ITEM 1. BUSINESS
THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING EVENTS AND FINANCIAL TRENDS WHICH MAY AFFECT OUR FUTURE OPERATING RESULTS AND FINANCIAL POSITION. SUCH STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT COULD CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM THOSE ANTICIPATED IN FORWARD-LOOKING STATEMENTS. THESE FACTORS INCLUDE FLUCTUATIONS IN THE MARKET FOR NATURAL GAS FROM WHICH OUR REVENUES ARE DERIVED, PRODUCTION DECLINES FROM WELLS SERVICED BY OUR GATHERING SYSTEMS, REDUCED DRILLING FOR NEW WELLS IN OUR SERVICE AREAS AND OUR NEED FOR ADDITIONAL CAPITAL TO EXPAND OUR GATHERING SYSTEMS.
General
We are a Delaware limited partnership with common units traded on the American Stock Exchange under the symbol "APL." We own and operate natural gas pipeline gathering systems in eastern Ohio, western New York and western Pennsylvania. As of December 31, 2002, our gathering systems, in the aggregate, consisted of over 1,380 miles of intrastate pipelines, including approximately 80 miles of intrastate pipelines we constructed or acquired during the year then ended. Our gathering systems served approximately 4,200 wells at December 31, 2002, with an average daily throughput for the year then ended of 50.4 million cubic feet, or Mmcf, of natural gas. Our gathering systems provide a means through which well owners and operators can transport the natural gas produced by their wells to public utility pipelines for delivery to customers. To a significantly lesser extent, our gathering systems transport natural gas directly to customers. During the year ended December 31, 2002, our gathering systems transported 18.4 billion cubic feet, or Bcf, of natural gas, an increase of 7% and 27% from the years ended December 31, 2001 and 2000, respectively. We connected 214 wells to our gathering systems in the year ended December 31, 2002 and 559 wells since our commencement of operations in January 2000. In addition, we have added 433 wells through acquisitions of pipeline.
Our gathering systems currently connect with public utility pipelines operated by Peoples Natural Gas Company, National Fuel Gas Supply, Tennessee Gas Pipeline Company, National Fuel Gas Distribution Company, East Ohio Gas Company, Columbia of Ohio, Consolidated Natural Gas Co., Texas Eastern Pipeline, Columbia Gas Transmission Corp. and Equitable Utilities. Public utility pipelines charge transportation fees to the person having title to the natural gas being transported, typically the well owner, an intermediate purchaser such as a natural gas distribution company, or a final purchaser. We do not have title to the natural gas gathered and delivered by us and, accordingly, do not pay transportation fees charged by public utility pipelines. We do not 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 our gathering systems.
During the years ended December 31, 2002, 2001 and 2000, we had one business segment, the transportation segment. We derive our revenues primarily from the transportation of natural gas. In the year ended December 31, 2002, substantially all of our revenues were generated by transporting natural gas produced by Atlas America, Inc., a wholly-owned subsidiary of Resource America, Inc., the indirect parent of our general partner, Atlas Pipeline Partners GP, LLC. Under our transportation agreements with Atlas America, the gathering fees we receive are generally equal to a percentage, generally 16%, of the gross or weighted average sales price of the natural gas we transport subject, in certain cases, to minimum prices of $.35 or $.40 per thousand cubic feet, or Mcf. Our business therefore depends in large part upon the prices at which the natural gas we transport is sold. Due to the volatility of natural gas prices, our gross revenues can vary materially from period to period.
Objectives and Strategy
Our objective is to increase cash flow, earnings and returns to our unitholders by:
o expanding our existing asset base through construction of extensions necessary to service additional wells drilled by Atlas America and others;
o expanding our existing asset base through accretive acquisitions of gathering systems from other persons;
o achieving economies of scale as a result of expanding our operations through extensions and acquisitions;
o maintaining cost efficient operations and expansion of the system; and
o continuing to strengthen our balance sheet by financing our growth with a combination of long-term debt and equity so as to provide the financial flexibility to fund future opportunities.
Since commencing operations in January 2000, we have achieved these objectives by:
o adding 360 miles of pipeline to our original system;
o connecting 559 new wells to our pipeline, 500 of which were drilled by Atlas America and 59 by other operators;
o acquiring two gathering systems in Ohio and Pennsylvania, aggregating 120 miles of pipeline with approximately 433 wells connected to those systems; and
o upgrading our system and substantially expanding our capacity.
We believe that our focus on the mid stream gas industry, specifically gas gathering systems, the extensive prior experience of our general partner's management in the operation of gathering systems, our position as one of the largest operators of gathering systems in the Appalachian Basin and our relationship with Atlas America provide us with a competitive advantage in executing our growth strategy to achieve our business objectives.
Pipeline Characteristics
We set forth in the following table the volumes of the natural gas we transported, in Mcfs, in the years ended December 31, 2002, 2001 and 2000.
For the years ended Inception through December 31, December 31, --------------------------- 2002 2001 2000 ---------- ---------- ---------- New York systems............ 493,600 570,500 408,800 Ohio systems................ 5,396,900 5,378,200 3,902,200 Pennsylvania systems........ 12,492,100 11,176,300 10,175,800 ---------- ---------- ---------- 18,382,600 17,125,000 14,486,800 ========== ========== ==========
Of the approximately 4,200 wells currently connected to our gathering systems, approximately 3,800 are owned by Atlas America or its affiliates or by investment partnerships managed or operated by Atlas America or its affiliates with the remainder being owned or managed by third parties. We have agreements with Atlas America and its affiliates relating to the connection of future wells owned or controlled by them to our gathering systems and the transportation fees we will charge. We describe these agreements under "-Agreements with Atlas America." These wells are the principal producers of gas transported by our gathering systems and we anticipate that wells controlled by Atlas America will continue in the future to be the principal producers into our gathering systems. As of December 31, 2002, Atlas America and its affiliates controlled leases on developed properties in the operational area of our gathering systems totaling approximately 265,000 gross acres. In addition, Atlas America and its affiliates control leases on approximately 223,000 undeveloped gross acres of land. During the year ended December 31, 2002, Atlas America and its affiliates drilled and connected 195 wells to our gathering systems as compared to 196 wells during the year ended December 31, 2001.
The gathering systems are generally constructed with 2, 4, 6, 8 and 12 inch cathodically protected and wrapped steel pipe and are generally buried 36 inches below the ground. Pipelines constructed in this manner typically are expected to last at least 50 years from the date of construction. For the years ended December 31, 2002, 2001 and 2000, the cost of operating the gathering systems, excluding depreciation, was approximately $2.1 million, $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 and the price received for this natural gas. Our ability to increase the flow of natural gas through our gathering systems and to offset the natural decline of the production already connected to our gathering systems will be determined primarily by our ability to connect new wells to our gathering systems and to acquire additional gathering assets.
Agreements with Atlas America
At the completion of our initial public offering, we entered into an omnibus agreement and a master natural gas gathering agreement with Atlas America and two of its affiliates, Resource Energy, Inc. and Viking Resources Corporation. The purpose of these agreements is to maximize the use and expansion of our gathering systems and the volume of natural gas they transport. Since then, we have entered into additional gas gathering agreements with subsidiaries of Atlas America. None of these agreements resulted from arm's length negotiations and, accordingly, we cannot assure you that we could not have obtained more favorable terms from independent third parties similarly situated. However, since these agreements principally involve the imposition of obligations on Atlas America and its affiliates, we do not believe that we could obtain similar agreements from independent third parties.
Omnibus Agreement. Under the omnibus agreement, Atlas America and its affiliates agreed to add wells to the gathering systems and provide consulting services when we construct new gathering systems or extend existing systems. The omnibus agreement also imposes conditions upon our general partner's disposition of its general partner interest in us. The omnibus agreement is a continuing obligation, having no specified term or provisions regarding termination except for a provision terminating the agreement if our general partner is removed as general partner without cause.
