Attached files

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EX-23.1 - CONSENT OF GRANT THORNTON LLP - Atlas Energy, L.P.dex231.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - Atlas Energy, L.P.dex311.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - Atlas Energy, L.P.dex312.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - Atlas Energy, L.P.dex321.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - Atlas Energy, L.P.dex322.htm
EX-10.6(B) - AMENDMENT NO. 1 TO LONG-TERM INCENTIVE PLAN - Atlas Energy, L.P.dex106b.htm
EX-21.1 - SUBSIDIARIES OF REGISTRANT - Atlas Energy, L.P.dex211.htm
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

OR

 

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

For the transition period from              to             

Commission file number: 1-32953

 

 

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

DELAWARE   43-2094238

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

1550 Coraopolis Heights Road

Moon Township, Pennsylvania

  15108
(Address of principal executive office)   (Zip code)

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

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

 

Title of each class

 

Name of each exchange on which registered

Common Units representing Limited

Partnership Interests

  New York Stock Exchange

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

None

(Title of class)

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act (Check one):

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the equity securities held by non-affiliates of the registrant, based upon the closing price of $3.99 per common limited partner unit on June 30, 2010, was approximately $38.5 million.

The number of common units of the registrant outstanding on February 22, 2011 was 51,214,638.

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

None

 

 

 


Table of Contents

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

 

              Page  

PART I

     
 

Item 1:

   Business      7   
 

Item 1A:

   Risk Factors      30   
 

Item 1B:

   Unresolved Staff Comments      65   
 

Item 2:

   Properties      65   
 

Item 3:

   Legal Proceedings      65   
 

Item 4:

   [Removed and reserved]      65   

PART II

     
 

Item 5:

   Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities      66   
 

Item 6:

   Selected Financial Data      68   
 

Item 7:

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      73   
 

Item 7A:

   Quantitative and Qualitative Disclosures About Market Risk      100   
 

Item 8:

   Financial Statements and Supplementary Data      102   
 

Item 9:

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      151   
 

Item 9A:

   Controls and Procedures      151   
 

Item 9B:

   Other Information      154   

PART III

     
 

Item 10:

   Directors, Executive Officers and Corporate Governance      155   
 

Item 11:

   Executive Compensation      163   
 

Item 12:

   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters      180   
 

Item 13:

   Certain Relationships and Related Transactions, and Director Independence      185   
 

Item 14:

   Principal Accountant Fees and Services      187   

PART IV

     
 

Item 15:

   Exhibits and Financial Statement Schedules      188   

SIGNATURES

     190   

 

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FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

 

   

the demand for natural gas and natural gas liquids;

 

   

the price volatility of natural gas and natural gas liquids;

 

   

Atlas Pipeline Partners, L.P.’s (“APL”) ability to connect new wells to its gathering systems;

 

   

our ability to operate the assets we recently acquired from Atlas Energy, Inc., which we refer to as the asset acquisition, and the costs of such operation;

 

   

our ability to operate without Atlas Energy, Inc., as our majority unitholder;

 

   

changes in the market price of our common units;

 

   

future financial and operating results;

 

   

resource potential;

 

   

realized natural gas and oil prices;

 

   

economic conditions and instability in the financial markets;

 

   

success in efficiently developing and exploiting the reserves we acquired in the asset acquisition and economically finding or acquiring additional recoverable reserves;

 

   

the accuracy of estimated natural gas and oil reserves;

 

   

the financial and accounting impact of hedging transactions;

 

   

the ability to fulfill the respective substantial capital investment needs of us and APL;

 

   

expectations with regard to acquisition activity, or difficulties encountered in connection with acquisitions, dispositions or similar transactions;

 

   

the limited payment of dividends or distributions, or failure to declare a dividend or distribution, on outstanding common units or other equity securities;

 

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any issuance of additional common units or other equity securities, and any resulting dilution or decline in the market price of any such securities;

 

   

our lack of experience in drilling natural gas wells and the limited information available regarding reserves and decline rates in certain areas in which the assets acquired in the asset acquisition are located;

 

   

restrictive covenants in indebtedness of us and APL that may adversely affect operational flexibility;

 

   

potential changes in tax laws which may impair the ability to obtain capital funds through investment partnerships;

 

   

the ability to raise funds through the investment partnerships;

 

   

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations at a reasonable cost and within applicable environmental rules;

 

   

the potential introduction of Pennsylvania severance taxes;

 

   

changes and potential changes in the regulatory and enforcement environment in the areas in which we and APL conduct business;

 

   

the effects of intense competition in the natural gas and oil industry;

 

   

general market, labor and economic conditions and related uncertainties;

 

   

the ability to retain certain key customers, including customers of the businesses acquired in the asset acquisition;

 

   

dependence on the gathering and transportation facilities of third parties, including Laurel Mountain;

 

   

the availability of drilling rigs, equipment and crews;

 

   

potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;

 

   

uncertainties with respect to the success of drilling wells at identified drilling locations;

 

   

expirations of undeveloped leasehold acreage;

 

   

uncertainty regarding leasing operating expenses, general and administrative expenses and funding and development costs;

 

   

exposure to financial and other liabilities of the managing general partners of the investment partnerships;

 

   

the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our and APL’s business and operations;

 

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exposure to new and existing litigation;

 

   

risks of the business of APL to which we are exposed through our ownership interests in APL;

 

   

the potential failure to retain certain key employees and skilled workers; and

 

   

development of alternative energy resources.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Item 1A, “Risk Factors” in this report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

 

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Glossary of Terms

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:

 

Bbl    Barrel - measurement for a standard US barrel is 42 gallons. Crude oil and condensate are generally reported in barrels.
BPD    Barrels per day
BTU    British thermal unit, a basic measure of heat energy
Condensate    Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.
Distributable Cash Flow (“DCF”)    Net income plus depreciation, amortization, other non-cash expenses and maintenance capital expenditures. Used to determine the amount of cash flow available to distribute to units holders.
EBITDA    Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.
FASB    Financial Accounting Standards Board
FERC    Federal Energy Regulatory Commission
Fractionation    The process used to separate an NGL stream into its individual components.
GAAP    Generally Accepted Accounting Principles
G.P.    General Partner or General Partnership
Keep-Whole    Contract with producer whereby plant operator pays for or returns an equivalent BTU of the gas received at the well-head.
L.P.    Limited Partner or Limited Partnership
MCF    Thousand cubic feet
MCFD    Thousand cubic feet per day
MMBTU    Million British thermal units
MMCFD    Million cubic feet per day
NGL(s)    Natural Gas Liquid(s), primarily ethane, propane, normal butane, isobutane and natural gasoline
Percentage of Proceeds (“POP”)   

Contract with natural gas producers whereby the plant operator retains a negotiated percentage of the sale proceeds.

PV-10    Present value of future pre-tax net revenues. See “standardized measure”.
Residue gas    The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.
SEC    Securities Exchange Commission
Standardized Measure    Standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using constant prices and costs) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
Y-grade    A term utilized in the industry for the NGL stream prior to fractionation, also referred to as “raw mix.”

 

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PART I

 

ITEM 1. BUSINESS

Atlas Energy, L.P.

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: AHD). Our wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL”), a publicly-traded Delaware limited partnership (NYSE: APL).

As of December 31, 2010, our cash generating assets consisted solely of our interests in APL. APL is a leading provider of natural gas gathering, processing and treating services in the Mid-Continent and Appalachia regions. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, its general partner, which together with us owned at December 31, 2010:

 

   

a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL;

 

   

all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter adjusted as follows; and

 

   

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), Atlas Pipeline GP agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”);

 

   

5,754,253 common units of APL, representing approximately 10.8% of the outstanding common units of APL, or a 10.6% limited partner interest in APL.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”) does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

Atlas Energy, Inc. (“Atlas Energy, Inc.” or “ATLS”), a formerly publicly-traded company, owned 64.0% of our common units and also had a direct 2.1% interest in APL plus 8,000 $1,000 par value 12% APL Class C cumulative preferred limited partner units at December 31, 2010.

Atlas Pipeline GP’s ownership of APL’s incentive distribution rights entitles it to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle Atlas Pipeline GP, subject to the IDR Adjustment Agreement, to receive the following:

 

   

13.0% of all cash distributed in any quarter after each APL common unit has received $0.42 for that quarter;

 

   

23.0% of all cash distributed in any quarter after each APL common unit has received $0.52 for that quarter; and

 

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48.0% of all cash distributed in any quarter after each APL common unit has received $0.60 for that quarter.

These amounts are partially offset by the IDR Adjustment Agreement.

We pay our unitholders, on a quarterly basis, distributions equal to the cash we received from APL and operations, less certain reserves for expenses and other uses of cash, including:

 

   

our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

 

   

capital contributions to maintain or increase our ownership interest in APL; and

 

   

reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.

The following chart displays the corporate organizational structure as of December 31, 2010:

LOGO

 

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Recent Developments

Atlas Energy, Inc. Asset Acquisition

On February 17, 2011, we completed the transactions, which we refer to as the “Asset Acquisition,” contemplated by our transaction agreement (the “AHD Transaction Agreement”), dated November 8, 2010, with ATLS and Atlas Energy Resources, LLC, a wholly-owned subsidiary of ATLS, pursuant to which we purchased from ATLS (1) its investment partnership business, including the operations of its investment partnerships in Michigan, Pennsylvania, Tennessee, Indiana and Colorado, (2) its oil and gas exploration, development and production activities conducted in Tennessee, Indiana and Colorado, certain shallow wells and leases in New York and Ohio and certain well interests in Pennsylvania, and (3) its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (we refer to the businesses described in (1) through (3), together, as the “transferred business”). The assets we purchased include certain ATLS subsidiaries (referred to as the “purchased entities”) and certain other assets relating to the transferred business, including the names and marks of ATLS and its subsidiaries (which we refer to as the “purchased assets”). ATLS also transferred certain current liabilities that were assumed by us in the Asset Acquisition, of which certain amounts are subject to post-closing.

As consideration for the Asset Acquisition, we paid to ATLS $30 million in cash, issued to it 23,379,384 new common units, and assumed all of the historical and future liabilities associated with the transferred business. In addition, we repaid the $36.0 million outstanding under our amended and consolidated note owed to ATLS.

In connection with the Asset Acquisition, ATLS contributed our general partner, Atlas Pipeline Holdings GP, LLC to us, so that Atlas Pipeline Holdings GP became our wholly-owned subsidiary, our limited partnership agreement was amended and restated, and our new long-term equity incentive plan for employees became effective. ATLS distributed to its stockholders all our common units that it held, including the newly issued common units that it received in the Asset Acquisition. As a result, ATLS no longer owns any of our common units. We refer to all of these transactions, along with the Asset Acquisition, as the “AHD Transactions.”

New Credit Facility

We financed the cash portion of Asset Acquisition consideration and the repayment of the ATLS note by drawing on a $70 million revolving credit facility, administered by Citibank, N.A., that we entered into at closing of the Asset Acquisition. Our credit facility matures in February 2012 and bears interest, at our option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Citibank, N.A. prime rate (each plus the applicable margin). Borrowings under our credit facility are secured by a first-priority lien on a security interest in substantially all of our assets, including a pledge of 3,500,000 of our APL common units, and are guaranteed by Atlas Pipeline Holdings GP and our operating other subsidiaries (excluding Atlas Pipeline GP and APL and its subsidiaries). Our credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries; and requirements that we maintain certain financial ratios. The events which constitute an event of default under our credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against us in excess of a specified amount, and a change of control. We may borrow under our credit facility for working capital and general business purposes.

 

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Laurel Mountain Sale

Concurrently with our completion of the Asset Acquisition, APL completed its sale to Atlas Energy Resources of its 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from Laurel Mountain after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of Laurel Mountain entitling APL Laurel Mountain LLC to receive all payments made under a note issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of Laurel Mountain.

Atlas Energy, Inc. Merger

Concurrently with our completion of the Asset Acquisition and APL’s completion of the Laurel Mountain Sale, ATLS completed its merger transaction with Chevron Corporation (“Chevron”), pursuant to which, among other things, ATLS became a wholly-owned subsidiary of Chevron (the “Chevron Merger”). The APL common units and 12% cumulative Class C preferred units held directly by ATLS were acquired by Chevron as part of the Chevron Merger.

Atlas Pipeline Holdings, L.P. Name Change

On February 18, 2011, subsequent to the Asset Acquisition and the Chevron Merger, we changed our name to Atlas Energy, L.P.

The following chart displays the corporate organizational structure subsequent to the AHD Transactions and related developments described above:

LOGO

 

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Services Agreements

Concurrently with entering into the AHD Transaction Agreement, we entered into several services agreements with ATLS to allow for the continuation and transition of operations after closing. The following summarizes each of those agreements.

Transition Services Agreement. We entered into a transition services agreement with ATLS pursuant to which (1) ATLS will provide us a limited license to use certain of its facilities and (2) ATLS and we will provide each other certain services on a transitional basis including, among others, services related to operations, accounting, supply chain management, finance, human resources and information technology (the “Transition Services Agreement”). The recipient of each service listed in the Transition Services Agreement will be obligated to pay a fee specified in the Transition Services Agreement. Each service will be provided until the earlier of (1) the term specified for that service in the Transition Services Agreement, (2) two years from the closing of the AHD Transactions, (3) the termination of the Transition Services Agreement by ATLS or us following an uncured material breach by the other party or (4) the termination of the service by the recipient of the service (except that a recipient of any terminated service must continue to pay the relevant fee for that service for the remainder of the term specified in the transition services agreement). ATLS and we may request that the other party provide additional or different services, and the parties may negotiate the terms of the new service, although neither party has an obligation to provide any additional or different service.

The recipient of each service will generally assume the risks and liability arising in connection with its use of the service. The provider and recipient of each service will indemnify each other for any losses incurred in connection with the use of the service by the recipient, unless the loss is due to the provider’s gross negligence or willful misconduct.

Michigan Operating Agreement. We entered into an Operating Services Agreement (the “Michigan Operating Agreement”) with ATLS and Atlas Resources, LLC (“Resources”), a purchased entity, pursuant to which ATLS will provide Resources and us and our respective subsidiaries certain operational services including, among others, the superintendence and maintenance of wells in certain counties in Michigan and Indiana and the marketing and gathering of gas produced from those wells (the “Michigan Operational Services”). ATLS will also provide certain environmental project management services to us on a transitional basis (the “Michigan Environmental Services”). Resources, we or our subsidiaries are obligated to pay the fees specified in the Michigan Operating Agreement for the Michigan Operational Services and the Michigan Environmental Services. We may request that ATLS provide additional services under the Michigan Operating Agreement on a transitional basis, and we must negotiate in good faith regarding any such additional service, except that ATLS will not be obligated to provide any additional services if the provision of such service would be impracticable or would not be commercially reasonable, or if it is not of a type being provided by ATLS or its affiliates as of immediately prior to the closing of the AHD Transactions.

We will indemnify ATLS against all claims and liabilities arising out of its provision of services under the Michigan Operating Agreement.

ATLS will provide the Michigan Operational Services for three years from the closing date of the AHD Transactions and from month-to-month thereafter until cancelled by ATLS, Resources or us. ATLS will provide the Michigan Environmental Services for six months from the closing of the AHD Transactions and from month-to-month thereafter for an additional eighteen months. We may terminate any part of the Michigan Operational Services and the Michigan Environmental Services at any time. ATLS, Resources and we may agree to terminate the Michigan Operating Agreement at any time, and each of ATLS, on the one hand, or Resources or we, on the other hand, may terminate the Michigan Operating Agreement following an uncured material breach by such other party.

Pennsylvania Operating Agreement. We entered into an operating services agreement with ATLS and Resources (the “Pennsylvania Operating Agreement”), pursuant to which ATLS will provide Resources, us and

 

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our respective subsidiaries certain operational services including, among others, gas volumetric control, measurement and balancing services and water disposal services with respect to certain wells in Pennsylvania ( the “Pennsylvania Services”). Resources, we or our subsidiaries are obligated to pay the fees specified in the Pennsylvania Operating Agreement for the Pennsylvania Services.

We will indemnify ATLS against all claims and liabilities arising out of its provision of services under the Pennsylvania Operating Agreement.

ATLS will provide the Pennsylvania Services for three years from the closing date of the AHD Transactions and from month-to-month thereafter until cancelled by ATLS, Resources or us. We may terminate any part of the Pennsylvania Services or terminate the Pennsylvania Operating Agreement at any time. ATLS, Resources and we may agree to terminate the Pennsylvania Operating Services Agreement at any time, and each of ATLS, on the one hand, or Resources or we, on the other hand, may terminate the Pennsylvania Operating Agreement following an uncured material breach by such other party.

Petro-Technical Services Agreement. We entered into a petro-technical services agreement with ATLS (the “Petro-Technical Services Agreement”), pursuant to which ATLS will perform for us certain consulting activities including, among others, planning, designing, drilling, stimulating, completing and equipping wells (the “Petro-Technical Services”). We are obligated to pay the actual costs incurred by ATLS in the performance of the Petro-Technical services, up to a maximum of the market rate for the same or similar services in Pittsburgh, Pennsylvania and Traverse City, Michigan.

We will indemnify ATLS against all claims and liabilities arising out of its provision of services under the Petro-Technical Services Agreement.

ATLS will provide the Petro-Technical Services for one year from the closing date of the AHD Transactions and from month-to-month thereafter until the earlier of (1) cancellation by ATLS, Resources or us; or (2) eighteen months after the closing date of the AHD Transactions. We may terminate any part of the Petro-Technical Services or terminate the Petro-Technical Services Agreement at any time. ATLS, Resources and we may agree to terminate the Petro-Technical Services Agreement at any time, and each of ATLS, on the one hand, or Resources or we, on the other hand, may terminate the Petro-Technical Services Agreement following an uncured material breach by such other party.

Gas Marketing Agreement. Certain of the purchased entities entered into a base contract for the sale and purchase of natural gas with a subsidiary of Chevron (which we refer to as the “Gas Marketing Agreement”) pursuant to which, following the closing of the AHD Transactions and the Chevron merger, the purchased entities will sell gas to the subsidiary of Chevron. Under the Gas Marketing Agreement, the subsidiaries are responsible for transporting the gas to specified delivery points, at which points the subsidiary of Chevron will assume responsibility for the purchased gas. The Gas Marketing Agreement will terminate upon the expiration of the latest period for which the parties have agreed to make deliveries or upon 30 days’ written notice of any party to the gas marketing agreement.

Employee Matters Agreement. We entered into an employee matters agreement with ATLS, pursuant to which certain current employees of ATLS will be transferred to us in connection with the AHD Transactions, and we will assume certain pre-closing liabilities attributable to such transferred employees. We will be required to establish benefit plans for such transferred employees, including a 401(k) plan and health and welfare benefit plans, as of the closing date for the AHD Transactions. Effective as of the closing date for the AHD Transactions, we will adopt the new equity plan, under which awards of options to purchase our common units, restricted units and phantom units may be granted to our employees, directors and other service providers. Pursuant to the employee matters agreement, we will also amend our long-term incentive plan to provide that outstanding awards granted under the plan will not vest in connection with the Chevron merger and the AHD transactions pursuant to the terms and conditions of the plan.

