Edgar Filing: ATLAS PIPELINE PARTNERS LP

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION
13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

[ ] TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to __________

Commission file number: 1-14998

ATLAS PIPELINE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

DELAWARE 23-3011077
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

311 Rouser Road
Moon Township, Pennsylvania 15108
(Address of principal executive office) (Zip code)

Registrant's telephone number, including area code: (412) 262-2830

Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange on
Title of each class which registered

Common Units of Limited Partnership Interest American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

N/A
------------------------
Title of class

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2) of the Act. Yes [X] No [ ]

The aggregate market value of the equity securities held by
non-affiliates of the registrant, based on the closing price on June 30, 2003
was approximately $81.6 million.

DOCUMENTS INCORPORATED BY REFERENCE
None

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K

Page
----

PART I
Item 1: Business.................................................................................. 3 - 15
Item 2: Properties................................................................................ 16
Item 3: Legal Proceedings......................................................................... 16
Item 4: Submission of Matters to a Vote of Security Holders....................................... 16

PART II
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters..................... 17 - 18
Item 6: Selected Financial Data................................................................... 18 - 19
Item 7: Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................................. 20 - 28
Item 7A: Quantitative and Qualitative Disclosures About Market Risk................................ 29
Item 8: Financial Statements and Supplementary Data............................................... 30 - 44
Item 9: Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure................................................ 45
Item 9A: Controls and Procedures................................................................... 45

PART III
Item 10: Directors and Executive Officers of the Registrant........................................ 46 - 49
Item 11: Executive Compensation.................................................................... 50
Item 12: Security Ownership of Certain Beneficial Owners and Management............................ 51
Item 13: Certain Relationships and Related Transactions............................................ 51 - 52
Item 14: Principal Accountant Fees and Services.................................................... 52

PART IV
Item 15: Exhibits, Financial Statement Schedules and Reports on Form 8-K........................... 53

SIGNATURES................................................................................................ 54

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PART I
ITEM 1. BUSINESS

THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING
EVENTS AND FINANCIAL TRENDS WHICH MAY AFFECT OUR FUTURE OPERATING RESULTS AND
FINANCIAL POSITION. SUCH STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT
COULD CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM
THOSE ANTICIPATED IN THESE FORWARD-LOOKING STATEMENTS. THESE FACTORS INCLUDE
FLUCTUATIONS IN THE MARKET FOR NATURAL GAS FROM WHICH OUR REVENUES ARE DERIVED,
PRODUCTION DECLINES FROM WELLS SERVICED BY OUR GATHERING SYSTEMS, REDUCED
DRILLING FOR NEW WELLS IN OUR SERVICE AREAS AND OUR NEED FOR ADDITIONAL CAPITAL
TO EXPAND OUR GATHERING SYSTEMS.

General

We are a Delaware limited partnership with common units traded on the
American Stock Exchange under the symbol "APL." We own and operate natural gas
pipeline gathering systems through our operating partnership and its operating
subsidiaries. As of December 31, 2003, our primary assets consisted of
approximately 1,380 miles of intrastate gathering systems located in eastern
Ohio, western New York and western Pennsylvania. Our gathering systems served
approximately 4,500 wells at December 31, 2003, with an average daily throughput
for the year then ended of 52.5 million cubic feet, or Mmcf, of natural gas. Our
gathering systems provide a means through which well owners and operators can
transport the natural gas produced by their wells to public utility pipelines
for delivery to customers. To a lesser extent, our gathering systems transport
natural gas directly to customers. Our gathering systems currently connect with
public utility pipelines operated by Peoples Natural Gas Company, National Fuel
Gas Supply, Tennessee Gas Pipeline Company, National Fuel Gas Distribution
Company, East Ohio Gas Company, Columbia of Ohio, Consolidated Natural Gas Co.,
Texas Eastern Pipeline, Columbia Gas Transmission Corp. and Equitable Utilities.
We do not engage in storage or gas marketing programs, nor do we engage in the
purchase and resale for our own account of natural gas transported through our
gathering systems. During the year ended December 31, 2003, our gathering
systems transported 19.2 billion cubic feet, or Bcf, of natural gas, an increase
of 4% and 7% from the years ended December 31, 2002 and 2001, respectively. We
connected 270 wells to our gathering systems in the year ended December 31, 2003
and have connected 829 wells since we commenced operations in January 2000. In
addition, we have added 433 wells through acquisitions of pipelines.

In May 2003, we completed a public offering of 1,092,500 common units
of limited partner interest. The net proceeds after underwriting discounts and
commissions were approximately $25.2 million. These proceeds were used in part
to repay existing indebtedness of $8.5 million. We intend to use the balance of
these proceeds to fund future capital projects and for working capital.

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In September 2003, we entered into a purchase and sale agreement with
SEMCO Energy, Inc., or SEMCO, under which we or our designee will purchase all
of the outstanding equity of SEMCO's wholly-owned subsidiary, Alaska Pipeline
Company, L.L.C., which owns a 354-mile intrastate natural gas transmission
pipeline that delivers gas to metropolitan Anchorage. The total consideration,
payable in cash at closing, will be approximately $95.0 million, subject to an
adjustment based on the amount of working capital that Alaska Pipeline has at
closing. For a description of how we intend to finance this acquisition, see
Item 7, "Management's Discussion and Analysis of Financial Condition and Results
of Operations-Pending Acquisition." Completion of the transaction is subject to
a number of conditions, including receipt of governmental and non-governmental
consents and approvals and the absence of a material adverse change in Alaska
Pipeline's business. Among the required governmental authorizations are approval
of the Regulatory Commission of Alaska and expiration, without adverse action,
of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. We
received an early termination of the Hart-Scott-Rodino waiting period in January
2004. The purchase and sale agreement may be terminated by either SEMCO or us if
the transaction is not completed by June 16, 2004.

Public utility pipelines charge transportation fees to the entity
having title to the natural gas being transported, typically the well owner, an
intermediate purchaser such as a natural gas distribution company, or a final
purchaser. We do not have title to the natural gas gathered and delivered by us
and, accordingly, do not pay transportation fees charged by public utility
pipelines. We do not transport any oil produced by wells connected to our
gathering systems.

We are party to an omnibus agreement with Atlas America, Inc. that is
intended to maximize the use and expansion of our gathering systems and the
amount of natural gas they transport. Among other things, the omnibus agreement
requires Atlas America to install required flow lines and connect wells it
operates that are located within 2,500 feet of one of our gathering systems.

We are also party to natural gas gathering agreements with Atlas
America under which it pays us gathering fees generally equal to a percentage,
generally 16%, of the gross or weighted average sales price of the natural gas
we transport subject, in most cases, to minimum prices of $0.35 or $0.40 per
thousand cubic feet, or Mcf. Our business, therefore, depends in large part on
the prices at which the natural gas we transport is sold. Due to the volatility
of natural gas prices, our gross revenues can vary materially from period to
period. During the year ended December 31, 2003, we received gathering fees
averaging $0.82 per Mcf, while during the years ended December 31, 2002 and
2001, our average gathering fees were $0.58 and $0.76 per Mcf, respectively.

Objectives and Strategy

Our objective is to increase cash flow, earnings and returns to our
unitholders by:

o expanding our existing asset base through construction of
extensions necessary to service additional wells drilled by Atlas
America and others;

o expanding our existing asset base through accretive acquisitions of
gathering systems from others;

o achieving economies of scale as a result of expanding our
operations through extensions and acquisitions; and

o continuing to strengthen our balance sheet by financing our growth
with a combination of long-term debt and equity so as to provide
the financial flexibility to fund future opportunities.

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Since commencing operations in January 2000, we have pursued these
objectives by:

o adding 360 miles of pipeline to our original system;

o connecting 829 new wells to our pipeline, 770 of which were drilled
by Atlas America;

o acquiring two gathering systems, one in Ohio and one in
Pennsylvania, aggregating 120 miles of pipeline with approximately
433 wells connected to those systems; and

o upgrading our system and substantially expanding our capacity.

We believe that our focus on the mid-stream gas industry, specifically
gas gathering systems, the extensive prior experience of our general partner's
management in the operation of gathering systems, our position as one of the
largest operators of gathering systems in the Appalachian Basin and our
relationship with Atlas America provide us with a competitive advantage in
executing our growth strategy to achieve our business objectives.

Pipeline Characteristics

We set forth in the following table the volumes of the natural gas we
transported, in Mcfs, in the years ended December 31, 2003, 2002 and 2001.

For the years ended
December 31,
---------------------------------------------
2003 2002 2001
---------- ---------- ----------

New York systems......................... 449,800 493,600 570,500
Ohio systems............................. 5,060,200 5,396,900 5,378,200
Pennsylvania systems..................... 13,642,300 12,492,100 11,176,300
---------- ---------- ----------
19,152,300 18,382,600 17,125,000
========== ========== ==========

Of the approximately 4,500 wells currently connected to our gathering
systems, approximately 4,100 are owned by Atlas America or its affiliates or by
investment partnerships managed or operated by Atlas America or its affiliates,
with the remainder being owned or managed by third parties. We have agreements
with Atlas America and its affiliates relating to the connection of future wells
owned or controlled by them to our gathering systems and the transportation fees
we will charge. We describe these agreements under "-Agreements with Atlas
America." These wells are the principal producers of gas transported by our
gathering systems and we anticipate that wells controlled by Atlas America will
continue in the future to be the principal producers into our gathering systems.
As of December 31, 2003, Atlas America and its affiliates controlled leases on
developed properties in the operational area of our gathering systems totaling
approximately 226,000 gross acres. In addition, Atlas America and its affiliates
control leases on approximately 205,000 undeveloped gross acres of land. During
the year ended December 31, 2003, Atlas America and its affiliates drilled and
connected 270 wells to our gathering systems as compared to 195 and 196 wells
during the years ended December 31, 2002 and 2001, respectively.

The gathering systems are generally constructed with 2, 4, 6, 8 and 12
inch cathodically protected and wrapped steel pipe and are generally buried 36
inches below the ground. Pipelines constructed in this manner typically are
expected to last at least 50 years from the date of construction. For the years
ended December 31, 2003, 2002 and 2001, the cost of operating the gathering
systems, excluding depreciation, was approximately $2.4 million, $2.1 million
and $1.9 million, respectively. We do not believe that there are any significant
geographic limitations upon our ability to expand in the areas served by our
gathering systems.

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Our revenues are determined primarily by the amount of natural gas
flowing through our gathering systems and the price received for this natural
gas. Our ability to increase the flow of natural gas through our gathering
systems and to offset the natural decline of the production already connected to
our gathering systems will be determined primarily by our ability to connect new
wells to our gathering systems and to acquire additional gathering assets.

Agreements with Atlas America

At the completion of our initial public offering, we entered into an
omnibus agreement and a master natural gas gathering agreement with Atlas
America and two of its affiliates, Resource Energy, Inc. and Viking Resources
Corporation. The purpose of these agreements is to maximize the use and
expansion of our gathering systems and the volume of natural gas they transport.
Since then, we have entered into additional gas gathering agreements with
subsidiaries of Atlas America. None of these agreements resulted from arm's
length negotiations and, accordingly, we cannot assure you that we could not
have obtained more favorable terms from independent third parties similarly
situated. However, since these agreements principally involve the imposition of
obligations on Atlas America and its affiliates, we do not believe that we could
obtain similar agreements from independent third parties.

Omnibus Agreement. Under the omnibus agreement, Atlas America and its
affiliates agreed to add wells to the gathering systems and provide consulting
services when we construct new gathering systems or extend existing systems. The
omnibus agreement also imposes conditions upon our general partner's disposition
of its general partner interest in us. The omnibus agreement is a continuing
obligation, having no specified term or provisions regarding termination except
for a provision terminating the agreement if our general partner is removed as
general partner without cause.

Well Connections. Atlas America sponsors oil and gas drilling
investment partnerships in areas served by the gathering systems. Under the
omnibus agreement, Atlas America must construct up to 2,500 feet of small
diameter (two inches or less) sales or flow lines from the wellhead of any well
it drills and operates to a point of connection to our gathering systems. Where
Atlas America has extended sales and flow lines to within 1,000 feet of one of
our gathering systems, we must extend our system to connect to that well.

With respect to wells drilled that are more than 3,500 feet from our
gathering systems, we have the right, at our cost, to extend our gathering
systems. If we do not elect to extend our gathering systems, Atlas America may
connect the wells to an interstate or intrastate pipeline owned by third
parties, a local natural gas distribution company or an end user; however, we
will have the right to assume the cost of construction of the necessary lines,
which then become part of our gathering systems. We must exercise our rights
within 30 days of notice to us from Atlas America that it intends to drill on a
particular site that is not within 3,500 feet of our gathering systems. If we
elect to have the well connected to our gathering systems, we must complete
construction of one of our gathering systems to within 2,500 feet of the well
within 60 days after Atlas America has notified us that the well will be
completed as a producing natural gas well. If we elect to assume the cost of
constructing lines, Atlas America will be responsible for the construction, and
we must pay the cost of that construction within 30 days of Atlas America's
invoice.

Consulting Services. The omnibus agreement requires Atlas America to
assist us in identifying existing gathering systems for possible acquisition and
to provide consulting services to us in evaluating and making a bid for these
systems. Any gathering system that Atlas America or its affiliates identify as a
potential acquisition must first be offered to us. We will have 30 days to
determine whether we want to acquire the identified system and advise Atlas
America of our intent. If we intend to acquire the system, we have an additional
60 days to complete the acquisition. If we do not complete the acquisition, or
advise Atlas America that we do not intend to acquire the system, then Atlas
America may do so.

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Gathering System Construction. The omnibus agreement requires Atlas
America to provide us with construction management services if we determine to
expand one or more of our gathering systems. We must reimburse Atlas America for
its costs, including an allocable portion of employee salaries, in connection
with its construction management services.

Construction Financing. The omnibus agreement requires Atlas America to
provide us with stand-by financing of up to $1.5 million per year for the cost
of constructing new gathering systems or gathering system expansions until
February 2005. If we choose to use the stand-by commitment, the financing will
be provided through the purchase by Atlas America of our common units in the
amount of the construction costs as they are incurred. The purchase price of the
common units will be the average daily closing price for the common units on the
American Stock Exchange for the 20 consecutive trading days before the purchase.
Construction costs do not include maintenance expenses or capital improvements
following construction or costs of acquiring gathering systems. We are not
obligated to use the stand-by commitment and may seek financing from other
sources. We have not used the stand-by commitment to date.