Well Connections. Atlas America sponsors oil and gas drilling 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 drilled that are more than 3,500 feet from our gathering systems, we have the right, at our cost, to extend our gathering systems. If we do not elect to extend our gathering systems, Atlas America may connect the wells to an interstate or intrastate pipeline owned by third parties, a local natural gas distribution company or an end user; however, we will have the right to assume the cost of construction of the necessary lines, which then become part of our gathering systems. We must exercise our rights within 30 days of notice to us from Atlas America that it intends to drill on a particular site that is not within 3,500 feet of our gathering systems. If we elect to have the well connected to our gathering systems, we must complete construction of one of our gathering systems to within 2,500 feet of the well within 60 days after Atlas America has notified us that the well will be completed as a producing natural gas well. If we elect to assume the cost of constructing lines, Atlas America will be responsible for the construction, and we must pay the cost of that construction within 30 days of Atlas America's invoice.
Consulting Services. The omnibus agreement requires Atlas America to assist us in identifying existing gathering systems for possible acquisition and to provide consulting services to us in evaluating and making a bid for these systems. Any gathering system that Atlas America or its affiliates identify as a potential acquisition must first be offered to us. We will have 30 days to determine whether we want to acquire the identified system and advise Atlas America of our intent. If we intend to acquire the system, we have an additional 60 days to complete the acquisition. If we do not complete the acquisition, or advise Atlas America that we do not intend to acquire the system, then Atlas America may do so.
Gathering System Construction. The omnibus agreement requires Atlas America to provide us with construction management services if we determine to expand one or more of our gathering systems. We must reimburse Atlas America for its costs, including an allocable portion of employee salaries, in connection with its construction management services.
Construction Financing. The omnibus agreement requires Atlas America to provide us with stand-by financing of up to $1.5 million per year for the cost of constructing new gathering systems or gathering system expansions until February 2005. If we choose to use the stand-by commitment, the financing will be provided through the purchase by Atlas America of our common units in the amount of the construction costs as they are incurred. The purchase price of the common units will be the average daily closing price for the common units on the American Stock Exchange for the 20 consecutive trading days before the purchase. Construction costs do not include maintenance expenses or capital improvements following construction or costs of acquiring gathering systems. We are not obligated to use the stand-by commitment and may seek financing from other sources. We have not used the stand-by commitment to date.
Disposition of Interest in Our General Partner. Direct and indirect wholly-owned subsidiaries of Atlas America act as the general partners, operators or managers of the oil and gas investment partnerships sponsored by Atlas America. Our general partner is a subsidiary of Atlas America. Under the omnibus agreement, those subsidiaries, including our general partner, that currently act as the general partners, operators or managers of partnerships sponsored by Atlas America must also act as the general partners, operators or managers for all new 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%.
Natural Gas Gathering Agreements. Under the master natural gas gathering agreement, we receive a fee from Atlas America for gathering natural gas, determined as follows:
o for natural gas from well interests allocable to Atlas America, or its subsidiaries (excluding general or limited partnerships sponsored by them) that were connected to our gathering systems at February 2, 2000, the greater of $.40 per mcf or 16% of the gross sales price of the natural gas transported;
o for natural gas from well interests allocable to general and limited partnerships sponsored by Atlas America that are connected to our gathering systems at any time, and well interests allocable to independent third parties in wells connected to our gathering systems before February 2, 2000, the greater of $.35 per Mcf or 16% of the gross sales price of the natural gas transported;
o for natural gas from well interests allocable to Atlas America that are connected to our gathering systems after February 2, 2000, the greater of $.35 per Mcf or 16% of the gross sales price of the natural gas transported; and
o for natural gas from well interests operated by Atlas America and drilled after December 1, 1999 that are connected to a gathering system that is not owned by us and for which we assume the cost of constructing the connection to that gathering system, an amount equal to the greater of $.35 per Mcf or 16% of the gross sales price of the natural gas transported, less the gathering fee charged by the other gathering system.
Atlas America receives gathering fees from contracts or other arrangements with third party owners of well interests connected to our gathering systems. However, Atlas America must pay gathering fees owed to us from 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 as the shipper of natural gas, will indemnify us against claims relating to ownership of the natural gas transported. For all other claims relating to natural gas we transport, the party that has control and possession of the natural gas must indemnify the other party with respect to losses arising in connection with or related to the natural gas when it is in the first party's possession and control.
In addition to the master natural gas gathering agreement, we have three other gas gathering agreements with subsidiaries of Atlas America. Under two of these agreements, relating to wells located in southeastern Ohio which Atlas America acquired from Kingston Oil Corporation and wells located in Fayette County, Pennsylvania which Atlas America acquired from American Refining and Exploration Company, we receive a fee of $.80 per Mcf. Under the third agreement, which covers wells owned by third-parties unrelated to Atlas America or the investment partnerships it sponsors, we receive fees that range from $.20 to $.29 per Mcf and 10% to 16% of the weighted average credit facility sales price for the natural gas we transport.
Credit Facility
In December 2002, we entered into a $7.5 million credit facility administered by Wachovia Bank, National Association. In March 2003, Wachovia Bank and KeyBank increased the facility by an additional $2.5 million until June 2003. KeyBank, National Association increased this facility to $15.0 million. This facility replaced a similar facility administered by PNC Bank. Borrowings under the facility are secured by a lien on and security interest in all of our property and our subsidiaries. Up to $3.0 million of the facility may be used for standby letters of credit. The revolving credit facility has a term ending in December 2005 and bears interest at one of two rates, elected at our option:
o the base rate plus the applicable margin; or
o the adjusted LIBOR plus the applicable margin.
The base rate for any day equals the higher of the federal funds rate plus 1/2 of 1% or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for euro currency funding. The applicable margin is as follows:
o where our leverage ratio, that is, the ratio of our debt to EBITDA, as defined in the credit facility agreement, is less than or equal to 1.5, the applicable margin is 0.00% for base rate loans and 1.50% for LIBOR loans;
o where our leverage ratio is greater than 1.5, but less than or equal to 2.5, the applicable margin is 0.25% for base rate loans and 1.75% for LIBOR loans; and
o where our leverage ratio is greater than 2.5, the applicable margin is 0.50% for base rate loans and 2.00% for LIBOR loans.
The credit facility requires us to maintain specified net worth and specified ratios of current assets to current liabilities and debt to EBITDA, and requires us to maintain a specified interest coverage ratio. We used this credit facility to pay off our previous revolving credit facility with PNC Bank.
Our principal purpose in obtaining the facility was to fund the expansion of our existing gathering systems and the acquisitions of other gas gathering systems. In the years ended December 31, 2002 and 2001, we used $4.4 million and $2.1 million of our credit facility to fund, in part, capital expenditures for expansions of our existing gathering systems and the acquisitions of two gas gathering systems. At December 31, 2002, $6.5 million was outstanding under our facility.
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.
We principally service wells drilled by Atlas America and are thus affected by competitive factors affecting Atlas America's ability to obtain properties and drill wells. 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.
As our omnibus agreement with Atlas America generally requires it to connect wells it operates to our system, we do not expect any direct competition in connecting wells drilled and operated by Atlas America in the future. In addition, we occasionally connect wells operating by third parties. During 2002, we connected 19 such wells. We did not encounter, nor do we expect, significant competition to connect such wells as they are generally in close proximity to our gathering system and distant from others. In any case, revenue derived from the gas transportation on behalf of third parties represents an insignificant portion of our annual revenue.
During 2002 we did encounter competition in acquiring gas gathering systems owned by third parties. In several instances we submitted bids in auction situations and in direct negotiations for the acquisition of existing gas gathering systems. In each case we were either outbid by others or were unwilling to meet the sellers' expectations and, as a result, were unsuccessful in acquiring other systems. In the future, we expect to encounter equal if not greater competition for such acquisitions as gas prices have recently increased as has the economic attractiveness of owning such assets.
Regulation
Federal Regulation. Under the Natural Gas Act, the Federal Energy Regulatory Commission regulates various aspects of the operations of any "natural gas company," including the transportation of natural gas, rates and charges, construction of new facilities, extension or abandonment of services and facilities, the acquisition and disposition of facilities, reporting requirements, and similar matters. However, the Natural Gas Act definition of a "natural gas company" requires that the company be engaged in the transportation of natural gas in interstate commerce, or the sale in interstate commerce of natural gas for resale. Since we believe that each of our individual gathering systems performs primarily a gathering function, we believe that we are not subject to regulation under the Natural Gas Act. If we were determined to be a natural gas company, our operations would become regulated under the Natural Gas Act. We believe the expenses associated with seeking certificates of authority for construction, service and abandonment, establishing rates and a tariff for our gas gathering activities, and meeting the detailed regulatory accounting and reporting requirements would substantially increase our operating costs and would adversely affect our profitability, thereby reducing our ability to make distributions to unitholders.
