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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, 2001
OR
[ ] 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. [ ]
The aggregate market value of the equity securities held by
non-affiliates of the registrant, based on the closing price on March 27, 2002
was approximately $47.1 million.
DOCUMENTS INCORPORATED BY REFERENCE
None
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K
PART I Page
----
Item 1: Business.................................................................................. 3 - 15
Item 2: Properties................................................................................ 15
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................................................................... 19
Item 7: Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................................. 20 - 26
Item 7A: Quantitative and Qualitative Disclosures About Market Risk................................ 26
Item 8: Financial Statements and Supplementary Data............................................... 27 - 40
Item 9: Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure................................................ 40
PART III
Item 10: Directors and Executive Officers of the Registrant........................................ 41 - 42
Item 11: Executive Compensation.................................................................... 43
Item 12: Security Ownership of Certain Beneficial Owners and Management............................ 43
Item 13: Certain Relationships and Related Transactions............................................ 44
PART IV
Item 14: Exhibits, Financial Statement Schedules and
Reports on Form 8-K................................................................... 45
SIGNATURES................................................................................................ 46
-2-
PART I
ITEM 1. BUSINESS
General
We own and operate natural gas pipeline gathering systems in Eastern
Ohio, Western New York and Western Pennsylvania. As of December 31, 2001, our
gathering systems, in the aggregate, consisted of over 1,300 miles of intrastate
pipelines, including approximately 300 miles of intrastate pipelines we
constructed or acquired during the year ended December 31, 2001. Our gathering
systems served approximately 4,000 wells at December 31, 2001 with an average
daily throughput for the year then ended of 46,918 thousand cubic feet, or mcf,
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 significantly lesser extent,
our gathering systems transport their natural gas directly to customers. During
the year ended December 31, 2001, the gathering systems transported 17.1 billion
cubic feet, or bcf, of natural gas.
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 and
Columbia Gas Transmission Corp. Public utility pipelines charge transportation
fees to the person having title to the natural gas being transported, typically
either 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 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. We do not
transport any oil produced by wells connected to the gathering systems.
Our objective is to increase distributions to our unitholders and
general partner and to increase the value of our limited and general partnership
interests by growing and enhancing the quality of our cash flow. We continue to
benefit from the unique sponsorship we receive from Resource America, Inc., the
indirect parent of our general partner, Atlas Pipeline Partners GP, LLC.
Resource America is a specialized financial services company with operations in
energy, real estate and equipment leasing, with total assets of $480.4 million
as of December 31, 2001. Through its subsidiaries, Resource owns approximately
50%, or 1,641,026, of our limited partner units and a 2% general partner
interest.
In January 2001, we 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 consisted of
$1,250,000 of cash and 88,235 common units. In March 2001, we 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 consisted of $150,000 of cash and 32,924 common
units. We drew on our $10.0 million line of credit in order to make both cash
payments. We accounted for these acquisitions under the purchase method of
accounting and, accordingly, we allocated the purchase prices to the assets
acquired based on their fair values at the dates of acquisition.
Following the end of fiscal 2001, on January 18, 2002 we entered into
an agreement to acquire substantially all of the equity interests in Triton Coal
Company, LLC from New Vulcan Coal Holdings, L.L.C. and Vulcan Intermediary,
L.L.C. The Vulcan entities will contribute 98% of the equity interests in Triton
and $6.0 million in cash to us in exchange for 6,960,676 common units, 3,977,529
newly created subordinated units and 17,642,264 newly created deferred
participation units. The deferred participation units will convert into
subordinated units only if our combined operations meet specified target levels
for distributions and available cash from operations. In addition, New Vulcan
Coal Holdings will acquire our general partner.
-3-
Triton is a coal mining company that owns and operates two large,
union-free surface coal mines located in the Southern Powder River Basin near
Gillette, Wyoming that produce environmentally compliant, sub-bituminous coal
for use by electric utilities.
Upon the closing of the Triton acquisition, we will make a special,
one-time distribution of $3.70 per common unit to holders of common units as of
the date of the special meeting of unitholders called to approve the
acquisition. In addition, the 1,641,026 outstanding subordinated units held by
our general partner will be transferred to Resource America and will convert
into 1,481,026 common units. As a result of these transactions, the Vulcan
entities will own approximately 69.2% of our outstanding common units,
approximately 77.9% of our outstanding common and subordinated units in the
aggregate, and approximately 90.2% of our common and subordinated units in the
aggregate if all deferred participation units convert into subordinated units.
As conditions to the completion of the Triton acquisition, we will
also:
o amend and restate our limited partnership agreement and the limited
partnership agreement of our operating subsidiary, Atlas Pipeline
Operating Partnership;
o amend, restate and consolidate our master natural gas gathering
agreement and omnibus agreement with Atlas America, which will allow
Atlas America to continue to operate our pipeline systems and
include a new commitment from Resource America and Atlas America to
drill and connect 500 wells to our gathering systems;
o terminate our distribution support agreement with our general
partner; and
o enter into a registration rights agreement with respect to the
common units we will issue to the Vulcan entities and Resource
America.
We will need the affirmative vote of a majority of our outstanding
common units and outstanding subordinated units, each voting separately as a
class, to approve the Triton acquisition. Our general partner holds all of our
outstanding subordinated units and has agreed to vote all of them in favor of
the proposal. Accordingly, the class vote for the subordinated units approving
the Triton acquisition is assured.
Pipeline Characteristics
We set forth in the following table the volumes of the natural gas we
transported in fiscal 2001 and 2000. We express gas volumes in mcfs.
Volume Transported for the
Period from
Volume Transported January 28, 2000
Year Ended through
December 31, 2001 December 31, 2000
-------------------------- ----------------------
New York systems......................................... 570,500 408,800
Ohio systems............................................. 5,378,200 3,902,200
Pennsylvania systems..................................... 11,176,300 10,175,800
------------- -------------
17,125,000 14,486,800
============= =============
-4-
The gathering systems were constructed at various times beginning in
1969. 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 year
ended December 31, 2001 and the period ended December 31, 2000, the cost of
operating the gathering systems was approximately $1.9 million and $1.2 million,
respectively. We do not believe that there are any significant geographic
limitations upon our ability to expand in the areas serviced by our gathering
systems.
Our revenues are determined primarily by the amount of natural gas
flowing through our gathering systems. 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.
We have an agreement with Atlas America and its affiliates relating to
the connection of future wells owned or controlled by them to our gathering
systems. We anticipate that these wells will be the principal producers of gas
transported by our gathering systems. As of December 31, 2001, Atlas America and
its affiliates controlled leases on developed properties in the operational area
of our gathering systems totaling approximately 252,000 acres. In addition,
Atlas America and its affiliates control leases on approximately 244,000
undeveloped acres of land. During the year ended December 2001, Atlas America
and its affiliates drilled and completed 196 wells as compared to 172 wells
during the period ended December 31, 2000.
Pipeline Construction
During fiscal 2001, we added approximately 180 miles of pipeline and
upgraded compressors at a cost of $1.9 million. These additions were associated
with the completion of 196 wells drilled by Atlas America. During fiscal 2000,
we added approximately 100 miles of pipeline at a cost of $1.3 million in
connection with the completion of 172 wells drilled by Atlas America. We
anticipate that we will continue to make ongoing capital expenditures to
maintain and enhance our gathering systems, including improvements to meet
increases in volumes transported and requirements of new environmental and
safety standards.
Agreements with Atlas America and its Affiliates
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 was to maximize the use and
expansion of our gathering systems and the volume of natural gas they transport.
Neither of these agreements resulted from arm's 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.
Omnibus Agreement. Under the omnibus agreement, Atlas America and its
affiliates have 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 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.
-5-
Well Connections. Atlas America has sponsored in the past, and expects
that it will continue to sponsor in the future, oil and gas drilling programs 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 to be drilled that will be more than 3,500 feet
from our gathering systems, we have the right under the omnibus agreement, 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. Alternatively, Atlas America may connect the wells to a third party
gathering system, in which case we may assume the construction costs for, and
own, the lines from the well to the third party gathering system. 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.
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 will have an additional 60 days
to complete the acquisition. If we do not complete the acquisition, or advise
Atlas America that we do not intend to acquire the system, then Atlas America
may do so.
Gathering System Construction. The omnibus agreement requires Atlas
America to provide us with construction management services if we determine to
expand one or more of our gathering systems. We must reimburse Atlas America for
its costs, including an allocable portion of employee salaries, in connection
with its construction management services. We used Atlas America's construction
management services during the fiscal year ended December 31, 2001 and 2000 for
gathering system expansions and reimbursed Atlas America $1.9 million and $1.3
million, respectively. At December 31, 2001, Atlas America was continuing to
provide on-going construction management services for gathering systems
expansions.