Disposition of Interest in Our General Partner. Direct and indirect
wholly-owned subsidiaries of Atlas America act as the general partners,
operators or managers of the drilling investment partnerships sponsored by Atlas
America. Our general partner is a subsidiary of Atlas America. Under the omnibus
agreement, those subsidiaries, including our general partner, that currently act
as the general partners, operators or managers of partnerships sponsored by
Atlas America must also act as the general partners, operators or managers for
all new drilling investment partnerships sponsored by Atlas America. Atlas
America and its affiliates may not divest their ownership of one entity without
divesting their ownership of the other entities to the same acquirer. For these
purposes, divestiture means a sale of all or substantially all of the assets of
an entity, the disposition of more than 50% of the capital stock or equity
interest of an entity, or a merger or consolidation that results in Atlas
America and its affiliates, on a combined basis, owning, directly or indirectly,
less than 50% of the entity's capital stock or equity interest. Atlas America
and its affiliates may transfer their interests to each other, or to their
wholly or majority-owned direct or indirect subsidiaries, or to a parent of any
of them, provided that their combined direct or indirect interest is not reduced
to less than 50%.

Natural Gas Gathering Agreements. Under the master natural gas
gathering agreement, we receive a fee from Atlas America for gathering natural
gas, determined as follows:

o for natural gas from well interests allocable to Atlas America, or
its subsidiaries (excluding general or limited partnerships
sponsored by them) that were connected to our gathering systems at
February 2, 2000, the greater of $0.40 per mcf or 16% of the gross
sales price of the natural gas transported;

o for natural gas from well interests allocable to general and
limited partnerships sponsored by Atlas America that are connected
to our gathering systems at any time, and well interests allocable
to independent third parties in wells connected to our gathering
systems before February 2, 2000, the greater of $0.35 per Mcf or
16% of the gross sales price of the natural gas transported;

o for natural gas from well interests allocable to Atlas America that
are connected to our gathering systems after February 2, 2000, the
greater of $0.35 per Mcf or 16% of the gross sales price of the
natural gas transported; and

o for natural gas from well interests operated by Atlas America and
drilled after December 1, 1999 that are connected to a gathering
system that is not owned by us and for which we assume the cost of
constructing the connection to that gathering system, an amount
equal to the greater of $0.35 per Mcf or 16% of the gross sales
price of the natural gas transported, less the gathering fee
charged by the other gathering system.

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Atlas America receives gathering fees from contracts or other
arrangements with third party owners of well interests connected to our
gathering systems. However, Atlas America must pay gathering fees owed to us
from its own resources regardless of whether it receives payment under those
contracts or arrangements.

The master natural gas gathering agreement is a continuing obligation
and, accordingly, has no specified term or provisions regarding termination.
However, if our general partner is removed as our general partner without cause,
then no gathering fees will be due under the agreement with respect to new wells
drilled by Atlas America. The agreement provides that Atlas America, as the
shipper of natural gas, will indemnify us against claims relating to ownership
of the natural gas transported. For all other claims relating to natural gas we
transport, the party that has control and possession of the natural gas must
indemnify the other party with respect to losses arising in connection with or
related to the natural gas when it is in the first party's possession and
control.

In addition to the master natural gas gathering agreement, we have
three other gas gathering agreements with subsidiaries of Atlas America. Under
two of these agreements, relating to wells located in southeastern Ohio which
Atlas America acquired from Kingston Oil Corporation and wells located in
Fayette County, Pennsylvania which Atlas America acquired from American Refining
and Exploration Company, we receive a fee of $0.80 per Mcf. Under the third
agreement, which covers wells owned by third parties unrelated to Atlas America
or the investment partnerships it sponsors, we receive fees that range between
$0.20 to $0.29 per Mcf or between 10% to 16% of the weighted average sales price
for the natural gas we transport.

Credit Facility

We have a $20.0 million credit facility administered by Wachovia Bank,
National Association. Borrowings under the facility are secured by a lien on and
security interest in all of our property and that of our subsidiaries. Up to
$3.0 million of the facility may be used for standby letters of credit. The
credit facility has a term ending 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 London Interbank Offered Rate, or LIBOR, plus the
applicable margin.

The base rate for any day equals the higher of the federal funds rate
plus 1/2 of 1% or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided
by 1.00 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 0.00% for base rate loans and
1.50% 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
2.00% 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.

The credit facility requires us to maintain specified net worth and
specified ratios of current assets to current liabilities and debt to EBITDA,
and requires us to maintain a specified interest coverage ratio.

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Competition

Our gathering systems do not encounter direct competition in their
respective service areas since Atlas America controls the majority of the
drillable acreage in each area. However, because we principally serve wells
drilled by Atlas America we are affected by competitive factors affecting Atlas
America's ability to obtain properties and drill wells, which affects our
ability to expand our gathering systems and to maintain or increase the volume
of natural gas we transport and, thus, our transportation revenues. Atlas
America also may encounter competition in obtaining drilling services from
third-party providers. Any competition it encounters could delay Atlas America
in drilling wells for its sponsored partnerships, and thus delay the connection
of wells to our gathering systems. These delays would reduce the volume of gas
we otherwise would have transported, thus reducing our potential transportation
revenues.

As our omnibus agreement with Atlas America generally requires it to
connect wells it operates to our system, we do not expect any direct competition
in connecting wells drilled and operated by Atlas America in the future. In
addition, we occasionally connect wells operated by third parties. During 2003
we connected no such wells. We did not encounter, nor do we expect, significant
competition to connect such wells as they are generally in close proximity to
our gathering system and distant from others. In any case, revenue derived from
the gas transportation on behalf of third parties represents an insignificant
portion of our annual revenue.

During 2003 we encountered competition in acquiring gas gathering
systems owned by third parties. In several instances we submitted bids in
auction situations and in direct negotiations for the acquisition of existing
gas gathering systems. Except for our bid for Alaska Pipeline, in each case we
were either outbid by others or were unwilling to meet the sellers' expectations
and, as a result, were unsuccessful in acquiring those systems. In the future,
we expect to encounter equal if not greater competition for gathering system
acquisitions because, as gas prices increase, the economic attractiveness of
owning gathering systems increases.

Regulation

Federal Regulation. Under the Natural Gas Act, the Federal Energy
Regulatory Commission regulates various aspects of the operations of any
"natural gas company," including the transportation of natural gas, rates and
charges, construction of new facilities, extension or abandonment of services
and facilities, the acquisition and disposition of facilities, reporting
requirements, and similar matters. However, the Natural Gas Act definition of a
"natural gas company" requires that the company be engaged in the transportation
of natural gas in interstate commerce, or the sale in interstate commerce of
natural gas for resale. Since we believe that each of our individual gathering
systems performs primarily a gathering function, we believe that we are not
subject to regulation under the Natural Gas Act. If we were determined to be a
natural gas company, our operations would become regulated under the Natural Gas
Act. We believe the expenses associated with seeking certificates of authority
for construction, service and abandonment, establishing rates and a tariff for
our gas gathering activities, and meeting the detailed regulatory accounting and
reporting requirements would substantially increase our operating costs and
would adversely affect our profitability, thereby reducing our ability to make
distributions to unitholders.

State Regulation. Our operations are subject to regulation at the state
level. The Public Utility Commission of Ohio, the New York Public Service
Commission and the Pennsylvania Public Utilities Commission regulate the
transportation of natural gas in their respective states. In Ohio, a producer or
gatherer of natural gas may file an application seeking exemption from
regulation as a public utility. We have been granted an exemption by the Public
Utility Commission of Ohio for our Ohio facilities. The New York Public Service
Commission imposes traditional public utility regulation on the transportation
of natural gas by companies subject to its regulation. This regulation includes
rates, services and sitting authority for the construction of certain
facilities. Our gas gathering operations currently are not subject to regulation
by the New York Public Service Commission. Our operations in Pennsylvania
currently are not subject to the Pennsylvania Public Utility Commission's
regulatory authority since they do not provide service to the public generally
and, accordingly, do not constitute the operation of a public utility. In the
event the New York and Pennsylvania authorities seek to regulate our operations,

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we believe that our operating costs could increase and our transportation fees
could be adversely affected, thereby reducing our net revenues and ability to
make distributions to unitholders.

Environmental and Safety Regulations. Under the Comprehensive
Environmental Response, Compensation and Liability Act, the Toxic Substances
Control Act, the Resource Conservation and Recovery Act, the Clean Air Act, the
Clean Water Act and other federal and state laws relating to the environment,
owners of natural gas pipelines can be liable for fines, penalties and clean-up
costs with respect to pollution caused by the pipelines. Moreover, the owners'
liability can extend to pollution costs from situations that occurred prior to
their acquisition of the pipeline. Natural gas pipelines are also subject to
safety regulation under the Natural Gas Pipeline Safety Act of 1968 and the
Pipeline Safety Act of 1992 which, among other things, dictate the type of
pipeline, quality of pipeline, depth, methods of welding and other
construction-related standards. The state public utility regulators discussed
above have either adopted the federal standards or promulgated their own safety
requirements consistent with federal regulations. Although we believe that our
gathering systems comply in all material respects with applicable environmental
and safety regulations, risks of substantial costs and liabilities are inherent
in pipeline operations, and we cannot assure you that we will not incur these
costs and liabilities. Moreover, it is possible that other developments, such as
increasingly rigorous environmental laws, regulations and enforcement policies,
and claims for damages to property or persons resulting from our operations,
could result in substantial costs and liabilities to us.

We are also subject to the requirements of the Occupational Safety &
Health Act, or OSHA, and comparable state statutes. We believe that our
operations comply in all material respects with OSHA requirements, including
general industry standards, record keeping, hazard communication requirements
and monitoring of occupational exposure and other regulated substances.

We have not expended and do not anticipate that we will be required in
the near future to expend, amounts that are material in relation to our revenues
by reason of environmental and safety laws. However, we cannot predict
legislative or regulatory developments or the costs of compliance with those
developments. In general, however, we anticipate that new laws, regulations or
policies will increase our operating costs and impose additional capital
expenditure requirements on us.

Tax Treatment of Publicly Traded Partnerships under the Internal Revenue Code

The Internal Revenue Code of 1986, as amended, imposes certain
limitations on the current deductibility of losses attributable to investments
in publicly traded partnerships and treats certain publicly traded partnerships
as corporations for federal income tax purposes. The following discussion
briefly describes certain aspects of the Code that apply to individuals who are
citizens or residents of the United States without commenting on all of the
federal income tax matters affecting us or the holders of our units, and is
qualified in its entirety by reference to the Code. UNITHOLDERS ARE URGED TO
CONSULT THEIR OWN TAX ADVISOR ABOUT THE FEDERAL, STATE, LOCAL AND FOREIGN TAX
CONSEQUENCES TO THEM OF AN INVESTMENT IN US.

Characterization for Tax Purposes. The Code treats a publicly traded
partnership as a corporation for federal income tax purposes unless, for each
taxable year, 90% or more of its gross income consists of qualifying income.
Qualifying income includes interest, dividends, real property rents, gains from
the sale or disposition of real property, income and gains derived from the
exploration, development, mining or production, processing, refining,
transportation (including pipelines transporting gas, oil or products thereof),
or the marketing of any mineral or natural resource (including fertilizer,
geothermal energy and timber), and gain from the sale or disposition of capital
assets that produce such income. Because we are engaged primarily in the natural
gas pipeline transportation business, we believe that 90% or more of our gross
income has been qualifying income. If this continues to be true and no
subsequent legislation amends that provision, we will continue to be classified
as a partnership and not as a corporation for federal income tax purposes.

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Passive Activity Loss Rules. The Code provides that an individual,
estate, trust, or personal service corporation generally may not deduct losses
from passive activities, to the extent they exceed income from all such passive
activities, against other (active) income. Income that may not be offset by
passive activity losses includes not only salary and active business income, but
also portfolio income such as interest, dividends or royalties or gain from the
sale of property that produces portfolio income. Credits from passive activities
are also limited to the tax attributable to any income from passive activities.
The passive activity loss rules are applied after other applicable limitations
on deductions, such as the at-risk rules and basis limitations.

Under the Code, net income from publicly traded partnerships is not
treated as passive income for purposes of the passive lose rule, but is treated
as non-passive income. Net losses and credits attributable to an interest in a
publicly traded partnership may not be used to offset a partner's other income.
Thus, a unitholder's proportionate share of our net losses may be used to offset
only partnership net income from our trade or business in succeeding taxable
years or, upon a complete disposition of a unitholder's interest in us to an
unrelated person in a fully taxable transaction, may be used to offset gain
recognized upon the disposition, and then against all other income of the
unitholder. In effect, net losses are suspended and carried forward indefinitely
until utilized to offset net income of the partnership from its trade or
business or allowed upon the complete disposition to an unrelated person in a
fully taxable transaction of the unitholder's interest in the partnership. A
unitholder's share of partnership net income may not be offset by passive
activity losses generated by other passive activities. In addition, a
unitholder's proportionate share of our portfolio income, including portfolio
income arising from the investment of our working capital, is not treated as
income from a passive activity and may not be offset by such unitholder's share
of net losses of the partnership.

Deductibility of Interest Expense. The Code generally provides that
investment interest expense is deductible only to the extent of a non-corporate
taxpayer's net investment income. In general, net investment income for purposes
of this limitation includes gross income from property held for investment, gain
attributable to the disposition of the property held for investment (except for
net capital gains for which the taxpayer has elected to be taxed at special
capital gains rates) and portfolio income (determined pursuant to the passive
lose rules) reduced by certain expenses (other than interest) which are directly
connected with the production of such income. Property subject to the passive
loss rules is not treated as property held for investment. However, the IRS has
issued a Notice which provides that net income from a publicly traded
partnership (not otherwise treated as a corporation) may be included in net
investment income for purposes of the limitation on the deductibility of
investment interest. A unitholder's investment income attributable to its
interest in us will include both its allocable share of our portfolio income and
trade or business income. A unitholder's investment interest expense will
include its allocable share of our interest expense attributable to portfolio
investments.

Unrelated Business Taxable Income. Certain entities otherwise exempt
from federal income taxes (such as individual retirement accounts, pension plans
and charitable organizations) are nevertheless subject to federal income tax on
net unrelated business taxable income and each such entity must file a tax
return for each year in which it has more than $1,000 of gross income from
unrelated business activities. We believe that substantially all of our gross
income will be treated as derived from an unrelated trade or business and
taxable to such entities. The tax-exempt entity's share of our deductions
directly connected with carrying on such unrelated trade or business are allowed
in computing the entity's taxable unrelated business income.

State Tax Treatment. During 2003, we owned property or conducted
business in the states of Pennsylvania, New York and Ohio. A unitholder is
required to file state income tax returns and to pay applicable state income
taxes in the states and may be subject to penalties for failure to comply with
such requirements. None of these states have required that we withhold a
percentage of income attributable to our operations within the state for
unitholders who are non-residents of the state. In the event that one or more of
them do require withholding in the future, (which may be greater or less than a
particular unitholder's income tax liability to the state), such withholding
would generally not relieve the non-resident unitholder from the obligation to
file a state income tax return.