State Regulation. Our 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 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 there-under, 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 OSHA and comparable state statutes. We believe that our operations comply in all material respects with OSHA requirements, including general industry standards, record keeping, hazard communication requirements and monitoring of occupational exposure and other regulated substances.
We have not expended and do not anticipate that we will be required in the near future to expend, amounts that are material in relation to our revenues by reason of environmental and safety laws. However, we cannot predict legislative or regulatory developments or the costs of compliance with those developments. In general, however, we anticipate that new laws, regulations or policies will increase our operating costs and impose additional capital expenditure requirements on us.
Tax Treatment of Publicly Traded Partnerships under the Internal Revenue Code
The Internal Revenue Code of 1986, as amended, imposes certain limitations on the current deductibility of losses attributable to investments in publicly traded partnerships and treats certain publicly traded partnerships as corporations for federal income tax purposes. The following discussion briefly describes certain aspects of the Code that apply to individuals who are citizens or residents of the United States without commenting on all of the federal income tax matters affecting us or the holders of our units, and is qualified in its entirety by reference to the Code. UNITHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISOR ABOUT THE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF AN INVESTMENT IN US.
Characterization for Tax Purposes. The Code treats a publicly traded partnership as a corporation for federal income tax purposes, unless, for each taxable year 90% or more of its gross income consists of qualifying income. Qualifying income includes interest, dividends, real property rents, gains from the sale or disposition of real property, income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber), and gain from the sale or disposition of capital assets that produce such income. Because we are engaged primarily in the natural gas pipeline transportation business, we believe that 90% or more of our gross income has been qualifying income. If this continues to be true and no subsequent legislation amends that provision, we will continue to be classified as a partnership and not as a corporation for federal income tax purposes.
Passive Activity Loss Rules. The Code provides that an individual, estate, trust, or personal service corporation generally may not deduct losses from passive activities, to the extent they exceed income from all such passive activities, against other (active) income. Income that may not be offset by passive activity losses includes not only salary and active business income, but also portfolio income such as interest, dividends or royalties or gain from the sale of property that produces portfolio income. Credits from passive activities are also limited to the tax attributable to any income from passive activities. The passive activity loss rules are applied after other applicable limitations on deductions, such as the at-risk rules and basis limitations.
Under the Code, net income from publicly traded partnerships is not treated as passive income for purposes of the passive lose rule, but is treated as non-passive income. Net losses and credits attributable to an interest in a publicly traded partnership may not be used to offset a partner's other income. Thus, a unitholder's proportionate share of our net losses may be used to offset only partnership net income from our trade or business in succeeding taxable years or, upon a complete disposition of a unitholder's interest in us to an unrelated person in a fully taxable transaction, may be used to offset gain recognized upon the disposition, and then against all other income of the unitholder. In effect, net losses are suspended and carried forward indefinitely until utilized to offset net income of the partnership from its trade or business or allowed upon the complete disposition to an unrelated person in a fully taxable transaction of the unitholder's interest in the partnership. A unitholder's share of partnership net income may not be offset by passive activity losses generated by other passive activities. In addition, a unitholder's proportionate share of our portfolio income, including portfolio income arising from the investment of our working capital, is not treated as income from a passive activity and may not be offset by such unitholder's share of net losses of the partnership.
Deductibility of Interest Expense. The Code generally provides that investment interest expense is deductible only to the extent of a non-corporate taxpayer's net investment income. In general, net investment income for purposes of this limitation includes gross income from property held for investment, gain attributable to the disposition of the property held for investment (except for net capital gains for which the taxpayer has elected to be taxed at special capital gains rates) and portfolio income (determined pursuant to the passive lose rules) reduced by certain expenses (other than interest) which are directly connected with the production of such income. Property subject to the passive loss rules is not treated as property held for investment. However, the IRS has issued a Notice which provides that net income from a publicly traded partnership (not otherwise treated as a corporation) may be included in net investment income for purposes of the limitation on the deductibility of investment interest. A unitholder's investment income attributable to its interest in us will include both its allocable share of our portfolio income and trade or business income. A unitholder's investment interest expense will include its allocable share of our interest expense attributable to portfolio investments.
Unrelated Business Taxable Income. Certain entities otherwise exempt from federal income taxes (such as individual retirement accounts, pension plans and charitable organizations) are nevertheless subject to federal income tax on net unrelated business taxable income and each such entity must file a tax return for each year in which it has more than $1,000 of gross income from unrelated business activities. We believe that substantially all of our gross income will be treated as derived from an unrelated trade or business and taxable to such entities. The tax-exempt entity's share of our deductions directly connected with carrying on such unrelated trade or business are allowed in computing the entity's taxable unrelated business income.
State Tax Treatment. During 2002, we owned property or conducted business in the states of Pennsylvania, New York and Ohio. A unitholder is required to file state income tax returns and to pay applicable state income taxes in the states and may be subject to penalties for failure to comply with such requirements. None of these states have required that we withhold a percentage of income attributable to our operations within the state for unitholders who are non-residents of the state. In the event that one or more of them do require withholding in the future, (which may be greater or less than a particular unitholder's income tax liability to the state), such withholding would generally not relieve the non-resident unitholder from the obligation to file a state income tax return.
Depreciation. Upon our formation in 2000, we elected fifteen-year 150% declining-balance depreciation for tax purposes. Unitholders, however, will continue to offset partnership income with individual unitholder depreciation pursuant to our Section 754 election. Each unitholder's tax situation will differ depending upon the price paid and when Units were purchased. Furthermore, sale of units will result in a portion of gain (if any) being taxable as ordinary income through recapture of previous deductions for depreciation.
Employees
As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for our management or operations. In general, Atlas America and Resource America personnel manage the gathering systems and operate our business.
Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occurs, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline and investors may lose some or all of their investment.
Our cash distributions are not assured and may fluctuate with our performance. The amounts of cash that we will generate may not be sufficient to pay the minimum quarterly distributions established in our partnership agreement or any other level of distributions. The actual amounts of cash we generate will depend upon numerous factors relating to our business which may be beyond our control, including:
o the demand for and price of natural gas;
o the volume of natural gas we transport;
o 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 to perform its obligations under the natural gas gathering agreements may adversely affect our revenues. Our revenues consist of the fees we receive under the master natural gas gathering agreement and other transportation agreements we have with Atlas America and its affiliates. While Atlas America receives gathering fees from the well owners, it is contractually obligated to pay our fees even if those gathering fees are less than the fees it pays us. Our cash flow could be materially adversely affected if Atlas America failed to discharge its obligations to us.
The amount of natural gas we transport will decline over time unless new wells are connected to our gathering systems. Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to our gathering systems could, therefore, result in the amount of natural gas we transport reducing substantially over time and could, upon exhaustion of the current wells, cause us to abandon one or more of our gathering systems and, possibly, cease operations. As a consequence, our revenues and, thus, our ability to make distributions to unitholders would be materially adversely affected.
Although we entered into the omnibus agreement described in "Business-Agreements with Atlas America-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 investment partnerships and completing wells for these partnerships in areas where our gathering systems are located. 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 increase our costs, decrease our revenues or both, as discussed under "-Regulation."
Gas gathering operations are subject to regulation at the state level. Matters subject to regulation include rates, service and safety. We have been granted an exemption from regulation as a public utility in Ohio. Presently, our rates are not regulated in New York and Pennsylvania. Changes in state regulations, or our status under these regulations that subject us to further regulation, could increase our operating costs or require material capital expenditures.
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 may also be held liable for clean-up costs resulting from pollution which occurred before our acquisition of the gathering systems. In addition, we are subject to federal and state safety laws that dictate the type of pipeline, quality of pipe protection, depth, methods of welding and other construction-related standards. While we believe that our 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 impose substantial costs on us.
