXY CARD PROMPTLY USING THE ENCLOSED
ENVELOPE.