- 11 -

Depreciation. Upon our formation in 2000, we elected fifteen-year 150%
declining-balance depreciation for tax purposes. Unitholders, however, will
continue to offset partnership income with individual unitholder depreciation
pursuant to our Section 754 election. Each unitholder's tax situation will
differ depending upon the price paid and when units were purchased. Furthermore,
sale of units will result in a portion of gain (if any) being taxable as
ordinary income through recapture of previous deductions for depreciation.

Employees

As is commonly the case with publicly traded limited partnerships, we
do not directly employ any of the persons responsible for our management or
operations. In general, employees of Atlas America and its parent company,
Resource America, Inc., manage the gathering systems and operate our business.
Affiliates of our general partner will conduct business and activities of their
own in which we will have no economic interest. If these separate activities are
significantly greater than our activities, there could be material competition
between us, our general partner and affiliates of our general partner for the
time and effort of the officers and employees who provide services to our
general partner. The officers of our general partner who provide services to us
are not required to work full time on our affairs. These officers may devote
significant time to the affairs of our general partner's affiliates and be
compensated by these affiliates for the services rendered to them. There may be
significant conflicts between us and affiliates of our general partner regarding
the availability of these officers to manage us.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934,
including our annual report on Form 10-K, our quarterly reports on Form 10-Q and
our current reports on Form 8-K, available through the website of Resource
America, Inc., the parent of our general partner, at www.resourceamerica.com. To
view these reports, click on "Investor Relations," then "APL Investor
Information," then "SEC Filings." We do not have a separate website. You may
also receive a paper copy of any such filings by request to us at 311 Rouser
Road, Moon Township, Pennsylvania 15108, tel. no. (412) 262-2830.

- 12 -

Risk Factors

Limited partner interests are inherently different from the capital
stock of a corporation, although many of the business risks to which we are
subject are similar to those that would be faced by a corporation engaged in a
similar business. If any of the following risks actually occurs, our business,
financial condition or results of operations could be materially adversely
affected. In that case, the trading price of our common units could decline and
investors may lose some or all of their investment.

Risks Inherent in Our Business

Our cash distributions are not assured and may fluctuate with our
performance. The amounts of cash that we generate may not be sufficient to pay
the minimum quarterly distributions established in our partnership agreement or
any other level of distributions. The actual amounts of cash we generate will
depend upon numerous factors relating to our business which may be beyond our
control, including:

o the demand for and price of natural gas;
o the volume of natural gas we transport;
o continued development of wells for connection to our gathering
systems;
o the expenses we incur in providing our gathering services;
o the cost of acquisitions and capital improvements;
o our issuance of equity securities;
o required principal and interest payments on our debt;
o prevailing economic conditions;
o fuel conservation measures;
o alternate fuel requirements;
o government regulations; and
o technical advances in fuel economy and energy generation devices.

Our ability to make cash distributions depends primarily on our cash
flow. Cash distributions do not depend directly on our profitability, which is
affected by non-cash items. Therefore, cash distributions may be made during
periods when we record losses and may not be made during periods when we record
profits.

The failure of Atlas America to perform its obligations under the
natural gas gathering agreements may adversely affect our revenues. Our revenues
currently consist of the fees we receive under the master natural gas gathering
agreement and other transportation agreements we have with Atlas America and its
affiliates. While Atlas America receives gathering fees from the well owners, it
is contractually obligated to pay our fees even if the gathering fees paid to it
by well owners are less than the fees it must pay us. Our cash flow could be
materially adversely affected if Atlas America failed to discharge its
obligations to us.

The amount of natural gas we transport will decline over time unless
new wells are connected to our gathering systems. Production of natural gas from
a well generally declines over time until the well can no longer economically
produce natural gas and is plugged and abandoned. Failure to connect new wells
to our gathering systems could, therefore, result in the amount of natural gas
we transport reducing substantially over time and could, upon exhaustion of the
current wells, cause us to abandon one or more of our gathering systems and,
possibly, cease operations. As a consequence, our revenues and, thus, our
ability to make distributions to unitholders would be materially adversely
affected unless new wells are connected to our gathering systems.

- 13 -

We entered into the omnibus agreement described in "Agreements with
Atlas America-Omnibus Agreement" to, among other things, increase the number of
natural gas wells connected to our gathering systems. However, well connections
resulting from that agreement depend principally upon the success of Atlas
America in sponsoring drilling investment partnerships and completing wells for
these partnerships in areas where our gathering systems are located. If Atlas
America cannot or does not continue to organize these partnerships, if the
amount of money raised by these partnerships decreases, or if the number of
wells actually drilled and completed as commercial producing wells decreases,
our revenues and ability to make cash distributions will be materially adversely
affected.

The amount of natural gas we transport may be reduced if the public
utility pipelines to which we deliver gas cannot or will not accept the gas. Our
gathering systems principally serve as intermediate transportation facilities
between sales lines from wells connected to our systems and the public utility
pipelines to which we deliver natural gas. If one or more of these public
utility pipelines has service interruptions, capacity limitations or otherwise
does not accept the natural gas we transport, and we cannot arrange for delivery
to other public utility pipelines, local distribution companies or end users,
the amount of natural gas we transport may be reduced. Since our revenues depend
upon the volumes of natural gas we transport, this could result in a material
reduction in our revenues.

We will incur substantial indebtedness to acquire Alaska Pipeline which
may restrict our liquidity and, if interest rates increase, affect cash flow
from the acquisition. We intend to finance the Alaska Pipeline acquisition in
part through borrowing all of the $20.0 million available under our existing
credit facility. Unless the borrowing is paid down, or the amount of
availability increased, we will not have further borrowing capacity to finance
future acquisitions, capital expenditures or other liquidity needs. Moreover,
since this borrowing, and the $50.0 million borrowing that APC Acquisition LLC
(the entity we have formed to acquire Alaska Pipeline) will also make to finance
the acquisition, are at variable interest rates, any increase in interest rates
will adversely affect the cash flow we expect to derive from the acquisition.
While we intend to make a public offering of our common units and use the
proceeds, in part, to reduce the amount of these borrowings, we may be unable to
complete such an offering on acceptable terms, or at all.

Governmental regulation of our pipelines could increase our operating
costs. Currently our gathering of natural gas from wells is exempt from
regulation under the Natural Gas Act. However, the implementation of new laws or
policies could subject us to regulation by the Federal Energy Regulatory
Commission under the Natural Gas Act. We expect that any such regulation would
increase our costs, decrease our revenues, or both, as discussed under
"Regulation."

Gas gathering operations are subject to regulation at the state level.
Matters subject to regulation include rates, service and safety. We have been
granted an exemption from regulation as a public utility in Ohio. Presently, our
rates are not regulated in New York and Pennsylvania. Changes in state
regulations, or our status under these regulations that subject us to further
regulation, could decrease our revenues, increase our operating costs or require
material capital expenditures.

- 14 -

Litigation or governmental regulation relating to environmental
protection and operational safety may result in substantial costs and
liabilities. Our operations are subject to federal and state environmental laws
under which owners of natural gas pipelines can be liable for clean-up costs and
fines in connection with any pollution caused by their pipelines. We may also be
held liable for clean-up costs resulting from pollution which occurred before
our acquisition of the gathering systems. In addition, we are subject to federal
and state safety laws that dictate the type of pipeline, quality of pipe
protection, depth, methods of welding and other construction-related standards.
Any violation of environmental, construction or safety laws could impose
substantial liabilities and costs on us.

We are also subject to the requirements of the OSHA, and comparable
state statutes. Any violation of OSHA could impose substantial costs on us.

We cannot predict whether or in what form any new legislation or
regulatory requirements might be enacted or adopted, nor can we predict our
costs of compliance. In general, we expect that new regulations would increase
our operating costs and, possibly, require us to obtain additional capital to
pay for improvements or other compliance action necessitated by those
regulations.

We may not be able to fully execute our growth strategy. Our current
strategy contemplates substantial growth through both the acquisition of other
gathering systems and the development of our existing system. Typically, we have
paid for system development in cash and have made acquisitions either for cash
or a combination of cash and common units. As a result, limitations on our
access to capital or on the market for our common units will impair our ability
to execute our growth strategy. In addition, our strategy of growth through
acquisitions involves numerous risks, including:

o we may not be able to identify suitable acquisition candidates;

o we may not be able to make acquisitions on economically acceptable
terms;

o our costs in seeking to make acquisitions may be material, even if
we cannot complete an acquisition we have pursued;

o irrespective of estimates at the time we make an acquisition, the
acquisition may prove to be dilutive to earnings and operating
surplus; and

o we may encounter difficulties in integrating operations and
systems.

If Atlas America and its affiliates default on their obligations to us,
we do not have contractual recourse to Resource America. The omnibus agreement
and natural gas agreements with Atlas America are material to our business,
financial condition and results of operations. Although Atlas America is a
subsidiary of Resource America, Resource America has not guaranteed or otherwise
assumed responsibility for any of these obligations.

A decline in natural gas prices could adversely affect our revenues.
Our gathering fees are generally equal to a percentage of either the gross or
weighted average sales price of the natural gas we transport, although in some
cases we receive a flat fee per Mcf of gas transported. Our income therefore
depends upon the prices at which the natural gas we transport is sold.
Historically, the price of natural gas has been volatile; as a result, our
income may vary widely from period to period.

Gathering system operations are subject to operational hazards and
unforeseen interruptions. The operations of our gathering systems are subject to
hazards and unforeseen interruptions, including natural disasters, adverse
weather, accidents or other events beyond our control. A casualty occurrence
might result in injury and extensive property or environmental damage. Our
insurance coverage may not be sufficient for any casualty loss we may incur.

- 15 -

ITEM 2. PROPERTIES

As of December 31, 2003, our principal facilities include approximately
1,380 miles of 2-inch to 12-inch diameter pipeline and 56 compressors, of which
four are leased from third parties. Substantially all of our gathering systems
are constructed within rights-of-way granted by property owners named in the
appropriate land records. In a few cases, property for gathering system purposes
was purchased in fee. All of our compressor stations are located on property
owned in fee or on property under long-term leases

Our property or rights-of-way are subject to encumbrances, restrictions
and other imperfections, although these imperfections have not interfered, and
our general partner does not expect that they will materially interfere with the
conduct of our business. In many instances, lands over which rights-of-way have
been obtained are subject to prior liens which have not been subordinated to the
right-of-way grants. In a few instances, our rights-of-way are revocable at the
election of the land owners. In some cases, not all of the owners named in the
appropriate land records have joined in the right-of-way grants, but in
substantially all such cases signatures of the owners of majority interests have
been obtained. Substantially all permits have been obtained from public
authorities to cross over or under, or to lay facilities in or along, water
courses, county roads, municipal streets, and state highways, where necessary,
although in some instances these permits are revocable at the election of the
grantor. Substantially all permits have also been obtained from railroad
companies to cross over or under lands or rights-of-way, many of which are also
revocable at the grantor's election.

Certain of our rights to lay and maintain pipelines are derived from
recorded gas well leases, which wells are currently in production; however, the
leases are subject to termination if the wells cease to produce. In some of
these cases, the right to maintain existing pipelines continues in perpetuity,
even if the well associated with the lease ceases to be productive. In addition,
because many of these leases affect wells at the end of lines, these
rights-of-way will not be used for any other purpose once the related wells
cease to produce.

ITEM 3. LEGAL PROCEEDINGS

We are not, nor are any of our gathering systems, subject to any
pending legal proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of the common unitholders during
the fourth quarter of the year ended December 31, 2003.

- 16 -

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS

Our common units are listed on the American Stock Exchange under the
symbol "APL." As of December 31, 2003, 74 holders of record held our common
units. In connection with our initial public offering, we also issued 1,641,026
subordinated units, discussed below, all of which are held by our general
partner. There is no established public trading market for the subordinated
units.

The following table sets forth the range of high and low sales prices
of our common units and distributions per unit on our common and subordinated
units for the last two years.

Distributions
High Low Declared
---------- -------- -------------

Fiscal 2003
-----------
Fourth Quarter.................................. $ 42.50 $ 34.70 $ .625
Third Quarter................................... $ 36.00 $ 29.40 $ .62
Second Quarter.................................. $ 31.70 $ 24.16 $ .58
First Quarter................................... $ 28.96 $ 24.90 $ .56

Fiscal 2002
-----------
Fourth Quarter.................................. $ 27.90 $ 21.80 $ .54
Third Quarter................................... $ 26.95 $ 20.40 $ .54
Second Quarter.................................. $ 29.10 $ 22.00 $ .54
First Quarter................................... $ 29.60 $ 23.51 $ .52

Our partnership agreement generally requires us to distribute available
cash 98% to the limited partners and 2% to our general partner except for our
general partner's incentive distribution rights. These rights require
distributions of increased percentages of available cash to the general partner
as distributions to limited partners exceed specified minimums, as follows:

Percent of Available
Cash in Excess
Minimum Distributions of Minimum Allocated
Per Unit Per Quarter to the General Partner
-------------------- ----------------------
$ .42 15%
$ .52 25%
$ .60 50%

Available cash generally means for any of our quarters, all cash on
hand at the end of the quarter less cash reserves that our general partner
determines are appropriate to provide for our operating costs, including
potential acquisitions, and to provide funds for distributions to the partners
for any one or more of the next four quarters.

Our partnership agreement allocates distributions to limited partners
in accordance with their relative number of units except that, during the
subordination period, distributions to subordinated units are subordinated to
the receipt by the common units of a minimum quarterly distribution of $.42 per
common unit, plus any unpaid minimum quarterly distribution amounts from prior
periods. The subordination period terminates on January 1, 2005 unless we do not
meet certain financial criteria established by our partnership agreement.

- 17 -

We make distributions of available cash to unitholders regardless of
whether the amount distributed is less than the minimum quarterly distribution.
If distributions from available cash on the common units for any quarter during
the subordination period are less than the minimum quarterly distribution of
$.42 per common unit, holders of common units will be entitled to arrearages.
Common unit arrearages will accrue and be payable in a future quarter after the
minimum quarterly distribution is paid for the quarter. Subordinated units will
not accrue any arrearages on distributions for any quarter. Upon expiration of
the subordination period, the subordinated units will convert into common units
on a one-for-one basis, and will then participate pro rata with the other common
units in distributions of our available cash.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data should be read together with our
consolidated financial statements, the notes to our consolidated financial
statements and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 7 in this report. We have derived the selected
financial data set forth below for each of the years ended December 31, 2003,
2002 and 2001 and at December 31, 2003 and 2002 from our consolidated financial
statements appearing elsewhere in this report, which have been audited by Grant
Thornton LLP, independent accountants. The financial data for the period ended
December 31, 2000 is for the period beginning with the inception of our
operations on January 28, 2000 through December 31, 2000; and, accordingly, we
deem January 28, 2000 to be the commencement of our operations and we refer to
the period from that date through December 31, 2000 to as the year ended
December 31, 2000.