We are also subject to the requirements of the Occupational Health and Safety Act, or OSHA and comparable state statutes. We believe that our operations comply in all material respects with OSHA requirements, including general industry standards, record keeping, hazard communication requirements and monitoring of occupational exposure to regulated substances. We cannot, however, assure you that future events will not occur for which we may be liable, imposing substantial costs on us.
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, we expect that new regulations would increase our operating costs and possibly require us to obtain additional capital to pay for improvements or other compliance action necessitated by those regulations.
We may not be able to fully execute our growth strategy. Our current strategy contemplates substantial growth through both the acquisition of other gathering systems and the development of our existing systems. Typically we have paid for system development in cash and have made acquisitions either for cash or a combination of cash and common units. As a result, limitations on our access to capital or on the market for our common units will impair our ability to execute our growth strategy. In addition, our strategy of growth through acquisitions involves numerous additional risks, including:
o we may not be able to identify suitable acquisition candidates;
o we may not be able to make acquisitions on economically acceptable terms;
o irrespective of estimates at the time we make an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus; and
o we may encounter difficulties in integrating operations and systems.
If Atlas America and its affiliates default on their obligations to us, we do not have contractual recourse to Resource America. The omnibus agreement and natural gas agreements with Atlas America are material to our business, financial condition and results of operations. Although Atlas America is a subsidiary of Resource America, Resource America has not guaranteed or otherwise assumed responsibility for any of these obligations.
A decline in natural gas prices could adversely affect our revenues. Our gathering fees are generally equal to a percentage of either the gross or weighted average sales price of the natural gas we transport, although in some cases we receive a flat fee per Mcf of gas transported. Our income therefore depends upon the prices at which the natural gas we transport is sold. Historically, the price of natural gas has been volatile, as a result, our income may vary from period to period.
Gathering system operations are subject to operational hazards and unforeseen interruptions. The operations of our gathering systems are subject to hazards and unforeseen interruptions, including natural disasters, adverse weather, accidents or other events, beyond our control. A casualty occurrence might result in injury and extensive property or environmental damage. Although we 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, Atlas America personnel manage and operate our business. Therefore, if we were to lose the management expertise of Atlas America, we would not have sufficient stand-alone resources to operate. Neither we or our general partner has or intends to obtain keymen life insurance for the officers and employees of our general partner.
ITEM 2.
ITEM 2. PROPERTIES
As of December 31, 2002, our principal facilities include approximately 1,380 miles of 2-inch to 12-inch diameter pipeline and 55 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 these imperfections have not interfered, and our general partner does not expect that they will materially interfere with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In a few instances, our rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election.
Certain of our rights to lay and maintain pipelines are derived from recorded gas well leases, which wells are currently in production; however, the leases are subject to termination if the wells cease to produce. In some of these cases, the rights to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because many of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related well ceases to produce.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We are not, nor are any of our gathering systems, subject to any pending legal proceedings.
ITEM 4.
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, 2002.
PART II
ITEM 5.
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 3,300 record holders held our common units as of December 31, 2002. In connection with our initial public offering, we also issued 1,641,026 subordinated units, discussed below, all of which are held by our general partner. There is no established public trading market for the subordinated units.
The following table sets forth the range of high and low sales prices of our common units and distributions on our common and subordinated units for the last two years.
Distributions High Low Declared ------- -------- ------------- Fiscal 2002 - ----------- Fourth Quarter............. $ 27.90 $ 21.80 $ .54 Third Quarter.............. $ 26.95 $ 20.40 $ .54 Second Quarter............. $ 29.10 $ 22.00 $ .54 First Quarter.............. $ 29.60 $ 23.51 $ .52
Fiscal 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
Our partnership agreement generally requires us to distribute available cash 98% to the limited partners and 2% to our general partner except for our general partner's incentive distribution rights. These rights require distributions of increased percentages of available cash to the general partner as distributions to limited partners exceed specified minimums, as follows:
Percent of Available Cash in Excess Minimum Distributions of Minimum Allocated Per Unit Per Quarter to the General Partner -------------------- ---------------------- $ .42 15% $ .52 25% $ .60 50%
Available cash generally means for any of our quarters, all cash on hand at the end of the quarter less cash reserves that our general partner determines are appropriate to provide for our operating costs, including potential acquisitions, and to provide funds for distributions to the partners for any one or more of the next four quarters.
Our partnership agreement allocates distributions to limited partners in accordance with their relative number of units except that, during the subordination period, distributions to subordinated units are subordinated to the receipt by the common units of a minimum quarterly distribution of $.42 per common unit, plus any unpaid minimum quarterly distribution amounts from prior periods. The subordination period extends until December 31, 2004 and thereafter until our operations meet certain financial criteria established by our partnership agreement.
We make distributions of available cash to unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. If distributions from available cash on the common units for any quarter during the subordination period are less than the minimum quarterly distribution of $.42 per common unit, holders of common units will be entitled to arrearages. Common unit arrearages will accrue and be payable in a future quarter after the minimum quarterly distribution is paid for the quarter. Subordinated units will not accrue any arrearages on distributions for any quarter. Upon expiration of the subordination period, the subordinated units will convert into common units on a one-for-one basis, and will then participate pro rata with the other common units in distributions of our available cash.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read together with our consolidated financial statements, the notes to our consolidated financial statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7
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 discussion provides information to assist in understanding our financial condition and results of operation. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report.
General
Our principal business objective is to generate income for distribution to our unitholders from the transportation of natural gas through our gathering systems. We completed an initial public offering of our common units in January 2000 and used the proceeds of that offering to acquire the gathering systems formerly owned by Atlas America. 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.
In January 2001, we acquired the gas gathering system of Kingston Oil Corporation, consisting 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, consisting 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. 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. In addition to these acquisitions, we added approximately 80, 180 and 100 miles of pipeline during fiscal years 2002, 2001 and 2000, respectively.
On January 18, 2002, we entered into an agreement to acquire substantially all of the equity interests in Triton Coal Company from New Vulcan Coal Holdings, L.L.C. and Vulcan Intermediary, L.L.C. On July 31, 2002, we terminated the agreement. We have incurred approximately $1,456,000 in costs in connection with the terminated Triton transaction through December 31, 2002. Pursuant to the terms of the acquisition agreement, we have requested reimbursement from the Vulcan entities of $1,187,500 of the transaction costs. We have expensed transaction costs of $268,500, the difference between costs incurred and those reimbursable by the Vulcan entities. As of December 31, 2002, Vulcan has reimbursed us $687,500 of these costs. Because Atlas America advanced funds to us in order to pay our transaction costs, we have remitted amounts reimbursed thus far to Atlas America. The advances, net of the reimbursements, are included in "accounts payable-affiliates" at December 31, 2002. Our remaining reimbursable costs of $500,000 are included on our consolidated balance sheet as accounts receivable; we expect to collect this amount over the first two quarters of 2003.
Results of Operations
In the years ended December 31, 2002, 2001 and 2000, our principal revenues came from the operation of our pipeline gathering systems which transport and compress natural gas. Two variables which affect our transportation revenues are:
o the volumes of natural gas transported by us which, in turn, depend upon the number of wells connected to our gathering system, the amount of natural gas they produce, and the demand for that natural gas; and
o the transportation fees paid to us which, in turn, depend upon the price of the natural gas we transport, which itself is a function of the relevant supply and demand in the Mid-Atlantic and North-Eastern areas of the United States.
We set forth the average volumes we transported, our average transportation rates per Mcf and revenues received by us for the periods indicated in the following table:
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Revenues. Our transportation revenue decreased to $10,660,300 in the year ended December 31, 2002 from $13,094,700 in the year ended December 31, 2001. This decrease of $2,434,400 (19%) resulted from a decrease in the average transportation rate paid to us ($3,163,700), partially offset by an increase in the volumes of natural gas we transported ($729,300).
Our average daily throughput volumes were 50,363 Mcfs in the year ended December 31, 2002 as compared to 46,918 Mcfs in the year ended December 31, 2001, an increase of 3,445 Mcfs (7%). The increase in the average daily throughput volume resulted principally from volumes associated with new wells added to our pipeline system; we turned on-line 214 and 234 wells in the years ended December 31, 2002 and 2001, respectively. These increases were partially offset by the natural decline in production volumes inherent in the life of a well.