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 through December 31, 2001.
-6-
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 general and limited 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 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 acquiror. 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%.
Master Natural Gas Gathering Agreement. Under this agreement, we
receive a fee for gathering natural gas, determined as follows:
o for natural gas from well interests allocable to Atlas America,
Resource Energy and Viking Resources or their subsidiaries
(excluding general or limited partnerships sponsored by them) that
were connected to the gathering systems at February 2, 2000, the
greater of $.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 the
gathering systems at any time, and well interests allocable to
independent third parties in wells connected to the gathering
systems before February 2, 2000, the greater of $.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,
Resource Energy and Viking Resources that are connected to the
gathering systems after February 2, 2000, the completion of our
initial offering, the greater of $.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
Viking Resources 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 $.35 per mcf or
16% of the gross sales price of the natural gas transported, less
the gathering fee charged by the other gathering system.
Atlas America, Resource Energy and Viking Resources receive gathering
fees from contracts or other arrangements with third party owners of well
interests connected to our gathering systems. However, Atlas America, Resource
Energy and Viking Resources must pay gathering fees owed to us from their own
resources regardless of whether they receive 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, Resource
Energy and Viking Resources, as the shippers 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.
-7-
The master natural gas gathering agreement does not cover all of the
natural gas we transport. None of the natural gas produced by wells owned by
independent third parties and connected to our gathering systems after February
2, 2000 or wells connected to gathering systems we may acquire from independent
third parties after February 2, 2000 come under the agreement. We must negotiate
gathering fees for these wells with the well owners or assume the gathering fees
under any existing gathering contracts.
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, our gathering systems may be subject to
two forms of indirect competition:
o competition to extend the gathering systems to wells owned or
operated by persons other than Atlas America and its affiliates; and
o competition to acquire gathering systems owned by third parties.
Although we did not encounter significant competition with respect to
well connections or gathering system acquisitions during the year ended 2001, we
may encounter competition in the future. Any competition may reduce
transportation charges or use of our gathering systems and increase the cost of
acquiring other gathering systems. This may adversely affect our revenues, cause
dilution to existing unitholders and result in a decrease of per unit
distributions.
Atlas America may encounter competition in obtaining drilling sources
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. Although Atlas America did not experience any material
adverse effects from this competition in the year ended 2001, we cannot assure
you that it will not do so in 2002.
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.
-8-
State Regulation. Our gas 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. This regulation includes rates, services and sitting authority
for the construction of certain facilities. Our gas gathering operations
currently are not regulated 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 on our operations, 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 Regulation
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 thereunder, 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 Federal Occupational
Safety and Health Act ("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 cannot predict whether or in what form any new legislation or
regulatory requirements might be enacted or adopted or the costs of compliance.
In general, any such new regulations would increase operating costs and impose
additional capital expenditure requirements on us. We do not presently expect
that such costs or capital expenditure requirements would have a material
adverse effect on us.
-9-
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.
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 (i) offset gain
recognized upon the disposition, and (ii) 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.
-10-
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 2001, we owned property or conducted
business in the states of Pennsylvania, New York and Ohio. A unitholder will
likely be required to file state income tax returns and to pay applicable state
income taxes in many of these states and may be subject to penalties for failure
to comply with such requirements. Some of the 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 amounts
are required to be withheld (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.
Depreciation. Upon our formation in 2000, we elected fifteen-year
straight-line 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, Atlas America and Resource America personnel manage the
gathering systems and operate our business as officers and employees of our
general partner.
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
you may lose some or all of your investment.
-11-
The Triton acquisition, if completed, will materially change our
business. If we complete the Triton acquisition, our business will principally
be Triton's coal mining operations. We will amend our partnership agreement to
create the new subordinated and deferred participation units issued to the
Vulcan entities as well as to make other changes in connection with the Triton
acquisition. In addition, our master natural gas gathering agreement and omnibus
agreement will be amended and consolidated into one agreement, which amendments
will include the elimination of the provisions previously described relating to
construction financing and restrictions on the disposition of our general
partner. In addition, the distribution support agreement, described in the next
risk factor, will terminate. The Triton acquisition must be approved by our
unitholders, along with other conditions, prior to its completion. We cannot
assure you that the Triton acquisition will be completed.
After the expiration of the distribution support period, cash
distributions are not assured and may fluctuate with our performance. Our
general partner is obligated to fund deficiencies in available cash so that we
can pay minimum quarterly distributions through February 2003. We cannot assure
you that the amounts of cash that we will generate will be sufficient to pay the
minimum quarterly distributions or any other level of distributions following
February 2003. 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 profitability of operations;
o required principal and interest payments on any debt we may incur;
o the cost of acquisitions;
o our issuance of equity securities;
o fluctuations in working capital;
o capital expenditures;
o continued development of wells for connection to our gathering
systems;
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 and Resource Energy to perform their
obligations under the master natural gas gathering agreement may adversely
affect our revenues. All of our revenues for the foreseeable future will consist
of the fees we receive under the master natural gas gathering agreement. We
anticipate that Atlas America and Resource Energy will pay our fees from the
gathering fees they receive from the well owners. However, Atlas America and
Resource Energy are contractually obligated to pay our fees even if the
gathering fees they receive from well owners are insufficient. Our cash flow
could be materially adversely affected if Atlas America and Resource Energy fail
to discharge their obligations to us.
-12-
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 it can no longer economically produce
natural gas and is plugged and abandoned. Failure to connect new wells to the
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.
Although we entered into the omnibus agreement to, among other things,
increase the number of natural gas wells connected to our gathering systems,
well connections resulting from that agreement depend principally upon the
success of Atlas America in sponsoring drilling programs for investors and
completing wells for these programs. We cannot assure you that Atlas America
will be able to continue to organize these partnerships, the amount of money
these partnerships will raise, the number of wells that will actually be drilled
or that wells drilled for these partnerships will produce natural gas in
economic quantities. Moreover, we cannot assure you that production from any
newly developed wells will be sufficient to offset production declines from
existing wells.
The amount of 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.
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. We cannot assure you, however, that this
will remain the case. The implementation of new laws or policies that would
subject us to regulation by the Federal Energy Regulatory Commission under the
Natural Gas Act could have a material adverse effect on our financial condition
and operations, as discussed under "Regulation."
Our gas gathering operations are subject to regulation at the state
level, which increases the costs of operating our pipeline facilities. 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 have
a material adverse effect on our financial condition and operations.
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 the pipelines. We can also be
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. While we
believe that the gathering systems comply in all material respects with
applicable laws and will be indemnified for any violations arising from events
that occurred before our acquisition of the gathering systems, we cannot assure
you that future events will not occur for which we may be liable. Possible
future developments, including stricter laws or enforcement policies, or claims
for personal or property damages resulting from our operations could result in
substantial costs and liabilities to us.
-13-
We are also subject to the requirements of 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 to regulated
substances.
We cannot predict whether or in what form any new legislation or
regulatory requirements might be enacted or adopted or the costs of compliance.
In general, any such new regulations would increase operating costs and impose
additional capital requirements on us, but we do not presently expect that such
costs or capital expenditure requirements would have a material adverse effect
on us.
We may not be able to fully execute our growth strategy if we encounter
tight capital markets or increased competition for qualified assets. Our current
strategy contemplates substantial growth through the acquisition and development
of assets and businesses. This strategy includes purchasing, constructing and
otherwise acquiring additional assets or businesses. Limitations on our access
to capital will impair our ability to execute this growth strategy. If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly.
Our ability to expand our gathering systems could be adversely affected
if Atlas America fails to provide the required financing. If we elect to use the
standby commitment from Atlas America to provide financing described in "Omnibus
Agreement - Construction Financing," Atlas America most likely will be required
to seek its own financing. If it cannot secure sufficient financing, expansion
of our gathering systems could be adversely affected. This could adversely
affect our growth and the amount of natural gas transported by our gathering
systems.
The amount of natural gas recoverable from properties potentially
served by our gathering systems may be less than our estimates, which could
materially adversely affect the amount of natural gas we gather and, thus, our
revenues. Estimates of the amount of natural gas recoverable from properties
potentially served by our gathering systems may vary substantially from actual
amounts that are economically recoverable. There are numerous uncertainties
inherent in estimating quantities of recoverable natural gas, including many
factors over which Atlas America has no control. Estimates of recoverable
natural gas necessarily depend upon a number of factors, any one of which may
vary considerably from actual results. These factors and assumptions relate to:
o the geological features of the rock formations in which the natural
gas is found;
o historical production from the area compared with production from
other producing areas;
o the assumed effects of regulation by governmental agencies; and
o assumptions concerning future natural gas prices, operating costs
and capital expenditures.