For the years ended December 31,
---------------------------------------------------------
2003 2002 2001 2000
------------- -------------- ------------- --------------
(in thousands, except average transportation rate and
per unit data)

Income statement data:
Revenues.......................................................... $ 15,749 $ 10,667 $ 13,129 $ 9,466
========== ========== ========== ===========
Total transportation and compression, general and
administrative expenses........................................ $ 4,081 $ 3,544 $ 3,042 $ 1,813
========== ========== ========== ===========
Depreciation and amortization..................................... $ 1,770 $ 1,476 $ 1,356 $ 1,020
========== ========== ========== ===========
Net income........................................................ $ 9,639 $ 5,398 $ 8,556 $ 6,625
========== ========== ========== ===========
Average transportation rate per Mcf............................... $ .82 $ .58 $ .76 $ .65
========== ========== ========== ===========
Net income per limited partner unit - basic and diluted........... $ 2.17 $ 1.54 $ 2.30 $ 2.07
========== ========== ========== ===========

At December 31,
---------------------------------------------------------
2003 2002 2001 2000
------------- -------------- ------------- --------------
(in thousands, except per unit data)

Balance sheet data:
Total assets..................................................... $ 49,512 $ 28,515 $ 26,002 $ 22,092
========== ========== ========== ===========
Long-term debt................................................... $ - $ 6,500 $ 2,089 $ -
========== ========== ========== ===========

Common unitholders' capital...................................... $ 43,551 $ 19,164 $ 20,129 $ 18,122
Subordinated unitholder's capital................................ 354 684 1,661 2,074
General partner's capital (deficit).............................. 340 (161) (116) (89)
---------- ---------- ---------- -----------
Total partners' capital.......................................... $ 44,245 $ 19,687 $ 21,674 $ 20,107
========== ========== ========== ===========
Distributions declared per common unit........................... $ 2.38 $ 2.14 $ 2.50 $ 1.85
========== ========== ========== ===========

- 18 -

For the years ended December 31,
---------------------------------------------------------
2003 2002 2001 2000
------------- -------------- ------------- --------------
(in thousands)

Other financial data:
Net cash provided by operating activities......................... $ 13,702 $ 8,138 $ 10,268 $ 5,968
========== ========== ========== ===========
Net cash used in investing activities............................. $ (9,154) $ (5,231) $ (3,128) $ (17,965)
========== ========== ========== ===========
Net cash provided by (used in) financing activities............... $ 8,671 $ (3,211) $ (7,022) $ 14,039
========== ========== ========== ===========

EBITDA means income before net interest expense, income taxes and
depreciation and amortization. EBITDA is not intended to represent cash flow and
does not represent the measure of cash available for distribution. Our method of
computing EBITDA may not be the same method used to compute similar measures
reported by other companies, or EBITDA may be computed differently by us in
different contexts (i.e., public reporting versus computation under financing
agreements).

Certain items excluded from EBITDA are significant components in
understanding and assessing a company's financial performance, such as a
company's cost of capital and its tax structure, as well as historic costs of
depreciable assets. We have included information concerning EBITDA because
EBITDA provides investors and management with additional information as to our
ability to pay our fixed charges and is presented solely as a supplemental
financial measure. EBITDA should not be considered as an alternative to, or more
meaningful than, net income or cash flow as determined in accordance with
generally accepted accounting principles or as an indicator of our operating
performance or liquidity. The table below shows our EBITDA and reconciles it to
our net income.

For the years ended December 31,
---------------------------------------------------------
2003 2002 2001 2000
------------- -------------- ------------- --------------
(in thousands)

Income data:
Net income........................................................ $ 9,639 $ 5,398 $ 8,556 $ 6,625
Interest expense.................................................. 258 250 176 9
Depreciation and amortization..................................... 1,770 1,476 1,356 1,020
---------- ---------- ---------- -----------
EBITDA............................................................ $ 11,667 $ 7,124 $ 10,088 $ 7,654
========== ========== ========== ===========

- 19 -

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-K the words "believes" "anticipates"
"expects" and similar expressions are intended to identify forward-looking
statements. Such statements are subject to certain risks and uncertainties more
particularly described in Item 1 of this report, under the caption "Risk
Factors". These risks and uncertainties could cause actual results to differ
materially. Readers are cautioned not to place undue reliance on these
forward-looking statements, which speak only as of the date hereof. We undertake
no obligation to publicly release the results of any revisions to
forward-looking statements which we may make to reflect events or circumstances
after the date of this Form 10-K or to reflect the occurrence of unanticipated
events.

The following information is provided to assist in understanding our
financial condition and results of operations. This discussion should be read in
conjunction with our consolidated financial statements and related notes
appearing elsewhere in this report.

General

Our principal business objective is to generate income for distribution
to our unitholders from the transportation of natural gas through our gathering
systems. Our gathering systems gather natural gas from wells in eastern Ohio,
western New York, and western Pennsylvania and transport the natural gas
primarily to public utility pipelines. To a lesser extent, the gathering systems
transport natural gas to end-users.

In September 2003, we entered into a purchase and sale agreement with
SEMCO under which we or our designee will purchase all of the outstanding equity
of SEMCO's wholly-owned subsidiary, Alaska Pipeline, L.L.C., which owns a
354-mile intrastate natural gas transmission pipeline that delivers gas to
metropolitan Anchorage. The total consideration, payable in cash at closing,
will be approximately $95.0 million, subject to an adjustment based on the
amount of working capital that Alaska Pipeline has at closing. Completion of the
transaction is subject to a number of conditions, including receipt of
governmental and non-governmental consents and approvals and the absence of a
material adverse change in Alaska Pipeline's business. Among the required
governmental authorizations are approval of the Regulatory Commission of Alaska
and expiration, without adverse action, of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act. We received an early termination
of the Hart-Scott-Rodino waiting period in January 2004. The purchase and sale
agreement may be terminated by either SEMCO or us if the transaction is not
completed by June 16, 2004.

- 20 -

Results of Operations

In the years ended December 31, 2003, 2002 and 2001, our principal
revenues came from the operation of our pipeline gathering systems which
transport and compress natural gas. Two variables which affect our
transportation revenues are:

o the volumes of natural gas transported by us which, in turn, depend
upon the number of wells connected to our gathering system, the
amount of natural gas they produce, and the demand for that natural
gas; and

o the transportation fees paid to us which, in turn, depend upon the
price of the natural gas we transport, which itself is a function
of the relevant supply and demand in the mid-Atlantic and
northeastern areas of the United States.

We set forth the average volumes we transported, our average
transportation rates per Mcf and revenues received by us for the periods
indicated in the following table:

For the years ended
December 31,
--------------------------------------------------
2003 2002 2001
------------- -------------- -------------

Average daily throughput volumes, in Mcf....................... 52,472 50,363 46,918
============= ============== =============
Average transportation rate per Mcf............................ $ .82 $ .58 $ .76
============= ============== =============
Total transportation and compression revenues.................. $ 15,650,800 $ 10,660,300 $ 13,094,700
============= ============== =============

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Revenues. Our transportation and compression revenues increased to
$15,650,800 in the year ended December 31, 2003 from $10,660,300 in the year
ended December 31, 2002. This increase of $4,990,500 (47%) resulted from an
increase in the average transportation rate paid to us ($4,361,500) and an
increase in the volumes of natural gas we transported ($629,000).

Our transportation rate was $.82 per Mcf in the year ended December 31,
2003 as compared to $.58 per Mcf in the year ended December 31, 2002, an
increase of $.24 per Mcf (41%). During the year ended December 31, 2003, natural
gas prices increased significantly over the year ended December 31, 2002. Since
our transportation rates are generally at fixed percentages of the sale prices
of the natural gas we transport, the higher prices resulted in an increase in
our average transportation rate.

Our average daily throughput volumes were 52,472 Mcfs in the year ended
December 31, 2003 as compared to 50,363 Mcfs in the year ended December 31,
2002, an increase of 2,109 Mcfs (4%). The increase in the average daily
throughput volume resulted principally from volumes associated with new wells
added to our pipeline system; we turned on-line 270 and 214 wells in the years
ended December 31, 2003 and 2002, respectively. These increases were partially
offset by the natural decline in production volumes from existing wells
connected to our gathering systems.

Costs and Expenses. Our transportation and compression expenses
increased to $2,420,500 in the year ended December 31, 2003 as compared to
$2,061,600 in the year ended December 31, 2002, an increase of $358,900 (17%).
Our average cost per Mcf of transportation and compression increased to $.13 in
the year ended December 31, 2003 as compared to $.11 in the year ended December
31, 2002, an increase of $.02 (18%). This increase resulted primarily from an
increase in compressor expenses due to the addition of more compressors and
increased lease rates for our compressors. However, during 2003, we have
substantially completed the process of purchasing several compressors which we
previously leased. We anticipate this will reduce future compressor expenses on
a per Mcf basis.

- 21 -

Our general and administrative expenses increased to $1,660,900 in the
year ended December 31, 2003 as compared to $1,481,900 in the year ended
December 31, 2002, an increase of $179,000 (12%). This increase primarily
resulted from an increase of $600,000 in allocations of compensation and
benefits from Atlas America and its affiliates due to an increase in management
time spent during the year on acquisitions, potential acquisitions and our
public offering. This increase was largely offset by a decrease in professional
fees which, in the prior period, had been higher than normal due to costs
associated with the proposed acquisition of Triton Coal Company. We were also
reimbursed $156,100 by Atlas America in the current year for one half of our
unreimbursed costs associated with the proposed Triton acquisition.

Our depreciation and amortization expense increased to $1,770,500 in
the year ended December 31, 2003 as compared to $1,475,600 in the year ended
December 31, 2002, an increase of $294,900 (20%). This increase resulted from
our increased asset base associated with pipeline extensions and compressor
upgrades and purchases. We anticipate that our depreciation expense will
increase in 2004 as a result of our pipeline extensions and compressor upgrades.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Revenues. Our transportation revenue decreased to $10,660,300 in the
year ended December 31, 2002 from $13,094,700 in the year ended December 31,
2001. This decrease of $2,434,400 (19%) resulted from a decrease in the average
transportation rate paid to us ($3,163,700), partially offset by an increase in
the volumes of natural gas we transported ($729,300).

Our average daily throughput volumes were 50,363 Mcfs in the year ended
December 31, 2002 as compared to 46,918 Mcfs in the year ended December 31,
2001, an increase of 3,445 Mcfs (7%). The increase in the average daily
throughput volume resulted principally from volumes associated with new wells
added to our pipeline system; we turned on-line 214 and 234 wells in the years
ended December 31, 2002 and 2001, respectively. These increases were partially
offset by the natural decline in production volumes inherent in the life of a
well.

Our average transportation rate was $.58 per Mcf in the year ended
December 31, 2002 as compared to $.76 per Mcf in the year ended December 31,
2001, a decrease of $.18 per Mcf (24%). The decrease in our average
transportation rate resulted from the decrease in the average natural gas price
received by producers for gas transported through our pipeline system.

Costs and Expenses. Our transportation and compression expenses
increased to $2,061,600 in the year ended December 31, 2002 as compared to
$1,929,200 in the year ended December 31, 2001, an increase of $132,400 (7%),
principally due to the increased volumes of natural gas we transported in 2002.
Our average cost per Mcf of transportation and compression was $.11 in both the
years ended December 31, 2002 and 2001.

Our general and administrative expenses increased to $1,481,900 in the
year ended December 31, 2002 as compared to $1,112,800 in the year ended
December 31, 2001, an increase of $369,100 (33%). This increase primarily
resulted from professional fees of $268,500 incurred in connection with the
terminated Triton transaction (see Note 10 to our consolidated financial
statements) and our cost of insurance ($92,000) reflecting increased operating
activities and assets, as well as significant increases in insurance rates in
general.

Our depreciation and amortization expense increased to $1,475,600 in
the year ended December 31, 2002 as compared to $1,356,100 in the year ended
December 31, 2001, an increase of $119,500 (9%). This increase resulted from the
increased asset base associated with pipeline extensions and acquisitions
partially offset by a reduction in goodwill amortization as compared to the
previous period due to the adoption of Statement of Financial Accounting
Standards No. 142 on January 1, 2002.

Our interest expense increased to $249,800 in the year ended December
31, 2002 as compared to $175,600 in the year ended December 31, 2001. This
increase of $74,200 (42%) resulted primarily from the write-off of deferred
finance fees of $51,000 relating to our former credit facility with PNC Bank,
which we paid off upon obtaining our current credit facility with Wachovia Bank.
In addition, we had an increase in the amount of funds borrowed due to an
increase in pipeline extensions. These increases were partially offset by lower
borrowing rates.

- 22 -

Liquidity and Capital Resources

Our primary cash requirements, in addition to normal operating
expenses, are for debt service, maintenance capital expenditures, expansion
capital expenditures and quarterly distributions to our unitholders and general
partner. In addition to cash generated from operations, we have the ability to
meet our cash requirements, other than distributions to our unitholders and
general partner, through borrowings under our credit facility. In general, we
expect to fund:

o cash distributions and maintenance capital expenditures through
existing cash and cash flows from operating activities;

o expansion capital expenditures and working capital deficits through
the retention of cash and additional borrowings;

o debt principal payments through additional borrowings as they
become due or by the issuance of additional common units.

In September 2003 we entered into an agreement to purchase Alaska
Pipeline, L.L.C., subject to certain conditions, principally the expiration of
the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and
the approval of the Regulatory Commission of Alaska. We received an early
termination of the Hart-Scott-Rodino waiting period in January 2004. We discuss
this transaction and its potential effects on our liquidity and capital
resources in "Pending Acquisition."

At December 31, 2003, we had no outstanding borrowings and $20.0
million of remaining borrowing capacity under our credit facility.

The following table summarizes our financial condition and liquidity at
the dates indicated:

At December 31,
------------------------------------
2003 2002 2001
------- -------- --------

Current ratio.................................................. 2.9x 1.0x 1.6x
Working capital (in thousands)................................. $ 9,890 $ 57 $ 1,359
Ratio of long-term debt to total partners' capital............. N/A .33x .10x

Net cash provided by operations of $13,701,900 in the year ended
December 31, 2003 increased $5,563,900 from $8,138,000 in the year ended
December 31, 2002. The increase derived principally from income from operations
and changes in our operating assets and liabilities. Net income before
depreciation and amortization was $11,515,200 in the year ended December 31,
2003, an increase of $4,551,600 from the year ended December 31, 2002. This
increase was principally due to the increase in the average transportation rate
we received in the year ended December 31, 2003 as compared to the year ended
December 31, 2002. During the year ended December 31, 2003, our accounts
payable-affiliates increased as a result of advances from Atlas America in
connection with expenses associated with the pending acquisition of Alaska
Pipeline.