Our transportation rates are primarily at fixed percentages of the sales price of the natural gas we transport. Our average transportation rate was $.58 per Mcf in the year ended December 31, 2002 as compared to $.76 per Mcf in the year ended December 31, 2001, a decrease of $.18 per Mcf (24%). The decrease in our average transportation rate resulted from the decrease in the average natural gas price received by producers for gas transported through our pipeline system.
Costs and Expenses. Our transportation and compression expenses increased to $2,061,600 in the year ended December 31, 2002 as compared to $1,929,200 in the year ended December 31, 2001, an increase of $132,400 (7%), principally due to the increased volumes of natural gas we transported in 2002. Our average cost per Mcf of transportation and compression was $.11 in both the years ended December 31, 2002 and 2001. The majority of our compressors are under short term leases which will be expiring over the next twelve months.
Our general and administrative expenses increased to $1,481,900 in the year ended December 31, 2002 as compared to $1,112,800 in the year ended December 31, 2001, an increase of $369,100 (33%). This increase primarily resulted from professional fees of $268,500 incurred in connection with the terminated Triton transaction (see Note 8 to the Consolidated Financial Statements) and our cost of insurance ($92,000) reflecting increased operating activities and assets, as well as significant increases in insurance rates in general.
Our depreciation and amortization expense increased to $1,475,600 in the year ended December 31, 2002 as compared to $1,356,100 in the year ended December 31, 2001, an increase of $119,500 (9%). This increase resulted from the increased asset base associated with pipeline extensions and acquisitions partially offset by a reduction in goodwill amortization as compared to the previous period due to the adoption of Statement of Financial Accounting Standards No. 142, or SFAS 142, on January 1, 2002.
Our interest expense increased to $249,800 in the year ended December 31, 2002 as compared to $175,600 in the year ended December 31, 2001. This increase of $74,200 (42%) resulted primarily from the write-off of deferred finance fees of $51,000 relating to our former credit facility with PNC Bank, which we paid off upon obtaining our current credit facility with Wachovia Bank. In addition, we had an increase in the amount of funds borrowed due to an increase in pipeline extensions. These increases were partially offset by lower borrowing rates.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
We commenced operations on January 28, 2000 when the pipeline operations, formerly owned by Atlas America, began to be operated for our account. Because our initial year of operations was not a full twelve months, the year ended December 31, 2001 may not be entirely comparable to the period ended December 31, 2000.
Revenues. Our transportation 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 the volumes of natural gas we transported ($2,017,300) and an increase in the average transportation fees paid to us ($1,636,400).
Our average daily throughput volumes were 46,918 Mcf in the year ended December 31, 2001 as compared to 42,669 Mcf in the year ended December 31, 2000, an increase of 4,249 Mcf (10%). The increase in the average daily throughput volume resulted principally from volumes associated with pipelines acquired during the first quarter of 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 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.
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 first quarter of 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), 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 in insurance rates.
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.
Liquidity and Capital Resources
Our primary cash requirements, in addition to normal operating expenses, are for debt service, maintenance capital expenditures, expansion capital expenditures and quarterly distributions to our unitholders and general partner. In addition to cash generated from operations, we have the ability to meet our cash requirements, (other than distributions to our unitholders and general partner) through borrowings under our credit facility. In general, we expect to fund:
o cash distributions and sustaining capital expenditures through existing cash and cash flows from operating activities;
o expansion capital expenditures and working capital deficits through the retention of cash and additional borrowings;
o interest payments through cash flows from operating activities; and
o debt principal payments through additional borrowings as they become due or by the issuance of additional common units.
At December 31, 2002, we had $1.0 million of remaining borrowing capacity under our credit facility. We recently received a commitment to increase the borrowing capacity to $15.0 million.
The following table summarizes our financial condition and liquidity at the dates indicated:
Net cash provided by operations of $8,138,000 in 2002 was derived principally from $6,963,600 of income from operations before depreciation and amortization. This decrease of $2,130,200 in cash provided by operations from 2001 resulted primarily from a decrease of $2,434,400 in transportation fees earned by us as a result of lower gas prices received by producers for gas transported through our pipeline system. The change in the decrease in "accounts receivable-affiliates" in the current year of $559,000 resulted primarily from the advance by Atlas America for expenses we incurred in connection with the terminated Triton acquisition.
Net cash used in investing activities was $5,230,600 for the year ended December 31, 2002, an increase of $2,102,600 from $3,128,000 in the year ended December 31, 2001. Net cash used in investing activities during the year ended December 31, 2001 consisted of the acquisition of two small pipelines from third parties ($1,400,000) and capital expenditures associated with gathering system extensions and compressor upgrades to our existing pipeline systems ($1,728,000). In the year ended December 31, 2002, we used $165,000 for the acquisition of one small gathering system and incurred capital expenditures of $5,065,600 for gathering system extensions and compressor upgrades to accommodate new wells drilled by Atlas America and its affiliates.
Net cash used in financing activities was $3,211,000 for the year ended December 31, 2002, a decrease of $3,810,500 from cash used in financing activities of $7,021,500 in the year ended December 31, 2001. Distributions paid to partners in the year ended December 31, 2002 decreased $1,557,200 as compared to the year ended December 31, 2001 as a result of a decrease in net income. Net borrowings during the year increased $2,322,000 to $4,411,000 in the year ended December 31, 2002 due to an increase in pipeline extensions and compressor upgrades.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of available cash to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.
Our general partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.
Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner if quarterly distributions to unitholders exceed certain specified targets.
Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. The general partner's incentive distribution for the distributions that they received during the year ended December 31, 2002 was $313,900.
Capital Expenditures
Our property and equipment was approximately 83% and 77% of our total consolidated assets at December 31, 2002 and 2001, respectively. Capital expenditures, other than the acquisitions of gathering systems, were $5.1 million and $1.7 million for the years ended December 31, 2002 and 2001, respectively. These capital expenditures principally consisted of costs relating to expansion of our existing gathering systems to accommodate new wells drilled in our service area and compressor upgrades. During 2002, we connected 214 wells were connected to our gathering system. As of December 31, 2002, we were committed to expend approximately $1.3 million for pipeline extensions. Our capital expenditures could increase materially if the number of wells connected to our gathering systems in fiscal 2003 increases significantly.
Inflation and Changes in Prices
Inflation affects the operating expenses of our gathering systems. Increases in those expenses are not necessarily offset by increases in transportation fees that the gathering operations are able to charge. We have not been materially affected by inflation because we were formed relatively recently and have only a limited period of operations. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects. In addition, the value of 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 believe we are in compliance with applicable environmental laws and regulations. To date, compliance with environmental laws and regulations has not had a material impact on our capital expenditures, earnings or competitive position. 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.
Contractual Obligations and Commercial Commitments
The following tables set forth our obligations and commitments as of December 31, 2002:
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenues and expenses during the reporting period. Although we believe our estimates are reasonable, actual results could differ from those estimates. We summarize our significant accounting policies in Note 2 to our Consolidated Financial Statements included in this report. The critical accounting policies that we have identified are discussed below.
Revenue and Expenses
We routinely make accruals for both revenues and expenses due to the timing of receiving information from third parties and reconciling our records with those of third parties. We have determined these estimates using available market data and valuation methodologies. We believe our estimates for these items are reasonable, but there is no assurance that actual amounts will not vary from estimated amounts.
Depreciation and Amortization
We calculate our depreciation based on the estimated useful lives and salvage values of our assets. However, factors such as usage, equipment failure, competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.
Impairment of Assets
Effective January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." In accordance with SFAS No. 144, whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, we review our long-lived assets for impairment and recognize an impairment loss if estimated future cash flows associated with an asset or group of assets are less than the asset carrying amount.
Our gathering systems are subject to numerous factors which could affect future cash flows which we discuss in Item 1, "Business-Risk Factors". We continuously monitor these factors and pursue alternative strategies to maintain or enhance cash flows associated with these assets; however, we cannot assure you that we can mitigate the effects, if any, on future cash flows related to any changes in these factors.