 

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The remainder of this “Business” section discusses our business as it existed on December 31, 2010, without giving effect to the Asset Acquisition.

Atlas Pipeline Partners, L.P.

General

APL is a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” APL is a leading provider of natural gas gathering, processing and treating services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States and a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

In APL’s Mid-Continent operations, it owns and operates five natural gas processing plants with aggregate capacity of approximately 520 MMCFD. These facilities are connected to approximately 8,600 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which gathers gas from wells and central delivery points and delivers the natural gas to APL’s processing and treating plants, as well as third-party pipelines.

The Appalachia operations of APL are conducted principally through its 49% non-controlling ownership interest in the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which owns and operates approximately 1,000 miles of natural gas gathering systems in the Appalachian Basin located in Pennsylvania. APL also owns and operates approximately 70 miles of active natural gas gathering pipelines located in Tennessee.

APL’s operations are all located in or near areas of abundant and long-lived natural gas production including the; Golden Trend; Woodford Shale; Hugoton field in the Anadarko basin; the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin and the Marcellus Shale in the Appalachian Basin. APL’s Mid-Continent gathering systems are connected to approximately 7,700 central delivery points or wells. In Appalachia, Laurel Mountain’s systems are connected to approximately 4,700 wells. Thus we believe APL has significant scale in its service areas. APL provides gathering and processing services to the wells connected to its systems, primarily under long-term contracts. As a result of the location and capacity of APL’s gathering and processing assets, APL management believes it is strategically positioned to capitalize on the drilling activity in its service areas. APL intends to continue to expand its business through strategic acquisitions and internal growth projects in efforts to increase distributable cash flow.

Laurel Mountain gathers the majority of the natural gas from wells operated by Atlas Energy Resources and its subsidiaries. Laurel Mountain has gas gathering agreements with Atlas Energy Resources under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) 100% interest in the Chaney Dell natural gas gathering systems and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas.

 

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APL’s Business Strategy

The primary business objective of APL’s management team is to provide stable long-term cash distributions to its unitholders. APL’s business strategies focus on creating value for its unitholders by providing efficient operations, focusing on prudent growth opportunities via organic growth projects and external acquisitions, and maintaining a commodity risk management program in an attempt to manage our commodity price exposure. APL intends to accomplish its primary business objectives by executing on the following:

 

   

Increasing the profitability of APL’s existing assets. In many cases, APL can expand gathering pipelines and processing plants and may have excess capacity, which provides it with opportunities to connect and process new supplies of natural gas with minimal additional capital requirements, also increasing plant efficiency and economics. APL plans to accomplish this goal by providing excellent service to its existing customers, aggressively marketing its services to new customers and prudently expanding its existing infrastructure to ensure its services can meet the needs of potential customers. APL’s recent construction of its Consolidator Plant in West Texas is an example of executing this strategy. Other opportunities include pursuing relationships with new producers, the elimination of pipeline bottlenecks, reducing operating line pressures and focusing on a reduction of pipeline losses along its gathering systems.

 

   

Expanding operations through organic growth projects and pursuing strategic acquisitions. APL continues to explore opportunities to expand its existing infrastructure. APL also plans to pursue strategic acquisitions that are accretive to its unitholders, by seeking acquisition opportunities that leverage its existing asset base, employees and existing customer relationships. In the past, APL has pursued opportunities in certain regions outside of its current areas of operation and will continue to do so when these options make sense economically and strategically.

 

   

Reducing the sensitivity of APL’s cash flows through prudent economic risk management and contract arrangements. APL attempts to structure its contracts in a manner that allows it to achieve its target rate of return goals while reducing its exposure to commodity price movements. APL actively reviews its contract mix and seeks to optimize a balance of cash flow stability with attractive economic returns. APL’s commodity risk management activities are designed to reduce the effect of commodity price volatility related to future sales of natural gas, NGLs and crude oil, while allowing APL to meet its debt service requirements, fund its maintenance capital program and meet its distribution objectives.

 

   

Maintaining APL’s financial flexibility. APL intends to maintain a capital structure in which it does not significantly exceed equal amounts of debt and equity on a long-term basis, while not jeopardizing its ability to achieve its other business strategies. APL believes that its revolving credit facility, its ability to issue additional long-term debt or partnership units and its relationships with its partners provide APL with the ability to achieve this strategy. APL will also consider alternative financing, joint venture arrangements and other means that allow it to achieve its business strategies while continuing to maintain an acceptable capital structure.

The Midstream Natural Gas Gathering and Processing Industry

The midstream natural gas gathering and processing industry is characterized by regional competition based on the proximity of gathering systems and processing plants to producing natural gas wells.

The natural gas gathering process begins with the drilling of wells into natural gas or oil bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of pipelines that collect natural gas from points near producing wells and transport gas and other associated products to processing plants for processing and treating and to larger

 

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pipelines for further transportation to end-user markets. Gathering systems are operated at design pressures via pipe size and compression that will maximize the total throughput from all connected wells.

LOGO

While natural gas produced in some areas does not require treatment or processing, natural gas produced in many other areas, such as APL’s Chaney Dell, Midkiff/Benedum and Velma operations in the Mid-Continent, are not suitable for long-haul pipeline transportation or commercial use and must be compressed, gathered via pipeline to a central processing facility, potentially treated and then processed to remove certain hydrocarbon components such as NGLs and other contaminants that would interfere with pipeline transportation or the end use of the natural gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and extract the NGLs, enabling the treated, “dry” gas (low BTU content) to meet pipeline specification for long-haul transport to end users. After being separated from natural gas at the processing plant, the mixed NGL stream, commonly referred to as “y-grade” or “raw mix,” is typically transported in pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

Natural gas transportation pipelines receive natural gas from producers, other mainline transportation pipelines, shippers and gathering systems through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial end-users, utilities and other pipelines. Generally natural gas transportation agreements generate revenue for these systems based on a fee per unit of volume transported.

Contracts and Customer Relationships

APL’s principal revenue is generated from the gathering, processing and sale of natural gas, NGLs and condensate. Primary contracts are Fee-Based, Percentage of Proceeds (“POP”) and Keep-Whole (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Revenue Arrangements”).

APL’s Mid-Continent Operations

APL owns and operates approximately 8,600 miles of intrastate natural gas gathering systems located in Oklahoma, Kansas, and Texas. APL also owns and operates five processing plants located in Oklahoma and Texas. APL’s gathering, processing and treating assets service long-lived natural gas regions, including the Permian and Anadarko Basins. APL’s systems gather natural gas from oil and natural gas wells and process the raw natural gas into residue gas by extracting NGLs and removing impurities. In the aggregate, APL’s Mid-Continent systems have approximately 7,700 receipt points, consisting primarily of individual well connections and, secondarily, central delivery points which are linked to multiple wells. APL’s gathering systems interconnect with interstate and intrastate pipelines operated by El Paso Natural Gas Company; Enogex LLC; Kinder Morgan Texas Pipeline; Natural Gas Pipeline Company of America; Northern Natural Gas Company;

 

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ONEOK Gas Transportation, LLC; Panhandle Eastern Pipe Line Company, LP; and Southern Star Central Gas Pipeline, Inc. APL’s processing facilities are connected to NGL pipelines operated by ONEOK Hydrocarbon, L.P.

Mid-Continent Overview

APL considers the Mid-Continent region as running from Kansas through Oklahoma and Texas, branching into Louisiana, as well as southeastern New Mexico and western Arkansas (see the highlighted area of the map below). Two of the primary producing areas in the region include the Anadarko Basin and the Permian Basin, which is where APL’s Mid-Continent systems are located.

LOGO

Mid-Continent Gathering Systems

Chaney Dell. The Chaney Dell gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin. As of December 31, 2010, the gathering systems had approximately 4,300 miles of active natural gas gathering pipelines with approximately 4,300 receipt points. The primary producers on the Chaney Dell gathering system include certain subsidiaries of Chesapeake Energy Corporation; Sandridge Exploration and Production, LLC; and Bluestem Marketing, LLC.

LOGO

 

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Midkiff/Benedum. The Midkiff/Benedum gathering system, which APL operates and in which APL has an approximate 72.8% ownership, as of December 31, 2010, had approximately 3,100 miles of active natural gas gathering pipelines and approximately 2,800 receipt points located across seven counties within the Permian Basin in West Texas. Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”), the largest active driller in the Spraberry Trend and a major producer in the Permian Basin, owns the remaining interest in the Midkiff/Benedum system. The primary producers on the Midkiff/Benedum gathering system include Pioneer; COG Operating, LLC; and Endeavor Energy Resources, LP.

LOGO

Velma. The Velma gathering system is located in the Golden Trend and near the Woodford Shale areas of southern Oklahoma. As of December 31, 2010, the gathering system had approximately 1,200 miles of active pipelines with approximately 600 receipt points consisting primarily of individual well connections and, secondarily, central delivery points which are linked to multiple wells. The primary producers on the Velma gathering system include certain subsidiaries of Chesapeake Energy Corporation; Range Resources; and XTO Energy, Inc.

LOGO

 

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Mid-Continent Processing and Treating Plants

Chaney Dell. The Chaney Dell system processes natural gas through the Waynoka and Chester plants, which are active cryogenic natural gas processing facilities. The Chaney Dell system’s processing operations have total capacity of approximately 228 MMCFD. The Waynoka processing plant, located in Woods County, Oklahoma began operations in December 2006 and became fully operational in July 2007. The Chaney Dell plant located in Major County is inactive. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Waynoka and Chester plants and sells NGL production to ONEOK Hydrocarbon, L.P.

Midkiff/Benedum. The Midkiff/Benedum system processes natural gas through the Consolidator (located at Midkiff) and Benedum processing plants. The Consolidator plant is a 150 MMCFD cryogenic facility in Reagan County, Texas. The facility started operations in November 2009 and replaced the Midkiff plant. The Midkiff plant is currently inactive. The Benedum plant is a 45 MMCFD cryogenic facility in Upton County, Texas. APL’s Consolidator/Benedum processing operations have an aggregate processing capacity of approximately 195 MMCFD. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Consolidator/Benedum plants and sells NGL production to ONEOK Hydrocarbon, L.P.

Velma. The Velma processing plant, located in Stephens County, Oklahoma, is a cryogenic facility with a natural gas capacity of approximately 100 MMCFD. The Velma plant is one of only two facilities in the area that is capable of treating both high-content hydrogen sulfide and carbon dioxide gases which are characteristic in this area. APL has made capital expenditures at the facility to improve its efficiency and competitiveness, including installing electric-powered compressors rather than natural gas-powered compressors used by many of its competitors. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Velma plant and sells NGL production to ONEOK Hydrocarbon, L.P.

Natural Gas Supply

In the Mid-Continent, APL has natural gas purchase, gathering and/or processing agreements with approximately 560 producers. These agreements provide for the purchase or gathering of natural gas under Fee-Based, POP or Keep-Whole arrangements. Many of the agreements provide for compression, treating, processing and/or low volume fees. Producers generally provide, in-kind, their proportionate share of compressor and plant fuel required to gather the natural gas and to operate APL’s processing plants. In addition, the producers generally bear their proportionate share of gathering system line loss and, except for Keep-Whole arrangements, bear natural gas plant “shrinkage” for the gas consumed in the production of NGLs.

APL has long-term relationships with several of its Mid-Continent producers. For instance, APL has producer relationships going back over 20 years on its Velma System. Several of APL’s top producers, which accounted for a significant portion of the Velma volumes for the year ended December 31, 2010, have contracts with primary terms running into 2019 and beyond. At the end of the primary terms, most of the contracts with producers on APL’s gathering systems have evergreen term extensions. When APL acquired control of the Midkiff/Benedum system in July 2007, APL and Pioneer agreed to extend the existing gas sales and purchase agreement to 2022. The gas sales and purchase agreement requires that all Pioneer wells within an “area of mutual interest” be dedicated to that system’s gathering and processing operations in return for specified natural gas processing rates. Through this agreement, APL anticipates that it will continue to provide gathering and processing for the majority of Pioneer’s wells in the Spraberry Trend of the Permian Basin.

Natural Gas and NGL Marketing

APL typically sells natural gas to purchasers downstream of its processing plants priced at various first-of-month indices as published in Inside FERC. Additionally, swing gas, which is natural gas that is sold during the current month, is sold daily at various Platt’s Gas Daily midpoint pricing points. The Velma plant has

 

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access to ONEOK Gas Transportation, LLC, an intrastate pipeline; Southern Star Central Gas Pipeline, Inc. and Natural Gas Pipeline Company of America, interstate pipelines. The Chester plant has access to Panhandle Eastern Pipe Line Company, LP and the Waynoka plant has access to Enogex LLC, Panhandle Eastern Pipe Line Company, LP and Southern Star Central Gas Pipeline, Inc. The Consolidator/Benedum plants have access to Kinder Morgan Texas Pipeline, Northern Natural Gas Company and El Paso Natural Gas Company. As negotiated in specific agreements, various producers are allowed to take their share of gas in-kind at various delivery points.

APL sells its NGL production to ONEOK Hydrocarbon, L.P. under three separate agreements. The Velma agreement has an initial term expiring in 2016, the Midkiff/Benedum agreement has an initial term expiring in 2013, and the Chaney Dell agreement has a term expiring in 2014. All NGL agreements are priced at the average daily Oil Price Information Service (or OPIS) price for the month for the selected market, subject to reduction by a “Base Differential” and quality adjustment fees.

Condensate is collected at the Velma gas plant and gathering system and currently sold to EnerWest Trading Company LLC. Condensate collected at the Chaney Dell plants and around the Chaney Dell gathering system is currently sold to Plains Marketing. Condensate collected at the Consolidator/Benedum plants and around the Midkiff/Benedum gathering system is currently sold to Plains Marketing, Occidental Energy Marketing, Inc. and Oasis Marketing and Transportation Corporation.

Commodity Risk Management

APL’s Mid-Continent operations are exposed to certain commodity price risks. These risks result from either taking title to natural gas and NGLs, including condensate, or being obligated to purchase natural gas to satisfy contractual obligations with certain producers. APL attempts to mitigate a portion of these risks through a commodity risk management program which employs a variety of financial tools. The resulting combination of the underlying physical business and the commodity risk management program attempts to convert a physical price environment that consists of floating prices to a risk-managed environment that is characterized by fixed prices; floor prices on products where APL is long the commodity price; and ceiling prices on products where APL is short the commodity price. There are also risks inherent within risk management programs, including among others (i) price relationship between the physical and financial instrument deteriorating or (ii) projected physical volumes changing.

APL (a) purchases natural gas and subsequently sells processed natural gas and the resulting NGLs, or (b) purchases natural gas and subsequently sells the unprocessed natural gas, or (c) gathers and/or processes the natural gas for a fee without taking title to the commodities. Scenario (b) exposes APL to a generally neutral price risk (long sales approximate short purchases), while scenario (c) does not expose APL to any price risk; in both scenarios, risk management is not required. Scenario (a) does involve commodity price risk.

APL is exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of APL’s contractual relationships with natural gas producers or, alternatively, a function of cost of sales. APL is therefore exposed to price risk at a gross profit level rather than at a revenue level. These cost-of-sales or contractual relationships are generally of two types:

 

   

POP: requires APL to pay a percentage of revenue to the producer. This results in APL being net long physical natural gas and NGLs.

 

   

Keep-Whole: generally requires APL to deliver the same quantity of natural gas (measured in BTU’s) at the delivery point as it received at the receipt point; any resulting NGLs produced belong to APL, resulting in APL being long physical NGLs and short physical natural gas.

APL manages a portion of these risks by using fixed-for-floating swaps, which result in a fixed price, or by utilizing the purchase or sale of options, which result in floor prices, ceiling prices. APL utilizes natural gas

 

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swaps and options to manage its natural gas price risks. APL utilizes NGL and crude oil swaps and options to manage its NGL and condensate price risks.

APL generally realizes gains and losses from the settlement of its derivative instruments in other income at the same time it sells the associated physical residue gas or NGLs. APL determines gains or losses on open and closed derivative transactions as the difference between the derivative contract price and the physical price. This mark-to-market methodology uses daily closing New York Mercantile Exchange (“NYMEX”) prices when applicable and an internally-generated algorithm for commodities that are not traded on an open market. To ensure that these derivative instruments will be used solely for managing price risks and not for speculative purposes, APL has established a committee to review its derivative instruments for compliance with its policies and procedures.

For additional information on APL’s derivative activities and a summary of its outstanding derivative instruments as of December 31, 2010, please see “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Appalachia Operations

APL’s Appalachia operations are principally conducted through its 49% non-controlling interest in Laurel Mountain, which APL sold subsequent to December 31, 2010. Laurel Mountain owns and operates approximately 1,000 miles of intrastate gas gathering systems located in Pennsylvania, including substantial assets in the Marcellus Shale. APL also owns and operates approximately 70 miles of natural gas gathering pipelines in Tennessee. Laurel Mountain serves approximately 4,700 wells and experienced an average throughput of 109.5 MMCFD of natural gas for the year ended December 31, 2010. APL’s Tennessee systems serve approximately 180 receipt points and experienced an average throughput of 8.7 MMCFD of natural gas for the year ended December 31, 2010. APL’s gathering systems provide a means through which well owners and operators can transport the natural gas produced by their wells to interstate and public utility pipelines for delivery to customers. To a lesser extent, APL’s gathering systems transport natural gas directly to customers. Laurel Mountain’s systems are located in the Appalachian Basin, which encompasses the Marcellus Shale. The Marcellus Shale is a vast, newly developing shale play experiencing a significant increase in natural gas exploration and production. The Appalachian Basin is a region that has historically been characterized by long-lived, predictable natural gas reserves that are close to major eastern U.S. natural gas markets. Substantially all of the natural gas Laurel Mountain gathers in the Appalachian Basin is derived from wells operated by Atlas Energy Resources. Laurel Mountain has a gas gathering agreement with Atlas Energy Resources, which is intended to maximize the use and expansion of the gathering systems and the amount of natural gas which Laurel Mountain gathers in the region. In addition, other natural gas producers have acreage positions in relatively close proximity to Laurel Mountain’s current and planned assets, providing additional opportunities for expansion.

Appalachian Basin Overview

The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. The Appalachian Basin is strategically located near the energy-consuming regions of the mid-Atlantic and northeastern United States.

Natural Gas Supply

Substantially all of the natural gas Laurel Mountain gathers in the Appalachian Basin is derived from wells operated by Atlas Energy Resources. Laurel Mountain’s ability to increase the flow of natural gas through its gathering systems will be determined primarily by the number of wells drilled by Atlas Energy Resources and connected to the gathering systems; and Laurel Mountain’s ability to acquire additional gathering assets and secure gathering contracts with other natural gas producers with acreage positions in the area and expand

 

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existing systems. During the year ended December 31, 2010, approximately 90 wells were connected to the Laurel Mountain gathering system.