Net cash used in investing activities was $9,153,600 for the year ended
December 31, 2003, an increase of $3,923,000 from $5,230,600 in the year ended
December 31, 2002. The reason for this increase was an increase in expenditures
related to gathering system extensions and compressor upgrades to accommodate
new wells drilled by Atlas America and its affiliates and expenditures of
$1,519,400 associated with our pending acquisition.

- 23 -

Net cash provided by financing activities was $8,671,200 for the year
ended December 31, 2003, an increase of $11,882,200 from cash used in financing
activities of $3,211,000 in the year ended December 31, 2002. The principal
reason for the increase was the completion of our public offering in May 2003,
which provided net cash of $17,220,100 after repayment of our outstanding
indebtedness and the receipt of a $538,500 capital contribution from our General
Partner. Offsetting this increase was an increase in distributions of $2,039,600
and cash spent on other assets as a result of financing costs associated with
obtaining a new credit facility.

Partnership Distributions

Our partnership agreement requires that we distribute 100% of available
cash to our partners within 45 days following the end of each calendar quarter
in accordance with their respective percentage interests. Available cash
consists generally of all of our cash receipts, less cash disbursements and net
additions to reserves, including any reserves required under debt instruments
for future principal and interest payments.

Our general partner is granted discretion by our partnership agreement
to establish, maintain and adjust reserves for future operating expenses, debt
service, maintenance capital expenditures, rate refunds and distributions for
the next four quarters. These reserves are not restricted by magnitude, but only
by type of future cash requirements with which they can be associated. When our
general partner determines our quarterly distributions, it considers current and
expected reserve needs along with current and expected cash flows to identify
the appropriate sustainable distribution level.

Available cash is initially distributed 98% to our limited partners and
2% to our general partner. These distribution percentages are modified to
provide for incentive distributions to be paid to our general partner if
quarterly distributions to unitholders exceed specified targets, as described in
Item 5 of this report.

Incentive distributions are generally defined as all cash distributions
paid to our general partner that are in excess of 2% of the aggregate amount of
cash being distributed. The general partner's incentive distribution for year
ended December 31, 2003 was $594,000.

Capital Expenditures

Our property and equipment was approximately 60% and 83% of our total
consolidated assets at December 31, 2003 and 2002, respectively. Capital
expenditures, other than the acquisitions of gathering systems, were $7.6
million and $5.1 million for the years ended December 31, 2003 and 2002,
respectively. These capital expenditures principally consisted of costs relating
to the expansion of our existing gathering systems to accommodate new wells
drilled in our service area and compressor upgrades. During 2003, we connected
270 wells to our gathering system. As of December 31, 2003, we were committed to
expend approximately $1,117,000 in connection with our decision to purchase our
compressors rather than lease them and approximately $810,000 on pipeline
extensions. In addition, we anticipate capital expenditures of $5.2 million in
2004 for maintenance and expansion associated with Alaska Pipeline, our pending
acquisition. We anticipate that our capital expenditures will increase in 2004
as a result of an increase in the estimated number of well connections to our
gathering systems.

- 24 -

Pending Acquisition

As described in Item 1, "Business," and in Note 9 to our consolidated
financial statements, we have agreed to acquire Alaska Pipeline for $95.0
million. We anticipate incurring approximately $4.0 million in costs in
connection with the transaction. The acquisition is contingent upon the
satisfaction of certain conditions, principally approval of the transaction by
the Regulatory Commission of Alaska and the expiration of the waiting period
under the Hart-Scott-Rodino Antitrust Improvements Act. We received an early
termination of the Hart-Scott-Rodino waiting period in January 2004. We intend
to fund the acquisition price and expenses as follows:

o We will borrow all of the $20.0 million available under our
existing credit facility. We will use this amount, plus $4.0
million of advances from our General Partner, to make a common
equity contribution to APC Acquisition, the newly-formed entity
that will acquire Alaska Pipeline Company, L.L.C.

o Friedman, Billings, Ramsey Group, Inc. has committed to make a
$25.0 million preferred equity contribution in APC Acquisition.

o APC Acquisition has received a commitment for a $50.0 million
credit facility to be administered by Wachovia Bank. It will borrow
$50.0 million under this facility.

We anticipate that we will repay the equity financing from Friedman,
Billings, Ramsey Group and some portion of either or both of the Wachovia Bank
credit facilities with the proceeds of an offering of common units. We cannot
assure you, however, that we will be able to complete the anticipated offering.
If we do not, then the equity and debt financings will continue. While the
continuation of these financings will reduce our capacity for further borrowing
and reduce the amount of cash from operations that would otherwise be available
to us from the combination of our operations with those of Alaska Pipeline
Company, we believe that our remaining liquidity and capital resources would be
sufficient to meet our post-acquisition operational needs.

Inflation and Changes in Prices

Inflation affects the operating expenses of our gathering systems.
Increases in those expenses are not necessarily offset by increases in
transportation fees that the gathering operations are able to charge. We have
not been materially affected by inflation because we were formed relatively
recently and have only a limited period of operations. While we anticipate that
inflation will affect our future operating costs, we cannot predict the timing
or amounts of any such effects. In addition, the value of our gathering systems
has been and will continue to be affected by changes in natural gas prices.
Natural gas prices are subject to fluctuations which we are unable to control or
accurately predict.

Environmental Regulation

Our operations are subject to federal, state and local laws and
regulations governing the release of regulated materials into the environment or
otherwise relating to environmental protection or human health or safety. We
believe that our operations and facilities are in substantial compliance with
applicable environmental laws and regulations. Any failure to comply with these
laws and regulations may result in the assessment of administrative, civil and
criminal penalties, imposition of remedial requirements, and issuance of
injunctions as to future compliance or other mandatory or consensual measures.
We have an ongoing environmental compliance program. However, risks of
accidental leaks or spills are associated with the transportation of natural
gas. There can be no assurance that we will not incur significant costs and
liabilities relating to claims for damages to property, the environment, natural
resources, or persons resulting from the operation of our business. Moreover, it
is possible that other developments, such as increasingly strict environmental
laws and regulations and enforcement policies thereunder, could result in
increased costs and liabilities to us.

- 25 -

Environmental laws and regulations have changed substantially and
rapidly over the last 25 years, and we anticipate that there will be continuing
changes. One trend in environmental regulation is to increase reporting
obligations and place more restrictions and limitations on activities, such as
emissions of pollutants, generation and disposal of wastes and use, storage and
handling of chemical substances, that may impact human health, the environment
and/or endangered species. Increasingly strict environmental restrictions and
limitations have resulted in increased operating costs for us and other similar
businesses throughout the United States. It is possible that the costs of
compliance with environmental laws and regulations may continue to increase. We
will attempt to anticipate future regulatory requirements that might be imposed
and to plan accordingly, but there can be no assurance that we will identify and
properly anticipate each such charge, or that our efforts will prevent material
costs, if any, from arising.

Long-Term Debt

We increased our credit facility to $20.0 million in September 2003.
Our principal purpose in obtaining the increase in the facility was to enable us
to fund our pending acquisition of Alaska Pipeline Company and acquisitions of
other gas gathering systems. In May 2003 we used proceeds from our public
offering to repay our existing indebtedness of $8.5 million under the facility.

- 26 -

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations and
commercial commitments at December 31, 2003:

Payments Due By Period
------------------------------------------------------------------
Contractual cash obligations: Less than 1 - 3 4 - 5 After 5
----------------------------- Total 1 Year Years Years Years
-------------- -------------- --------------- ------------ -------------

Long-term debt........................... $ - $ - $ - $ - $ -
Capital lease obligations................ - - - - -
Operating leases......................... 370,500 171,000 199,500 - -
Unconditional purchase obligations....... - - - - -
Other long-term obligations.............. - - - - -
----------- ----------- ----------- --------- ---------
Total contractual cash obligations....... $ 370,500 $ 171,000 $ 199,500 $ - $ -
=========== =========== =========== ========= =========

Amount of Commitment Expiration Per Period
------------------------------------------------------------------
Other commercial commitments: Less than 1 - 3 4 - 5 After 5
----------------------------- Total 1 Year Years Years Years
-------------- -------------- --------------- ------------ -------------

Lines of credit........................ $ - $ - $ - $ - $ -
Standby letter of credit............... - - - - -
Guarantees............................. - - - - -
Standby replacement commitments........ - - - - -
Other commercial commitments........... 1,927,000 1,927,000 - - -
----------- ----------- ---------- --------- ---------
Total commercial commitments........... $ 1,927,000 $ 1,927,000 $ - $ - $ -
=========== =========== ========== ========= =========

Other commercial commitments relate to commitments to purchase
compressors which we had been leasing and for expenditures for pipeline
extensions.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires us 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 we believe our estimates are reasonable, actual
results could differ from those estimates. Changes in these estimates could
materially affect our financial position, results of operations or cash flows.
Key estimates used by our management include estimates used to record revenue
and expense accruals, depreciation and amortization, asset impairment and fair
values of assets acquired. We summarize our significant accounting policies in
Note 2 to our Consolidated Financial Statements included in this report. We
discuss below the critical accounting policies that we have identified.

Revenue and Expenses

We routinely make accruals for both revenues and expenses due to the
timing of receiving information from third parties and reconciling our records
with those of third parties. We have determined these estimates using available
market data and valuation methodologies. We believe our estimates for these
items are reasonable, but cannot assure you that actual amounts will not vary
from estimated amounts.

- 27 -

Depreciation and Amortization

We calculate our depreciation based on the estimated useful lives and
salvage values of our assets. However, factors such as usage, equipment failure,
competition, regulation or environmental matters could cause us to change our
estimates, thus impacting the future calculation of depreciation and
amortization.

Impairment of Assets

In accordance with Statement of Financial Accounting Standards, or
SFAS, 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we
review long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of long-lived assets may not be
recoverable. We determine if our 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, an impairment loss is recognized
in the amount of the excess, if any.

Our gathering systems are subject to numerous factors which could
affect future cash flows which we discuss in Item 1, "Business-Risk Factors". We
continuously monitor these factors and pursue alternative strategies to maintain
or enhance cash flows associated with these assets; however, we cannot assure
you that we can mitigate the effects, if any, on future cash flows related to
any changes in these factors.

Goodwill

At December 31, 2003, we had $2.3 million of goodwill, all of which
relates to our acquisition of pipeline assets. We test our goodwill for
impairment at each year end by comparing fair values to our carrying values. The
evaluation of impairment under SFAS 142, "Goodwill and Other Intangible Assets,"
requires the use of projections, estimates and assumptions as to the future
performance of the operations, including anticipated future revenues, expected
future operating costs and the discount factor used. Actual results could differ
from projections resulting in revisions to our assumptions and, if required,
recognizing an impairment loss. Our test during the current year resulted in no
impairment. We will continue to evaluate our 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.

- 28 -

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

All of our assets and liabilities are denominated in U.S. dollars, and
as a result, we do not have exposure to currency exchange risks.

We do not engage in any interest rate, foreign currency exchange rate
or commodity price-hedging transactions, and as a result, we do not have
exposure to derivatives risk.

Our major market risk exposure is in the pricing applicable to natural
gas sales. Realized pricing is primarily driven by spot market prices for
natural gas. Pricing for natural gas production has been volatile and
unpredictable for several years.

Market risk inherent in our debt is the potential change arising from
increases or decreases in interest rates. Changes in interest rates usually do
not affect the fair value of variable rate debt, but may affect our future
earnings and cash flows.

- 29 -

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Certified Public Accountants

Partners
Atlas Pipeline Partners, L.P.

We have audited the accompanying consolidated balance sheets of Atlas
Pipeline Partners, L.P. and subsidiaries (the "Partnership") as of December 31,
2003 and 2002, and the related consolidated statements of income, partners'
capital (deficit) and cash flows for each of the three years in the period ended
December 31, 2003. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with 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 consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
the Partnership at December 31, 2003 and 2002 and the consolidated results of
its operations and its consolidated cash flows for each of the three years in
the period ended December 31, 2003, in conformity with accounting principles
generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements,
effective January 1, 2002, the Partnership changed its method of accounting for
goodwill for the adoption of Statement of Financial Accounting Standards No.
142, Goodwill and Other Intangible Assets.

/s/ Grant Thornton LLP
---------------------
Cleveland, Ohio
January 30, 2004

- 30 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

December 31,
-----------------------------------
2003 2002
-------------- --------------

ASSETS
Current assets:
Cash and cash equivalents................................................. $ 15,078,100 $ 1,858,600
Accounts receivable....................................................... 12,300 500,000
Prepaid expenses.......................................................... 66,600 26,800
-------------- --------------
Total current assets.................................................... 15,157,000 2,385,400

Property and equipment:
Gas gathering and transmission facilities................................. 37,018,200 29,384,000
Less - accumulated depreciation........................................... (7,390,100) (5,619,600)
-------------- --------------
Net property and equipment.............................................. 29,628,100 23,764,400

Goodwill (net of accumulated amortization of $285,300)........................ 2,304,600 2,304,600

Other assets (net of accumulated amortization of $106,100 and $0)............. 2,422,400 60,900
-------------- --------------
$ 49,512,100 $ 28,515,300
============== ==============

LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities.................................. $ 520,900 $ 107,800
Accounts payable - affiliates............................................. 1,672,900 347,200
Distribution payable...................................................... 3,073,200 1,873,800
-------------- --------------
Total current liabilities............................................... 5,267,000 2,328,800

Long-term debt................................................................ - 6,500,000

Partners' capital (deficit):
Common unitholders, 2,713,659 and 1,621,159 units outstanding............. 43,551,400 19,163,500
Subordinated unitholder, 1,641,026 units outstanding...................... 354,200 683,700
General partner........................................................... 339,500 (160,700)
-------------- --------------
Total partners' capital................................................. 44,245,100 19,686,500
-------------- --------------
$ 49,512,100 $ 28,515,300
============== ==============

See accompanying notes to consolidated financial statements

- 31 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

December 31,
-------------------------------------------------------
2003 2002 2001
--------------- -------------- --------------

Revenues:
Transportation.............................................. $ 15,650,800 $ 10,660,300 $ 13,094,700
Interest income and other................................... 97,900 6,800 34,600
--------------- -------------- --------------
Total revenues............................................ 15,748,700 10,667,100 13,129,300

Costs and expenses:
Transportation and compression.............................. 2,420,500 2,061,600 1,929,200
General and administrative.................................. 1,660,900 1,481,900 1,112,800
Depreciation and amortization............................... 1,770,500 1,475,600 1,356,100
Interest.................................................... 258,200 249,800 175,600
--------------- -------------- --------------
Total costs and expenses.................................. 6,110,100 5,268,900 4,573,700
--------------- -------------- --------------