Goodwill
At December 31, 2002, we had $2.3 million of goodwill, all of which relates to our acquisition of pipeline assets. We test our goodwill for impairment each year. Our test during the current year resulted in no impairment. We will continue to evaluate our goodwill at least annually and will reflect the impairment of goodwill, if any, in operating income in the income statement in the period in which the impairment is indicated.
Recently Issued Financial Accounting Standards
Recently the Financial Accounting Standards Boards issued SFAS No. 143, "Accounting for Asset Retirement Obligations", and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS 143 establishes requirements for accounting for removal costs associated with asset retirements and SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 143 is effective for fiscal years beginning after September 15, 2002, with earlier adoption encouraged, and SFAS 144 is effective for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. We are currently assessing the impact of the adoption SFAS 143 on our results of operations and financial position. The adoption of SFAS 144 had no impact on our operations or financial position.
In May 2002, SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" was issued. SFAS 145 rescinds the automatic treatment of gains or losses from extinguishments of debt as extraordinary unless they meet the criteria for extraordinary items as outlined in APB No. 30, "Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions". SFAS 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects similar to a sale-leaseback transaction and makes various technical corrections to existing pronouncements. SFAS 145 is effective for all financial statements issued by us after January 1, 2003. We do not expect the adoption of SFAS 145 to have a material effect on our consolidated financial position or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS 146 addresses significant issues relating to the recognition, measurement, and reporting of costs associated with exit and disposal activities, including restructuring activities, and nullifies the guidance in Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)". The provisions of this statement are effective for exit and disposal activities that are initiated after December 31, 2002. We do not expect SFAS 146 to have a material impact on our results of operations or financial position.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.
We do not engage in any interest rate, foreign currency exchange rate or commodity price-hedging transactions, and as a result, we do not have exposure to derivatives risk.
Our major market risk exposure is in the pricing applicable to natural gas sales. Realized pricing is primarily driven by spot market prices for natural gas. Pricing for natural gas production has been volatile and unpredictable for several years.
Market risk inherent in our debt is the potential change arising from increases or decreases in interest rates. Changes in interest rates usually do not affect the fair value of variable rate debt, but may affect our future earnings and cash flows. At December 31, 2002, we had a $7.5 million revolving credit facility to fund the expansion of our existing gathering systems and the acquisition of other gas gathering systems. We have a commitment to increase this facility was increased to $15.0 million. The carrying value of our debt was $6.5 million at December 31, 2002. At our option, the facility bears interest at the lending institution's prime rate plus 0 to 50 basis points or the Euro rate, which is the average of specified LIBORs plus 150 or 200 basis points, depending upon our utilization of the line. At December 31, 2002, the interest rate was 2.92%. At December 31, 2002 and 2001, respectively, a hypothetical 10% change in the average interest rate applicable to this debt would result in a change of approximately $19,000 and $9,000 in our annual net income and would not affect the market value of this debt.
ITEM 8.
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, 2002 and 2001, and the related consolidated statements of income, partners' capital (deficit) and cash flows for the years then ended and for 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, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2002 and 2001 and the consolidated results of its operations and its consolidated cash flows for each of the three years in the period ended December 31, 2002, 2001 and 2000 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2002, the Partnership changed its method of accounting for goodwill for the adoption of SFAS No. 142.
/s/ Grant Thornton LLP - --------------------- Cleveland, Ohio January 27, 2003
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
See accompanying notes to consolidated financial statements
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (DEFICIT) YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
See accompanying notes to consolidated financial statements
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2002
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 and its affiliates, Viking Resources Corporation ("VRC") and Resource Energy, Inc. ("REI") (collectively referred to as the "Predecessor"), all of which are wholly-owned subsidiaries of Resource America, Inc. ("RAI" or "Parent"). RAI is a publicly traded company (trading under the symbol REXI on NASDAQ) operating in energy, real estate and financial services.
The accompanying financial statements and related notes present the Partnership's consolidated financial position as of December 31, 2002 and 2001 and its consolidated results of operations, cash flows and changes in partners' capital (deficit) for the years ended December 31, 2002, 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.
Initial Public Offering and Concurrent Transactions
On January 28, 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 the Partnership's operating partnership subsidiary, Atlas Pipeline Operating Partnership, L.P., (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% consists of 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 to distributions are different from and are subordinated to the rights of the holders of Common Units. Through the ownership of these Subordinated Units and the General Partner interest, the General Partner effectively manages and controls both the Partnership and the Operating Partnership.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies consistently applied (except as otherwise noted) in the preparation of the accompanying consolidated financial statements follows.
Principles of Consolidation
The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and the Operating Partnership's wholly-owned subsidiaries. The General Partner's interest in the Operating Partnership is reported as part of its overall 2% general partner interest in the Partnership, as opposed to a minority interest. All material intercompany transactions have been eliminated.
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 accounting principles generally accepted in the United States of America requires the Partnership to make estimates and assumptions that affect:
o the amount the Partnership reports for assets and liabilities;
o the Partnership's disclosure of contingent assets and liabilities at the date of the financial statements; and
o the amounts the Partnership reports for revenues and expenses during the reporting period.
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 or impairment of its long-lived assets, provisions for uncollectible 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 is provided for in amounts sufficient to relate the cost of depreciable assets to operations over the estimated useful lives of the assets. Gas gathering and transmission facilities are depreciated over 15 or 20 years using the straight-line and double-declining balance methods. Other equipment is depreciated over 5 to 10 years using the straight-line method.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
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 evaluated for impairment in accordance with Statement of Financial Accounting Standards (SFAS) No. 142. As of January 1, 2002, the date of adoption, the Partnership had unamortized goodwill in the amount of $2.3 million. The Partnership completed the transitional impairment and annual tests required by that standard, which involve the use of estimates related to the fair market value of the business operations associated with the goodwill. These tests did not indicate an impairment loss. The Partnership will continue to evaluate its goodwill at least annually and will reflect the impairment of goodwill, if any, in operating income in the income statement in the period in which the impairment is indicated.
Prior to the adoption of SFAS No. 142 on January 1, 2002, the Partnership amortized goodwill on a straight-line basis over 30 years. Amortization expense related to goodwill was $88,000 and $80,000 for the years ended December 31, 2001 and 2000, respectively. Assuming that the Partnership had applied SFAS No. 142 in 2001 and 2000, pro forma net income for those years would have been $8,643,600 and $6,704,600, respectively, and pro forma net income per limited partner unit for the years ended December 31, 2001 and 2000 would have been $2.33 and $2.09, respectively.
New Accounting Standards
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, "Accounting for Asset Retirement Obligations." 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 currently assessing the impact of the adoption of SFAS 143 on its results of operations and its financial position.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
In May 2002, SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" was issued. SFAS 145 rescinds the automatic treatment of gains and losses from extinguishments of debt as extraordinary unless they meet the criteria for extraordinary items as outlined in Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects similar to a sale-leaseback transaction and makes various corrections to existing pronouncements. The provisions of this statement are effective for financial statements issued by the Partnership in 2003. The Partnership does not expect the adoption of SFAS 145 to have a material effect on our consolidated financial position or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 addresses significant issues relating to the recognition, measurement, and reporting of costs associated with exit and disposal activities, including restructuring activities, and nullifies the guidance in Emerging Issues Task Force Issue ("EITF") No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)". The provisions of this statement are effective for exit and disposal activities that are initiated after December 31, 2002, with early application encouraged. The Partnership does not expect SFAS 146 to have a material impact on its results of operations or its financial position.
Distributions
The Partnership is required to distribute, within 45 days of the end of each quarter, all of its available cash for that quarter. For each quarter during the subordination period (through at least December 31, 2004), to the extent there is sufficient cash available, the original 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 gas 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.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Revenue Recognition
Revenues are recognized at the time the natural gas is transported through the gathering systems. Under the terms of its natural gas gathering agreements with Atlas and its affiliates, the Partnership receives fees for gathering natural gas from wells owned by Atlas, by limited partnerships sponsored by Atlas or by independent third parties whose wells were connected to the Partnership's gathering systems when operations commenced in 2000. The fees received for the gathering services are the greater of 16% of the gross sales price for gas produced from the wells, or $.35 or $.40 per thousand cubic feet ("Mcf"), depending on the ownership of the well. Substantially all gas gathering revenues are derived under this agreement. Fees for transportation services provided to independent third parties whose wells are connected to the Partnership's gathering systems are at separately negotiated prices.