Natural Gas Revenue

APL’s Appalachia revenue is determined primarily by the amount of natural gas flowing through Laurel Mountain’s and its Tennessee gathering systems and the price received for this natural gas. Laurel Mountain has an agreement with Atlas Energy Resources under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations). For the year ended December 31, 2010, Laurel Mountain received gathering fees averaging $0.95 per MCF.

Because APL does not buy or sell gas in connection with its Appalachia operations, it does not engage in hedging activities. Atlas Energy Resources maintains a hedging program. Since Laurel Mountain receives gathering fees from Atlas Energy Resources generally based on the selling price received by Atlas Energy Resources, inclusive of the effects of financial and physical hedging, these financial and physical hedges mitigate the risk of Laurel Mountain’s arrangements.

APL’s Relationship with Atlas Energy, Inc.

APL began its operations in January 2000 by acquiring the Appalachia gathering systems of ATLS. In May, 2009, APL contributed the majority of its Appalachia gathering system assets to Laurel Mountain, a joint venture in which APL has a 49% non-controlling interest. ATLS owned 64.0% of us and had a direct 2.1% ownership interest in APL at December 31, 2010.

ATLS and its affiliates sponsor limited and general partnerships to raise funds from investors to explore for, develop and produce natural gas and, to a lesser extent, oil from locations in northeastern Appalachia. Laurel Mountain’s gathering systems are connected to approximately 4,600 wells developed and operated by Atlas Energy Resources in the Appalachian Basin. Laurel Mountain gathers substantially all of the natural gas from wells operated by Atlas Energy Resources.

Natural Gas Gathering Agreements

In connection with the formation of Laurel Mountain, on June 1, 2009, Laurel Mountain entered into the following natural gas gathering agreements with Atlas Energy Resources, Atlas Energy Operating Company, LLC, Atlas America, LLC, Atlas Noble, LLC, Resource Energy, LLC and Viking Resources, LLC: (1) a gas gathering agreement for natural gas on the Legacy Appalachia system with respect to the existing gathering systems and any expansions to it (the “Legacy Agreement”) and (2) a gas gathering agreement for natural gas on the expansion gathering system with respect to other gathering systems constructed within a specified area of mutual interest (the “Expansion Agreement” and collectively with the Legacy Agreement, the “Gathering Agreements”). Under these Gathering Agreements, Atlas Energy Resources will dedicate its natural gas production in the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport Atlas Energy Resources’ dedicated natural gas in the Appalachian Basin subject to certain conditions.

Under the Gathering Agreements, Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

 

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The provisions in the Gathering Agreements regarding the allocation of responsibility for constructing additional gathering lines are that to the extent that Atlas Energy Resources own wells or propose wells that are within 2,500 feet of Laurel Mountain’s gathering system, Laurel Mountain must, at its own cost, construct up to 2,500 feet of the gathering lines as necessary to connect such wells to the gathering system. For wells more than 2,500 feet from Laurel Mountain’s gathering system, if Atlas Energy Resources construct a gathering line to within 1,000 feet of Laurel Mountain’s gathering system, then Laurel Mountain must, at its own cost, extend its gathering system to connect to such gathering lines.

The Gathering Agreements remain in effect so long as gas from Atlas Energy Resources’ wells is produced in economic quantities without lapse of more than 90 days.

APL’s Competition

Acquisitions. APL has encountered competition in acquiring midstream assets owned by third parties. In several instances APL submitted bids in auction situations and in direct negotiations for the acquisition of such assets and was either outbid by others or was unwilling to meet the sellers’ expectations. In the future, APL expects to encounter equal, if not greater, competition for midstream assets because as natural gas, crude oil and NGL prices increase the economic attractiveness of owning such assets increases.

Mid-Continent. In APL’s Mid-Continent service area, it competes for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by Carrera Gas Company, Copano Energy, LLC, DCP Midstream, Enogex, LLC, Hiland Partners, Mustang Fuel Corporation, ONEOK Field Services, Southern Union Company, Targa Resources and West Texas Gas.

APL believes that the principal factors upon which competition for new well connections is based are:

 

   

the price received by an operator or producer for its production after deduction of allocable charges, principally the use of the natural gas to operate compressors; and

 

   

the quality and efficiency of the gathering systems and processing plants that will be utilized in delivering the gas to market; and

 

   

the access to various residue markets that provides flexibility for producers and ensures that the gas will make it to market; and

 

   

the responsiveness to a well operator’s needs, particularly the speed at which a new well is connected by the gatherer to its system.

APL believes that its relationships with operators connected to its system are good and that APL presents an attractive alternative for producers. However, if APL cannot compete successfully, it may be unable to obtain new well connections.

Appalachia. The assets operated in the Appalachian Basin by APL and Laurel Mountain do not encounter direct competition in their service areas at this time, since Atlas Energy Resources controls the majority of the drillable acreage in the area. However, because these operations principally serve wells drilled by Atlas Energy Resources, APL and Laurel Mountain are affected by competitive factors affecting Atlas Energy Resources’ ability to obtain properties and drill wells, which affects APL’s and Laurel Mountain’s ability to expand gathering systems and to maintain or increase the volume of natural gas gathered and, thus, transportation revenues. Atlas Energy Resources also may encounter competition in obtaining drilling services from third-party providers. Any competition it encounters could delay Atlas Energy Resources in drilling wells, and thus delay the connection of wells to APL’s and Laurel Mountain’s gathering systems. These delays would

 

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reduce the volume of natural gas that otherwise would have been gathered, thus reducing potential transportation revenues.

In addition to the connections to Atlas Energy Resources wells, Laurel Mountain and APL seek to connect wells operated by third parties. As of December 31, 2010, these systems are connected to approximately 250 third party wells.

Seasonality

APL’s business is affected by seasonal fluctuations in commodity prices. Sales volumes are also affected by various factors such as fluctuating and seasonal demands for products and variations in weather patterns from year to year. Generally, natural gas demand increases during the winter months and decreases during the summer months. Freezing conditions can disrupt APL’s gathering process, which could adversely affect APL’s operating results.

Regulation

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, 15 U.S.C. § 717(b), exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). APL owns a number of intrastate natural gas gathering lines in Kansas, Oklahoma and Texas that APL believes meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated natural gas transportation facilities and federally unregulated natural gas gathering facilities is the subject of regular litigation, so the classification and regulation of some of APL’s or Laurel Mountain’s gathering facilities may be subject to change based on future determinations by FERC and the courts.

Laurel Mountain’s operations in Pennsylvania currently are not subject to the Pennsylvania Public Utility Commission’s regulatory authority since Laurel Mountain does not provide service to the public generally and, accordingly, its activities do not constitute the operation of a public utility. In the event the Pennsylvania authorities seek to regulate Laurel Mountain’s operations, APL’s operating costs could increase and its transportation fees could be adversely affected, thereby reducing its net revenues and ability to fund its operations, pay required debt service on its credit facilities and make distributions to its General Partner and common unitholders.

APL is currently subject to state ratable, take common purchaser and/or similar statutes in one or more jurisdictions in which it operates. Common purchaser statutes generally require gatherers to purchase without discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In particular, Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Kansas Corporation Commission, the Oklahoma Corporation Commission or the Texas Railroad Commission become more active, APL’s revenues could decrease. Collectively, any of these laws may restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or gather natural gas.

APL’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. APL’s gathering operations also may be or may become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such changes might have on APL’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

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Sales of Natural Gas and NGLs. A portion of APL’s revenue is tied to the price of natural gas and NGLs. The wholesale price of natural gas and NGLs is not currently subject to federal regulation and, for the most part, is not subject to state regulation. Sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation of natural gas and NGLs are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the segments of the natural gas industry, most notably interstate natural gas transportation companies that remain subject to FERC’s jurisdiction. While FERC is less active in proposing changes in the manner in which it regulates the transportation of NGLs under the Interstate Commerce Act, it does nevertheless have authority to address the rates, terms and conditions under which NGLs are transported. FERC initiatives could, therefore, affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of any regulatory changes that could result from FERC initiatives on APL’s operations.

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate natural gas pipelines in particular. Overall, the legislation attempts to increase supply sources by calling for various studies of the overall resource base and attempting to advantage deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the provisions of primary interest to APL as an operator of natural gas gathering lines and sellers of natural gas focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructure development, the Energy Policy Act includes provisions; confirming that FERC has exclusive jurisdiction over the siting of liquefied natural gas (“LNG”) terminals; provides for market-based rates for certain new underground natural gas storage facilities placed into service after the date of enactment; shortens depreciable life for gathering facilities; statutorily designates FERC as the lead agency for federal authorizations and permits relating to interstate natural gas pipelines and LNG terminals; provides for the assembly of a consolidated record for all federal decisions relating to necessary authorizations and permits with respect to interstate natural gas pipelines and LNG terminals; and provides for expedited judicial review of any agency action involving the permitting of such facilities and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act on a permit relating to an interstate natural gas pipeline or LNG terminal by a deadline set by FERC as lead agency. Such provisions, however, do not apply to review and authorization under the Coastal Zone Management Act of 1972. Regarding market transparency and manipulation, the Natural Gas Act has been amended to prohibit market manipulation and directs FERC to prescribe rules designed to encourage the public provision of data and reports regarding the price of natural gas in wholesale markets. The Natural Gas Act and the Natural Gas Policy Act were also amended to increase monetary criminal penalties to $1,000,000 from the $5,000 amount specified under prior law and to add and increase civil penalty authority to be administered by FERC to $1,000,000 per day per violation without any limitation as to total amount.

At present, APL believes none of its gathering lines qualify as interstate natural gas transmission systems subject to FERC regulation under the Natural Gas Act. Accordingly, the provisions of the Energy Policy Act have only limited applicability to APL, primarily in its capacity as a seller of natural gas.

Environmental Matters

The operation of pipelines, plant and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, APL must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact APL’s business activities in many ways, such as:

 

   

restricting the way APL can handle or dispose of its wastes;

 

   

limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by endangered species;

 

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requiring remedial action to mitigate pollution conditions caused by APL’s operations or attributable to former operators; and

 

   

enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment.

We believe that APL’s operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on its business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure you that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause APL to incur significant costs.

Hazardous Waste. APL’s operations generate wastes, including some hazardous wastes that are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

We believe that APL’s operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that APL’s operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploration and production wastes could increase APL’s costs to manage and dispose of such wastes.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of APL’s ordinary operations it may generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the Environmental Protection Agency, or EPA, and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs

 

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they incur. Under CERCLA, APL could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.

APL currently owns or leases, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas. Although APL used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by APL or on or under other locations where such substances have been taken for disposal. There is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by APL. However, none of these spills or releases were material and APL believes all of them have been remediated. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, APL could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform operations to prevent future contamination.

Air Emissions. APL’s operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including APL’s processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that APL obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. APL’s failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. APL likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that APL’s operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to APL than to any other similarly situated companies.

Water Discharges. APL’s operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by a permit. Any unpermitted release of pollutants from APL’s pipelines or facilities could result in administrative, civil or criminal penalties as well as significant remedial obligations. Further, natural gas extraction activities utilize a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Recently, this subject has received regulatory and legislative attention at both the federal and state levels and it is possible that the permitting and compliance requirements applicable to hydraulic fracturing activity may become more stringent. Such requirements could have an adverse impact on APL’s operations.

Pipeline Safety. APL’s pipelines are subject to regulation by the U.S. Department of Transportation, or DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA. The NGPSA authorizes the DOT to regulate pipeline transportation of natural (flammable, toxic, or corrosive) gas and other gases, and requires any entity that owns or operates pipeline facilities to comply with the regulations. The DOT’s Pipeline and Hazardous Material Safety Administration, or PHMSA, acting through the Office of Pipeline Safety, or OPS, administers the national regulatory program to assure safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. The OPS administers the federal pipeline safety regulations to (1) ensure

 

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safety in design, construction, inspection, testing, operation, and maintenance of pipeline facilities and (2) set out parameters for administering the pipeline safety program.

APL’s operations are required to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that APL’s pipeline operations are in substantial compliance with existing PHMSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the PHMSA could result in additional requirements and costs.

PHMSA recently finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transportation pipelines (including gathering lines) that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. To ensure uniform implementation of the pipeline safety program nationwide, Federal/State partnerships including the Texas Railroad Commission, the Oklahoma Corporation Commission and other state agencies have adopted similar regulations applicable to intrastate gathering and transportation lines. Compliance with these rules has not had a materially adverse effect on our operations but there is no assurance that this will continue in the future.

Employee Health and Safety. APL is subject to the requirements of the Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in APL’s operations and that this information be provided to employees, state and local government authorities and citizens.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans, and prolonged exposure can result in death. The gas produced at APL’s Velma gas plant contains high levels of hydrogen sulfide, and APL employs numerous safety precautions at the system to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and APL is in substantial compliance with all such requirements.

Chemicals of Interest. APL operates several facilities that are registered with the U.S. Department of Homeland Security, or DHS, in order to identify the quantities of various chemicals that are stored at the sites. These facilities are the Velma, Chaney Dell, Waynoka and Chester gas processing plants in Oklahoma; and the Midkiff and Benedum gas processing plants in Texas. The liquid hydrocarbons that are recovered and stored as a result of facility processing activities, and various chemicals utilized within the processes, have been identified and registered with DHS. These registration requirements for Chemical of Interest were first promulgated by DHS in 2008 and APL is currently in compliance with the Department’s requirements. None of APL’s affected facilities are considered high security risks by DHS at this time and no specific security plans for such per DHS regulations are required.

Greenhouse Gases. In October 2009, the EPA published rules in Title 40 of the Code of Federal Regulations, part 98 (40 CFR 98) requiring mandatory reporting of greenhouse gases. The rule specifies methods by which entities that produce these gases, which include Carbon Dioxide (CO2) and Methane (CH4), must inventory, monitor and report such gases. Compliance with this rule has resulted, and will continue to result, in higher costs of doing business. Additionally the United States Congress is also considering legislation to address the production and reduction of greenhouse gases primarily through the planned development of a greenhouse gas cap and trade program. As an alternative to the cap and trade program, the EPA may implement greenhouse gas reduction through traditional construction and operating permit programs, which would effectively circumvent the need for congressional action. The cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of

 

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fuels it processes. In addition, APL’s operations could face additional costs for emissions control and higher costs of doing business. Although APL would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could result in a significant effect on APL’s cost of doing business. However, we are currently unable to assess the timing and effect of the pending legislation.

APL Properties

As of December 31, 2010, our assets consisted principally of our ownership interests in APL. As of December 31, 2010, APL’s principal facilities in the Mid-Continent consist of five natural gas processing plants and approximately 8,600 miles of active 2 to 30 inch diameter pipeline. Substantially all of APL’s gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. As of December 31, 2010, APL’s principal facilities in Appalachia include approximately 70 miles of 2 to 12 inch diameter pipeline operated by its Tennessee gathering systems and approximately 1,000 miles of 2 to 12 inch diameter pipeline operated by Laurel Mountain. In a few cases, property for gathering system purposes was purchased in fee. All of APL’s compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

The following tables set forth certain information relating to APL’s gas processing facilities and natural gas gathering systems:

Gas Processing Facilities

 

Facility

 

Location

 

Year

Constructed

   Design
Throughput

Capacity
(MMCFD)
     2010
Average
Througput
(MMCFD)
     2010
Average
Utilization
Rate
 

Velma plant

  Stephens County, OK   Updated 2003      100         78         78
                              

Waynoka plant

  Woods County, OK   2006      200         

Chester plant

  Woodward County, OK   1981      28         
                              

Total Chaney Dell

         228         214         94
                              

Consolidator plant(1)

  Reagan County, TX   2009      150         

Benedum plant

  Upton County, TX   Updated 1981      45         
                              

Total Midkiff/Benedum

         195         163         84
                              

 

(1) Replaced 110 MMCFD Midkiff plant, which has been shut down. Midkiff plant is available for processing if natural gas supply increases beyond the Consolidator plant capacity.

Natural Gas Gathering Systems

 

System

  

Location

   Approximate
Active Miles
of Pipe
     Receipt
Points
 

Chaney Dell

   North Central Oklahoma and Southern Kansas      4,300         4,300   

Velma

   Southern Oklahoma and Northern Texas      1,200         600   

Midkiff/Benedum

   West Texas      3,100         2,800   

Laurel Mountain

   Pennsylvania      1,000         4,700   

Tennessee

   Tennessee      70         180   

APL’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not materially interfered, and we do not expect that they will materially interfere, with the conduct of APL’s 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 rights-of-way grants. In a few instances, APL’s 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 rights-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,

 

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

Employees

As is commonly the case with publicly-traded limited partnerships, we do not directly employ any of the persons responsible for our management, nor does APL directly employ any of the persons responsible for its operations. In general, employees of ATLS and its affiliates manage APL’s gathering systems and operate its business. ATLS employed approximately 270 people at December 31, 2010 who provided direct support to APL’s operations.

ATLS and its affiliates will conduct business and activities of their own in which we and APL will have no economic interest. If these separate activities are significantly greater than our and APL’s activities, there could be material competition between us, APL, ATLS and affiliates of ATLS for the time and effort of the officers and employees who provide services to us or APL. Apart from our Chairman and Vice Chairman, our officers who provide services to APL are generally assigned solely to our or APL’s operations. However, they are not required to work full time on our or APL’s affairs. These officers may also devote time to the affairs of ATLS and its affiliates and be compensated by these affiliates for the services rendered to them. There may be conflicts between us and APL and affiliates of our general partner regarding the availability of these officers to manage us and APL.

On February 17, 2011, ATLS consummated its merger with Chevron pursuant to the Chevron Merger Agreement whereby ATLS became a wholly-owned subsidiary of Chevron. Additionally, on February 17, 2011, we consummated the AHD Transactions with ATLS and Atlas Energy Resources and subsequent to such transaction, we or one of our subsidiaries employs all of the persons responsible for our management and operations. See “–Recent Developments” for further discussion.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q and our current reports on Form 8-K, available through our website at www.atlasenergy.com. To view these reports, click on “Investor Relations,” then “SEC Filings.” You may also receive, without charge, a paper copy of any such filings by request to us at 1550 Coraopolis Heights Road, Moon Township, Pennsylvania 15108, telephone number (412) 262-2830. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

 

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ITEM 1A. RISK FACTORS

Partnership 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 were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Relating to the Recent AHD Transactions

Our historical results are not necessarily representative of the results that we would have achieved without ATLS as our majority unitholder, as the owner of the transferred business or otherwise as an operating entity and may not be a reliable indicator of our future results.