Net income...................................................... $ 9,638,600 $ 5,398,200 $ 8,555,600
=============== ============== ==============

Net income - limited partners................................... $ 8,650,900 $ 5,022,300 $ 7,499,200
=============== ============== ==============

Net income - general partner.................................... $ 987,700 $ 375,900 $ 1,056,400
=============== ============== ==============

Basic and diluted net income per limited partner unit........... $ 2.17 $ 1.54 $ 2.30
=============== ============== ==============

Weighted average limited partner units outstanding.............. 3,980,541 3,262,185 3,254,543
=============== ============== ==============

See accompanying notes to consolidated financial statements

- 32 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (DEFICIT)
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

Number of Limited
Partner Units
----------------------------------
Common Subordinated Common Subordinated
------------------------------------------------------------------------------------------------------------------------------

Balance at December 31, 2000...................... 1,500,000 1,641,026 $ 18,122,200 $ 2,073,800
Issuance of common units.......................... 121,159 - 2,250,000 -
Capital contributions............................. - - - -
Distributions paid to partners.................... - - (3,112,800) (3,150,700)
Distribution payable.............................. - - (940,300) (951,800)
Net income........................................ - - 3,809,600 3,689,600
------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001...................... 1,621,159 1,641,026 $ 20,128,700 $ 1,660,900
Distributions paid to partners.................... - - (2,585,700) (2,617,400)
Distribution payable.............................. - - (875,400) (886,200)
Net income........................................ - - 2,495,900 2,526,400
------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002...................... 1,621,159 1,641,026 $ 19,163,500 $ 683,700
Issuance of common units net of offering costs.... 1,092,500 - 25,181,600 -
Capital contributions............................. - - - -
Distributions paid to partners.................... - - (4,164,200) (2,888,200)
Distribution payable.............................. - - (1,696,000) (1,025,700)
Net income........................................ - - 5,066,500 3,584,400
------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003................... 2,713,659 1,641,026 $ 43,551,400 $ 354,200
========= ========= ============= ==============
------------------------------------------------------------------------------------------------------------------------------

Total
Partners'
General Capital
Partner (Deficit)
-----------------------------------------------------------------------------------------

Balance at December 31, 2000...................... $ (88,900) $ 20,107,100
Issuance of common units.......................... - 2,250,000
Capital contributions............................. 45,500 45,500
Distributions paid to partners.................... (971,500) (7,235,000)
Distribution payable.............................. (157,500) (2,049,600)
Net income........................................ 1,056,400 8,555,600
-----------------------------------------------------------------------------------------
Balance at December 31, 2001...................... $ (116,000) $ 21,673,600
Distributions paid to partners.................... (308,400) (5,511,500)
Distribution payable.............................. (112,200) (1,873,800)
Net income........................................ 375,900 5,398,200
-----------------------------------------------------------------------------------------
Balance at December 31, 2002...................... $ (160,700) $ 19,686,500
Issuance of common units net of offering costs.... - 25,181,600
Capital contributions............................. 538,500 538,500
Distributions paid to partners.................... (674,500) (7,726,900)
Distribution payable.............................. (351,500) (3,073,200)
Net income........................................ 987,700 9,638,600
-----------------------------------------------------------------------------------------
Balance at December 31, 2003................... $ 339,500 $ 44,245,100
============= =============
-----------------------------------------------------------------------------------------

See accompanying notes to consolidated financial statements

- 33 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended
December 31,
----------------------------------------------------
2003 2002 2001
--------------- -------------- --------------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................ $ 9,638,600 $ 5,398,200 $ 8,555,600
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization................................. 1,770,500 1,475,600 1,356,100
Amortization of deferred finance costs........................ 106,100 89,800 44,500
Change in operating assets and liabilities:
Decrease in accounts receivable
and prepaid expenses........................................ 447,900 909,000 350,000
Increase (decrease) in accounts payable and
accrued liabilities......................................... 413,100 (81,800) (38,000)
Increase in accounts payable - affiliates..................... 1,325,700 347,200 -
--------------- -------------- --------------
Net cash provided by operating activities................... 13,701,900 8,138,000 10,268,200
--------------- -------------- --------------

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of gathering systems.................................. - (165,000) (1,400,000)
Increase in other assets.......................................... (1,519,400) - -
Capital expenditures.............................................. (7,634,200) (5,065,600) (1,728,000)
--------------- -------------- --------------
Net cash used in investing activities....................... (9,153,600) (5,230,600) (3,128,000)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on revolving credit facility........................... 2,000,000 10,815,800 2,089,000
Repayments on revolving credit facility........................... (8,500,000) (6,404,800) -
Issuance of common units net of offering costs.................... 25,181,600 - -
Capital contributions............................................. 538,500 - 45,500
Distributions paid to partners.................................... (9,600,700) (7,561,100) (9,118,300)
Increase in other assets.......................................... (948,200) (60,900) (37,700)
--------------- -------------- --------------
Net cash provided by (used in) financing activities......... 8,671,200 (3,211,000) (7,021,500)
--------------- -------------- --------------

Increase (decrease) in cash and cash equivalents.................. 13,219,500 (303,600) 118,700

Cash and cash equivalents, beginning of year...................... 1,858,600 2,162,200 2,043,500
--------------- -------------- --------------
Cash and cash equivalents, end of year............................ $ 15,078,100 $ 1,858,600 $ 2,162,200
=============== ============== ==============

Supplemental Cash Flow Information:
Cash paid during the year for interest............................ $ 178,000 $ 165,200 $ 94,800

Non-cash Activities:
Issuance of units in exchange for gas gathering and transmission facilities:
Common........................................................ - - $ 2,250,000
Subordinated.................................................. - - -
Liability assumed for gas system acquisition...................... - - $ 126,500

See accompanying notes to consolidated financial statements

- 34 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - NATURE OF OPERATIONS

The Partnership

Atlas Pipeline Partners, L.P. (the "Partnership") is a Delaware limited
partnership formed in May 1999 to acquire, own and operate natural gas gathering
systems theretofore owned by Atlas America, Inc. ("Atlas") and its affiliates,
Viking Resources Corporation ("VRC") and Resource Energy, Inc. ("REI")
(collectively referred to as the "Predecessor"), all of which are wholly-owned
subsidiaries of Resource America, Inc. ("RAI" or "Parent"). RAI is a publicly
traded company (trading under the symbol REXI on NASDAQ) operating in energy,
real estate, equipment leasing and financial services.

Partnership Structure and Management

The Partnership's operations are conducted through subsidiary entities
whose equity interests are owned by the Partnership's operating subsidiary,
Atlas Pipeline Operating Partnership, L.P., (the "Operating Partnership"). Atlas
Pipeline Partners GP, LLC (a wholly-owned subsidiary of Atlas (the "General
Partner")), owns, through its general partner interests in the Partnership and
the Operating Partnership, a 2% general partner interest in the consolidated
pipeline operations. The remaining 98% consists of limited partner interests of
which 62% consists of common units ("Common Units") and 38% consists of
subordinated units ("Subordinated Units"). The Subordinated Units are
subordinated to the rights of the holders of Common Units. Through the ownership
of these Subordinated Units and the General Partner interest, the General
Partner effectively manages and controls both the Partnership and the Operating
Partnership.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies consistently applied
(except as otherwise noted) in the preparation of the accompanying consolidated
financial statements follows.

Principles of Consolidation

The consolidated financial statements include the accounts of the
Partnership, the Operating Partnership and the Operating Partnership's
wholly-owned subsidiaries. The General Partner's interest in the Operating
Partnership is reported as part of its overall 2% general partner interest in
the Partnership, as opposed to a minority interest. All material intercompany
transactions have been eliminated.

Accounting Estimates

Certain amounts included in or affecting the Partnership's consolidated
financial statements and related disclosures must be estimated, requiring the
Partnership to make certain assumptions with respect to values or conditions
that cannot be known with certainty at the time the financial statements are
prepared.

The preparation of its consolidated financial statements in conformity
with accounting principles generally accepted in the United States of America
requires the Partnership to make estimates and assumptions that affect:

o the amount the Partnership reports for assets and liabilities;

o the Partnership's disclosure of contingent assets and liabilities
at the date of the financial statements; and

o the amounts the Partnership reports for revenues and expenses
during the reporting period.

- 35 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Accounting Estimates - (Continued)

Therefore, the reported amounts of the Partnership's assets and
liabilities, revenues and expenses and associated disclosures with respect to
contingent assets and obligations are necessarily affected by these estimates.
The Partnership evaluates these estimates on an ongoing basis, utilizing
historical experience, consultation with experts and other methods the
Partnership considers reasonable in the particular circumstances. Nevertheless,
actual results may differ significantly from the Partnership's estimates. Any
effects on the Partnership's business, financial position or results of
operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.

Property and Equipment

Depreciation is provided for in amounts sufficient to relate the cost
of depreciable assets to operations over the estimated useful lives of the
assets. Gas gathering and transmission facilities are depreciated over 15 or 20
years using the straight-line and double-declining balance methods. Other
equipment is depreciated over 5 to 10 years using the straight-line method.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever
events or circumstances indicate that the carrying amount of an asset may not be
recoverable. If it is determined that an asset's estimated future cash flows
will not be sufficient to recover its carrying amount, an impairment charge will
be recorded to reduce the carrying amount for that asset to its estimated fair
value if such carrying amount exceeds the fair value.

Goodwill

On January 1, 2002, the Partnership adopted SFAS No. 142 ("SFAS 142")
"Goodwill and Other Intangible Assets," which requires that goodwill no longer
be amortized, but instead tested for impairment at least annually. At that time,
the Partnership had unamortized goodwill of $2.3 million. The transitional
impairment test required upon adoption of SFAS 142, which involved the use of
estimates related to the fair market value of the business operations associated
with the goodwill, did not indicate an impairment loss. The Partnership will
continue to evaluate its goodwill at least annually and will reflect the
impairment of goodwill, if any, in operating income in the statement of
operations in the period in which the impairment is indicated.

Changes in the carrying amount of goodwill for the periods indicated
are as follows:

Years Ended December 31,
---------------------------------------------
2003 2002 2001
----------- ---------- -----------

Goodwill at beginning of period,
(less accumulated amortization of $285,300, $285,300
and $197,300)........................................................ $ 2,304,600 $2,304,600 $ 2,392,600
Amortization expense...................................................... - - (88,000)
----------- ---------- -----------
Goodwill at end of period (net of accumulated amortization
of $285,300 at each year end)......................................... $ 2,304,600 $2,304,600 $ 2,304,600
=========== ========== ===========

- 36 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Goodwill - (Continued)

Prior to the adoption of SFAS 142, the Partnership amortized goodwill
on a straight-line basis over 30 years. Assuming that the Partnership had
applied SFAS 142 in 2001, pro forma net income for that year would have been
$8,643,600, and pro forma net income per limited partner unit for the year ended
December 31, 2002 would have been $2.33.

Distributions

The Partnership is required to distribute, within 45 days of the end of
each quarter, all of its available cash for that quarter. For each quarter
during the subordination period (through at least December 31, 2004), to the
extent there is sufficient cash available, the Common Unit holders have the
right to receive a minimum quarterly distribution ("MQD") of $.42 per unit prior
to any distribution to the subordinated units. If distributions in any quarter
exceed specified target levels, the General Partner will receive between 15% and
50% of such distributions in excess of the specified target levels.

Federal Income Taxes

The Partnership is a limited partnership. As a result, the
Partnership's income for federal income tax purposes is reportable on the tax
returns of the individual partners. Accordingly, no recognition has been given
to income taxes in the accompanying financial statements of the Partnership.

Net income, for financial statement purposes, may differ significantly
from taxable income reportable to unitholders as a result of differences between
the tax bases and financial reporting bases of assets and liabilities and the
taxable income allocation requirements under the partnership agreement. These
different allocations can and usually will result in significantly different tax
capital account balances in comparison to the capital accounts per the
consolidated financial statements.

Environmental Matters

The Partnership is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Partnership has
established procedures for the ongoing evaluation of its operations, to identify
potential environmental exposures and to comply with regulatory policies and
procedures.

The Partnership accounts for environmental contingencies in accordance
with SFAS 5, "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable, and the costs can be reasonably estimated. The Partnership maintains
insurance which may cover in whole or in part certain environmental
expenditures. For the three years ended December 31, 2003, the Partnership had
no environmental matters requiring specific disclosure or requiring recording of
a liability.

- 37 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Revenue Recognition

Revenues are recognized at the time the natural gas is transported
through the gathering systems. Under the terms of its natural gas gathering
agreements with Atlas and its affiliates, the Partnership receives fees for
gathering natural gas from wells owned by Atlas, by drilling investment
partnerships sponsored by Atlas or by independent third parties whose wells were
connected to the Partnership's gathering systems when operations commenced in
2000. The fees received for the gathering services are generally the greater of
16% of the gross sales price for gas produced from the wells, or $.35 or $.40
per thousand cubic feet ("Mcf"), depending on the ownership of the well.
Substantially all gas gathering revenues are derived under this agreement. Fees
for transportation services provided to independent third parties whose wells
are connected to the Partnership's gathering systems are at separately
negotiated prices.

Segment Information

The Partnership has one business segment, the transportation segment,
which derives its revenues primarily from the transportation of natural gas that
it receives from producers. Transportation revenues are, for the most part,
based on contractual arrangements with Atlas and its affiliates.

Fair Value of Financial Instruments

For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair values because of the short maturity of these
instruments. The carrying value of long-term debt approximates fair market value
since interest rates approximate current market rates.

Net Income Per Unit

There is no difference between basic and diluted net income per limited
partner unit since there are no potentially dilutive units outstanding. Net
income per limited partner unit is determined by dividing net income, after
deducting the General Partner's 2% interest and incentive distributions, by the
weighted average number of outstanding Common Units and Subordinated Units (a
total of 3,980,541, 3,262,185 and 3,254,543 units as of December 31, 2003, 2002
and 2001, respectively).

Comprehensive Income

Comprehensive income includes net income and all other changes in the
equity of a business during a period from non-owner sources. These changes,
other than net income, are referred to as "other comprehensive income." The
Partnership has no other elements of comprehensive income, other than net
income, to report.

Cash Flow Statements

For purposes of the statements of cash flows, all highly liquid debt
instruments purchased with a maturity of three months or less are considered to
be cash equivalents.

- 38 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Concentration of Credit Risk

Financial instruments, which potentially subject the Partnership to
concentrations of credit risk, consist principally of periodic temporary
investments of cash. The Partnership places its temporary cash investments in
high quality short-term money market instruments and deposits with high quality
financial institutions. At December 31, 2003, the Partnership and its
subsidiaries had $15.1 million in deposits at one bank, of which $14.8 million
was over the insurance limit of the Federal Deposit Insurance Corporation. No
losses have been experienced on such investments.