Segment Information
The Partnership has one business segment, the transportation segment, which derives its revenues primarily from the transportation of natural gas that it receives from producers. Transportation revenues are, for the most part, based on contractual arrangements with Atlas and its affiliates.
Fair Value of Financial Instruments
For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair values because of the short maturity of these instruments. The carrying value of long-term debt approximates fair market value since interest rates approximate current market rates.
Net Income Per Unit
There is no difference between basic and diluted net income per limited partner unit since there are no potentially dilutive units outstanding. Net income per limited partner unit is determined by dividing net income, after deducting the General Partner's 2% interest and incentive distributions, by the weighted average number of outstanding Common Units and Subordinated Units (a total of 3,262,185, 3,254,543 and 3,141,026 units as of December 31, 2002, 2001 and 2000, respectively).
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Comprehensive Income
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. At December 31, 2002, the Partnership and its subsidiaries had $1.9 million in deposits at one bank, of which $1.7 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.
NOTE 3 - RELATED PARTY TRANSACTIONS
The Partnership is affiliated with RAI and its subsidiaries, including Atlas, VRC and REI ("Affiliates"). The Partnership is dependent upon the resources and services provided by RAI and these Affiliates. Accounts receivable/payable-affiliates represents the net balance due from or due to these Affiliates for natural gas transported through the gathering systems, net of reimbursements for Partnership costs and expenses paid by these Affiliates. Substantially all Partnership revenue is from these Affiliates.
The Partnership does not 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. The General Partner does not receive a management fee or other compensation in connection with its management of the Partnership apart from its interest as general partner and its right to receive incentive distributions. The Partnership reimburses Atlas and/or its Affiliates for all direct and indirect costs of services provided, including the cost of employees, officer and managing board member compensation and benefits properly allocable to the Partnership and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership.
The partnership agreement provides that the General Partner will determine the costs and expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner at its sole discretion. For the years ended December 31, 2002, 2001 and 2000, such reimbursements were approximately $4.4 million, $4.1 million and $3.0 million, respectively, including costs capitalized by the Partnership.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
NOTE 3 - RELATED PARTY TRANSACTIONS - (Continued)
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, 2002, the Partnership had not availed itself of the stand-by financing.
NOTE 4 - DISTRIBUTION DECLARED
On December 23, 2002, the Partnership declared a cash distribution of $.54 per unit on its outstanding Common Units and Subordinated Units. The distribution represented the available cash flow for the three months ended December 31, 2002. The $1,873,800 distribution, which includes a distribution of $112,200 to the General Partner in respect to its general partner interest, is scheduled to be paid on February 7, 2003 to unit holders of record on December 31, 2002.
NOTE 5 - CREDIT FACILITY
In December 2002, the Partnership entered into a $7.5 million credit facility administered by Wachovia Bank, National Association. In January 2003, Wachovia Bank increased the facility by an additional $2.5 million through June 2003. Borrowings under the facility are secured by a lien on and security interest in all the property of the Partnership and its subsidiaries, including pledges by the Partnership of the issued and outstanding equity interests in its subsidiaries. Up to $3.0 million of the facility may be used for standby letters of credit. No such letters of credit have been issued under the facility. The revolving credit facility has a term ending in December 2005 and bears interest at one of two rates, elected at the Partnership's option:
o the base rate plus the applicable margin; or
o the adjusted LIBOR plus the applicable margin.
The base rate for any day equals the higher of the federal funds rate plus 1/2 of 1% or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for euro currency funding. The applicable margin is as follows:
o where the Partnership's leverage ratio, as defined in the credit facility agreement, is less than or equal to 1.5, the applicable margin is 0.00% for base rate loans and 1.50% for LIBOR loans;
o where the Partnership's leverage ratio is greater than 1.5 but less than or equal to 2.5, the applicable margin is 0.25% for base rate loans and 1.75% for LIBOR loans; and
o where the Partnership's leverage ratio is greater than 2.5, the applicable margin is 0.50% for base rate loans and 2.00% for LIBOR loans.
At December 31, 2002, borrowings under the Wachovia credit facility bore interest at 2.92%.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
NOTE 5 - CREDIT FACILITY - (Continued)
The Wachovia credit facility requires the Partnership to maintain specified net worth and specified ratios of current assets to current liabilities and debt to EBITDA, and requires it to maintain a specified interest coverage ratio. The Partnership used this credit facility to pay off our previous revolving credit facility at PNC Bank. At December 31, 2002, $6.5 million was outstanding under this facility.
NOTE 6 - LEASES AND COMMITMENTS
The Partnership leases certain compressors associated with its gathering systems under lease agreements which expire in 2003. Rent expense for the years ended December 31, 2002, 2001 and 2000 was $839,900, $783,700 and $617,900, respectively. Minimum future lease payments for these leases in 2003 amount to $127,200.
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.
In March 2001, the Partnership acquired the gas gathering system of American Refining and Exploration Company. The gas gathering system consists of approximately 20 miles of pipeline located in Fayette County, Pennsylvania. The purchase price was $900,000, consisting of $150,000 of cash and 32,924 common units valued at $22.78 per unit.
These acquisitions were accounted for under the purchase method of accounting and, accordingly, the purchase prices were allocated to the assets acquired based on their fair values at the dates of acquisition. The pro forma effect of these acquisitions on prior operations to the acquisition dates is not material.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) DECEMBER 31, 2002
NOTE 8 - TERMINATION OF PROPOSED ACQUISITION
On July 31, 2002, the Partnership terminated its agreement with New Vulcan Coal Holdings, L.L.C. and Vulcan Intermediary, L.L.C. (collectively, "Vulcan") to acquire Triton Coal Company ("Triton"). The related purchase agreement for the sale of the interests held by Atlas in the Partnership's General Partner also terminated. The Partnership has incurred approximately $1,456,000 in costs in connection with the Triton transaction. Atlas had advanced these costs to the Partnership. Such advances, net of reimbursements of $687,500 from Vulcan referred to in the next paragraph, are included in "accounts payable--affiliates" at December 31, 2002.
The Partnership and its affiliates have requested reimbursement from Vulcan under the terms of the acquisition agreement for $1,187,500 of the transaction costs. The Partnership has expensed transaction costs of $268,500, the difference between costs incurred and those reimbursable by Vulcan. As of December 31, 2002, Vulcan has reimbursed the Partnership $687,500 of these costs, which in turn were reimbursed to Atlas. The remaining costs of $500,000 that are reimbursable by Vulcan are included on the Partnership's consolidated balance sheet as accounts receivable and are expected to be collected over the next two quarters. The Partnership anticipates that it will further repay Atlas from the Vulcan reimbursement.
NOTE 9 - QUARTERLY FINANCIAL DATA (Unaudited)
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.
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.
Edward E. Cohen has been Chairman of the Board of Directors of Resource America since 1990, Chief Executive Officer and a director of Resource America since 1988 and President of Resource America since 2000. He has been Chairman of the Board of Directors of Atlas America since 1998. He is Chairman of the Board of Directors of Brandywine Construction & Management, Inc., a property management company, and a director of TRM Corporation, a publicly traded consumer services company. Mr. Cohen is the father of Jonathan Z. Cohen.
Jonathan Z. Cohen has been Chief Operating Officer and a director of Resource America since 2002 and Executive Vice President since 2001. Before that, Mr. Cohen had been a Senior Vice President since 1999. Mr. Cohen has been Vice Chairman of Atlas America since 1998. Mr. Cohen has also served as Trustee and Secretary of RAIT Investment Trust, a real estate investment trust, since 1997 and Chairman of the Board of Directors of The Richardson Company, a sales consulting company, since 1999. Mr. Cohen is the son of Edward E. Cohen.