For these reasons, estimates of the recoverable quantities of natural
gas attributable to any particular group of properties, classifications of
properties based on risk of recovery of natural gas, and estimates of future net
cash flows expected from these properties, as prepared by different engineers or
by the same engineers at different times, may vary substantially. Actual
production, revenue and expenditures will likely vary from estimates, and these
variations may be material. If the amount of recoverable natural gas is
materially less than the estimates, the amount of natural gas we gather and,
thus, our revenues could be materially adversely affected.
If Atlas America, Resource Energy or Viking Resources default on their
obligations to us, we do not have contractual recourse to Resource America. The
omnibus agreement and master natural gas agreement between us and Atlas America,
Resource Energy and Viking Resources are material to our business, financial
condition and results of operations. Although Atlas America, Resource Energy and
Viking Resources are subsidiaries of Resource America, Resource America has not
guaranteed or otherwise assumed responsibility for any of its subsidiaries'
obligations to us.
-14-
A decline in natural gas prices could adversely affect our revenues.
Our master natural gas gathering agreement with Atlas America, Resource Energy
and Viking Resources provides for gathering fees equal to 16% of the gross sales
price of the natural gas we transport, subject to minimum prices of $.35 or $.40
per mcf. Contracts for wells connected to our gathering systems in the future
that will not be subject to the agreement will contain similar fee provisions,
but may not establish minimum prices. Our business will therefore depend in part
upon the prices at which the natural gas we transport is sold. Although
historically there has been an abundant demand for natural gas, there has from
time to time been a surplus of natural gas which has caused sharp fluctuations
and declines in prices obtainable.
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. Although
we intend to maintain customary insurance coverage for gathering systems of
similar capacity, we can offer no assurance that this coverage will be
sufficient for any casualty loss we may incur.
If we were to lose the management expertise of Atlas America, we would
not have sufficient stand-alone resources to operate. We do not directly employ
any of the persons responsible for our management. Rather, we rely on Atlas
America personnel to manage and operate our business as officers and employees
of our general partner. Therefore, if we were to lose the management expertise
of Atlas America, we would not have sufficient stand-alone resources to operate.
Further, neither our general partner nor we intend to obtain key man life
insurance for the officers and employees of our general partner.
ITEM 2. PROPERTIES
As of December 31, 2001, our principal facilities include approximately
1,300 miles of 2-inch to 12-inch diameter pipeline and 56 compressors, of which
eight 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 general partner believes that we have satisfactory
title to all of our properties.
Our property or rights-of-way are subject to encumbrances, restrictions
and other imperfections, although our general partner does not expect that these
imperfections will interfere materially 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 rights to maintain existing pipelines continue 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 well
ceases to produce.
-15-
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, 2001.
-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." Approximately 4,000 record holders held our common units as of
March 27, 2002. In connection with our initial public offering, we also issued
1,641,026 subordinated units, 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 on our common and subordinated units on a
quarterly basis since our common units began trading on January 28, 2000.
Distributions
Declared
High Low Per Unit
------ ------- --------------
2002
- ----
First quarter (through March 27, 2002)............................. $29.60 $23.51 $.52
2001
- ----
Fourth quarter..................................................... 29.50 19.25 .58
Third quarter...................................................... 31.95 25.01 .60
Second quarter..................................................... 53.95 24.00 .67
First quarter...................................................... 28.00 19.19 .65
2000
- ----
Fourth quarter..................................................... 18.94 13.50 .56
Third quarter...................................................... 19.38 12.75 .54
Second quarter..................................................... 14.06 10.88 .45
First quarter...................................................... 12.88 10.50 .30(1)
- ------------
(1) Minimum quarterly distribution of $.42 prorated for period from inception,
January 28, 2000, through March 31, 2000.
Pending completion or termination of our proposed acquisition of Triton, we
have agreed that we will not declare or pay quarterly distributions on our
common and subordinated units of more than $.60 per unit.
On January 5, 2001, we issued 88,235 of our common units to Kingston Oil
Corporation as partial consideration for the gas gathering system we acquired
from it on that date. We issued these common units to Kingston without
registration under the Securities Act in reliance on the exemption from
registration provided by Section 4(2) of the Securities Act and Rule 506
promulgated thereunder, which provides an exemption for sales of securities in a
private transaction.
On March 16, 2001, we issued 32,924 of our common units to American
Refining and Exploration Company as partial consideration for the gas gathering
system we acquired from it on that date. We issued these common units to
American Refining Exploration Company without registration under the Securities
Act in reliance on the exemption from registration provided by Section 4(2) of
the Securities Act and Rule 506 promulgated thereunder.
-17-
Our limited 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 which 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 of Minimum
---------- --------------------
$ .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.
Distributions to limited partners are allocated among the 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 extends until December 31, 2004 and,
thereafter, until certain financial criteria established by our limited
partnership agreement are met.
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.
-18-
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read together with the
consolidated financial statements, the notes to the consolidated financial
statements and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" which are included elsewhere in this report. The selected
financial data set forth below for the years ended December 31, 2001 and 2000 is
derived from financial statements appearing elsewhere in this report, audited by
Grant Thornton LLP.
For Years Ended
--------------------------------
December 31,
--------------------------------
2001 2000
----------- ----------
(in thousands, except per share data)
Income statement data:
Revenues............................................................................ $ 13,129 $ 9,466
=========== ==========
Depreciation and amortization....................................................... $ 1,356 $ 1,020
=========== ==========
Net income.......................................................................... $ 8,556 $ 6,625
=========== ==========
Net income per limited partner unit - basic and diluted............................. $ 2.30 $ 2.07
=========== ==========
Cash distributions declared per common unit......................................... $ 2.50 $ 1.85
=========== ==========
December 31,
--------------------------------
2001 2000
----------- ----------
(in thousands)
Balance sheet data:
Total assets........................................................................ $ 26,002 $ 22,092
Long-term debt...................................................................... 2,089 -
Common unitholders' capital......................................................... 20,129 18,122
Subordinated unitholder capital..................................................... 1,661 2,074
General partner's capital........................................................... (116) (89)
----------- ----------
Total capital.................................................................... $ 21,674 $ 20,107
=========== ==========
-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 is a discussion of our results of operations and
liquidity and capital resources for the periods indicated below. This discussion
should be read in conjunction with the consolidated financial statements and
notes thereto, which are included 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. We completed an initial public offering of our common units in February
2000 and used the proceeds of that offering to acquire the gathering systems
formerly owned by Atlas America, Inc. and its affiliates, all subsidiaries of
Resource America. The acquisition agreement provided that operations of the
gathering systems from and after January 28, 2000 would be for our account and,
accordingly, we deem January 28, 2000 to be the commencement of our operations.
The 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. The results of operations discussed below are for the year
ended December 31, 2001 and the period ended December 31, 2000.
In January 2001, we 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 consisted of
$1,250,000 of cash and 88,235 common units valued at $17.00 per unit. In March
2001, we 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 consisted of
$150,000 of cash and 32,924 common units valued at $22.78 per unit. We drew on
our $10.0 million line of credit in order to make both cash payments. These
acquisitions were accounted for under the purchase method of accounting and,
accordingly we allocated the purchase prices to the assets acquired based on
their fair values at the dates of acquisition.
Following the end of fiscal 2001, on January 18, 2002 we entered into
an agreement to acquire substantially all of the equity interests in Triton from
New Vulcan Coal Holdings and Vulcan Intermediary. The Vulcan entities will
contribute 98% of the equity interests in Triton and $6.0 million in cash to us
in exchange for 6,959,782 common units, 3,977,018 newly created subordinated
units and 17,640,000 newly created deferred participation units. The deferred
participation units will convert into subordinated units only if our combined
operations meet specified target levels for distributions and available cash
from operations. In addition, New Vulcan Coal Holdings will acquire our general
partner.
Triton is a coal mining company that owns and operates two large,
union-free surface coal mines located in the Southern Powder River Basin near
Gillette, Wyoming that produce environmentally compliant, sub-bituminous coal
for use by electric utilities. Triton is one of the ten largest domestic
producers of coal in total tons produced.
-20-
Upon the closing of the Triton acquisition, we will make a special,
one-time distribution of $3.70 per common unit to holders of common units as of
the date of the special meeting of unitholders called to approve the
acquisition. In addition, the 1,641,026 outstanding subordinated units held by
our general partner will be transferred to Resource America and will convert
into 1,481,026 common units. As a result of these transactions, the Vulcan
entities will own approximately 69.2% of our outstanding common units,
approximately 77.9% of our outstanding common and subordinated units in the
aggregate, and approximately 90.2% of our common and subordinated units in the
aggregate if all deferred participation units convert into subordinated units.