NOTE 3 - RELATED PARTY TRANSACTIONS

The Partnership is affiliated with RAI and its subsidiaries, including
Atlas, VRC and REI ("Affiliates"). The Partnership is dependent upon the
resources and services provided by RAI and these Affiliates. Accounts
payable-affiliates represents the net balance due to these Affiliates for
natural gas transported through the gathering systems, net of reimbursements for
Partnership costs and expenses paid by these Affiliates. Substantially all
Partnership revenue is from these Affiliates.

The Partnership does not directly employ any persons to manage or
operate its business. These functions are provided by the General Partner and
employees of RAI and/or its Affiliates. The General Partner does not receive a
management fee or other compensation in connection with its management of the
Partnership apart from its interest as general partner and its right to receive
incentive distributions. The Partnership reimburses Atlas and/or its Affiliates
for all direct and indirect costs of services provided, including the cost of
employees, officer and managing board member compensation and benefits properly
allocable to the Partnership and all other expenses necessary or appropriate to
the conduct of the business of, and allocable to, the Partnership.

The partnership agreement provides that the General Partner will
determine the costs and expenses that are allocable to the Partnership in any
reasonable manner determined by the General Partner at its sole discretion. For
the years ended December 31, 2003, 2002 and 2001, such reimbursements were
approximately $11.7 million, $8.8 million and $6.2 million, respectively,
including certain costs that have been capitalized by the Partnership.

Under an agreement with Atlas, VRC and REI, Atlas must construct up to
2,500 feet of sales lines from its existing wells to a point of connection to
the Partnership's gathering systems. The Partnership must, at its own cost,
extend its system to connect to any such lines extended to within 1,000 feet of
its gathering systems. With respect to wells to be drilled by Atlas that will be
more than 3,500 feet from the Partnership's gathering systems, the Partnership
has various options to connect those wells to its gathering systems at its own
cost.

Atlas has agreed to provide the Partnership with financing for the cost
of constructing new gathering system expansions through February 2, 2005, on a
stand-by basis. If the Partnership chooses to use this stand-by commitment, the
financing will be provided through the issuance of Common Units to Atlas. The
number of Common Units issued will be based upon the construction costs advanced
and the fair value of the Common Units at the time of such advances. The
commitment is for a maximum of $1.5 million in any contract year. As of December
31, 2003, the Partnership had not availed itself of the stand-by financing.

- 39 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 3 - RELATED PARTY TRANSACTIONS - (Continued)

In connection with the acquisition of Alaska Pipeline Company, L.L.C.
("Alaska Pipeline") (see Note 9), the Partnership has the right to purchase the
preferred equity interest of Friedman Billings Ramsey Group and, if the
Partnership does not do so, Friedman Billings Ramsey Group has the right to
require RAI to purchase the interest. The Partnership paid RAI a fee of $70,750
for this commitment, and will pay RAI an additional fee of $141,500 upon closing
of the Alaska Pipeline transaction. RAI has the right to sell the Partnership
any portion of the preferred interest it acquires at its cost plus a purchase
premium of 2% or, after the 90th day following closing, an amount equal to 1%
per month for each month following RAI's acquisition of the preferred interest.
The Partnership's purchase from RAI is payable in Common Units and is subject to
receipt of any necessary unitholder approval of the issuance of those units.

NOTE 4 - DISTRIBUTION DECLARED

On December 18, 2003, the Partnership declared a cash distribution of
$.625 per unit on its outstanding Common Units and Subordinated Units. The
distribution represented the available cash flow for the three months ended
December 31, 2003. The $3,073,200 distribution, which includes a distribution of
$351,500 to the General Partner in respect to its general partner interest, is
scheduled to be paid on February 6, 2004 to unit holders of record on December
31, 2003.

NOTE 5 - CREDIT FACILITY

In September 2003, the Partnership amended and increased its credit
facility from $15.0 million to $20.0 million. Borrowings under the facility are
secured by a lien on and security interest in all the property of the
Partnership and its subsidiaries, including pledges by the Partnership of the
issued and outstanding equity interests in its subsidiaries. Up to $3.0 million
of the facility may be used for standby letters of credit. No such letters of
credit have been issued under the facility. The revolving credit facility has a
term ending in December 2005 and bears interest at one of two rates, elected at
the Partnership's option:

o the base rate plus the applicable margin; or

o the adjusted London Interbank Offered Rate ("LIBOR") rate plus the
applicable margin.

o where the Partnership's leverage ratio, as defined in the credit
facility agreement, is less than or equal to 1.5, the applicable
margin is 0.00% for base rate loans and 1.50% for LIBOR loans;

o where the Partnership's 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 the Partnership's 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 2.00% for LIBOR loans; and

o where the Partnership's leverage ratio is greater than 3.0, the
applicable margin is 0.75% for base rate loans and 2.50% for LIBOR
loans.

- 40 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 5 - CREDIT FACILITY - (Continued)

There were no outstanding borrowings under this credit facility at
December 31, 2003 and $6.5 million was outstanding at December 31, 2002.

The credit facility requires the Partnership to maintain specified net
worth and specified ratios of current assets to current liabilities and debt to
earnings before interest, taxes, depreciation and amortization ("EBITDA"), and
requires it to maintain a specified interest coverage ratio. At December 31,
2003 and 2002, the Partnership was in compliance with all of the financial
covenants.

NOTE 6 - LEASES AND COMMITMENTS

The Partnership leases certain compressors associated with its
gathering systems under lease agreements which expire in 2006. Rent expense for
the years ended December 31, 2003, 2002 and 2001 was $1,039,400, $839,900 and
$783,700, respectively. Minimum future lease payments for these leases in 2004,
2005 and 2006 are $171,000, $171,000 and $28,500, respectively.

NOTE 7 - ACQUISITIONS

In January 2001, the Partnership acquired the gas gathering system of
Kingston Oil Corporation. The gas gathering system consists of approximately 100
miles of pipeline located in southeastern Ohio. The purchase price was
$2,750,000, consisting of $1.3 million of cash and 88,235 common units valued at
$17.00 per unit.

In March 2001, the Partnership acquired the gas gathering system of
American Refining and Exploration Company. The gas gathering system consists of
approximately 20 miles of pipeline located in Fayette County, Pennsylvania. The
purchase price was $900,000, consisting of $150,000 of cash and 32,924 common
units valued at $22.78 per unit.

These acquisitions were accounted for under the purchase method of
accounting and, accordingly, the purchase prices were allocated to the assets
acquired based on their fair values at the dates of acquisition. The pro forma
effect of these acquisitions on prior operations to the acquisition dates is not
material.

NOTE 8 - PUBLIC OFFERING OF COMMON UNITS

In May 2003, the Partnership completed a public offering of 1,092,500
common units of limited partner interest. The net proceeds after underwriting
discounts and commissions were approximately $25.2 million. These proceeds were
used in part to repay existing indebtedness of $8.5 million. The Partnership
intends to use the balance of these proceeds to fund future capital projects and
for working capital.

- 41 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 9 - PENDING ACQUISITION

In September 2003, the Partnership entered into a purchase and sale
agreement with SEMCO Energy, Inc. ("SEMCO") pursuant to which the Partnership or
its designee will purchase all of the outstanding equity of SEMCO's wholly-owned
subsidiary, Alaska Pipeline Company, L.L.C., ("Alaska Pipeline") which owns an
intrastate natural gas transmission pipeline that delivers gas to metropolitan
Anchorage (the "Acquisition"). The total consideration, payable in cash at
closing, will be approximately $95.0 million, subject to an adjustment based on
the amount of working capital that Alaska Pipeline has at closing.

Consummation of the Acquisition is subject to a number of conditions,
including receipt of governmental and non-governmental consents and approvals
and the absence of a material adverse change in Alaska Pipeline's business.
Among the required governmental authorizations are approval of the Regulatory
Commission of Alaska and expiration, without adverse action, of the waiting
period under the Hart-Scott-Rodino Antitrust Improvements Act. Early termination
of the waiting period was granted in January 2004. The purchase and sale
agreement may be terminated by either the Partnership or SEMCO if the
transaction is not consummated by June 16, 2004. The purchase and sale agreement
contains customary representations, warranties and indemnifications.

As part of the Acquisition, at closing, Alaska Pipeline and ENSTAR
Natural Gas Company ("ENSTAR"), a division of SEMCO which conducts its gas
distribution business in Alaska, will enter into a Special Contract for Gas
Transportation pursuant to which ENSTAR will pay a reservation fee for use of
all of the pipeline's transportation capacity of $943,000 per month, plus $0.075
per Mcf of gas transported, for 10 years. During 2002, total gas volumes
transported on the Alaska Pipeline system averaged 130,000 Mcf per day. SEMCO
will execute a gas transmission agreement with Alaska Pipeline pursuant to which
SEMCO will be obligated to make up any difference if the Regulatory Commission
of Alaska reduces the transportation rates payable by ENSTAR pursuant to the
Special Contract.

Further, 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 five years for a fee
of $334,000 per month for the first three years. Thereafter, ENSTAR's fee will
be adjusted for inflation.

- 42 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 9 - PENDING ACQUISITION - (Continued)

The Partnership has received a commitment from Friedman, Billings,
Ramsey Group, Inc. ("FBR") to make a $25.0 million preferred equity investment
in a special purpose vehicle (the "SPV"), to be jointly owned by FBR and the
Partnership, which entity will be the acquirer of Alaska Pipeline. Under the
terms of the FBR commitment, the Partnership will have the right, during the 18
months following the closing of the Acquisition, to purchase FBR's preferred
equity interest in the SPV at FBR's original cost plus accrued and unpaid
preferred distributions and a premium. If the Partnership does not purchase
FBR's interest, FBR has the right to require RAI to purchase this interest. RAI
will then have the right to require the Partnership to purchase the equity
interest from it. The Partnership intends to make a $24.0 million common equity
investment in the SPV which the Partnership will fund in part through its
existing $20.0 million credit facility. The SPV has received a commitment from
Wachovia Bank, National Association and Wachovia Capital Markets, LLC for a
$50.0 million credit facility to partially finance the Acquisition. Up to $25.0
million of borrowings under the facility will be secured by a lien on and
security interest in all of the SPV's property. In addition, upon the earlier to
occur of the termination of the Partnership's subordination period or the
amendment of the restrictions in the partnership agreement on the Partnership's
incurrence of debt, the Partnership will guarantee all borrowings under the
facility, securing the guarantee with a pledge of its interest in the SPV.

NOTE 10 - TERMINATION OF PROPOSED ACQUISITION

On July 31, 2002, the Partnership terminated its agreement with New
Vulcan Coal Holdings, L.L.C. and Vulcan Intermediary, L.L.C. (collectively,
"Vulcan") to acquire Triton Coal Company ("Triton"). The related purchase
agreement for the sale of the interests held by Atlas in the General Partner
also terminated. The Partnership incurred approximately $1,500,000 in costs in
connection with the Triton transaction. Atlas had advanced these costs to the
Partnership.

Vulcan reimbursed the Partnership under the terms of the acquisition
agreement for $1,187,500 of the transaction costs. The Partnership expensed
transaction costs of $156,300, one half of the difference between costs incurred
and those reimbursed by Vulcan. Atlas paid the balance of the unreimbursed
costs.

- 43 -

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 11 - QUARTERLY FINANCIAL DATA (Unaudited)

March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(in thousands, except per unit data)
Year ended December 31, 2003

Revenues............................................... $ 3,330 $ 4,348 $ 4,199 $ 3,872
Costs and expenses..................................... 1,418 1,662 1,530 1,500
Net income............................................. 1,912 2,686 2,669 2,372
Net income - limited partners.......................... 1,780 2,479 2,352 2,040
Net income - general partner........................... 132 207 317 332
Basic and diluted net income per limited partner unit.. .55 .63 .54 .47
Weighted average units outstanding..................... 3,262,185 3,934,493 4,354,685 4,354,685

Year ended December 31, 2002:
Revenues............................................... $ 2,577 $ 2,618 $ 2,667 $ 2,805
Costs and expenses..................................... 1,205 1,382 1,276 1,406
Net income............................................. 1,372 1,236 1,391 1,399
Net income - limited partners.......................... 1,292 1,143 1,290 1,297
Net income - general partner........................... 80 93 101 102
Basic and diluted net income per limited partner unit.. .40 .35 .40 .39
Weighted average units outstanding..................... 3,262,185 3,262,185 3,262,185 3,262,185

- 44 -

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The chairman and chief financial officer of our general partner, our
principal executive officer and financial officer, respectively, have evaluated
our disclosure controls and procedures, (as defined in Rules 13a-14 (c) and
15d-14(c)) within 90 days prior to the filing of this report. Based upon this
evaluation, these officers believe that our disclosure controls and procedures
are effective.

Changes in Internal Controls

There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
the last evaluation of our internal controls by the chairman and chief financial
officer of our general partner.

- 45 -

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER

Our general partner manages our activities. Unitholders do not directly
or indirectly participate in our management or operation or have actual or
apparent authority to enter into contracts on our behalf or to otherwise bind
us. Our general partner will be liable, as general partner, for all of our debts
to the extent not paid, except to the extent that indebtedness or other
obligations incurred by us are specifically with recourse only to our assets.
Whenever possible, our general partner intends to make any of our indebtedness
or other obligations with recourse only to our assets.

Three members of the managing board of our general partner who are
neither officers nor employees of our general partner nor directors, managing
board members, officers or employees of any affiliate of our general partner
(and have not been for the past five years) serve on the conflicts committee.
Messrs. William Bagnell, Donald Delson and Murray Levin currently serve as the
conflicts committee of the managing board. The conflicts committee has the
authority to review specific matters as to which the managing board believes
there may be a conflict of interest in order to determine if the resolution of
the conflict proposed by our general partner is fair and reasonable to us. Any
matters approved by the conflicts committee are conclusively judged to be fair
and reasonable to us, approved by all our partners and not a breach by our
general partner or its managing board of any duties they may owe us or the
unitholders. In addition, the members of the conflicts committee also constitute
an audit committee which reviews the external financial reporting by our
management, the audit by our independent public accountants, the procedures for
internal auditing and the adequacy of our internal accounting controls. Mr.
Delson has been designated as the audit committee financial expert by the "board
of managers of the general partner, who determined that he is independent within
the meaning of Item 7(d)(3)(iv) of Schedule 14A of the Securities Exchange Act.

As is commonly the case with publicly traded limited partnerships, we
do not directly employ any of the persons responsible for our management or
operation. Rather, Atlas America personnel manage and operate our business.
Officers of our general partner may spend a substantial amount of time managing
the business and affairs of Atlas America and its affiliates and may face a
conflict regarding the allocation of their time between our business and affairs
and their other business interests.