Our historical results do not reflect the financial condition, results of operations or cash flows that we would have achieved without ATLS as our majority unitholder, if we were the owner and operator of the transferred business on a stand-alone basis or otherwise as an operating entity, primarily due to the following factors:

 

   

Our historical financial results do not reflect the AHD Transactions or the disposition by APL of its 49% non-controlling ownership interest in Laurel Mountain;

 

   

Since our formation, ATLS has been our majority unitholder, has provided us with management and other services, and has managed or performed certain of our corporate functions at no cost to us. In addition, following the AHD Transactions, our financial results will reflect certain corporate expenses for which we became solely responsible and certain additional corporate expenses which were previously inapplicable to us, including management compensation, financial reporting, tax administration, human resources administration, information technology, legal and other services;

 

   

We will incur significant increases in our cost structure following the AHD Transactions. Prior to the AHD Transactions, we did not have any significant stand-alone operations. Following the AHD Transactions, our operations may require a significant number of additional operational, technical and other personnel whose costs are not reflected in our historical financial data. Our operations following the AHD Transactions also require us to newly implement or expand our current capabilities in areas including operations, maintenance, geophysical, geotechnical, land acquisition and management, sales and marketing, legal and regulatory compliance, treasury, accounting, auditing, risk management, information technology, human resources, corporate affairs, tax administration, governance and external reporting. We also became responsible for the significant field-related capital and operating expenditures required in connection with the exploration for and production of hydrocarbons and all of the attendant risks associated with such activities. These requirements, among others, will materially increase the cost of our operations and our businesses above historical levels;

 

   

Our cost of funds is likely to change following the AHD Transactions, including due to the fact that our former parent, ATLS no longer exists to guarantee any of our indebtedness or provide any financing to us; and

 

   

the AHD Transactions and the fact that we are no longer controlled by ATLS may adversely affect client and other business relationships of ours and of the transferred business, which effects may be material, and may result in the loss of certain preferred pricing previously available to us or to the transferred business by virtue of our relationship with ATLS.

 

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Our financial condition and future results of operations, after giving effect to the AHD Transactions and the Laurel Mountain Sale, will be materially different from the amounts reflected in our historical financial information. As a result of the AHD Transactions and the disposition of APL’s 49% non-controlling ownership interest in Laurel Mountain, it may be difficult for investors to compare our future results to historical results or to evaluate our relative performance or trends in our business, which may adversely affect the trading market for, and price of, our common units.

We may not be successful in transitioning to a company not controlled by ATLS and may be unable to obtain all of the services and resources we need to operate independently of ATLS and to operate the transferred business.

Historically, ATLS has provided us with certain services essential to our business, including managing the business of APL, the direct and indirect interests which prior to the AHD Transactions, were our only significant cash-generating assets. Following the recent consummation of the AHD Transactions, other than as provided in the Transition Services Agreement, the Michigan Operating Agreement, the Pennsylvania Operating Agreement, the Petro-Technical Services Agreement and the Gas Marketing Agreement, ATLS and Chevron have no obligation to provide us with financial, operational or organizational assistance. Furthermore, the services to be provided by ATLS and Chevron under such agreements are limited in scope and duration. We may need to develop our own capabilities or otherwise supplement the services contemplated by these agreements, and the other services historically provided to us by ATLS, and may need to hire and train personnel to undertake some or all of the services following the termination or expiration of these agreements or to otherwise provide certain services historically provided by ATLS or historically inapplicable to us, any of which could adversely affect the operation of our business and financial results. We may need to hire additional personnel, upgrade our systems and infrastructure and make other changes necessary to operate independently and to conduct the transferred business. We cannot guarantee that the services historically provided by ATLS will continue or be replaced without disruption or at a cost comparable to that provided by ATLS or that we will be able to implement successfully the changes necessary to operate independently.

Our costs to operate the transferred business may be significantly higher than ATLS’s historical costs.

The costs of operating the transferred business cannot be estimated with certainty, and may be materially higher than historical costs to ATLS for such operations, primarily due to the following factors:

 

   

the loss of certain economies of scope and scale;

 

   

the need to replace certain contracts associated with the transferred business that are being retained by ATLS in the AHD Transactions;

 

   

our lack of experience in operating assets of this type;

 

   

the likely increase in hedging costs associated with the transferred business, including hedging relating to the oil, gas and liquids production of the transferred business, relative to the analogous hedging costs incurred by ATLS’s historical hedging activities;

 

   

the need to rely on ATLS for certain transitional and operating services for some period of time following closing (see “Item 1: Business –Services Agreements”), and the need to hire and train personnel to undertake some or all of those services following the termination or expiration of those transition and operating services agreements; and

 

   

potential increases in regulatory, compliance, severance and tax liabilities associated with the operations of the transferred business (see “–Changes in tax laws may impair our ability to obtain capital funds through investment partnerships,” “–Potential introduction of severance taxes in Pennsylvania could materially increase our liabilities,” and “–We are subject to comprehensive

 

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federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of doing business”).

Any increase in the operational costs of conducting the transferred business could adversely affect our results of operations and financial condition, which could limit the amount of cash available for distribution and could adversely affect the trading market for our common units.

Our business is now substantially different following the consummation of the AHD Transactions and the Laurel Mountain Sale, and management may not be able to operate the transferred business to achieve the anticipated results.

As a result of the AHD Transactions and the Laurel Mountain Sale, we now own ATLS’s investment partnership business and certain producing oil and gas assets and assumed certain of the historical and future liabilities associated with such businesses, and we no longer derive revenue from the gas gathering business of Laurel Mountain. Our business is substantially different following the AHD Transactions and our results of operations and the market price of our common units following the AHD Transactions may be affected by factors different from those historically affecting our results of operations and the market price of our common units. Although our management includes individuals that have historically managed the transferred business, we may not be able to retain all of these employees and we cannot guarantee that we will be able to operate the transferred business in a profitable manner or will be able to achieve the projected benefits from the AHD Transactions.

After the AHD Transactions, we are no longer able to obtain financing from ATLS

Our plans to operate, expand and improve our business may require funds in excess of our cash flow and may require us to seek financing from third parties. In the past, ATLS has provided us with capital. After the AHD Transactions, however, ATLS will not provide funds to us. Without the opportunity to obtain financing from ATLS, we will need to obtain additional financing from banks, or through public offerings or private placements of debt or equity securities, strategic relationships or other arrangements. We cannot give assurances at this time that we will be able to obtain such funding. In addition, the terms, interest rates, costs and fees of new credit facilities may not be as favorable as those historically provided by ATLS. If financing is not available when needed, or is available on unfavorable terms, we may be unable to meet our capital needs, maintain our existing businesses, develop new businesses or enhance our existing businesses, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition and results of operations.

APL’s ability to make distributions to its partners, including us, and the amount of any such distributions may be affected by APL’s sale of its 49% non-controlling ownership interest in Laurel Mountain, by APL’s use of proceeds from such sale, and by APL’s conduct of its business following such sale. The amount and timing of such distributions by APL, if any, will have an impact on our ability to make distributions and the amount of any such distributions.

Our direct and indirect ownership interests in APL historically represented our only cash-generating assets and they continue to represent a significant source of operating cash for us following the completion of the AHD Transactions. APL’s ability to make distributions to its partners, including us, may be affected by APL’s sale of its 49% non-controlling ownership interest in Laurel Mountain and APL’s use of the proceeds from such sale. APL’s use of proceeds from the sale of its 49% non-controlling ownership interest in Laurel Mountain may be different from the use that holders of our common units would prefer, and may be limited in whole or in part by the terms of APL’s outstanding indebtedness. For example, holders of our common units might prefer that APL distributes all or a portion of such proceeds to APL’s partners, or to use such proceeds to make one or more acquisitions, but APL may, subject to the terms of its outstanding indebtedness, use such proceeds for the repayment of debt or for acquisitions or capital investments or for other purposes. In addition, cash flows from APL to us continue to be subject to the various regulatory, commercial, operating and other

 

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risks arising in connection with APL’s conduct of its business, some of which may differ from the risks associated with the assets and liabilities acquired in the AHD Transactions.

If commodity prices decline significantly, our cash flow from operations will decline.

Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil, and will continue to do so following the AHD Transactions. The natural gas and oil markets are very volatile, and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices will have a significant impact on the value of our reserves, on APL’s business and on each of our and APL’s cash flow. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

   

the level of the domestic and foreign supply and demand;

 

   

the price and level of foreign imports;

 

   

the level of consumer product demand;

 

   

weather conditions and fluctuating and seasonal demand;

 

   

overall domestic and global economic conditions;

 

   

political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;

 

   

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

   

the impact of the U.S. dollar exchange rates on natural gas and oil prices;

 

   

technological advances affecting energy consumption;

 

   

domestic and foreign governmental relations, regulations and taxation;

 

   

the impact of energy conservation efforts;

 

   

the cost, proximity and capacity of natural gas pipelines and other transportation facilities; and

 

   

the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2010, the NYMEX Henry Hub natural gas index price ranged from a high of $6.01 per MMBTU to a low of $3.29 per MMBTU, and West Texas Intermediate oil prices ranged from a high of $91.51 per Bbl to a low of $68.01 per Bbl.

Unless we replace the oil and gas reserves that we acquired in the AHD Transactions, our reserves and production will decline, which would reduce our cash flow from operations and income.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Following the AHD Transactions, our natural gas reserves and production and, therefore, our cash flow and income became highly dependent on our success in

 

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efficiently developing and exploiting the reserves that we acquired in the AHD Transactions and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, principally from the sponsorship of new investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

Estimates of the reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we will make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our PV-10 and standardized measure are calculated using natural gas prices that include our physical hedges but not our financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on historical prices and costs. However, the actual future net cash flows we derive from such properties also will be affected by factors such as:

 

   

actual prices we receive for natural gas;

 

   

the amount and timing of actual production;

 

   

the amount and timing of our capital expenditures;

 

   

supply of and demand for natural gas; and

 

   

changes in governmental regulations or taxation.

The timing of both our production and incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of our reserves, the amount of PV-10 and standardized measure, and our financial condition and results of operations. In addition, our reserves or PV-10 and standardized measure may be revised downward or upward based upon production history, results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of our

 

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reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10 and standardized measure.

A decrease in natural gas prices could subject our oil and gas properties to a non-cash impairment loss.

Oil and gas properties and other long-lived assets are to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We will test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable depletion, depreciation and amortization and abandonment was less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our own economic interests and our plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market-related information, including published future prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, further declines in the price of natural gas may cause the carrying value of our oil and gas properties to exceed the expected future cash flows, and a non-cash impairment loss would be required to be recognized in the financial statements for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

Hedging transactions may limit our potential gains or cause us to lose money.

In connection with the AHD Transactions, we entered into hedging arrangements intended to benefit from or reduce the risk of fluctuations in the price of natural gas and oil or other commodities produced by the transferred business, including the investment partnership business. With this new hedging arrangement in place, we will reduce, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for the periods covered by this hedging arrangement. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. Under circumstances in which, among other things, production is substantially less than expected, the counterparties to our futures contracts fail to perform under the contracts or a sudden, unexpected event materially impacts commodity prices, we may be exposed to the risk of financial loss. In addition, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we are unable to enter into a completely effective hedge transaction.

Our operations will require substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our revenues may decline.

The natural gas and oil industry is capital intensive. If we are unable to obtain sufficient capital funds with capital raised through equity and debt offerings, cash flow from operations, bank borrowings and the investment partnerships on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. As a result, our revenues will decline and our ability to service debt may be diminished. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations.

 

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The scope and costs of the risks involved in making acquisitions, including the AHD Transactions, may prove greater than estimated at the time of the acquisition.

Any acquisition involves potential risks, including, among other things:

 

   

mistaken assumptions about revenues and costs, including synergies;

 

   

significant increases in our indebtedness and working capital requirements;

 

   

an inability to integrate successfully or timely the businesses we acquire;

 

   

the assumption of unknown liabilities;

 

   

limitations on rights to indemnity from the seller;

 

   

the diversion of management’s attention from other business concerns;

 

   

increased demands on existing personnel;

 

   

customer or key employee losses at the acquired businesses; and

 

   

the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically, or in connection with the AHD Transactions. Any of these factors could adversely affect our growth.

We may be unsuccessful in integrating the operations from the AHD Transactions or any future acquisitions with our operations.

The integration of previously independent operations can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations we may acquire in the future, include, among other things:

 

   

operating a significantly larger combined entity;

 

   

the necessity of coordinating geographically disparate organizations, systems and facilities;

 

   

integrating personnel with diverse business backgrounds and organizational cultures;

 

   

consolidating operational and administrative functions;

 

   

integrating internal controls, compliance under Sarbanes-Oxley Act of 2002 and other corporate governance matters;

 

   

the diversion of management’s attention from other business concerns;

 

   

customer or key employee loss from the acquired businesses;

 

   

a significant increase in its indebtedness; and

 

   

potential environmental or regulatory liabilities and title problems.

 

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Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to operate, maintain or expand our operations could harm our business or future prospects, and result in significant decreases in our gross margin and cash flows.

Changes in tax laws may impair our ability to obtain capital funds through investment partnerships.

Under current federal tax laws, there are tax benefits to investing in investment partnerships such as those we sponsor following the AHD Transactions, including deductions for intangible drilling costs and depletion deductions. However, President Obama’s administration has proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs, the passive activity exception for working interests and the marginal production tax credit. These proposals may or may not be adopted. The repeal of these oil and gas tax benefits, if it happens, would result in a substantial decrease in tax benefits associated with an investment in our investment partnerships. These or other changes to federal tax law may make investment in our investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds.

Drilling and production operations that we acquired in the AHD Transactions require adequate sources of water to facilitate the fracturing process and the disposal of that water. If we are unable to dispose of the water we use or remove from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

A significant portion of our natural gas extraction activity will utilize a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance. Our ability to remove and dispose of water will affect our production, and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil.

Potential introduction of severance taxes in Pennsylvania could materially increase our liabilities.

In 2010, charges for severance taxes (relating to the extraction of natural gas) incurred by ATLS in the states in which ATLS operated, other than Pennsylvania, were approximately $6.0 million. While Pennsylvania has historically not imposed a severance tax, with a focus on its budget deficit and the increasing exploration of the Marcellus shale, various legislation has been proposed since 2008 to implement such a tax, the most recent of which would have imposed a tax of 5% of the value of natural gas at the wellhead plus $0.047 per MCF. Although that proposal was not adopted, lawmakers may propose similar taxes in the future. If adopted, these taxes may materially increase our operating costs in Pennsylvania relative to historical operating costs for the assets acquired in the AHD Transactions located in Pennsylvania.

We may not be able to continue to raise funds through the investment partnerships at the levels ATLS had recently experienced, which may in turn restrict our ability to maintain drilling activity at recent levels.

ATLS had sponsored partnerships to raise funds from investors to finance certain of its development drilling activities. We expect that we will continue this practice. Accordingly, the amount of development activities that we will undertake depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. ATLS raised $149.3 million, $353.4 million and $438.4 million for such partnerships in calendar years 2010, 2009 and 2008, respectively. In the future, we may not be successful in raising funds through these investment partnerships at the same levels that ATLS had recently experienced, and we also may

 

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not be successful in increasing the amount of funds we raise. Our ability to raise funds through investment partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by ATLS’s historical track record of generating returns and tax benefits to the investors in ATLS’s former investment partnerships.

Investors may be less willing to rely on ATLS’s historical results in light of the AHD Transactions, in which case we may have difficulty in maintaining or increasing the level of funds ATLS had recently raised through investment partnerships. In this event, we may need to obtain financing for our drilling activities on a less attractive basis than the financing ATLS realized through these investment partnerships or we may determine to reduce drilling activity.

Fee-based revenues may decline if we are unsuccessful in sponsoring new investment partnerships.

Our fee-based revenues will be based on the number of investment partnerships we sponsor and the number of partnerships and wells we manage or operate. If we are unsuccessful in sponsoring future investment partnerships, our fee-based revenues may decline.

Revenues from the investment partnerships may decrease if investors in the investment partnerships do not receive a minimum return.

ATLS had agreed to subordinate up to 50% of its share of production revenues, net of corresponding production costs, to specified returns to the investor partners in its investment partnerships, typically 10% per year for the first five years of distributions, and we are bound by this agreement following the AHD Transactions. Our revenues from a particular investment partnership will therefore decrease if the investment partnership does not achieve the specified minimum return.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel.

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through the investment partnership business that we acquired in the AHD Transactions, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Our competitors may be able to pay more for natural gas and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or better connections in the securities industry segment that markets oil and gas investment partnerships. All of these challenges could make it more difficult for us to execute our growth strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our competitors possess greater financial and other resources than we do, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than us.

 

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We may depend on certain key customers for sales of our natural gas. To the extent these customers reduce the volumes of natural gas they purchase following the AHD Transactions, our revenues could be negatively affected.

In Appalachia, ATLS’s natural gas was sold under contracts with various purchasers. During the year ended December 31, 2010, natural gas sales to Equitable Gas Company, Sequient Energy Management and South Jersey Resources Group accounted for approximately 14%, 14% and 12%, of its total Appalachian oil and gas revenues, respectively. Following the closing of the AHD Transactions and the Chevron Merger, certain purchased entities sell gas produced in four key counties in southwest Pennsylvania to a subsidiary of Chevron pursuant to the gas marketing agreement, which has a term of three years. In Michigan, during the year ended December 31, 2010, gas under contracts to DTE Energy, Conoco Phillips, BP Energy and Total Gas and Power accounted for approximately 30%, 26%, 19% and 14% of its total Michigan oil and gas revenues, respectively. Following the closing of the AHD Transactions and the Chevron Merger, all of the gas produced by the wells in Michigan indirectly owned by us through our ownership of the investment partnership business will be marketed by a subsidiary of Chevron pursuant to the Michigan Operating Agreement. To the extent these and other key customers are less willing to purchase natural gas from us, the Gas Marketing Agreement terminates, or the gas marketing services provided under the Michigan Operating Agreement are no longer provided, our revenues could be harmed in the event we are unable to sell to additional purchasers at similar prices.

Shortages of drilling rigs, equipment and crews, or the costs required to obtain the foregoing in a highly competitive environment, could impair our operations and results.

Higher natural gas and oil prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, ATLS and other natural gas and oil companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which are currently planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues.

Because we handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of wells and other facilities that we acquired in the AHD Transactions are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

 

   

the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

 

   

the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

 

   

Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from facilities acquired in the AHD Transactions; and

 

   

Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties previously owned or operated by ATLS, or at locations to which ATLS has sent waste for disposal, in each case that relate to assets acquired in connection with the AHD Transactions.

 

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Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of the wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under our insurance policies.

Many of the leases that we acquired in the AHD Transactions are in areas that have been partially depleted or drained by offset wells.