As conditions to the completion of the Triton acquisition, we will
also:
o amend and restate our limited partnership agreement and the limited
partnership agreement of our operating subsidiary, Atlas Pipeline
Operating Partnership;
o amend, restate and consolidate our master natural gas gathering
agreement and omnibus agreement with Atlas America, which will allow
Atlas America to continue to operate our pipeline systems and
include a new commitment from Resource America and Atlas America to
drill and connect 500 wells to our gathering systems;
o terminate our distribution support agreement with our general
partner; and
o enter into a registration rights agreement with respect to the
common units we will issue to the Vulcan entities and Resource
America.
We will need the affirmative vote of a majority of our outstanding
common units and outstanding subordinated units, each voting separately as a
class, to approve the Triton acquisition. Our general partner holds all of our
outstanding subordinated units and has agreed to vote all of them in favor of
the proposal. Accordingly, the class vote for the subordinated units approving
the Triton acquisition is assured. We filed a preliminary proxy statement, which
describes the Triton acquisition, with the Securities and Exchange Commission on
February 15, 2002.
Results of Operations
Our income for the year ended December 31, 2001, other than interest
income, was transportation and compression revenue. Two variables which affect
our transportation and compression revenues are:
o the volumes of natural gas transported by us, which are in turn a
function of the demand for natural gas in the regions served by our
gathering systems, and
o the transportation fees paid to us.
The following table sets forth the average volumes transported, average
transportation rates and revenues received by us for the years ended December
31, 2001 and 2000.
For The Years Ended
--------------------------------
December 31,
--------------------------------
2001 2000
--------------- -------------
Average daily throughput volumes in mcf.............. 46,918 42,734
=============== =============
Average transportation rate per mcf.................. $ .76 $ .65
=============== =============
Total transportation and compression revenues........ $ 13,094,700 $ 9,441,000
=============== =============
-21-
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Revenues. Our transportation and compression revenue increased to
$13,094,700 in the year ended December 31, 2001 from $9,441,000 in the year
ended December 31, 2000. The increase of $3,653,700 (39%) resulted from an
increase in both the volumes of natural gas we transported and an increase in
the average transportation fees paid to us.
Our average daily throughput volumes were 46,918 mcfs in the year ended
December 31, 2001 as compared to 42,734 mcfs in the year ended December 31,
2000, an increase of 4,184 mcfs (10%). The increase in the average daily
throughput volume resulted principally from volumes associated with pipelines
acquired during the three months ended March 31, 2001 and new wells added to our
pipeline system; 196 wells were turned on-line in the year ended December 31,
2001. These increases were partially offset by the natural decline in production
volumes inherent in the life of a well.
Our transportation rates are primarily at fixed percentages of the
sales price of natural gas transported. Our transportation rates for natural gas
produced by Atlas America and its affiliates also have specified minimums. Our
average transportation rate was $.76 per mcf in the year ended December 31, 2001
as compared to $.65 per mcf in the year ended December 31, 2000, an increase of
$.11 per mcf (17%). The increase in our average transportation rate resulted
from the increase in the average natural gas price received by producers for gas
transported through our pipeline system. Transportation rates had increased
significantly during the year, but had fallen back to an average of $.50 per mcf
for the month ended December 31, 2001.
Interest income of $34,600 consists of interest earned on funds
temporarily invested in short-term money market accounts, an increase of $9,400
(37%) from $25,200 for the year ended December 31, 2000.
Costs and Expenses. Our transportation and compression expenses
increased to $1,929,200 in the year ended December 31, 2001 as compared to
$1,223,800 in the year ended December 31, 2000, an increase of $705,400 (58%).
Our average cost per mcf of transportation and compression was $.11 in the year
ended December 31, 2001 as compared to $.08 in the year ended December 3, 2000,
an increase of $.03 (38%). This increase primarily resulted from an increase in
compressor expenses, including lease payments, in the year ended December 31,
2001 as compared to the prior year, due to upgrades and additions, and increased
costs approximating $253,600 associated with operating pipelines acquired in the
three months ended March 31, 2001.
Our general and administrative expenses increased to $1,112,800 in the
year ended December 31, 2001 as compared to $589,400 in the year ended December
31, 2000, an increase of $523,400 (89%). This increase primarily resulted from
an increase in allocated compensation and benefits ($182,000), and legal and
professional fees ($200,000) due to the increased level of activity associated
with acquisitions, and an increase in our insurance ($88,600), reflecting an
increase in our operating activities and assets and the insurance market.
Our depreciation and amortization expense increased to $1,356,100 in
the year ended December 31, 2001 as compared to $1,019,600 in the year ended
December 31, 2000, an increase of $336,500 (33%). This increase resulted from
the increased depreciation associated with pipeline extensions and acquisitions.
Our interest expense increased to $175,600 in the year ended December
31, 2001 as compared to $8,800 in the year ended December 31, 2000. This
increase of $166,800 resulted from borrowings on our credit facility in January
and March of 2001 to fund two acquisitions and an additional draw in June 2001
to fund capital expenditures associated with pipeline extensions.
-22-
Liquidity and Capital Resources
Our primary cash requirements, in addition to normal operating
expenses, are debt service, sustaining capital expenditures, expansion capital
expenditures and quarterly distributions to our common unitholders, subordinated
unitholders and general partner. In addition to utilizing cash generated from
operations, we could meet our cash requirements through borrowings under our
credit facilities or through contributions from our general partner pursuant to
the distribution support agreement.
The following table summarizes our financial condition at December 31, 2001 and
2000:
December 31,
-------------------------
2001 2000
---------- ----------
Current ratio........................................ 1.6 to 1 1.9 to 1
Working capital (in thousands)....................... $ 1,359 $ 1,845
Ratio of long-term debt to total partners' capital... .10 to 1 N/A
During 2001, net cash provided by operations of $10,268,200 was derived
principally from $9,911,700 of income from operations before depreciation and
amortization. This increase of $4,299,900 in cash provided by operations from
fiscal 2000 resulted primarily from an increase in income from operations before
depreciation and amortization of $2,267,500 and changes in operating assets and
liabilities of $1,996,700. The increase in cash flow provided by operations was
principally due to and increase in transportation revenue of $3,653,700 due to
an increase in both the volumes transported by us and the average price per mcf
received by us in fiscal 2001 as compared to fiscal 2000. This increase in
revenue was partially offset by increases of $1,228,800 in transportation and
general and administrative expenses due to an increase in our operating
activities. The increase in accounts receivable and prepaid expenses in the
prior year of $1,785,800, which represents two months of transportation fees,
was a result of fiscal 2000 being our initial year of operations.
Net cash used in investing activities was $3,128,000, a decrease of
$14,836,600 from cash used in investing activities in fiscal 2000. Net cash used
in investing activities during 2001 consisted of the acquisition of two small
pipelines from third parties ($1,400,000) and capital expenditures associated
with extensions and compression upgrades to our existing pipeline systems
($1,728,000). In the prior year, we used $16,635,100 for the initial acquisition
of our gathering system.
Net cash used in financing activities was $7,021,500, a change of
$21,060,300 from cash provided by financing activities of $14,038,800 in the
prior year. Distributions paid to partners during 2001 amounted to $9,118,300,
an increase of $5,435,400 over the year ended December 31, 2000. Net borrowings
of $2,089,000 were used to acquire two gas gathering systems and fund pipeline
extensions. In the prior year, we had received proceeds from our initial public
offering of $18,135,000.
Commitments
Through December 31, 2001, we have incurred costs of approximately
$400,000 and estimate that total costs associated with the Triton acquisition,
for which we will be responsible if the transaction does not close, will
ultimately exceed $3.0 million. We would then have the right to seek
reimbursement of up to $1.2 million from the Vulcan entities if Triton had not
obtained the $225.0 million of financing that is a condition of closing. Our
obligation to pay any remaining un-reimbursed costs could adversely affect our
ability to pay future minimum quarterly distributions. If the transaction
closes, we expect to use the Triton financing to pay the transaction costs,
which we estimate will be $21.0 million.
-23-
Debt Obligations and Credit Facilities
We entered into $10.0 million revolving credit facility in October
2000. For a description of the terms of this facility, you should read Note 5 to
our consolidated financial statements. Our principal purpose in obtaining the
facility was to help fund the expansion of out existing gathering systems and
the acquisitions of other gas gathering systems. In the year ended December 31,
2001, we used $1.4 million of the facility to fund, in part, the acquisitions of
two gas gathering systems and $689,000 of the facility to fund capital
expenditures for expansions of our existing gathering systems. At December 31,
2001, $2,089,000 was outstanding on this facility.