- 46 -

Managing Board Members and Executive Officers of Our General Partner

The following table sets forth information with respect to the
executive officers and managing board members of our general partner.

Year
in which
Name Age Position with general partner service began
---- --- ----------------------------- -------------

Edward E. Cohen 65 Chairman of the Managing Board 1999
Jonathan Z. Cohen 32 Vice Chairman of the Managing Board 1999
Michael L. Staines 54 President, Chief Operating Officer
and Managing Board Member 1999
Steven J. Kessler 60 Chief Financial Officer 2002
Tony C. Banks 48 Managing Board Member 1999
William R. Bagnell 40 Managing Board Member 1999
Donald W. Delson 52 Managing Board Member 2003
Murray S. Levin 61 Managing Board Member 2001

Edward E. Cohen has been Chairman of the Board of Directors of Resource
America since 1990, Chief Executive Officer and a director of Resource America
since 1988 and President of Resource America from 2000 to 2003. He has been
Chairman of the Board of Directors of Atlas America since 1998. He is Chairman
of the Board of Directors of Brandywine Construction & Management, Inc., a
property management company, and a director of TRM Corporation, a publicly
traded consumer services company. Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen has been the President of Resource America since
October 2003, and its Chief Operating Officer and a director since 2002. He was
the Executive Vice President of Resource America from 2001 until 2003. Before
that, Mr. Cohen had been a Senior Vice President since 1999. Mr. Cohen has been
Vice Chairman of Atlas America since 1998. Mr. Cohen has also served as Trustee
and Secretary of RAIT Investment Trust, a publicly-traded real estate investment
trust, since 1997, Vice Chairman of RAIT since 2003 and Chairman of the Board of
Directors of The Richardson Company, a sales consulting company, since 1999. Mr.
Cohen is the son of Edward E. Cohen.

Michael L. Staines has been Senior Vice President of Resource America
since 1989 and served as a director from 1989 through 2000 and Secretary from
1989 through 1998. Since 1998, Mr. Staines has been Executive Vice President,
Secretary and a director of Atlas America. Mr. Staines is a member of the Ohio
Oil and Gas Association, the Independent Oil and Gas Association of New York and
the Independent Petroleum Association of America.

Steven J. Kessler has been Senior Vice President and Chief Financial
Officer of Resource America since 1997. Before that he was Vice President,
Finance and Acquisitions, at Kravco Company, a national shopping center
developer and operator.

- 47 -

Tony C. Banks is a consultant to utilities, energy service companies
and energy technology firms. From 2000 through early 2002, Mr. Banks was
President of RAI Ventures, Inc. and Chairman of the Board of Optiron
Corporation, which was an energy technology subsidiary of Atlas America until
2002. In addition, Mr. Banks served as President of our general partner during
2000. He was Chief Executive Officer and President of Atlas America from 1998
through 2000. From 1995 to 1998, Mr. Banks was Vice President of various
subsidiaries of Atlas America.

William R. Bagnell has been Vice President-Energy for Planalytics,
Inc., an energy industry software company, since 2000. Before that, he was from
1998 the Director of Sales for Fisher Tank Company, a national manufacturer of
carbon and stainless steel bulk storage tanks. From 1992 through 1998, Mr.
Bagnell was a Manager of Business Development for Buckeye Pipeline Partners,
L.P., a publicly traded master limited partnership which is a transporter of
refined petroleum products.

Donald W. Delson has been a managing director in corporate finance at
Keefe, Bruyette & Woods, Inc. since 1997. Before that, he was a managing
director at Alex Brown & Sons.

Murray S. Levin is a senior litigation partner at Pepper Hamilton LLP.
Mr. Levin served as the first American President of the Association
Internationale des Jeunes Avocats (Young Lawyers International Association),
headquartered in Western Europe. He is a past president of the American Chapter
and a member of the board of directors of the Union Internationale des Avocats
(International Association of Lawyers), a Paris-based organization that is the
world's oldest international lawyers association.

Other Significant Employees

Nancy J. McGurk, 48, has been the Chief Accounting Officer of our
general partner since 1999. Ms. McGurk has been Vice President of Resource
America since 1992 and Treasurer and Chief Accounting Officer since 1989.

- 48 -

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires executive
officers and managing board members of our general partner and persons who own
more than 10% of a registered class of our equity securities to file reports of
ownership and changes in ownership with the Securities and Exchange Commission
and to furnish us with copies of all such reports. Based solely upon our review
of reports received by us, or representations that no filings were required, we
believe that all of the officers and managing board members of our general
partner complied with all applicable filing requirements during 2003. We did not
have any record holders of 10% or more of our common units in 2003.

Reimbursement of Expenses of Our General Partner and Its Affiliates

Our general partner does not receive any management fee or other
compensation for its services apart from its general partnership and incentive
distribution interests. We reimburse our general partner and its affiliates,
including Atlas, for all expenses incurred on our behalf. These expenses include
the costs of employee, officer and managing board member compensation and
benefits properly allocable to us, and all other expenses necessary or
appropriate to the conduct of our business. Our partnership agreement provides
that our general partner will determine the expenses that are allocable to us in
any reasonable manner determined by our general partner in its sole discretion.
Our general partner allocates the costs of employee and officer compensation and
benefits based upon the amount of business time spent by those employees and
officers on our business. We reimbursed our general partner $11.7 million for
expenses incurred and capitalized costs during 2003.

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, discussed in "Reimbursement of Expenses of our
General Partner and Its Affiliates, above and in Item 11, "Executive
Compensation." None of the independent managing board members is an employee or
former employee of ours or of our general partner. However, Mr. Bagnell was,
until September 1992, an employee of Resource America, the ultimate parent of
our general partner and served from December 1998 until February 2003 as a
trustee of its employee stock ownership plan and from September 1999 until
February 2003 as a trustee of its 401(k) plan. No executive officer of our
general partner is a director or executive officer of any entity in which an
independent managing board member is a director or executive officer.

Code of Business Conduct and Ethics

Because we do not directly employ any persons, we rely on a Code of
Business Conduct and Ethics adopted by Resource America that applies to the
principal executive officer, principal financial officer and principal
accounting officer of our general partner, as well as to persons performing
services for us generally. You may obtain a copy of this code of ethics by a
request to our general partner at 311 Rouser Road, Moon Township, Pennsylvania
15108. We will disclose any amendment to, or waiver from, a provision of our
code of ethics by filing a current report on Form 8-K.

- 49 -

ITEM 11. 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. We reimburse our general partner for the
compensation allocated to us. The compensation allocation was $1,035,000,
$438,000 and $431,500 for the years ended December 31, 2003, 2002 and 2001,
respectively. The following table sets forth the compensation allocation for the
last three fiscal years 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 2003 $ 179,600 $ 119,700
Chief Executive Officer 2002 0 0
2001 0 0
------------------------------------------------------------------ ---------- --------------- --------------

Michael L. Staines, President, Chief Operating Officer 2003 $ 133,300 $ 10,000
and Managing Board Member 2002 169,979 28,058
2001 193,500 0
------------------------------------------------------------------ ---------- --------------- --------------

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. In
fiscal year 2003, each non-employee managing board member received 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. Effective
January 1, 2004, each non-employee managing board member will receive an annual
retainer of $20,000 in cash and an annual grant of phantom units (1) with DER's
(2) in an amount equal to the lesser of 500 units or $15,000 worth of units
(based upon the market price of our common units) pursuant to our Long-term
Incentive Plan, which was approved by our unitholders on February 11, 2004. 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.

----------------------
(1) A phantom unit is one which, upon vesting, entitles the holder to
receive a common unit or its then fair market value in cash, as as
specified in the grant.

(2) 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 us on our outstanding common units.

- 50 -

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of our common
units held by beneficial owners of 5% or more of either our common or
subordinated units, by executive officers and members of the managing board of
our general partner and by all of the executive officers and managing board
members of our general partner as a group as of February 10, 2004. The
subordinated units listed opposite the name of each person 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.

Name of Beneficial Owner Common Units Percent of Class Subordinated Units Percent of Class
------------------------ ------------ ---------------- ------------------ ----------------

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%.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

At December 31, 2003, our general partner owned 1,641,026 subordinated
units constituting 38% of the limited partner interest in us. Our general
partner also owned, through its 1.0101% general partnership interest in us and
1.0101% general partnership interest in our operating subsidiary, Atlas Pipeline
Operating Partnership, a 2% general partner interest in our consolidated
pipeline operations. We paid our general partner distributions totaling
$4,561,100 during fiscal 2003 in respect of these interests.

The omnibus agreement and the natural gas gathering agreements, which
we describe in Item 1, "Business Agreements with Atlas America," with Atlas
America and its affiliates were not the result of arms-length negotiations and,
accordingly, we cannot assure you that we could have obtained more favorable
terms from independent third parties similarly situated. However, since these
agreements principally involve the imposition of obligations on Atlas America
and its affiliates, we do not believe that we could obtain similar agreements
from independent third parties.

In connection with the acquisition of Alaska Pipeline described in Item
1, "Business - General," and Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Pending Acquisition," we have
the right to purchase the preferred equity interest of Friedman Billings Ramsey
Group in APC Acquisition, the entity we formed to acquire Alaska Pipeline. If we
do not do so, Friedman Billings Ramsey Group has the right to require Resource
America, the parent of our general partner, to purchase the interest. We paid
Resource America a fee of $70,750 for this commitment, and will pay it an
additional fee of $141,500 upon closing of the Alaska Pipeline transaction.
Resource America has the right to sell us any portion of the preferred interest
it acquires at its cost plus a purchase premium of 2% or, after the 90th day
following closing, an amount equal to 1% per month for each month following
Resource America's acquisition of the preferred interest. Our purchase from
Resource America is payable in common units and is subject to receipt of any
necessary unitholder approval of the issuance.

- 51 -

We do not currently directly employ any persons to manage or operate
our business. These functions are provided by employees of Resource America
and/or its affiliates. As discussed in Items 10 and 11, we reimburse our general
partner, Atlas America and its affiliates for expenses they incur in managing
our operations and for an allocation of the compensation paid to the executive
officers of our general partner.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees recognized by the Partnership during the years ending
December 31, 2003 and 2002 by its principal accounting firm, Grant Thornton, LLP
are set forth below. The audit committee of the managing board of our general
partner has considered whether the provision of the non-audit services described
below is compatible with maintaining the principal accountant's independence.

2003 2002
------------- -------------
Audit fees (1)........................... $ 89,100 $ 80,400
Audit related fees (2)................... -- --
Tax fees (3)............................. 47,000 185,700
All other fees (4)....................... 237,600 84,500
------------- -------------
Total aggregate fees billed.............. $ 373,700 $ 350,600
============= =============

(1) Includes the aggregate fees recognized in each of the last two
years for professional services rendered by Grant Thornton, LLP for
the audit of the Partnership's annual financial statements and the
review of financial statements included in Form 10-Q. The fees are
for services that are normally provided by Grant Thornton, LLP in
connection with statutory or regulatory filings or engagements.

(2) There were no aggregate fees billed in each of the last two years
for assurance and related services by Grant Thornton, LLP that are
reasonably related to the performance of the audit or review of the
Partnership's financial statements.

(3) Includes the aggregate fees recognized in each of the last two
years for professional services rendered by Grant Thornton, LLP for
tax compliance, tax advice, and tax planning.

(4) Includes the aggregate fees recognized in each of the last two
years for products and services provided by Grant Thornton, LLP,
other than those services described above. Services in this
category include due diligence related to an acquisition.

Procedures For Audit Committee Pre-Approval of Audit and Permissible Non-Audit
Services of Independent Auditor

Pursuant to its charter, the Audit Committee of the managing board of
our general partner is responsible for reviewing and approving, in advance, any
audit and any permissible non-audit engagement or relationship between us and
our independent auditors.

- 52 -

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)(1) Financial Statements
The financial statements required by this Item 15(a)(1) are
set forth in Item 8.

(a)(2) Financial Statement Schedules No schedules are required to
be presented.

(a)(3) Exhibits

Exhibit No. Description
----------- -----------

2.1(1) Purchase and Sale Agreement dated
September 16, 2003 between Atlas Pipeline
Partners, L.P. and SEMCO Energy, Inc.(1)
3.1(2) Amended and Restated Agreement of Limited
Partnership of Atlas Pipeline Partners, L.P.(2)
3.2(2) Certificate of Limited Partnership of Atlas
Pipeline Partners, L.P.(2)
4.1(2) Common unit certificate.(2)
10.1 Third Amendment to Credit Agreement among
Atlas Pipeline Partners, L.P., Wachovia Bank,
National Association and certain subsidiaries
of Atlas Pipeline Partners, L.P. as guarantors
dated September 15, 2003.

21.1 Subsidiaries of Atlas Pipeline Partners, L.P.

31.1 Rule 13a-14(a)/15d-14(a) Certification

31.2 Rule 13a-14(a)/15d-14(a) Certification

32.1 Section 1350 Certification

32.2 Section 1350 Certification

(b) Reports on Form 8-K

None

------------------------
(1) Filed previously as an exhibit to our current report on Form 8-K dated
September 16, 2003 and by this reference incorporated herein.

(2) Filed previously as an exhibit to our Registration Statement on Form
S-1 (Registration No. 333-85193) and by this reference incorporated
herein.

- 53 -

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934 the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

ATLAS PIPELINE PARTNERS, L.P.
By: Atlas Pipeline Partners GP, LLC,
its General Partner
March 1, 2004 By: /s/ Edward E. Cohen
---------------------------------
Chairman of the Managing Board

Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated as of March 1, 2004.

/s/ Edward E. Cohen Chairman of the Managing Board of the General
------------------------------ Partner (Chief Executive Officer of the
EDWARD E. COHEN General Partner)

/s/ Jonathan Z. Cohen Vice Chairman of the Managing Board of the
------------------------------ General Partner
JONATHAN Z. COHEN

/s/ Michael L. Staines President, Chief Operating Officer, Secretary
------------------------------ and Managing Board Member of the General Partner
MICHAEL L. STAINES

/s/ Steven J. Kessler Chief Financial Officer of the General Partner
------------------------------
STEVEN J. KESSLER

/s/ Nancy J. McGurk Chief Accounting Officer of the General Partner
------------------------------
NANCY J. McGURK

/s/ Tony C. Banks Managing Board Member of the General Partner
------------------------------
TONY C. BANKS

/s/ William R. Bagnell Managing Board Member of the General Partner
------------------------------
WILLIAM R. BAGNELL

/s/ Donald W. Delson. Managing Board Member of the General Partner
------------------------------
Donald W. Delson

/s/ Murray S. Levin Managing Board Member of the General Partner
------------------------------
MURRAY S. LEVIN

- 54 -