Many of the leases that we acquired in the AHD Transactions are in areas in the Appalachian Basin that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Drilling for and producing natural gas are high-risk activities with many uncertainties.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

   

the high cost, shortages or delivery delays of equipment and services;

 

   

unexpected operational events and drilling conditions;

 

   

adverse weather conditions, including the delay of drilling and/or the freeze-off of existing wells;

 

   

facility or equipment malfunctions;

 

   

title problems;

 

   

pipeline ruptures or spills;

 

   

compliance with environmental and other governmental requirements;

 

   

unusual or unexpected geological formations;

 

   

formations with abnormal pressures;

 

   

injury or loss of life;

 

   

unavailability or costs of gathering, processing and/or transportation services;

 

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limitations on or disruptions in gathering or transmission capacity;

 

   

environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or oil leaks, including groundwater contamination;

 

   

fires, blowouts, craterings and explosions; and

 

   

uncontrollable flows of natural gas or well fluids.

Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings, and could reduce revenues in one or more of our investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships. In addition, any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

Although we maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks will not be available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.

Properties that we acquired in the AHD Transactions or that we subsequently acquire may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, reviews of acquired properties are necessarily incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity.

We or one of our subsidiaries may be exposed to financial and other liabilities as the managing general partner in investment partnerships.

We or one of our subsidiaries serves as the managing general partner of the investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we or one of our subsidiaries will be contingently liable for the obligations of the partnerships to the extent that partnership assets or insurance proceeds are insufficient. ATLS agreed to indemnify each investor partner in the investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets, and we or one of our subsidiaries are bound by this agreement after the AHD Transactions.

 

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We are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of doing business.

Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate following the AHD Transactions includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans will be the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in its industry who can spread these additional costs over a greater number of wells and larger operating staff.

Certain provisions of our limited partnership agreement and Delaware law could deter acquisition proposals and make it difficult for a third party to acquire control of us. This could have a negative effect on the price of our common units.

Our limited partnership agreement following the Limited Partnership Agreement Amendment (“the LPA Amendment”) discussed below contains provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include:

 

   

a board of directors that is divided into three classes with staggered terms;

 

   

rules regarding how our common unitholders may present proposals or nominate directors for election;

 

   

rules regarding how our common unitholders may call special meetings; and

 

   

limitations on the right of our common unitholders to remove directors.

These provisions are intended to protect our common unitholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions will apply even if an offer may be considered beneficial by some of our unitholders and could delay or prevent an acquisition that our board of directors determines is in our best interest and that of our unitholders. Any of the foregoing provisions could limit the price that some investors might be willing to pay for our common units.

 

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The LPA Amendment changed the rights of holders of our common units under our limited partnership agreement.

In connection with the consummation of the AHD Transactions, the LPA Amendment was effected, and the rights of our unitholders are now governed by our limited partnership agreement as amended and restated by the LPA Amendment. The changes effected by the LPA Amendment, among other things, (1) permit our unitholders to elect our general partner’s board of directors, (2) classify our general partner’s board of directors into three classes and (3) eliminate our general partner’s right to call all of our common units for redemption if less than 12.5% of the common units are held by persons other than our general partner and its affiliates. These changes will affect our governance, and may affect the market for our common units.

Risks Relating to Our Business

We may not have sufficient cash to pay distributions.

Our ability to fund our operations, pay debt service and to make distributions to our unitholders may fluctuate based on the level of distributions APL makes to its partners and the cash flows generated by the assets acquired in the AHD Transactions.

Our ability to distribute cash to our unitholders will be limited by a number of factors, including:

 

   

interest expense and principal payments on any current or future indebtedness;

 

   

restrictions on distributions contained in any current or future debt agreements;

 

   

our general and administrative expenses, including expenses we incur as a result of being a public company;

 

   

expenses of our subsidiaries other than APL, including tax liabilities of our corporate subsidiaries, if any;

 

   

reserves necessary for us to make the necessary capital contributions to maintain our 2.0% general partner interest in APL as required by its partnership agreement upon the issuance of additional partnership securities by APL; and

 

   

reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distribution we make will be at or above our previous quarterly distribution levels. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.

We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute existing limited partners’ ownership interest in us and may increase the risk that we will not have sufficient available cash to make distributions.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders on terms and conditions established by our general partner at any time. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

our unitholders’ proportionate ownership interest in us will decrease;

 

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the amount of cash available for distribution on each unit may decrease;

 

   

the relative voting strength of each previously outstanding unit may be diminished;

 

   

the ratio of taxable income to distributions may increase; and

 

   

the market price of the common units may decline.

If the market price of our common units declines, our common unitholders could lose a significant part of their investment.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

 

   

changes in securities analysts’ recommendations and their estimates of our financial performance;

 

   

the public’s reaction to our or APL’s press releases, announcements and filings with the SEC;

 

   

fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly-traded limited partnerships and limited liability companies;

 

   

changes in market valuations of similar companies;

 

   

departures of key personnel;

 

   

commencement of or involvement in litigation;

 

   

variations in our quarterly results of operations or those of other natural gas and oil companies;

 

   

variations in the amount of our quarterly cash distributions;

 

   

future issuances and sales of our common units; and

 

   

changes in general conditions in the United States economy, financial markets or the natural gas and oil industry.

In recent years the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Our ability to meet our future financial needs may be adversely affected by our cash distribution policy.

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash quarterly. Given that our cash distribution policy is to distribute available cash and not retain it, we may not have enough cash to meet our needs if any of the following events occur:

 

   

an increase in our operating expenses;

 

   

an increase in general and administrative expenses;

 

   

an increase in principal and interest payments on our outstanding debt; or

 

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an increase in working capital requirements.

Covenants in our new credit facility restrict our business in many ways.

Our new credit facility contains various restrictive covenants that limit our ability to, among other things:

 

   

incur additional debt or liens or provide guarantees in respect of obligations of other persons;

 

   

pay distributions or redeem or repurchase our securities;

 

   

prepay, redeem or repurchase debt;

 

   

make loans, investments and acquisitions;

 

   

enter into hedging arrangements;

 

   

sell assets;

 

   

enter into certain transactions with affiliates; and

 

   

consolidate or merge with or into, or sell substantially all of our assets to, another person.

In addition, our credit facility requires us to maintain specified financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we may be unable to meet those tests. A breach of any of these covenants could result in a default under our credit facility. Upon the occurrence of an event of default under our credit facility, the lenders could elect to declare all amounts outstanding immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our credit facility. If the lenders under our credit facility accelerate the repayment of borrowings, we may not have sufficient assets to repay our credit facility and our other liabilities. Our borrowings under our credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

There is no guarantee that our unitholders will receive quarterly distributions from us.

While our cash distribution policy, which is consistent with the terms of our partnership agreement, requires that we distribute all of our available cash quarterly, our cash distribution policy is subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

   

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our current and future outstanding debt, elimination of future distributions from APL, the effect of the IDR Adjustment Agreement, working capital requirements and anticipated cash needs of us or APL and its subsidiaries;

 

   

Our cash distribution policy is, and APL’s cash distribution policy is, subject to restrictions on distributions under our credit facility and APL’s credit facility, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default;

 

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Our general partner’s board of directors has the authority under our partnership agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy;

 

   

Our partnership agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units;

 

   

Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement; and

 

   

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations on our cash distribution policy and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

Our and APL’s cash distribution policies limit our ability to grow.

Consistent with the terms of our partnership agreements, we and APL distribute to our partners our available cash each quarter. In determining the amount of cash available for distribution, we each set aside cash reserves, including reserves we believe prudent to maintain for the proper conduct of our businesses or to provide for future distributions. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policies will significantly impair our ability to grow. In addition, to the extent either of us issue additional units or incur additional debt in connection with any acquisitions or capital expenditures, the payment of distributions on those additional common units may increase the risk that we will be unable to maintain or increase our prior per common unit distribution level. Moreover, the incurrence of additional debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the cash we have available to distribute to our unitholders.

Our unitholders’ liability as a limited partner may not be limited and they may have to repay distributions or make additional contributions under certain circumstances.

Under Delaware law, our unitholders could be held liable for our obligations if a court determined that the right, or the exercise of the right, by our unitholders as a group to approve some amendments to the limited partnership agreement, or to take other action under our limited partnership agreement, constituted participation in the “control” of our business.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Reduced APL distributions will disproportionately affect the amount of cash distributions to which we are entitled.

We are entitled to receive incentive distributions from APL, through our ownership of Atlas Pipeline GP, with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Furthermore, as described in the immediately following risk factor, in the IDR Adjustment Agreement, Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distributions per quarter back to APL.

 

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Atlas Pipeline GP’s incentive distribution rights entitle it to receive percentages increasing up to 48% of all cash distributed by APL, subject to the IDR Adjustment Agreement. Distribution by APL above $0.60 per common unit per quarter would result in Atlas Pipeline GP’s incremental cash distributions to be the maximum 48%. Atlas Pipeline GP’s percentage of the incremental cash distributions reduces from 48% to 23%, if APL’s distribution is between $0.52 and $0.59, and to 13%, if APL’s distribution is between $0.43 and $0.51, subject in both cases to the effect of the IDR Adjustment Agreement. As a result, lower quarterly cash distributions from APL have the effect of disproportionately reducing the amount of all incentive distributions that Atlas Pipeline GP receives as compared to cash distributions Atlas Pipeline GP receives on its 2.0% general partner interest in APL.

We, as the parent of APL’s general partner, may limit or modify the incentive distributions we are entitled to receive from APL in order to facilitate the growth strategy of APL. Our general partner’s board of directors can give this consent without a vote of our unitholders.

We own APL’s general partner, which owns the incentive distribution rights in APL that entitle us to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per common unit in any quarter. APL’s board of directors may reduce the incentive distribution rights payable to us with our consent, which we may provide without the approval of our unitholders. In July 2007, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after it receives the initial $7.0 million per quarter of incentive distribution rights.

In order to facilitate acquisitions by APL, the general partner of APL may elect to limit the incentive distributions we are entitled to receive with respect to a particular acquisition or unit issuance contemplated by APL. This is because a potential acquisition might not be accretive to APL’s common unitholders as a result of the significant portion of that acquisition’s cash flows which would be paid as incentive distributions to us. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of APL, the cash flows associated with that acquisition could be accretive to APL’s common unitholders as well as substantially beneficial to us. In doing so, the managing board of APL’s general partner would be required to consider both its fiduciary obligations to investors in APL as well as to us. Our partnership agreement specifically permits our general partner to authorize the general partner of APL to limit or modify the incentive distribution rights held by us if our general partner determines that such limitation or modification does not adversely affect our limited partners in any material respect.

APL may issue additional units, which may increase the risk of not having sufficient available cash to make distributions at prior per unit distribution levels.

APL has wide discretion to issue additional limited partner units, including units that rank senior to its common units and the incentive distribution rights as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on additional APL common units may increase the risk of APL being unable to make distributions at its prior per unit distribution levels. To the extent new APL limited partner units are senior to the APL common units and the incentive distribution rights, their issuance will increase the uncertainty of the payment of distributions on the common units and the incentive distribution rights. Neither the common units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

Our ability to sell our general partner interest and incentive distribution rights in APL is limited.

We face contractual limitations on our ability to sell our general partner interest and incentive distribution rights and the market for such interests is illiquid.

 

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APL’s common unitholders have the right to remove APL’s general partner with the approval of the holders of 66 2/3% of all units, which would cause us to lose our general partner interest and incentive distribution rights in APL and the ability to manage APL.

We currently manage APL through Atlas Pipeline GP, APL’s general partner and our wholly-owned subsidiary. APL’s partnership agreement, however, gives common unitholders of APL the right to remove the general partner of APL upon the affirmative vote of holders of 66 2/3% of APL’s outstanding common units. If Atlas Pipeline GP were removed as general partner of APL, it would receive cash or common units in exchange for its 2.0% general partner interest and the incentive distribution rights and would lose its ability to manage APL. While the common units or cash we would receive are intended under the terms of APL’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.

If APL’s general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of APL, its value, and therefore the value of our common units, could decline.

The general partner of APL may make expenditures on behalf of APL for which it will seek reimbursement from APL. In addition, under Delaware partnership law, APL’s general partner, in its capacity, has unlimited liability for the obligations of APL, such as its debts and environmental liabilities, except for those contractual obligations of APL that are expressly made without recourse to the general partner. To the extent Atlas Pipeline GP incurs obligations on behalf of APL, it is entitled to be reimbursed or indemnified by APL. If APL is unable or unwilling to reimburse or indemnify its general partner, Atlas Pipeline GP may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of our common units.

Economic conditions and instability in the financial markets could negatively impact our and APL’s business which, in turn, could impact the cash we have to make distributions to our unitholders.

Our and APL’s operations are affected by the financial markets and related effects in the global financial system. The consequences of an economic recession and the effects of the financial crisis include a lower level of economic activity and increased volatility in energy prices. This may result in a decline in energy consumption and lower market prices for oil and natural gas and has previously resulted in a reduction in drilling activity in our and APL’s service areas and in wells currently connected to APL’s pipeline system being shut in by their operators until prices improved. Any of these events may adversely affect our and APL’s revenues and ability to fund capital expenditures and, in the future, may impact the cash that we have available to fund our operations, pay required debt service on our credit facility and make distributions to our unitholders.

Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our and APL’s ability to raise capital and reduce the amount of cash available to fund operations. We cannot be certain that additional capital will be available to us or APL to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact our and APL’s access to liquidity needed for our businesses and impact flexibility to react to changing economic and business conditions. We and APL may be unable to execute our growth strategies, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact our business.

Economic situations could have an adverse impact on producers, key suppliers or other customers, or on our and APL’s lenders, causing them to fail to meet their obligations to APL. Market conditions could also impact our and APL’s derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and APL’s cash flow and ability to pay distributions could be impacted which in turn affects the amount of distributions that we are able to make to our unitholders. The uncertainty

 

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and volatility surrounding the global financial system may have further impacts on our business and financial condition that we and APL currently cannot predict or anticipate.

Due to the accounting treatment of derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions.

With the objective of enhancing the predictability of future revenues, from time to time we and APL enter into natural gas, natural gas liquids and crude oil derivative contracts. We and APL account for these derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We and APL could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in us recognizing a non-cash loss in our consolidated statements of operations and a consequent non-cash decrease in our Equity between reporting periods. Any such decrease could be substantial. In addition, we or APL may be required to make cash payments upon the termination of any of these derivative contracts.

Risks Relating to APL’s Business

Because our cash flow relies upon distributions from APL, risks to APL’s business are also risks to us. We have set forth below the material risks to APL’s business or results of operations, the occurrence of which could negatively impact APL’s financial performance and decrease the amount of cash it is able to distribute to us, thereby decreasing the amount of cash we have available for funding our operations, paying required debt service on our credit facility or making distributions to our unitholders.

The amount of cash APL generates depends, in part, on factors beyond APL’s control.

The amounts of cash that APL generates may not be sufficient for APL to pay distributions in the future. APL’s ability to make cash distributions depends primarily on APL’s cash flow. Cash distributions do not depend directly on APL’s profitability, which is affected by non-cash items. Therefore, cash distributions may be made during periods when APL records losses and may not be made during periods when APL records profits. The actual amounts of cash APL generates will depend upon numerous factors relating to APL’s business which may be beyond APL’s control, including:

 

   

the demand for natural gas, NGLs, crude oil and condensate;

 

   

the price of natural gas, NGLs, crude oil and condensate (including the volatility of such prices);

 

   

the amount of NGL content in the natural gas APL processes;

 

   

the volume of natural gas APL gathers;

 

   

efficiency of APL’s gathering systems and processing plants;

 

   

expiration of significant contracts;

 

   

continued development of wells for connection to APL’s gathering systems;

 

   

APL’s ability to connect new wells to its gathering systems;

 

   

APL’s ability to integrate newly formed ventures or acquired businesses with its existing operations;

 

   

the availability of local, intrastate and interstate transportation systems;

 

   

the availability of fractionation capacity;

 

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the expenses APL incurs in providing its gathering services;

 

   

the cost of acquisitions and capital improvements;

 

   

APL’s issuance of equity securities;

 

   

required principal and interest payments on APL’s debt;

 

   

fluctuations in working capital;

 

   

prevailing economic conditions;

 

   

fuel conservation measures;

 

   

alternate fuel requirements;

 

   

the strength and financial resources of APL’s competitors;

 

   

the effectiveness of APL’s hedging program and the creditworthiness of APL’s hedging counterparties;

 

   

governmental (including environmental and tax) laws and regulations; and

 

   

technical advances in fuel economy and energy generation devices.

In addition, the actual amount of cash that APL will have available for distribution will depend on other factors, including:

 

   

the level of capital expenditures it makes;

 

   

the sources of cash used to fund its acquisitions;

 

   

limitations on its access to capital or the market for APL’s common units or notes;

 

   

its debt service requirements; and

 

   

the amount of cash reserves established by us, as APL’s general partner, for the conduct of APL’s business.

APL’s financial and operating performance may fluctuate significantly from quarter to quarter. APL may be unable to continue to generate sufficient cash flow to fund its operations, pay required debt service and make distributions to its unitholders. If APL is unable to do so, it may be required to sell assets or equity, reduce capital expenditures, reduce or eliminate distributions to unit holders, refinance all or a portion of its existing indebtedness or obtain additional financing. APL may be unable to do so on acceptable terms, or at all.

APL cannot borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” under its partnership agreement. Because APL cannot borrow money to pay distributions unless it establishes a facility that meets the definition contained in its partnership agreement, APL’s ability to pay a distribution in any quarter solely depends on its ability to generate sufficient operating surplus with respect to that quarter.

 

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APL’s debt level and restrictions in its credit facility could limit its ability to fund operations, pay required debt service on its credit facility and make future distributions to its unitholders.

APL will need a portion of its cash flow to make principal and interest payments on its indebtedness, which will reduce the funds that would otherwise be available for operations, future business opportunities and distributions to its unitholders. If APL’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing its indebtedness, seeking additional equity capital or other alternatives. APL may not be able to affect any of these remedies on satisfactory terms, or at all. Therefore, APL’s ability to make distributions to us and consequently, our ability to fund our operations and pay required debt service could be impacted, which could force us to sell some or all of our interest in APL, seek additional equity capital, incur additional indebtedness or bankruptcy protection.

APL’s credit facility contains covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. APL’s credit facility also contains covenants requiring APL to maintain certain financial ratios.

Due to APL’s lack of asset diversification, negative developments in its operations would reduce its ability to fund its operations, pay required debt service on its credit facilities and make distributions to its common unitholders.

APL relies exclusively on the revenues generated from its gathering and processing operations, and as a result, its financial condition depends upon prices of, and continued demand for, natural gas, NGLs and crude oil. Due to APL’s lack of asset-type diversification, a negative development in one of these businesses would have a significantly greater impact on its financial condition and results of operations than if APL maintained more diverse assets.

APL is exposed to the credit risks of its key customers, and any material nonpayment or nonperformance by its key customers could negatively impact APL’s business.