Capital Expenditures
Our property and equipment was approximately 77% and 71% of our total
consolidated assets at December 31, 2001 and 2000, respectively. Capital
expenditures, other than for the initial acquisition of the gathering system in
2000, and the acquisitions of two pipelines in 2001, were $1.9 million and $1.3
million for the years ended December 31, 2001 and 2000, respectively. These
capital expenditures principally consisted of costs relating to expansion of our
existing gathering systems as a result of new wells connected to our system and
compressor upgrades. We anticipate capital expenditures for 2002 of $4.3 million
for further expansion of our gathering systems, including approximately $2.5
million for a major trunk system expansion in Fayette County, Pennsylvania, and
upgrading of our compressor facilities. These capital expenditures will be
funded by a combination of cash generated from operations and from our existing
line of credit. As of December 31, 2001, however, we did not have any specific
commitments to make any capital expenditures. Our capital expenditures could
increase materially from our estimate if the number of wells connected to our
gathering systems in fiscal 2002 exceeds our current estimate.
Inflation and Changes in Prices
Inflation affects the operating expenses of the gathering systems.
Increases in those expenses are not necessarily offset by increases in
transportation rates 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 the 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
A continuing trend to greater environmental and safety awareness and
increasing environmental regulation has generally resulted in higher operating
costs for the oil and gas industry. We monitor environmental and safety laws and
we believe are in compliance with applicable environmental laws and regulations.
To date, however, compliance with environmental laws and regulations has not had
a material impact on our capital expenditures, earnings or competitive position.
We believe, however, that environmental and safety costs will increase in the
future. We cannot assure you that compliance with environmental laws and
regulations will not, in the future, materially adversely affect our operations
through increased costs of doing business or restrictions on the manner in which
we conduct our operations.
-24-
Recently Issued Financial Accounting Standards
In June 2001, the Financial Accounting Standards Board issued (SFAS)
No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 143, "Accounting
for Asset Retirement Obligations".
SFAS 142 requires that goodwill no longer be amortized, but instead
tested for impairment at least annually. Any goodwill and any intangible asset
determined to have an indefinite useful life that are acquired in a purchase
combination completed after June 2001 will not be amortized, but will be
evaluated for impairment in accordance with the appropriate existing accounting
literature. Goodwill and intangible assets acquired in business combinations
completed before July 2001 will continue to be amortized until we adopt SFAS
142, which is required to be adopted for fiscal years beginning after December
15, 2001. We do not expect the impact of adoption to have a material effect on
our consolidated financial statements. As of January 1, 2002, the date of
adoption, we have unamortized goodwill in the amount of $2.3 million which will
be subject to the transition provisions of SFAS 142. Amortization expense
related to goodwill was $88,000 for the year ended December 31, 2001.
SFAS 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
SFAS 143 will be effective for fiscal years beginning after June 15, 2002. We
are evaluating the impact of SFAS 143, but do not expect the adoption of it to
have a material effect on our consolidated financial statements.
In August 2001, SFAS No. 144, "Accounting for the Impairment of
Disposal of Long-Lived Assets" was issued, addressing financial accounting and
reporting for the impairment or disposal of long-lived assets. SFAS 144 requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
Implementation will be effective for fiscal years beginning after December 31,
2001. We are evaluating the impact of SFAS 144, but do not expect the adoption
of it to have a material effect on our consolidated financial statements.
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our consolidated financial
statements and related disclosures must be estimated, requiring us 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 our consolidated financial statements in conformity
with generally accepted accounting principles requires our management to make
estimates and assumptions that affect:
o the amount we report for assets and liabilities;
o our disclosure of contingent assets and liabilities at the date of
the consolidated financial statements; and
o the amounts we report for revenues and expenses during the reporting
period.
Therefore, the reported amounts of our assets and liabilities, revenues
and expenses and associated disclosures with respect to contingent assets and
obligations are necessarily affected by these estimates. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with experts and other methods we consider reasonable in the particular position
circumstances. Nevertheless, actual results may differ significantly from our
estimates. Any effects on our 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.
-25-
In preparing our consolidated financial statements and related
disclosures, we must use estimates in determining the economic useful lives of
our assets, provisions for uncollectable accounts receivable, exposures under
contractual indemnifications and various other recorded or disclosed amounts.
However, we believe that certain accounting policies are of more significance in
our financial statement preparation process than others. With respect to our
environmental exposure, we utilize both internal and external experts to assist
us in identifying environmental issues.
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.
Market risk inherent in our debt is the potential change arising from
increases or decreases in interest rates. Changes in variable rate debt usually
do not affect the fair value of the debt instrument, but may affect our future
earnings and cash flows.
We have a $10.0 million revolving credit facility to fund the expansion
of our existing gathering systems and the acquisition of other gas gathering
systems. The carrying value of our debt was approximately $2.1 million at
December 31, 2001. At our option, the facility bears interest at either the
lending institution's prime rate plus 50 basis points or the Euro Rate, which is
defined as an average of specified London InterBank Offered Rates ("LIBOR") plus
150 or 200 basis points, depending upon Atlas' leverage ratio. At December 31,
2001, the weighted average interest rate was 4.0%. A hypothetical 10% change in
the average interest rate applicable to this debt would result in a change of
approximately $9,000 in our net income and would not affect the market value of
this debt.
-26-
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,
2001 and 2000, and the related consolidated statements of income, partners'
capital (deficit) and cash flows for the year ended December 31, 2001 and the
period from commencement of operations on January 28, 2000 through December 31,
2000, hereafter referred to as the year ended December 31, 2000. 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, such consolidated financial statements present fairly,
in all material respects, the consolidated financial position of the Partnership
at December 31, 2001 and 2000 and the consolidated results of its operations and
its consolidated cash flows for the years ended December 31, 2001 and 2000 in
conformity with accounting principles generally accepted in the United States of
America.
/s/ Grant Thornton LLP
- ---------------------
Cleveland, Ohio
February 8, 2002
-27-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
------------------------------------
2001 2000
----------------- ---------------
ASSETS
Current assets:
Cash and cash equivalents........................................................ $ 2,162,200 $ 2,043,500
Accounts receivable - affiliates................................................. 1,312,300 1,781,400
Prepaid expenses................................................................. 123,500 4,400
------------- -------------
Total current assets........................................................... 3,598,000 3,829,300
Property and equipment:
Gas gathering and transmission facilities........................................ 24,153,400 18,648,900
Less - accumulated depreciation.................................................. (4,144,000) (2,875,900)
------------- -------------
Net property and equipment..................................................... 20,009,400 15,773,000
Goodwill (net of accumulated amortization of $285,300 and $197,300)................. 2,304,600 2,392,600
Other Assets (net of accumulated amortization of $53,300 and $8,800)................ 89,800 96,600
------------- -------------
$ 26,001,800 $ 22,091,500
============= =============
LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities......................................... $ 189,600 $ 101,100
Distribution payable............................................................. 2,049,600 1,883,300
------------- -------------
Total current liabilities...................................................... 2,239,200 1,984,400
Long-term debt...................................................................... 2,089,000 -
Partners' capital (deficit):
Common unitholders, 1,621,159 and 1,500,000 units outstanding.................... 20,128,700 18,122,200
Subordinated unitholder, 1,641,026 units outstanding............................. 1,660,900 2,073,800
General partner.................................................................. (116,000) (88,900)
------------- -------------
Total partners' capital........................................................ 21,673,600 20,107,100
------------- -------------
$ 26,001,800 $ 22,091,500
============= =============
See accompanying notes to consolidated financial statements
-28-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2001 AND 2000
December 31,
------------------------------------
2001 2000
-------------- -----------
Revenues:
Transportation and compression................................................... $ 13,094,700 $ 9,441,000
Interest income.................................................................. 34,600 25,200
------------- -----------
Total revenues................................................................. 13,129,300 9,466,200
Costs and expenses:
Transportation and compression................................................... 1,929,200 1,223,800
General and administrative....................................................... 1,112,800 589,400
Depreciation and amortization.................................................... 1,356,100 1,019,600
Interest......................................................................... 175,600 8,800
------------- -----------
Total costs and expenses....................................................... 4,573,700 2,841,600
------------- -----------
Net income.......................................................................... $ 8,555,600 $ 6,624,600
============= ===========
Net income - limited partners....................................................... $ 7,499,200 $ 6,492,100
============= ===========
Net income - general partner........................................................ $ 1,056,400 $ 132,500
============= ===========
Basic and diluted net income per limited partner unit............................... $ 2.30 $ 2.07
============= ===========
Weighted average limited partner units outstanding.................................. 3,254,543 3,141,026