Michael L. Staines has been Senior Vice President of Resource America since 1989 and served as a director and Secretary from 1989 through 2000 and Secretary from 1989 through 1998. Since 1998, Mr. Staines has been Executive Vice President, Secretary and a director of Atlas America. Mr. Staines is a member of the Ohio Oil and Gas Association and the Independent Oil and Gas Association of New York.
Steven J. Kessler has been Senior Vice President and Chief Financial Officer of Resource America since 1997. Before that he was Vice President-Finance and Acquisitions at Kravco Company (a national shopping center developer and operator) from 1994 to 1997.
Tony C. Banks is a consultant providing energy marketing, technology, price risk management and M&A advisory services to utilities, energy service companies and energy technology firms. From 2000 through early 2002, Mr. Banks was President of RAI Ventures, Inc. and chairman of the board of Optiron Corporation, which until 2002 had been an energy technology subsidiary of Atlas America. In addition, Mr. Banks served as President of our general partner during 2000. He was Chief Executive Officer and President of Atlas America from 1998 through 2000. From 1995 to 1998, Mr. Banks was Vice President of various subsidiaries of Atlas America.
William R. Bagnell has been Vice President-Energy for Planalytics, Inc., an energy industry software company, since 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.
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 and 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 a Senior Partner in the Litigation Department of Pepper Hamilton LLP, a Philadelphia law firm. Mr. Levin served as the first American president of the Association Internationale des Jeunes Avocats (Young Lawyers International Association), headquartered in Western Europe. He is a past president of the American Chapter and a member of the board of directors of the Union Internationale des Avocats (International Association of Lawyers), a Paris-based organization that is the world's oldest international lawyers association.
Other Significant Employees
Nancy J. McGurk, 47, has been the Chief Accounting Officer of our general partner since 2000. In addition, she has been Vice President of Resource America since 1992 and Treasurer and Chief Accounting Officer since 1989.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires executive officers and managing board members of our general partner and persons who own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies of all such reports. Based solely upon our review of reports received by us, or representations that no filings were required, we believe that all of the officers and managing board members of our general partner complied with all applicable filing requirements during 2002, except that Steven J. Kessler did not file a Form 3 on a timely basis after his appointment as Chief Financial Officer. We did not have any record holders of 10% or more of our common units in 2002.
Reimbursement of Expenses of Our General Partner and Its Affiliates
Our general partner does not receive any management fee or other compensation for its services apart from its general partnership and incentive distribution interests. We reimburse our general partner and its affiliates, including Atlas for all expenses incurred on our behalf. These expenses include the costs of employee, officer and managing board member compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Our general partner allocates the costs of employee and officer compensation and benefits based upon the amount of business time spent by those employees and officers on our business. We reimbursed our general partner $4.4 million for expenses incurred during 2002.
Compensation Committee Interlocks and Insider Participation
Neither we nor the managing board of our general partner has a compensation committee. Compensation of the personnel of Atlas and its affiliates who provide us with services is set by Atlas and such affiliates. The independent members of the managing board of our general partner, however, does review the allocation of the salaries of such personnel for purposes of reimbursement, discussed in "Reimbursement of Expenses of our General Partner and Its Affiliates and Item 11, "Executive Compensation.." None of the independent managing board members is an employee or former employee of ours or of our general partner. However, Mr. Bagnell was, until September 1992, an employee of Resource America, the ultimate parent of our general partner and served from December 1998 until February 2003 as a trustee of its employee stock ownership plan and from September 1999 until February 2003 as a trustee of its 401(k) plan. No executive officer of our general partner is a director or executive officer of any entity in which an independent managing board member is a director or executive officer.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Executive Compensation
We do not directly compensate the executive officers of our general partner. Rather, Atlas 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 and its affiliates based upon an estimate of the time spent by such persons on activities for us and for Atlas and its affiliates, and we reimburse our general partner for the compensation allocated to us. The compensation allocation was $344,700 and $397,500 for the years ended December 31, 2002 and 2001, respectively. The following table sets forth the compensation allocation since we commenced operations for our general partner's President. No other executive officer of the general partner received aggregate salary and bonus from us in excess of $100,000 during the periods indicated.
Summary Compensation Table
Compensation of Managing Board Members
Our general partner does not pay additional remuneration to officers or employees of Resource America who also serve as managing board members. Each independent managing board member receives an annual retainer of $6,000 together with $1,000 for each board meeting attended, $1,000 for each committee meeting attended where he is chairman of the committee and $500 for each committee meeting attended where he is not chairman. In addition, our general partner reimburses each independent board member for out-of-pocket expenses in connection with attending meetings of the board or committees. We reimburse our general partner for these expenses and indemnify our general partner's managing board members for actions associated with being managing board members to the extent permitted under Delaware law.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the number and percentage of our common units held by beneficial owners of 5% or more of either our common or subordinated units, by executive officers and members of the managing board of our general partner and by all of the executive officers and managing board members of our general partner as a group as of March 3 2003. The subordinated units listed opposite the name of each person represent subordinated units owned by our general partner. By reason of their position as managing board members or executive officers of our general partner, such persons may be deemed to have shared voting and investment power over the subordinated units. The address of our general partner, its executive officers and managing board members is 311 Rouser Road, Moon Township, Pennsylvania 15108.
- ----------- * Less than 1%.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
At December 31, 2002, 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 $4,035,100 during fiscal 2002 in respect of these interests.
The omnibus agreement and the natural gas gathering agreements with Atlas 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 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 employees of Resource America and/or its affiliates. As discussed in Items 10 and 11, we reimburse our general partner, Atlas 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.
Mr. Levin is associated with a firm to which the Partnership paid $60,000 for legal services during 2002.
Mr. Beyer, Jr. is associated with a firm which sold Resource America a life insurance policy on the life of Edward E. Cohen, Resource America's Chairman. Mr. Beyer's firm received $23,700, $22,500 and $204,500 in commissions in 2002, 2001 and 2000, respectively, in connection with the policy.
PART IV
ITEM 14.
ITEM 14. EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Chairman of the Managing Board of Directors and Chief Financial Officer of our general partner, our general partner's principal executive and accounting officers, respectively, after evaluating the effectiveness of our "disclosure controls and procedures" (as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c)) as of a date within 90 days before the filing date of this annual report, have concluded that as of the evaluation date, our disclosure controls and procedures were adequate and designed to ensure that material information relating to us would be made known to them by our employees or persons employed by the general partner and its affiliates working on our behalf.
Changes in Internal Controls
There were no significant changes in our internal controls or in other factors that could significantly affect these controls since the date of our last evaluation of internal controls.
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) Financial Statements The financial statements required by this Item 15(a)(1) are set forth in Item 8.
(a)(2) Financial Statement Schedules No schedules are required to be presented.
(a)(3) Exhibits 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. dated February 2, 2002. 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 dated February 2, 2000. 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 dated February 2, 2002. 10.4 Credit Agreement among Atlas Pipeline Partners, L.P., Wachovia Bank, National Association and certain subsidiaries of Atlas Pipeline Partners, L.P. as guarantors dated December 27, 2002. 10.5 First Amendment to Credit Agreement, dated January 30, 2003. 10.6 Second Amendment to Credit Agreement, dated March 28, 2003. 10.7 Natural Gas Gathering Agreement among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corp., Resource Energy, Inc. and Viking Resources Corporation dated January 1, 2002. 21.1 Subsidiaries of Atlas Pipeline Partners, L.P. 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of The Sarbanes-Oxley Act of 2002 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of The Sarbanes-Oxley Act of 2002 - ----------------
(1) Filed previously as an exhibit to our Registration Statement on Form S-1 (Registration No. 333-85193) and by this reference incorporated herein.
(b) Reports on Form 8-K None
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, 2003 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, 2003.
CERTIFICATIONS
I, Edward E. Cohen, certify that:
1. I have reviewed this annual report on Form 10-K of Atlas Pipeline Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 28, 2003 /s/ Edward E. Cohen Edward E. Cohen Chairman of the Managing Board of the General Partner
CERTIFICATIONS
I, Steven J. Kessler, certify that:
1. I have reviewed this annual report on Form 10-K of Atlas Pipeline Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 28, 2003 /s/ Steven J. Kessler Steven J. Kessler Chief Financial Officer of the General Partner