APL has historically experienced minimal collection issues with its counterparties; however APL’s revenue and receivables are highly concentrated in a few key customers and therefore APL is subject to risks of loss resulting from nonpayment or nonperformance by these key customers. In an attempt to reduce this risk, credit limits have been established for each customer and APL attempts to limit its credit risk by obtaining letters of credit, guarantees or other appropriate forms of security. Nonetheless, APL has key customers whose credit risk cannot realistically be otherwise mitigated.

APL is affected by the volatility of prices for natural gas and NGL products.

APL derives a majority of its gross margin from POP and Keep-Whole contracts. As a result, APL’s income depends to a significant extent upon the prices at which it buys and sells natural gas and at which it sells NGLs and condensate. Average estimated unhedged 2011 market prices for NGLs, natural gas and condensate, based upon NYMEX forward price curves as of January 11, 2011, are $1.14 per gallon, $4.54 per MMBTU and $92.77 per barrel, respectively. A 10% change in these prices would change our forecasted gross margin, excluding the effect of non-controlling interest in APL net income (loss), for the twelve-month period ended December 31, 2011 by approximately $13.5 million. Additionally, changes in natural gas prices may indirectly impact APL’s profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to APL’s pipeline system or that it expects will be connected to its system to shut in their production until prices improve, thereby affecting the volume of gas APL gathers and processes. Historically, the price of natural gas, NGLs and crude oil have been subject to significant volatility in response to relatively minor changes in the supply and demand for these products, market uncertainty and a variety of additional factors beyond APL’s control. Oil prices have traded in a range of $68.01 per barrel to $91.51 per barrel in 2010, while natural gas prices have traded in a range of $3.29 per MMBTU to $6.01 per MMBTU

 

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during the same time period. APL expects this volatility to continue. This volatility may cause APL’s gross margin and cash flows to vary widely from period to period. APL’s risk management strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the throughput volumes. Moreover, derivative instruments are subject to inherent risks, which we describe in “— APL’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.”

APL’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.

APL’s operations expose it to fluctuations in commodity prices. APL utilizes derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of its cash flows due to fluctuations in commodity prices. To the extent APL protects its commodity price using certain derivative contracts it may forego the benefits it would otherwise experience if commodity prices were to change in APL’s favor. APL’s commodity price risk management activity may fail to protect or could harm it because, among other things:

 

   

entering into derivative instruments can be expensive, particularly during periods of volatile prices;

 

   

available derivative instruments may not correspond directly with the risks against which APL seeks protection;

 

   

price relationship between the physical transaction and the derivative transaction could change;

 

   

the anticipated physical transaction could be different than projected due to changes in contracts, lower production volumes or other operational impacts, resulting in possible losses on the derivative instrument which is not offset by income on the anticipated physical transaction; and

 

   

the party owing money in the derivative transaction may default on its obligation to pay.

We cannot predict at this time the outcome of the ongoing efforts by the Commodities Futures Trading Commission (“CFTC”) to implement the Dodd-Frank Act and to increase the regulation of over-the-counter derivatives including those related to energy commodities. The CFTC efforts are seeking, among other things, increased clearing of such derivatives through clearing organizations and the increased standardization of contracts, products, and collateral requirements. Such changes could negatively impact our ability to hedge our portfolio in an efficient, cost-effective manner by, among other things, increasing the cost of entering into derivative contracts and decreasing liquidity in the forward commodity markets.

The amount of natural gas APL gathers will decline over time unless it is able to attract new wells to connect to its 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 APL’s gathering systems could, therefore, result in the amount of natural gas APL gathers declining substantially over time and could, upon exhaustion of the current wells, cause it to abandon one or more of its gathering systems and, possibly, cease operations. The primary factors affecting APL’s ability to connect new supplies of natural gas to its gathering systems include APL’s success in contracting for existing wells that are not committed to other systems, the level of drilling activity near its gathering systems and, in the Mid-Continent region, APL’s ability to attract natural gas producers away from its competitors’ gathering systems.

Over time, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. A decrease in exploration and development activities in the fields served by APL’s gathering and processing facilities could result if there is a sustained decline in natural gas prices which, in turn,

 

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would lead to a reduced utilization of those assets. The decline in the credit markets, the lack of availability of credit, debt or equity financing and the decline in natural gas prices may result in a reduction of producers’ exploratory drilling. APL has no control over the level of drilling activity in its service areas, the amount of reserves underlying wells that connect to its systems and the rate at which production from a well will decline. In addition, APL has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, drilling costs, geological considerations, governmental regulation and the availability and cost of capital. In a low price environment, producers may determine to shut in wells already connected to APL’s systems until prices improve. Because APL’s operating costs are fixed to a significant degree, a reduction in the natural gas volumes it gathers or processes would result in a reduction in its gross margin and cash flows.

The amount of natural gas APL gathers or processes may be reduced if the natural gas liquids pipelines or fractionation facilities to which it delivers NGLs cannot or will not accept the NGLs.

If one or more of the pipelines or fractionation facilities to which APL delivers NGLs has service interruptions, capacity limitations or otherwise does not accept the NGLs APL sells to or transports on, and APL cannot arrange for delivery to other pipelines, the amount of NGLs APL processes, sells or transport may be reduced. Since APL’s revenues depend upon the volumes of NGLs it sells or transports, this could result in a material reduction in its gross margin and cash flows.

The amount of natural gas APL gathers or processes may be reduced if the intrastate and interstate pipelines to which APL delivers gas cannot or will not accept the gas.

APL’s gathering systems principally serve as intermediate transportation facilities between wells connected to APL’s systems and the intrastate or interstate pipelines to which APL delivers natural gas. If one or more of these pipelines has service interruptions, capacity limitations or otherwise does not accept the natural gas APL gathers, and APL cannot arrange for delivery to other pipelines, local distribution companies or end users, the amount of natural gas APL gathers may be reduced. Since APL’s revenues depend upon the volumes of natural gas it gathers, this could result in a material reduction in APL’s gross margin and cash flows.

If APL is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then its cash flows could be reduced.

The construction of additions to APL’s existing gathering assets may require it to obtain new rights-of-way before constructing new pipelines. APL may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for APL to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then its cash flows could be reduced.

The success of APL’s Mid-Continent operations depends upon its ability to continually find and contract for new sources of natural gas supply.

APL’s agreements with most of the producers with which its Mid-Continent operations do business generally do not require them to dedicate significant amounts of undeveloped acreage to APL’s systems. While APL does have some undeveloped acreage dedicated on its systems, most notably with its partner Pioneer on its Midkiff/Benedum system, APL does not have assured sources to provide it with new wells to connect to its Mid-Continent gathering systems. Failure to connect new wells to APL’s Mid-Continent operations will, as described in “—The amount of natural gas APL gathers will decline over time unless it is able to attract new wells to connect to its gathering systems,” above, will reduce APL’s gross margin and cash flows.

 

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APL’s Mid-Continent operations currently depend on certain key producers for their supply of natural gas; the loss of any of these key producers could reduce its revenues.

During 2010, Apache, Inc., Bluestem Gas Marketing, Chesapeake Energy Corporation, COG Operating LLC, Endeavor Energy Resources LP, Pioneer, Prime Operating Company, Range Resources, Sandridge Exploration and Production, LLC and XTO Energy Inc. accounted for a significant amount of APL’s Mid-Continent operations natural gas supply. If these producers reduce the volumes of natural gas that they supply to APL, APL’s gross margin and cash flows would be reduced unless it obtains comparable supplies of natural gas from other producers.

The curtailment of operations at, or closure of, any of APL’s processing plants could harm its business.

If operations at any of APL’s processing plants were to be curtailed, or closed, whether due to accident, natural catastrophe, environmental regulation or for any other reason, APL’s ability to process natural gas from the relevant gathering system and, as a result, its ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, APL’s gross margin and cash flows would be materially reduced.

APL may face increased competition in the future in its Mid-Continent operations.

APL’s Mid-Continent operations face competition for well connections. Carrera Gas Company, Copano Energy, LLC, DCP Midstream, LLC, Enogex, LLC and ONEOK, Inc., operate competing gathering systems and processing plants in APL’s Velma service area. DCP Midstream, Hiland Partners, Mustang Fuel Corporation, ONEOK Partners and SemGas, L P operate competing gathering systems and processing plants APL’s Chaney Dell service area. DCP Midstream, Southern Union Company, Targa Resources and West Texas Gas operate competing gathering systems and processing plants in APL’s Midkiff/Benedum service area. Some of APL’s competitors have greater financial and other resources than APL does. If these companies become more active in APL’s Mid-Continent service areas, it may not be able to compete successfully with them in securing new well connections or retaining current well connections. If APL does not compete successfully, the amount of natural gas APL gathers, processes and treats will decrease, reducing its gross margin and cash flows.

The scope and costs of the risks involved in making acquisitions may prove greater than estimated at the time of the acquisition.

Any acquisition involves potential risks, including, among other things:

 

   

the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

 

   

mistaken assumptions about revenues and costs, including synergies;

 

   

significant increases in APL’s indebtedness and working capital requirements;

 

   

delays in obtaining any required regulatory approvals or third party consents;

 

   

the imposition of conditions on any acquisition by a regulatory authority;

 

   

an inability to integrate successfully or timely the businesses we acquire;

 

   

the assumption of unknown liabilities;

 

   

limitations on rights to indemnity from the seller;

 

   

the diversion of management’s attention from other business concerns;

 

   

increased demands on existing personnel;

 

   

customer or key employee losses at the acquired businesses; and

 

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the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, APL’s future acquisition costs may be higher than those it has achieved historically. Any of these factors could adversely impact APL’s future growth and its ability to make or increase distributions.

APL may be unsuccessful in integrating the operations from any future acquisitions with its operations and in realizing all of the anticipated benefits of these acquisitions.

APL has an active, on-going program to identify potential acquisitions. APL’s integration of previously independent operations with its own can be a complex, costly and time-consuming process. The difficulties of combining these systems with its existing systems include, among other things:

 

   

operating a significantly larger combined entity;

 

   

the necessity of coordinating geographically disparate organizations, systems and facilities;

 

   

integrating personnel with diverse business backgrounds and organizational cultures;

 

   

consolidating operational and administrative functions;

 

   

integrating pipeline safety-related records and procedures;

 

   

integrating internal controls, compliance under Sarbanes-Oxley Act of 2002 and other corporate governance matters;

 

   

the diversion of management’s attention from other business concerns;

 

   

customer or key employee loss from the acquired businesses;

 

   

a significant increase in our indebtedness; and

 

   

potential environmental or regulatory liabilities and title problems.

APL’s investment and the additional overhead costs it incurs to grow its NGL business may not deliver the expected incremental volume or cash flow. Costs incurred and liabilities assumed in connection with the acquisition and increased capital expenditures and overhead costs incurred to expand its operations could harm its business or future prospects, and result in significant decreases in its gross margin and cash flows.

APL’s construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could impair its results of operations and financial condition.

One of the ways APL may grow its business is through the construction of new assets. The construction of additions or modifications to its existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond APL’s control and require the expenditure of significant amounts of capital. Any projects APL undertakes may not be completed on schedule at the budgeted cost, or at all. Moreover, APL’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if APL expands a gathering system, the construction may occur over an extended period of time, and it will not receive any material increases in revenues until the project is completed. Moreover, APL may construct facilities to capture anticipated future growth in production in a region in which growth does not materialize. Since APL is not engaged in the exploration for, and development of, natural gas reserves, it often does not have access to estimates of potential reserves in an area before

 

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constructing facilities in the area. To the extent APL relies on estimates of future production in its decision to construct additions to its systems, the estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve APL’s expected investment return, which could impair its results of operations and financial condition. In addition, APL’s actual revenues from a project could materially differ from expectations as a result of the price of natural gas, the NGL content of the natural gas processed and other economic factors described in this section.

APL continues to expand the natural gas gathering systems surrounding its facilities in order to maximize plant throughput. In addition to the risks discussed above, expected incremental revenue from recent projects could be reduced or delayed due to the following reasons:

 

   

difficulties in obtaining capital for additional construction and operating costs;

 

   

difficulties in obtaining permits or other regulatory or third-party consents;

 

   

additional construction and operating costs exceeding budget estimates;

 

   

revenue being less than expected due to lower commodity prices or lower demand;

 

   

difficulties in obtaining consistent supplies of natural gas; and

 

   

terms in operating agreements that are not favorable to APL.

APL may not be able to execute its growth strategy successfully.

APL’s strategy contemplates substantial growth through both the acquisition of other gathering systems and processing assets and the expansion of its existing gathering systems and processing assets. APL’s growth strategy involves numerous risks, including:

 

   

APL may not be able to identify suitable acquisition candidates;

 

   

APL may not be able to make acquisitions on economically acceptable terms for various reasons, including limitations on access to capital and increased competition for a limited pool of suitable assets;

 

   

APL’s costs in seeking to make acquisitions may be material, even if it cannot complete any acquisition it has pursued;

 

   

irrespective of estimates at the time it makes an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;

 

   

APL may encounter delays in receiving regulatory approvals or may receive approvals that are subject to material conditions;

 

   

APL may encounter difficulties in integrating operations and systems; and

 

   

any additional debt APL incurs to finance an acquisition may impair its ability to service its existing debt.

 

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Limitations on APL’s access to capital or the market for its common units will impair APL’s ability to execute its growth strategy.

APL’s ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, APL has financed its acquisitions, and to a much lesser extent, expansions of its gathering systems by bank credit facilities and the proceeds of public and private debt and equity offerings of its common units and preferred units of its operating partnership. If APL is unable to access the capital markets, it may be unable to execute its strategy of growth through acquisitions.

Regulation of APL’s gathering operations could increase its operating costs, decrease its revenues, or both.

Currently APL believes its gathering and processing of natural gas is exempt from FERC regulation under the Natural Gas Act of 1938. However, the implementation of new laws or policies, or changed interpretations of existing laws, could subject APL’s gathering and processing operations to regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. APL expects that any such regulation could increase its costs, decrease its gross margin and cash flows, or both.

Even if APL’s gathering and processing operations are not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect APL’s business and the market for its products. FERC’s policies and practices affect a range of natural gas pipeline activities. Among these are FERC policies on interstate natural gas pipeline open access transportation, ratemaking, capacity release, environmental protection and market center promotion, which indirectly affect intrastate markets. FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. We cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

Since federal law generally leaves any economic regulation of natural gas gathering to the states, state and local regulations may also affect APL’s business. Matters subject to regulation include conditions of access, rates, terms of service and safety. For example, APL’s gathering lines are subject to ratable take, common purchaser and similar statutes in one or more jurisdictions in which APL operates. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without discrimination, natural gas production that may be tendered to the gatherer for handling. Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Texas Railroad Commission, Oklahoma Corporation Commission or Kansas Corporation Commission become more active, APL’s revenues could decrease. Collectively, all of these statutes restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or gathers natural gas.

Compliance with pipeline integrity regulations issued by the DOT and state agencies could result in substantial expenditures for testing, repairs and replacement.

DOT and state agency regulations require pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas.” The regulations require operators to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

   

improve data collection, integration and analysis;

 

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repair and remediate the pipeline as necessary; and

 

   

implement preventative and mitigating actions.

The cost of implementing integrity management program testing along certain segments of APL’s pipeline should not have a material effect on its results of operations. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be necessary as a result of the testing program. Such costs could be substantial.

APL’s midstream natural gas operations may incur significant costs and liabilities resulting from a failure to comply with new or existing environmental regulations or a release of hazardous substances into the environment.

The operations of APL’s gathering systems, plant and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations may restrict or impact APL’s business activities in many ways, including restricting the manner in which it disposes of substances, requiring remedial action to remove or mitigate contamination, or requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil or criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage allegedly caused by the release of pollutants or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in APL’s business due to its handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment, and waste disposal practices. For example, an accidental release from one of APL’s pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, it is possible that more stringent laws, regulations or enforcement policies could significantly increase APL’s compliance costs, and the cost of any necessary remediation. APL may not be able to recover some or any of these costs from insurance.

APL’s midstream natural gas operations may incur significant costs and liabilities resulting from new environmental regulations related to climate change.

Federal and state governments are considering and/or implementing measures to reduce emissions of greenhouse gases, primarily through the planned development of a greenhouse gas cap and trade program. As an alternative to the cap and trade program, the EPA may implement greenhouse gas reduction through traditional construction and operating permit programs. APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of fuels APL processes. In addition, APL’s operations could face additional taxes and higher costs of doing business. Although APL would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could result in a significant effect on our cost of doing business.

Litigation or governmental regulation relating to environmental protection and operational safety may result in substantial costs and liabilities.

APL’s operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and penalties in connection with any pollution caused by their

 

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pipelines. APL may also be held liable for clean-up costs resulting from pollution which occurred before its acquisition of a gathering system. In addition, APL is subject to federal and state safety laws that dictate the type of pipeline, quality of pipe protection, depth of pipelines, methods of welding and other construction-related standards. Any violation of environmental, construction or safety laws could impose substantial liabilities and costs on APL.

APL is also subject to the requirements of OSHA and comparable state statutes. Any violation of OSHA could impose substantial costs on APL.

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

APL is subject to operating and litigation risks that may not be covered by insurance.

APL’s operations are subject to all operating hazards and risks incidental to gathering and processing natural gas and NGLs. These hazards include:

 

   

damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;

 

   

inadvertent damage from construction and farm equipment;

 

   

leakage of natural gas, NGLs and other hydrocarbons;

 

   

fires and explosions;

 

   

other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations; and

 

   

acts of terrorism directed at APL’s pipeline infrastructure, production facilities and surrounding properties.

As a result, APL may be a defendant in various legal proceedings and litigation arising from its operations. APL may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for some of APL’s insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If APL were to incur a significant liability for which it was not fully insured, its gross margin and cash flows would be materially reduced.

APL’s control of the Chaney Dell and Midkiff/Benedum systems is limited by provisions of the limited liability company operating agreements with Anadarko and, with respect to the Midkiff/Benedum system, the operation and expansion agreement with Pioneer.

The managing member of each of the limited liability companies which owns the interests in the Chaney Dell and Midkiff/Benedum systems is APL’s subsidiary. However, the consent of Anadarko is required for specified extraordinary transactions, such as admission of new members, engaging in transactions with APL’s affiliates not approved by the company conflicts committee, incurring debt outside the ordinary course of business and disposing of company assets above specified thresholds. The Midkiff/Benedum system is also governed by an operation and expansion agreement with Pioneer which gives system owners having at least a 60% interest in the system the right to approve the annual operating budget and capital investment budget and to

 

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impose other limitations on the operation of the system. Thus, a holder of a greater than 40% interest in the system would effectively have a veto right over the operation of the system. Pioneer currently owns an approximate 27% interest in the system.