============= ===========
See accompanying notes to consolidated financial statements
-29-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (DEFICIT)
YEARS ENDED DECEMBER 31, 2001 AND 2000
Number of Limited
Partner Units
---------------------------------- General
Common Subordinated Common Subordinated Partner
-----------------------------------------------------------------------------------------------
Balance at January 1, 2000.......... - - $ - $ - $ 1,000
Issuance of common units............ 1,500,000 - 18,135,000 - -
Issuance of subordinated units...... - 1,641,026 - 1,220,600 -
Payment of offering expenses........ - - (352,500) (382,400) (16,100)
Capital contribution................ - - - - 443,100
Distributions paid to partners...... - - (1,920,600) (1,237,200) (525,100)
Distribution payable................ - - (840,000) (919,000) (124,300)
Net income.......................... - - 3,100,300 3,391,800 132,500
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000........ 1,500,000 1,641,026 $ 18,122,200 $ 2,073,800 $ (88,900)
Issuance of common units............ 121,159 - 2,250,000 - -
Capital contributions............... - - - - 45,500
Distributions paid to partners...... - - (3,112,800) (3,150,700) (971,500)
Distribution payable................ - - (940,300) (951,800) (157,500)
Net income.......................... - - 3,809,600 3,689,600 1,056,400
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001........ 1,621,159 1,641,026 $ 20,128,700 $ 1,660,900 $ (116,000)
============= =========== ============= ============== =============
Partners'
Capital
(Deficit)
- ------------------------------------------------------
Balance at January 1, 2000.......... $ 1,000
Issuance of common units............ 18,135,000
Issuance of subordinated units...... 1,220,600
Payment of offering expenses........ (751,000)
Capital contribution................ 443,100
Distributions paid to partners...... (3,682,900)
Distribution payable................ (1,883,300)
Net income.......................... 6,624,600
- ------------------------------------------------------
Balance at December 31, 2000........ $ 20,107,100
Issuance of common units............ 2,250,000
Capital contributions............... 45,500
Distributions paid to partners...... (7,235,000)
Distribution payable................ (2,049,600)
Net income.......................... 8,555,600
- ------------------------------------------------------
Balance at December 31, 2001........ $ 21,673,600
=============
See accompanying notes to consolidated financial statements
-30-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2001 AND 2000
December 31,
------------------------------------
2001 2000
-------------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.......................................................................... $ 8,555,600 $ 6,624,600
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization.................................................... 1,356,100 1,019,600
Amortization of deferred finance costs........................................... 44,500 8,800
Change in operating assets and liabilities:
Decrease (increase) in accounts receivable-affiliates and prepaid expenses....... 350,000 (1,785,800)
(Decrease) increase in accounts payable and accrued liabilities.................. (38,000) 101,100
------------- -----------
Net cash provided by operating activities........................................ 10,268,200 5,968,300
------------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of gathering systems.................................................... (1,400,000) (16,635,100)
Capital expenditures................................................................ (1,728,000) (1,329,500)
------------- -----------
Net cash used in investing activities............................................ (3,128,000) (17,964,600)
------------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings on revolving credit facility......................................... 2,089,000 -
Proceeds from initial public offering............................................... - 18,135,000
Capital contributions............................................................... 45,500 443,100
Payment of formation costs.......................................................... (751,000)
Distributions paid to partners...................................................... (9,118,300) (3,682,900)
Increase in other assets............................................................ (37,700) (105,400)
------------- -----------
Net cash (used in) provided by financing activities.............................. (7,021,500) 14,038,800
------------- -----------
Increase in cash and cash equivalents............................................... 118,700 2,042,500
Cash and cash equivalents, beginning of year........................................ 2,043,500 1,000
------------- -----------
Cash and cash equivalents, end of year.............................................. $ 2,162,200 $ 2,043,500
============= ===========
Supplemental Cash Flow Information:
Cash paid during the year for interest........................................... $ 94,800 $ -
Non-cash Activities:
Issuance of units in exchange for gas gathering and transmission facilities-
Common......................................................................... $ 2,250,000 -
Subordinated................................................................... - $21,333,300
Liability for gas system acquisition............................................. $ 126,500 -
See accompanying notes to consolidated financial statements
-31-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001
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 were 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 and equipment leasing.
The accompanying financial statements and related notes present the
Partnership's consolidated financial position as of December 31, 2001 and 2000
and the results of its consolidated results of its operations, cash flows and
changes in partners' capital (deficit) for the year ended December 31, 2001 and
the period from commencement of operations on January 28, 2000 through December
31, 2000, hereafter referred to as the year ended December 31, 2000. All
material intercompany transactions and accounts have been eliminated.
Initial Public Offering and Concurrent Transactions
On February 2, 2000, the Partnership completed its initial public
offering (the "IPO") of 1,500,000 common units ("Common Units") representing
limited partner interests in the Partnership at a price of $13.00 per unit. The
Partnership retained for working capital purposes $750,000 of the $18.1 million
of net proceeds from the IPO and used the balance to pay certain offering costs
and, along with the issuance of 1,641,026 subordinated units valued at $21.3
million, to acquire the gathering systems from the Predecessor.
Consistent with guidance provided by the Emerging Issues Task Force in
Issue No. 87-21 "Change of Accounting Basis in Master Limited Partnership
Transactions," the Partnership maintained the carrying value of the
Predecessor's historical gas gathering and transmission facilities and
associated goodwill of $17.8 million. The issuance of the subordinated units
were valued in the financial statements at $1.2 million, which represented the
excess of the Predecessor's carrying value in the transferred assets over the
cash amount paid for them.
Partnership Structure and Management
The Partnership's operations are conducted through subsidiary entities
whose equity interests are owned by its subsidiary, Atlas Pipeline Operating
Partnership, L.P., an operating partnership (the "Operating Partnership"). Atlas
Pipeline Partners GP, LLC (the General Partner and a wholly-owned subsidiary of
Atlas), 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% is owned by limited partner interests of
which 49.7% consists of Common Units and 50.3% consists of Subordinated Units.
The rights of holders of the Subordinated Units are different from and are
subordinated to the rights of the holders of Common Units to participate in
distributions. 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.
-32-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2001
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies consistently applied
in the preparation of the accompanying consolidated financial statements
follows.
Principles of Consolidation
The consolidated financial statements include the accounts of 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.
Critical Accounting Policies and 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 generally accepted accounting principles 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.
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.
In preparing its consolidated financial statements and related
disclosures, the Partnership must use estimates in determining the economic
useful lives of its assets, provisions for uncollectable accounts receivable,
exposures under contractual indemnifications and various other recorded or
disclosed amounts. However, the Partnership believes that certain accounting
policies are of more significance in its financial statement preparation process
than others. With respect to environmental exposure, the Partnership utilizes
both internal and external experts to assist it in identifying environmental
issues.
Property and Equipment
Depreciation and amortization are provided for in amounts sufficient to
relate the cost of depreciable assets to operations over their estimated service
lives. 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.
-33-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2001
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
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 (see New Accounting Standards).
Goodwill
Goodwill is associated with the Predecessor's acquisition of the gas
gathering operations, and has been maintained at the Predecessor's carrying
value. Goodwill is being amortized over a period of 30 years, using the
straight-line method (see New Accounting Standards).
New Accounting Standards
In June 2001, the Financial Accounting Standards Board issued SFAS No.
141, "Business Combinations," SFAS 142, "Goodwill and Other Intangible Assets,"
and SFAS 143, "Accounting for Asset Retirement Obligations."
SFAS 141 requires that the purchase method of accounting be used for
all business combinations initiated or completed after June 2001. SFAS 141 also
specifies criteria that intangible assets acquired in a purchase method business
combination must meet to be recognized and reported apart from goodwill. The
adoption of SFAS 141 as of July 2001 had no impact on the Partnership's
consolidated financial statements.
SFAS 142 requires that goodwill no longer be amortized, but instead
tested for impairment at least annually. Any goodwill and any intangible asset
determined to have an indefinite useful life that is acquired in a purchase
business combination completed after June 2001 will not be amortized, but will
be evaluated for impairment in accordance with the appropriate existing
accounting literature. Goodwill and intangible assets acquired in business
combinations completed before July 2001 will continue to be amortized until the
Partnership adopts SFAS 142, which is required to be adopted for fiscal years
beginning after December 15, 2001. As of January 1, 2002, the Partnership
expects to have unamortized goodwill in the amount of $2.3 million which will be
subject to the transition provisions of SFAS 142. Amortization expense related
to goodwill was $88,000 for the year ended December 31, 2001. The Partnership
does not expect the adoption of SFAS 142 to have a material effect on the
Partnership's operations or financial position.
SFAS 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
SFAS 143 will be effective for fiscal years beginning after June 15, 2002. The
Partnership is evaluating the impact of SFAS 143.