Risks Related to Our Conflicts of Interest

Although we control APL through our ownership of its general partner, APL’s general partner owes fiduciary duties to APL and APL’s unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including APL’s general partner, on the one hand, and APL and its limited partners, on the other hand. The directors and officers of Atlas Pipeline GP have fiduciary duties to manage APL in a manner beneficial to us, its owner. At the same time, these directors and officers have a fiduciary duty to manage APL in a manner beneficial to APL and its limited partners. The managing board of APL or its conflicts committee will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

For example, conflicts of interest may arise in the following situations:

 

   

the allocation of shared overhead expenses to APL and us;

 

   

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and APL, on the other hand;

 

   

the determination and timing of the amount of cash to be distributed to APL’s partners and the amount of cash reserved for the future conduct of APL’s business;

 

   

the decision as to whether APL should make acquisitions, and on what terms; and

 

   

any decision we make in the future to engage in business activities independent of, or in competition with, APL.

The fiduciary duties of our general partner’s officers and directors may conflict with those of APL’s general partner’s officers and directors.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, certain of our general partner’s executive officers and non-independent directors also serve as executive officers and directors of APL’s general partner, and, as a result, have fiduciary duties to manage the business of APL in a manner beneficial to APL and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to APL, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts of interest may not always be in our best interest or that of our unitholders.

If we are presented with certain business opportunities, APL will have the first right to pursue such opportunities.

Pursuant to the omnibus agreement between us and APL, we have agreed to certain business opportunity arrangements to address potential conflicts that may arise between us and APL. If a business opportunity in respect of any business activity in which APL is currently engaged is presented to us or APL, then APL will have the first right to pursue such business opportunity.

 

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APL and affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our partnership agreement nor the omnibus agreement between us and APL prohibits APL or affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us or one another. In addition, APL and its affiliates may acquire, construct or dispose of additional assets related to the gathering and processing of natural gas, NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition among these entities could adversely impact APL’s or our results of operations and cash available for paying required debt service on our credit facility or making distributions.

Tax Risks of Unit Ownership

If in the future we cease to manage and control APL through our ownership of its general partner interests, we may be deemed to be an investment company.

If we cease to manage and control APL and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

APL or we may no longer be qualified as a partnership or the current law may change causing APL or us to be treated as a corporation for tax purposes.

The value of our investment in APL depends largely on it being treated as a partnership for federal income tax purposes, which requires that 90% or more of APL’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as 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). APL may not meet this requirement or current law may change so as to cause, in either event, APL to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. Moreover, the anticipated after-tax benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If APL were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to us would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to our unit holders would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unit holders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unit holders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

 

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Current law may change, causing us or APL to be treated as a corporation for federal and/or state income tax purposes or otherwise subjecting us or APL to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or APL as an entity, the cash available for distribution to our unit holders would be reduced.

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Unitholders may be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability, which results from the taxation of their share of our taxable income.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in APL.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in APL. Other holders of common units in APL will receive remedial allocations of deductions from APL. Although we will receive remedial allocations of deductions from APL, remedial allocations of deductions to us will be very limited. In addition, our ownership of APL incentive distribution rights will cause more taxable income to be allocated to us from APL than will be allocated to holders who hold only common units in APL. If APL is successful in increasing its distributions over time, our income allocations from our APL incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in APL, our unitholders allocable taxable income will be significantly greater than that of a holder of common units in APL who receives cash distributions from APL equal to the cash distributions our unitholders would receive from us.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a unitholder sells their common units, they will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions and the allocation of losses, including depreciation deductions, to the unitholder in excess of the total net taxable income allocated to them, which decreased the tax basis in their common units, will, in effect, become taxable income to them if the common units are sold at a price greater than their tax basis in those common units, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

 

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We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

The sale or exchange of 50% or more of our or APL’s capital and profits interest within a 12-month period will result in the termination of our or APL’s partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in our capital and profits within a 12-month period. Likewise, APL will be considered to have terminated its partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in APL’s capital and profits within a 12-month period. The termination would, among other things, result in the closing of our or APL’s taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholder with respect to that period.

Unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or APL do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We and APL presently anticipate that substantially all of our income will be generated in Oklahoma, Pennsylvania and Texas. Each of those states, except Texas, currently imposes a personal income tax. We or APL may do business or own property in other states in the future. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

The IRS may challenge our tax treatment related to transfers of units, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

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If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our unitholders.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our positions. A court may not agree with some or all of our positions. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, we will bear the costs of any contest with the IRS thereby reducing the cash available for distribution to our unitholders.

APL has adopted certain valuation methodologies that may result in a shift of income, gain, loss or deduction between us and the public unitholders of APL. The IRS may challenge this treatment, which could adversely affect the value of APL’s common units and our common units.

When we or APL issue additional units or engage in certain other transactions, APL determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of APL’s unitholders and us. Although APL may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, APL makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. APL’s methodology may be viewed as understating the value of APL’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain APL unitholders and us, which may be unfavorable to such APL unitholders. Moreover, under APL’s current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to APL’s tangible assets and a lesser portion allocated to APL’s intangible assets. The IRS may challenge APL’s valuation methods, or our or APL’s allocation of Section 743(b) adjustment attributable to APL’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of APL’s unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders or APL’s unitholders. It also could affect the amount of gain on the sale of common units by our unitholders or APL’s unitholders and could have a negative impact on the value of our common units or those of APL or result in audit adjustments to the tax returns of our or APL’s unitholders without the benefit of additional deductions.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

ITEM 2. PROPERTIES

A description of our properties is contained within Item 1, “Business.”

 

ITEM 3. LEGAL PROCEEDINGS

Following the November 9, 2010 announcement (the “Announcement”) that ATLS had entered into a definitive agreement to be acquired by Chevron Corporation (the “Merger”) and that we and APL agreed to enter into separate transactions with ATLS relating to certain ATLS natural gas reserves and other assets and fee revenues, and APL’s interest in Laurel Mountain (the “Transactions”), with each of the Transactions and the Merger to be cross-conditioned on the completion of the others, a purported class action was filed on November 15, 2010, in Delaware Chancery Court on behalf of a class of ATLS shareholders, Katsman v. ATLS, et al., C.A. No. 5990-VCL. The complaint named us and APL and alleges that the ATLS directors violated their fiduciary duties in connection with the proposed Merger and that we, APL, and Chevron aided and abetted the alleged breaches of fiduciary duty, and requested, among other relief, injunctive relief and damages. This lawsuit was consolidated in Delaware Chancery with other class actions that have been filed against ATLS and its directors, among others. On December 28, 2010, the plaintiffs filed an amended complaint in which all claims against us and APL were dropped.

Additionally, following the Announcement, a purported shareholder derivative case was filed on November 16, 2010, in the Western District of Pennsylvania federal court, Ussach v. ATLS, et al., C.A. No. 2:10-cv-1533. The complaint is asserted derivatively on behalf of APL and names ATLS, Atlas Pipeline GP, and members of the Managing Board of Atlas Pipeline GP as defendants (“Defendants”) and alleges that Defendants have violated their fiduciary duties in connection with the proposed sale to ATLS of APL’s interest in Laurel Mountain and that ATLS has been unjustly enriched. In the complaint, among other relief, the plaintiff requests damages and equitable and injunctive relief, as well as restitution and disgorgement from the individual defendants. On February 22, 2011, the plaintiff voluntarily dismissed its complaint without prejudice. We have not received an indication whether the plaintiff intends to reassert its claim in another forum. In any event, the defendants believe the claims are without merit.

 

ITEM 4: [REMOVED AND RESERVED]

 

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PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed on the New York Stock Exchange under the symbol “AHD.” At the close of business on February 22, 2011, the closing price for the common units was $14.90 and there were 215 record holders, one of which is the holder for all beneficial owners who hold in street name.

The following table sets forth the range of high and low sales prices of our common units and distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2010 and 2009:

 

     High      Low      Distributions Declared  

2010

        

Fourth Quarter

   $ 15.44       $ 8.86       $ 0.07   

Third Quarter

     9.88         3.76         0.05   

Second Quarter

     6.80         3.67         0.00   

First Quarter

     7.45         5.14         0.00   

2009

        

Fourth Quarter

   $ 7.00       $ 3.11       $ 0.00   

Third Quarter

     4.78         2.88         0.00   

Second Quarter

     5.56         1.46         0.00   

First Quarter

     7.03         0.77         0.00   

Our Cash Distribution Policy

The board of directors of our general partner has adopted a cash distribution policy, pursuant to our partnership agreement, which requires that we distribute all of our available cash quarterly to our limited partners within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to, among other things:

 

   

provide for the proper conduct of our business;

 

   

comply with applicable law, any of our debt instruments or other agreements; or

 

   

provide funds for distributions to our unitholders for any one or more of 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. We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Our distributions to limited partners are not cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

For information concerning units authorized for issuance under our long-term incentive plan, see “Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

 

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APL’s Cash Distribution Policy

APL’s partnership agreement requires that it distribute 100% of available cash to its common unitholders and general partner, our wholly-owned subsidiary, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of APL’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

APL’s general partner is granted discretion by APL’s 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 APL’s general partner determines its 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 APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets, as follows:

 

APL
Minimum  Distributions
Per Unit Per Quarter
     Percent of APL Available Cash in
Excess of Minimum Allocated

to APL’s General Partner(1)
 
$ 0.42         15
$ 0.52         25
$ 0.60         50

 

(1) Percent allocated to APL’s General Partner includes 2% general partner interest in addition to incentive distributions.

APL makes distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. In July 2007, Atlas Pipeline GP, as general partner and the holder of all of APL’s incentive distribution rights, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement. APL declared no general partner’s incentive distributions for the years ended December 31, 2010 and 2009.

For information concerning units authorized for issuance under APL’s long-term incentive plan, see “Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

 

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ITEM 6. SELECTED FINANCIAL DATA

On July 26, 2006, ATLS contributed its ownership interests in Atlas Pipeline GP, its then wholly-owned subsidiary and APL’s general partner, to us. Concurrent with this transaction, we issued 3,600,000 common units, representing a then 17.1% ownership interest in us, in an initial public offering at a price of $23.00 per unit, with substantially all of the net proceeds from this offering distributed to ATLS. As of December 31, 2010, we had no separate operating activities apart from those conducted by APL, and our cash flows consisted of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own.

Prior to our initial public offering, the consolidated financial statements include only the results of Atlas Pipeline GP, which are presented on a consolidated basis including the financial statements of APL and are adjusted for the non-controlling limited partners’ interest in APL. Subsequent to our initial public offering, the consolidated financial statements contain our consolidated financial results including the accounts of Atlas Pipeline GP and APL. The non-controlling limited partner interest in APL is reflected as an expense or income in our consolidated results of operations and as a liability on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).

The following table should be read together with our consolidated financial statements and notes thereto included within “Item 8: Financial Statements and Supplementary Data” and “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report. We have derived the selected financial data set forth in the table for each of the years ended December 31, 2010, 2009 and 2008 and at December 31, 2010 and 2009 from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the years ended December 31, 2007 and 2006 from our consolidated financial statements, which were audited by Grant Thornton LLP and are not included within this report.

The selected financial data set forth in the table include our historical consolidated financial statements, which have been adjusted to reflect the following:

 

   

On September 16, 2010, APL completed the sale of its Elk City and Sweetwater, Oklahoma natural gas gathering systems (collectively “APL’s Elk City”). We have retrospectively adjusted our prior period consolidated financial statements to reflect the amounts related to the operations of APL’s Elk City as discontinued operations.

 

   

We reclassified a portion of our historical income, within our consolidated statements of operations, to “Transportation, Processing and Other Fees” for fee-based revenues which were previously reported within “Natural Gas and Liquids” and “Other income (loss), net.” This reclassification was made in order to provide clarity between commodity-based and fee-based revenue.

 

   

We reclassified “Equity income in joint venture” and “Gain (loss) on asset sales and other” to line items separate from total revenue and other income (loss) net. Additionally, we reclassified unrecognized economic impact of APL’s Chaney Dell and Midkiff/Benedum acquisition, long-lived asset impairment loss and goodwill impairment loss, net of associated non-controlling interest from reconciliation of EBITDA to reconciliation to adjusted EBITDA.

 

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     Years Ended December 31,  
     2010     2009(1)     2008(1)     2007(1)(2)     2006(1)  
     (in thousands, except per unit data)  

Statements of operations data:

          

Revenue:

          

Natural gas and liquids

   $ 890,048      $ 636,231      $ 1,078,714      $ 527,094      $ 174,221   

Transportation, compression and other fees

     41,093        59,075        87,442        50,695        31,263   

Other income (loss), net

     4,422        (23,061     36,602        (99,253     6,490   
                                        

Total revenue and other income (loss), net

     935,563        672,245       1,202,758        478,536        211,974   
                                        

Costs and expenses:

          

Natural gas and liquids

     720,215        527,730        900,460        407,994        147,583   

Plant operating

     48,670        45,566        47,371        22,974        6,484   

Transportation and compression

     1,061        6,657        11,249        6,235        4,946   

General and administrative(3)

     36,394        38,931        633        63,175        20,032   

Depreciation and amortization

     74,897        75,684        71,764        34,453        9,495   

Goodwill and other asset impairment loss

     —          10,325        615,724        —          —     

Gain on early extinguishment of debt

     —          —          (19,867     —          —     

Acquisition costs

     1,167        —          —          —          —     

Interest

     94,807        106,531        91,731        65,092        25,675   
                                        

Total costs and expenses

     977,211        811,424        1,719,065        599,923        214,215   
                                        

Equity income in joint venture

     4,920        4,043        —          —          —     

Gain (loss) on asset sales and other

     (10,729     108,947        —          —          —     
                                        

Income (loss) from continuing operations

     (47,457     (26,189     (516,307     (121,387     (2,241

Income (loss) from discontinued operations

     321,155        84,148        (93,802     (23,641     35,334   
                                        

Net income (loss)

     273,698        57,959        (610,109     (145,028     33,093   

(Income) loss attributable to non-controlling interests(4)

     (4,738     (3,176     22,781        (3,940     (118

(Income) loss attributable to non-controlling interest in Atlas Pipeline Partners, L.P.(5)

     (241,026     (50,748     513,675        133,321        (16,335
                                        

Net income (loss) attributable to common limited partners/owners

   $ 27,934      $ 4,035      $ (73,653   $ (15,647   $ 16,640   
                                        

Allocation of net income (loss) attributable to common limited partners/owners:

          

Portion applicable to owners’ interest (period prior to the initial public offering on July 26, 2006)

   $ —        $ —        $ —        $ —        $ 10,236   

Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)

     27,934        4,035        (73,653     (15,647 )     6,404   
                                        

Net income (loss) attributable to common limited partners/owners

   $ 27,934      $ 4,035      $ (73,653   $ (15,647 )   $ 16,640   
                                        

Allocation of net income (loss) attributable to common limited partners/owners:

          

Continuing operations

   $ (11,994   $ (7,768   $ (61,165   $ (12,940   $ (202

Discontinued operations

     39,928        11,803        (12,488     (2,707     6,606   
                                        
   $ 27,934      $ 4,035      $ (73,653   $ (15,647   $ 6,404   
                                        

Net income (loss) attributable to common limited partners per unit:

          

Basic

          

Continuing operations

   $ (0.43   $ (0.28   $ (2.23   $ (0.55   $ (0.01

Discontinued operations

     1.44        0.43        (0.45     (0.11     0.31   
                                        
   $ 1.01      $ 0.15      $ (2.68   $ (0.66   $ 0.30   
                                        

Diluted

          

Continuing operations

   $ (0.43   $ (0.28   $ (2.23   $ (0.55   $ (0.01

Discontinued operations

     1.44        0.43        (0.45     (0.11     0.31   
                                        
   $ 1.01      $ 0.15      $ (2.68   $ (0.66   $ 0.30   
                                        

 

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       Years Ended December 31,  
       2010     2009(1)     2008(1)     2007(1)(2)     2006(1)  
       (in thousands, except operating data)  

Balance sheet data (at period end):

             

Property, plant and equipment, net

  

   $ 1,341,002      $ 1,327,704      $ 1,415,517      $ 1,258,602      $ 204,362   

Total assets

  

     1,767,118        2,138,118        2,418,984        2,875,351        787,134   

Total debt, including current portion

  

     601,389        1,286,438        1,539,427        1,254,426        324,083   

Total Equity/owners’ equity

  

     1,005,329        690,679       609,852        1,246,525        379,121   

Cash flow data:

             

Net cash provided by (used in):

             

Operating activities

  

   $ 106,574      $ 53,507      $ (54,837   $ 104,586      $ 61,087   

Investing activities

  

     594,753        241,030        (292,970     (2,024,676     (104,499

Financing activities

  

     (702,183     (300,719     342,602        1,930,696        27,264   

Other financial data (unaudited):

             

Gross margin from continuing operations(6)

  

   $ 210,580      $ 163,677      $ 273,493      $ 167,525      $ 59,811   

EBITDA (7)

  

     451,577        257,000        (410,499     (35,357     81,785   

Adjusted EBITDA (7)

  

     207,504        173,900        321,631        182,600        87,039   

Maintenance capital expenditures

  

   $ 10,921      $ 3,750      $ 4,787      $ 6,383      $ 1,886   

Expansion capital expenditures

  

     35,715        106,524        176,869        40,268        24,498   
                                           

Total capital expenditures

  

   $ 46,636      $ 110,274      $ 181,656      $ 46,651      $ 26,384   
                                           

Operating data (unaudited):

          

Appalachia:

          

Laurel Mountain system:

          

Average throughput volume – (MCFD)

     109,480        96,975        85,348        68,715        61,892   

Tennessee system

          

Average throughput volume – (MCFD)

     8,740        7,907        1,951        —          —     

Mid-Continent:

          

Velma system:

          

Gathered gas volume (MCFD)

     84,455        76,378        63,196        62,497        60,682   

Processed gas volume (MCFD)

     78,606        73,940        60,147        60,549        58,132   

Residue Gas volume (MCFD)

     64,138        58,350        47,497        47,234        45,466   

NGL volume (BPD)

     9,218        8,232        6,689        6,451        6,423   

Condensate volume (BPD)

     416        377        280        225        193   

Chaney Dell system(8):

          

Gathered gas volume (MCFD)

     228,684        270,703        276,715        259,270        —     

Processed gas volume (MCFD)

     214,695        215,374        245,592        253,523        —     

Residue Gas volume (MCFD)

     193,200        228,261        239,498        221,066        —     

NGL volume (BPD)

     12,395        13,418        13,263        12,900        —     

Condensate volume (BPD)

     697        824        791        572        —     

Midkiff/Benedum system(8):

          

Gathered gas volume (MCFD)

     178,111        159,568        144,081        147,240        —     

Processed gas volume (MCFD)

     163,475        149,656        135,496        141,568        —     

Residue Gas volume (MCFD)

     105,982        101,788        92,019        94,281        —     

NGL volume (BPD)

     26,678        21,261        19,538        20,618        —     

Condensate volume (BPD)

     1,289        1,265        1,142        1,346        —     

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.
(2) Includes APL’s acquisition of control of a 100% interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided joint interest in the Midkiff/Benedum natural gas gathering system and processing plants on July 27, 2007, representing approximately five months’ operations for the year ended December 31, 2007. Operating data for the Chaney Dell and Midkiff/Benedum systems represent 100% of its operating activity.
(3) Includes non-cash compensation (income) expense of $4.9 million, $1.3 million, ($31.3) million, $39.0 million, and $6.8 million for the years ended December 31, 2010, 2009, 2008, 2007, and 2006, respectively.
(4) For the years ended December 31, 2010, 2009, 2008 and 2007, this represents Anadarko’s non-controlling interest in the operating results of the Chaney Dell and Midkiff/Benedum systems, which APL acquired on July 27, 2007.
(5) Represents the non-controlling interests in the net income (loss) of APL associated with the third-party unitholders of APL.