-34-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2001
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
In August 2001, SFAS No. 144, "Accounting for the Impairment of
Disposal of Long-Live Assets" was issued addressing financial accounting and
reporting for the impairment or disposal of long-lived assets. SFAS 144 requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
Implementation will be effective for fiscal years beginning after December 31,
2001. The Partnership is evaluating the impact of SFAS 144.
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 March 2005), 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. The General Partner, in connection with
a distribution support agreement, was required to advance the first distribution
due to the normal lag time between transportation of volumes and receipt of
cash. Since that time, the Partnership has met all MQD requirements. The General
Partner was subsequently repaid from the second quarterly distribution. 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.
Revenue Recognition
Revenues are recognized at the time the natural gas is transported
through the gathering systems. Under the terms of the master natural gas
gathering agreement with Atlas and its affiliates, the Partnership receives fees
for gathering natural gas from wells either owned by Atlas, and limited
partnerships sponsored by Atlas or by independent third parties whose wells were
connected to the Partnership's gathering systems when operations commenced. The
fees received for the gathering services are 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. Transportation with third
parties are at separately negotiated prices.
-35-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2001
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Fair Value of Financial Instruments
For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments. The carrying value of long-term debt at December 31, 2001
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, by the weighted average number of
outstanding Common Units and Subordinated Units (a total of 3,262,185 units as
of December 31, 2001).
Comprehensive Income
The Partnership is subject to the provisions of Statement of Financial
Accounting Standards No. 130 "Reporting Comprehensive Income," which requires
disclosure of comprehensive income and its components. Comprehensive income
includes net income and all other changes in 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 material
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.
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 and brokerage firms. At December 31, 2001, the
Partnership had $2.2 million in deposits at one bank, of which $2.0 million was
over the insurance limit of the Federal Deposit Insurance Corporation. No losses
have been experienced on such investments.
-36-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2001
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
receivable-affiliates represents the net balance due from these Affiliates for
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 currently 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 who are retained by the
General Partner. The General Partner does not receive a management fee or other
compensation in connection with its management of the Partnership. The
Partnership reimburses Atlas America 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 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, 2001 and 2000, such reimbursements were approximately $4.9
million and $3.0 million, respectively, including costs capitalized by the
Partnership.
Under an agreement with Atlas and its Affiliates, 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, 2001, the Partnership had not availed itself of the stand-by financing.
NOTE 4 - DISTRIBUTION DECLARED
On December 21, 2001, the Partnership declared a cash distribution of
$.58 per unit on its outstanding Common Units and Subordinated Units. The
distribution represented the available cash flow for the three months ended
December 31, 2001. The $2,049,600 distribution, which included a distribution of
$157,500 to the General Partner in respect of its general partner interest, was
paid on February 8, 2002 to unit holders of record on December 31, 2001.
-37-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2001
NOTE 5 - LONG-TERM DEBT AND CREDIT FACILITY
In October 2000, Atlas Pipeline entered into a $10.0 million revolving
credit facility administered by PNC Bank, National Association. Up to $3.0
million of the facility may be used for standby letters of credit. 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.
The revolving credit facility has a term ending in October 2003 and bears
interest at one of two rates, elected at the Partnership's option: (i) the Base
Rate plus the Applicable Margin or (ii) the Euro Rate plus the Applicable
Margin. As used in the facility agreement, the Base Rate is the higher of (a)
PNC Bank's prime rate or (b) the sum of the federal funds rate plus 50 basis
points. The Euro Rate is the average of specified LIBOR rates divided by 1.00
minus the percentage prescribed by the Federal Reserve Board for determining
reserve requirements. The Applicable Margin varies with the Partnership's
leverage ratio from between 150 to 200 basis points (for the Euro Rate option)
or 0 to 50 basis points (for the Base Rate option). Draws under any letter of
credit bear interest as specified under (i), above. The credit facility contains
financial covenants, including the requirement that Atlas Pipeline maintain: (a)
a leverage ratio not to exceed 3.0 to 1.0, (b) an interest coverage ratio
greater than 3.5 to 1.0 and (c) a minimum tangible net worth of $14.0 million.
In addition, the facility limits, among other things, sales, leases or transfers
of property by the Partnership, the incurrence by the Partnership of other
indebtedness and certain investments by Atlas Pipeline. As of December 31, 2001,
$2.1 million was outstanding under this facility at an average interest rate of
4.0%.
NOTE 6 - LEASES AND COMMITMENTS
The Partnership leases certain compressors associated with its
gathering systems. Rent expense for the year ended December 31, 2001 was
$783,742. Minimum future lease payments for these leases as of December 31, 2001
were as follows: 2002 - $617,800; 2003 - $48,500.
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 $1.25 million of cash and 88,235 common units valued
at $17.00 per unit. The Partnership drew on the $10.0 million line of credit in
order to make the cash payment.
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. The Partnership drew on its $10.0 million line
of credit in order to make the cash payment.
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.
-38-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2001
NOTE 8 - SUBSEQUENT EVENT
On January 18, 2002, the Partnership announced that it entered into an
agreement to acquire Triton Coal Company, LLC ("Triton"), from New Vulcan Coal
Holdings, L.L.C. and one of its affiliates (collectively, "Vulcan"). Vulcan will
make a $6.0 million cash contribution to the Partnership, which will be paid out
to the Partnership's Common Unitholders as a one-time cash distribution of $3.70
per outstanding Common Units promptly after closing. The Partnership will issue
to Vulcan 7.0 million Common Units, 4.0 million Subordinated Units and 17.6
million deferred participation units (representing a right to receive
Subordinated Units if certain financial thresholds are achieved). The
Partnership presently has outstanding 1.62 million Common Units and 1.64 million
Subordinated Units. In connection with the Triton transaction, the General
Partner's 1.64 million subordinated units will convert into 1.48 million Common
Units, which will constitute 14.7% of the Common Units and 10.5% of the Common
and Subordinated Units in the aggregate. The current common unitholders, who
currently own 100% of the outstanding Common Units and approximately 49.7% of
the total outstanding Common and Subordinated Units in the aggregate, will own
approximately 16.1% of the total Common Units and 11.5% of the Common and
Subordinated Units in the aggregate. The acquisition is contingent upon approval
by the Partnerships unitholders and refinancing of Triton's and the
Partnership's debt.
Additionally, the master gathering agreement will be modified so that
Atlas will continue to control and manage, maintain and extend the gas gathering
system in return for a fee and reimbursement of certain of its expenses. Atlas
will continue to sell interests in drilling partnerships and, as in the past,
when feasible, connect completed wells to the Partnership's gas gathering
systems.
Simultaneously with the closing of the acquisition of Triton Coal
Company, Atlas will sell its interest in the General Partner. Both agreements
may be terminated if the transactions are not consummated by May 15, 2002,
subject to an extension to June 30, 2002.
-39-
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001
NOTE 9 - QUARTERLY FINANCIAL DATA (Unaudited)
For the Quarter Ended
----------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ----------- ------------ -----------
(in thousands, except for unit and per unit data)
Year ended December 31, 2001
Revenues.................................................... $ 4,281 $ 3,424 $ 2,587 $ 2,837
Costs and expenses.......................................... 945 1,225 1,230 1,174
Net income.................................................. 3,336 2,199 1,357 1,663
Net income - limited partners............................... 2,987 1,801 1,195 1,516
Net income - general partner................................ 349 398 162 147
Basic and diluted net income per limited partner unit....... .92 .55 .37 .46
Weighted average units outstanding.......................... 3,231,193 3,262,185 3,262,185 3,262,185
Year ended December 31, 2000
Revenues.................................................... $ 1,150 $ 2,295 $ 2,938 $ 3,083
Costs and expenses.......................................... 384 656 945 856
Net income.................................................. 766 1,639 1,993 2,227
Net income - limited partners............................... 751 1,606 1,953 2,182
Net income - general partner................................ 15 33 40 45
Basic and diluted net income per limited partner unit....... .24 .51 .62 .70
Weighted average units outstanding.......................... 3,141,026 3,141,026 3,141,026 3,141,026
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE
None
-40-
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER
As is commonly the case with publicly traded limited partnerships, we
are managed and operated by our general partner. The following table sets forth
information with respect to the executive officers and managing board members of
our general partner, Atlas Pipeline Partners GP, LLC. Executive officers and
managing board members serve one year terms.
Name Age Position with General Partner
- ---- --- -----------------------------
Edward E. Cohen 62 Chairman of the Managing Board
Jonathan Z. Cohen 31 Vice-Chairman of the Managing Board
Michael L. Staines 52 President, Chief Operating Officer,
Secretary and Managing Board Member
Tony C. Banks 47 Managing Board Member
William R. Bagnell 39 Managing Board Member
George C. Beyer, Jr. 62 Managing Board Member
Murray S. Levin 55 Managing Board Member
Edward E. Cohen has been Chairman of the Board of Directors of Resource
America since 1990 and Chief Executive Officer and a director of Resource
America since 1988. He has been Chairman of the Board of Directors of Atlas
America since 1998. He is Chairman of the Board of Directors and a director of
Brandywine Construction & Management, Inc., a real estate construction and
management company, and a director of TRM Corporation, a consumer services
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 Executive Vice President of Resource America
since 2001. Before that, Mr. Cohen had been a Senior Vice President since 1999.
Mr. Cohen has been Vice Chairman and a director of Atlas America and a director
of Resource Energy since 1998. Mr. Cohen has also served as Trustee and
Secretary of RAIT Investment Trust, a real estate investment trust, since 1997
and Chairman of the Board of Directors of the Richardson Company, a sales
consulting company, since 1999. From 1994 to 1997, Mr. Cohen was Chief Executive
Officer of Blue Guitar Films, Inc., a New York based media company. 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 and Secretary from 1989 through 2000. Mr.
Staines has also been President, Secretary and a director of Resource Energy
since 1993. Since 1998, Mr. Staines has also been Executive Vice President,
Secretary and a director of Atlas America. Mr. Staines is a member of the Ohio
Oil and Gas Association and the Independent Oil and Gas Association of New York.
Tony C. Banks has been the Chairman of the Board of Directors of
Optiron Corporation, an energy technology subsidiary of Atlas America, since
2000. Before that, he was President and Chief Executive Officer of Atlas
America. From 1995 to 1998, Mr. Banks was a Vice President of various
subsidiaries of Atlas America. From 1974 to 1995, Mr. Banks was employed in
various accounting and administrative positions with subsidiaries of
Consolidated Natural Gas Company, most recently as Treasurer of its national
energy marketing subsidiary.
William R. Bagnell has been Vice President-Energy for Planalytics,
Inc., an energy industry software company, since March 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.
-41-
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER - (Continued)
George C. Beyer, Jr. has been Chief Executive Officer of Valley Forge
Financial Group, a financial planning company, since 1967, and is a co-founder
of Valley Forge Technologies Group, Inc. Mr. Beyer was also a co-founder of IBS,
Inc., an employee benefits consulting firm. Mr. Beyer serves as a director of
Commonwealth Bancorp, IBS, Valley Forge Financial Group, Inc., Valley Forge
Pension Management, Inc., Valley Forge Investment Consultants, Inc. and Valley
Forge Technologies Group, Inc.
Murray S. Levin is Managing Director and partner in the Litigation
Department of Pepper Hamilton LLP. He primarily handles pharmaceutical products
liability cases and an array of commercial matters, including those with an
international cast. In recent years, Mr. Levin has done a large volume of work
in the products liability area for many pharmaceutical companies and their
subsidiaries. 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.
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 on our review of reports received by us, or written
representations from certain reporting persons that they were not required to
make any filings, we believe that, during fiscal 2001, the executive officers
and directors of our general partner and greater than ten percent unitholders
complied with all applicable filing requirements except that Edward Cohen and
Jonathan Cohen failed to file Form 4s on a timely basis in connection with sales
of our common units by Charles Rennie Financial, Inc., on whose board of
directors they both serve.
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. We reimburse our general partner and its
affiliates, including Atlas America, 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. The partnership
agreement provides that the general partner will determine the expenses that are
allocable to us in any reasonable manner determined by the general partner in
its sole discretion. The 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 $4.9 million for expenses incurred during fiscal 2001.
-42-
ITEM 11. EXECUTIVE COMPENSATION
Executive Compensation
We do not directly compensate the executive officers of our general
partner. Rather, Atlas 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 Atlas America and its affiliates, and we
reimburse them for the compensation allocated to us. The compensation allocation
for fiscal 2001 was $208,000.
Compensation of Managing Board Members
We do not pay additional remuneration to officers of our general
partner or its affiliates who also serve as managing board members. We pay each
independent managing board member an annual retainer of $6,000, $1,000 for each
board meeting attended, $1,000 for each committee meeting attended where he is
chairman of the committee and $500 for each committee meeting attended where he
is not chairman. In addition, we reimburse each independent board member for
out-of-pocket expenses in connection with attending meetings of the board or
committees. We indemnify our general partner's managing board members for
actions associated with being managing board members to the extent permitted
under Delaware law. We paid an aggregate of $46,000 to managing board members in
fiscal 2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of common units
held by beneficial owners of 5% or more of the units, by members of the managing
board of our general partner and by all managing board members of our general
partner as a group as of February 22, 2002. The subordinated units listed
opposite the name of each managing board member represent subordinated units
owned by our general partner. By reason of their position as managing board
members 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 and its managing board members is 311 Rouser Road, Moon Township,
Pennsylvania 15108.
Percentage of
Percentage of Subordinated Subordinated
Common Units to Units to be Units to be
Common Units to be be Beneficially Beneficially Beneficially
Name of Beneficial Owner Beneficially Owned Owned Owned Owned
------------------------ ------------------ --------------- ------------ -------------
Atlas Pipeline Partners GP................... - - 1,641,026 100%
Edward E. Cohen.............................. - - 1,641,026 100%
Jonathan Z. Cohen............................ 2,397 * 1,641,026 100%
Michael L. Staines........................... - - 1,641,026 100%
William R. Bagnell........................... - - 1,641,026 100%
George C. Beyer, Jr.......................... - - 1,641,026 100%
Tony C. Banks................................ - - 1,641,026 100%
Murray S. Levin.............................. - - 1,641,026 100%
Managing board members as a group (7 persons) 2,397 * 1,641,026 100%
- -----------------------
* Less than 1%
-43-
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
At December 31, 2001, our general partner owned 1,641,026 subordinated
units constituting a 50% limited partnership 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
$5,165,500 during fiscal 2001 in respect of these interests.
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.
The omnibus agreement and the master natural gas gathering agreement
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.
We do not currently directly employ any persons to manage or operate
our business. These functions are provided by the General Partner and employees
of RAI and/or its Affiliates who are retained by the General Partner. The
General Partner does not receive a management fee or other compensation in
connection with its management of us. We reimburses the General Partner for all
direct and indirect costs of services provided, including the cost of employees
and officer and managing board member compensation and benefits properly
allocable to us, and all other expenses necessary or appropriate to the conduct
of the business of, and allocable to, us.
-44-
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) Financial Statements
The financial statements required by this Item 14(a)(1) are
set forth in Item 8.
(a)(2) Financial Statement Schedules
No schedules are required to be presented.
(a)(3) Exhibits
3.1 (1) Amended and Restated Agreement of Limited Partnership of
Atlas Pipeline Partners, L.P.
3.2 (1) Certificate of Limited Partnership of Atlas Pipeline Partners, L.P.
4.1 (1) Common unit certificate
10.1 (1) Amended and Restated Agreement of Limited Partnership of Atlas Pipeline
Operating Partnership, L.P.
10.2 (1) Omnibus Agreement among Atlas Pipeline Partners, L.P., Atlas Pipeline
Operating Partnership, L.P., Atlas America, Inc., Resource Energy Inc. and
Viking Resources Corporation
10.3 (1) Master Natural Gas Agreement among Atlas Pipeline Partners, L.P.,
Atlas Operating Pipeline Partnership, L.P., Atlas America, Inc.,
Resource Energy, Inc. and Viking Resources Corporation
10.4 (1) Distribution Support Agreement between Atlas Pipeline Partners, L.P. and
Atlas Pipeline Partners GP, LLC
10.5 (2) Loan Agreement among Atlas Pipeline Partners, L.P., PNC Bank,
National Association and First Union National Bank
21.1 Subsidiaries of Atlas Pipeline Partners, L.P.
- --------------
(1) Filed previously as an exhibit to our Registration Statement on Form S-1
(Registration No. 333-85193) and by this reference incorporated herein.
(2) Filed previously as an exhibit to our Annual Report on Form 10-K for the
year ended December 31, 2000, and by this reference incorporated herein.
(b) Reports on Form 8-K
None
-45-
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 28, 2002 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 28, 2002.
/s/ Edward E. Cohen Chairman of the Managing Board of the General Partner
- ----------------------------------
EDWARD E. COHEN
/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/ 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/ George C. Beyer, Jr. Managing Board Member of the General Partner
- ----------------------------------
GEORGE C. BEYER, JR.
/s/ Murray S. Levin Managing Board Member of the General Partner
- ----------------------------------
MURRAY S. LEVIN
-46-