 

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(6) We define gross margin from continuing operations as natural gas and liquids revenue and transportation, compression and other fees less purchased product costs. Product costs include the cost of natural gas and NGLs that APL purchases from third parties, subject to certain non-cash adjustments. Gross margin, as we define it, does not include plant operating expenses; transportation and compression expenses; and hedge gain/(losses) related to ineffective or undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories. Plant operating and transportation and compression expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, real estate taxes and other overhead costs. Our management views gross margin as an important performance measure of core profitability for our operations and as a key component of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses. The following table reconciles our revenues and costs to gross margin from continuing operations (in thousands):

RECONCILIATION OF GROSS MARGIN FROM CONTINUING OPERATIONS

 

     Years Ended December 31,  
     2010     2009(1)     2008(1)     2007(1) (2)     2006(1)  
     (in thousands)  

Revenue:

          

Natural gas and liquids

   $ 890,048      $ 636,231      $ 1,078,714      $ 527,094      $ 174,221   

Transportation, compression and other fees

     41,093        59,075        87,442        50,695        31,263   
                                        

Total revenue for gross margin

     931,141        695,306        1,166,156        577,789        205,484   

Natural gas and liquids costs:

     (720,215     (527,730     (900,460     (407,994     (147,583

Adjustments:

          

Effect of prior period items(9)

     —          —          —          —          1,090   

Non-cash linefill loss (gain) (10)

     (346     (3,899     7,797        (2,270     820   
                                        

Gross margin

   $ 210,580      $ 163,677      $ 273,493      $ 167,525      $ 59,811   
                                        

 

(7) EBITDA represents net income (loss) before net interest expense, income taxes, and depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, impairment charges and other cash items such as the non-recurring cash derivative early termination expense (see “Item 8: Financial Statements and Supplementary Data –Note 11). EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing EBITDA and Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation below is similar to the Consolidated EBITDA (see “Item 8: Financial Statements and Supplementary Data –Note 13) calculation that is utilized within financial covenants under APL’s credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of APL’s Elk City; (ii) the unrecognized economic impact of APL’s Chaney Dell and Midkiff/Benedum acquisition, and (iii) other non-cash items specifically excluded under APL’s credit facility.

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as their cost of capital and its tax structure, as well as historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles or as indicators of our operating performance or liquidity. The following table reconciles net income (loss) to EBITDA and EBITDA to Adjusted EBITDA (in thousands):

 

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RECONCILIATION OF EBITDA AND ADJUSTED EBITDA

 

     Years Ended December 31,  
     2010     2009(1)     2008(1)     2007(1) (2)     2006(1)  
     (in thousands)  

Net income (loss)

   $ 273,698      $ 57,959      $ (610,109   $ (145,028   $ 33,093   

Adjustments:

          

Effect of prior period items(9)

     —          —          —          —          1,090   

(Income) loss attributable to non-controlling interests from continuing operations(4)

     (4,738     (3,176     22,781        (3,940     —     

Interest expense

     94,807        106,531        91,731        65,092        25,675   

Other interest

     844        608        —          —          —     

Depreciation and amortization

     74,897        75,684        71,764        34,453        9,495   

Discontinued operations interest expense, depreciation, and amortization

     12,069        19,394        13,334        14,066        12,432   
                                        

EBITDA

   $ 451,577      $ 257,000      $ (410,499   $ (35,357   $ 81,785   
                                        

Adjustments:

          

Equity income in joint venture

     (4,920     (4,043     —          —          —     

Distributions from joint venture

     11,066        4,310        —          —          —     

Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition(11)

     —          —          —          10,423        —     

Long-lived asset impairment loss

     —          10,325        —          —          —     

Goodwill impairment loss, net of associated non-controlling interest

     —          —          585,053        —          —     

Gain on asset sales and other(12)

     (301,373     (162,518     —          —          —     

Non-cash (gain) loss on derivatives

     (10,381     75,018        (113,640     99,543        163   

Non-recurring net cash derivative early termination expense(13)

     22,401        2,260        102,146        —          —     

Premium expense on derivative instruments

     21,123        9,693        3,736        —          —     

Non-cash compensation (income) expense

     4,729        1,265        (31,345     38,966        6,750   

Non-cash line fill loss (gain) (10)

     (346     (3,899     7,797        (2,270     820   

Other non-cash items(14)

     —          —          —          1,414        —     

Discontinued operations adjustments(15)

     13,628        (15,511     178,383        69,881        (2,479
                                        

Adjusted EBITDA

   $ 207,504      $ 173,900      $ 321,631      $ 182,600      $ 87,039   
                                        

 

(8) Volumetric data for APL’s Chaney Dell and Midkiff/Benedum systems for the year ended December 31, 2007 represents volumes recorded for the 158-day period from July 27, 2007, the date of APL’s acquisition, through December 31, 2007.
(9) During 2006, APL identified measurement reporting inaccuracies on three newly installed pipeline meters. To adjust for such inaccuracies, which relate to natural gas volume gathered during 2005, APL recorded an adjustment to increase natural gas and liquids cost of goods sold.
(10) Includes the non-cash impact of commodity price movements on APL’s pipeline linefill.
(11) The acquisition of APL’s Chaney Dell and Midkiff/Benedum systems was consummated on July 27, 2007, although the acquisition’s effective date was July 1, 2007. As such, APL receives the economic benefits of ownership of the assets as of July 1, 2007. However, in accordance with generally accepted accounting principles, APL has only recorded the results of the acquired assets commencing on the closing date of the acquisition. The economic benefits of ownership APL received from the acquired assets from July 1 to July 27, 2007 were recorded as a reduction of the consideration paid for the assets.
(12) For the year ended December 31, 2010, includes the gain on the sale of APL’s Elk City and expenses related to the pending sale of APL’s non-controlling interest in Laurel Mountain. For the year ended December 31, 2009, includes the APL’s gain on the sale of assets to the Laurel Mountain joint venture and the gain on sale of APL’s NOARK gas gathering and interstate pipeline system.
(13) During the years ended December 31, 2010, 2009 and 2008, APL made net payments of $33.7 million, $5.0 million and $274.0 million, respectively, which resulted in a net cash expense recognized of $33.7 million, $5.0 million and $197.6 million, respectively, related to the early termination of derivative contracts that were principally entered into as proxy hedges for the prices received on the ethane and propane portion of our NGL equity volume. These derivative contracts were put into place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The 2008 settlements were funded through APL’s June 2008 issuance of 5.75 million common limited partner units in a public offering and issuance of 1.39 million common limited partner units to us and ATLS in a private placement. In connection with this transaction, APL also entered into an amendment to its credit facility to revise the definition of Consolidated EBITDA to allow for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of common equity.
(14) Includes the cash proceeds received from the sale of APL’s Enville plant and the non-cash loss recognized within our statements of operations.
(15) Includes non-cash (gain) loss on derivatives, non-recurring cash derivative early termination and premium expense on derivative instruments recorded in discontinued operations.

 

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

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

General

Overview

We are a publicly-traded Delaware limited partnership, formerly known as Atlas Pipeline Holdings, L.P. (NYSE: AHD). Our wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). APL is a midstream energy service provider engaged in the gathering, processing and treating of natural gas in the Mid-Continent and Appalachia regions. Our cash generating assets at December 31, 2010 consisted solely of our interests in APL, a publicly traded Delaware limited partnership. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP which together with us, owns at December 31, 2010:

 

   

a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL; and

 

   

all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter, adjusted by the following;

 

   

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), Atlas Pipeline GP agreed to allocate up to $3.75 million per quarter after it receives the initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”); and

 

   

5,754,253 common units of APL, representing approximately 10.8% of the outstanding common units of APL, or a 10.6% limited partner interest in APL.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

Atlas Pipeline GP’s ownership of APL’s incentive distribution rights entitles it to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle Atlas Pipeline GP, subject to the IDR Adjustment Agreement, to receive the following:

 

   

13.0% of all cash distributed in a quarter after each APL common unit has received $0.42 for that quarter;

 

   

23.0% of all cash distributed after each APL common unit has received $0.52 for that quarter; and

 

   

48.0% of all cash distributed after each APL common unit has received $0.60 for that quarter.

We pay to our unitholders, on a quarterly basis, distributions equal to the cash we receive from APL and operations, less certain reserves for expenses and other uses of cash, including:

 

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our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

 

   

capital contributions to maintain or increase our ownership interest in APL; and

 

   

reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.

Atlas Pipeline Partners, L.P.

APL is a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” APL is a leading provider of natural gas gathering, processing and treating services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States and a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States.

APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

APL’s Mid-Continent operations, as of December 31, 2010, owns, has interests in and operates five natural gas processing plants with aggregate capacity of approximately 520 MMCFD. These facilities are connected to approximately 8,600 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which gathers gas from wells and central delivery points to APL’s natural gas processing and treating plants, as well as third-party pipelines.

The Appalachia operations of APL are conducted principally through its 49% non-controlling ownership interest in the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which owns and operates approximately 1,000 miles of natural gas gathering systems in the Appalachian Basin located in Pennsylvania. APL also owns and operates approximately 70 miles of active natural gas gathering pipelines in Tennessee.

Laurel Mountain has natural gas gathering agreements with Atlas Energy Resources, LLC (“Atlas Energy Resources”), a wholly-owned subsidiary of Atlas Energy, Inc. (“Atlas Energy, Inc.” or “ATLS”), a formerly publicly-traded company, under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

Financial Presentation

As of December 31, 2010, we had no separate operating activities apart from those conducted by APL, and our cash flows consisted of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own. The non-controlling limited partner interest in APL is reflected as an expense in our consolidated results of operations and as a component of equity on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).

 

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Recent Events

On January 7, 2010, APL executed amendments to warrants previously issued, along with its common units, in connection with a private placement to institutional investors that closed on August 20, 2009. The common units and warrants were issued and sold in a transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 per unit from $6.35 per unit. In connection with the amendments, the holders of the warrants exercised all of the warrants for cash, which resulted in the issuance of 2,689,765 APL common units and net cash proceeds to APL of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility (see “–APL Term Loan and Revolving Credit Facility”) and to fund the early termination of certain derivative agreements (see “Item 8. Financial Statements and Supplementary Data –Note 11”).

On March 31, 2010, APL and Atlas Pipeline Operating Partnership, L.P. amended their respective partnership agreements to temporarily waive the requirement that Atlas Pipeline GP make aggregate cash contributions of approximately $0.3 million, which was required in connection with its issuance of an aggregate of 2,689,765 of its common units upon the exercise of certain warrants in January 2010. The waiver remained in effect until we received aggregate distributions from APL sufficient to fund the required capital contribution. During the waiver period, the aggregate ownership percentage attributable to our general partner interest in APL was reduced to 1.9%. Both amendments were approved by APL’s conflicts committee and managing board, and were effective as of January 11, 2010. On November 30, 2010, we made capital contribution of $0.3 million to APL to increase our general partner interest in APL back to 2.0%.

On June 15, 2010, APL’s unitholders approved the terms of the APL 2010 Long Term Incentive Plan (“2010 LTIP”), which provides for the grant of options, phantom units, unit awards, unit appreciation rights and distribution equivalents. The total number of APL common units that may be issued under the APL 2010 LTIP is 3,000,000 (see “Item 8. Financial Statements and Supplementary Data –Note 16”).

On June 30, 2010, APL sold 8,000 newly created 12% Cumulative Class C Preferred Units of limited partner interest (the “APL Class C Preferred Units”) to ATLS for cash consideration of $1,000 per APL Class C Preferred Unit resulting in total proceeds of $8.0 million (see “–APL Preferred Units”).

On July 19, 2010, we entered into an amended and consolidated note with ATLS. The note consolidated in one instrument the debt we owed to ATLS under our $15 million subordinate note and the guaranty note, both dated June 1, 2009, and ATLS’s advance of $16 million under its guaranty of our credit facility, which facility was repaid in full on April 13, 2010. The original principal amount of the note was $33.4 million. The interest rate is 12% per annum which, prior to demand by ATLS for cash payment, will be payable, at our option, by accruing such interest and adding the amount to the principal amount of the note on a quarterly basis. The note is payable on demand (See “Item 8: Financial Statements and Supplementary Data –Note 8”).

On September 1, 2010, APL entered into an amendment to its credit facility agreement, which, among other things, revised the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to premiums associated with hedging agreements and to exclude the net gains or losses attributable to a disposition of assets other than in the ordinary course of business (see “–APL Term Loan and Revolving Credit Facility”).

On September 16, 2010, APL completed the sale of its Elk City and Sweetwater, Oklahoma natural gas gathering systems, the related processing and treating facilities (including the Prentiss treating facility and the Nine Mile processing plant, collectively “Elk City”) to a subsidiary of Enbridge Energy Partners, L.P. (NYSE: EEP) for $682 million in cash, excluding working capital adjustments and transaction costs (See “Item 8. Financial Statements and Supplementary Data –Note 4”). APL utilized the proceeds from the sale to repay its

 

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senior secured term loan and a portion of its indebtedness under its revolving credit facility (see “–APL Term Loan and Revolving Credit Facility”).

On November 8, 2010, we entered into a Transaction Agreement (the “AHD Transaction Agreement”), with ATLS and Atlas Energy Resources pursuant to which, among other things (1) we agreed to acquire ATLS’s investment partnership business and certain other assets and assume certain liabilities in exchange for our newly issued common units and cash (the “Asset Acquisition”); (2) ATLS will contribute our general partner, Atlas Pipeline Holdings GP to us, so that Atlas Pipeline Holdings GP becomes our wholly-owned subsidiary; (3) our limited partnership agreement will be amended and restated; (4) we will repay all amounts outstanding under our amended and consolidated note to ATLS and (5) ATLS will distribute to its stockholders all our common units that it holds, including the newly issued common units that it receives in the Asset Acquisition.

On November 8, 2010, concurrently with entering into the AHD Transaction Agreement and the Laurel Mountain Purchase Agreement (referenced below), ATLS entered into an Agreement and Plan of Merger with Chevron Corporation, a Delaware corporation (“Chevron”), pursuant to which, among other things ATLS will become a wholly-owned subsidiary of Chevron.

On November 8, 2010, APL entered into a definitive agreement with ATLS and Atlas Energy Resources (the “Laurel Mountain Sales Agreement”), pursuant to which APL agreed to sell its 49% non-controlling interest in Laurel Mountain to Atlas Energy Resources for $403 million in cash, subject to certain closing adjustments. APL intends to utilize the proceeds from the sale to repay its indebtedness, to fund future capital expenditures, and for general corporate purposes.

On November 8, 2010, ATLS, our majority unitholder, delivered a written consent approving the adoption of a new equity plan. This action by ATLS is sufficient for our unitholders to approve the adoption of the new equity plan without the vote of any other unitholder. The new equity plan will become effective upon the closing of the AHD Transactions. The new equity plan is intended to promote our interests by providing to officers, employees and directors of our general partner, and employees of its affiliates, consultants and joint venture partners who perform services for our general partner or us, incentive awards for superior performance that are based on our common units. The new equity plan is intended to enhance the ability of our general partner and its affiliates to attract and retain the services of individuals who are essential for the growth and profitability of our general partner and us and to encourage them to devote their best efforts to the businesses of our general partner and us and advancing the interests of our general partner and us. Grants made under the new equity plan will be determined by our board of directors or a committee of our board of directors or equivalent. An aggregate of 3,500,000 common units may be issued under this plan in the form of options, restricted units and phantom units.

On November 15, 2010, Atlas Pipeline Holdings II, LLC (“AHD Sub”) exercised its option to redeem its 15,000 12.0% cumulative preferred units for cash at the liquidation value of $1,000 per unit, or $15.0 million, plus $0.2 million accrued dividends. Concurrently, APL redeemed its 15,000 units of Class B Preferred Units held by us for cash at the liquidation value of $1,000 per unit, or $15.0 million plus $0.2 million accrued dividends, in accordance with the terms of the amended preferred units’ certificate. There are no longer any APL Class B Preferred Units outstanding (See “–APL Preferred Units”).

On November 22, 2010, APL completed its consent solicitation to amend certain provisions of the Indenture governing APL’s 8.125% Senior Notes, dated as of December 20, 2005, by and among APL, Atlas Pipeline Finance Corporation, the Subsidiary Guarantors party thereto and U.S. Bank National Association. After receiving the requisite consents, APL entered into a Supplemental Indenture to the Indenture, dated as of November 22, 2010, which amended and restated the definition of “Permitted Investments” under Section 1.01 of the Indenture to permit APL, or its subsidiaries, to make capital contributions to Laurel Mountain through December 31, 2011.

 

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On December 22, 2010, APL entered into an amended and restated credit agreement (see “–APL Term Loan and Revolving Credit Facility”) which, among other changes:

 

   

set the maturity date of APL’s revolving credit facility to December 22, 2015;

 

   

reduced APL’s revolving credit facility from $380.0 million to $350.0 million;

 

   

eliminated the 2.0% per annum floor previously applied to adjusted LIBOR;

 

   

removed restrictions on APL making investments in the Laurel Mountain joint venture if specified financial thresholds are not met;

 

   

eliminated the requirements that APL meet specified financial thresholds in order to be permitted to make distributions to its unitholders;

 

   

eliminated the limits on APL’s annual capital expenditures if specified financial thresholds are not met; and

 

   

adjusted the maximum Consolidated Funded Debt Ratio (“leverage ratio”) to 5.0 to 1.0; the maximum Consolidated Senior Secured Funded Debt Ratio (“senior secured leverage ratio”) to 3.0 to 1.0; and the minimum Interest Coverage Ratio to 2.5 to 1.0.

Subsequent Events

Atlas Energy, Inc. Asset Acquisition

On February 17, 2011, we completed the Asset Acquisition contemplated by the AHD Transaction Agreement, pursuant to which we purchased from ATLS (1) its investment partnership business, including the operations of its investment partnerships in Michigan, Pennsylvania, Tennessee, Indiana and Colorado, (2) its oil and gas exploration, development and production activities conducted in Tennessee, Indiana and Colorado, certain shallow wells and leases in New York and Ohio and certain well interests in Pennsylvania, and (3) its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (we refer to the businesses described in (1) through (3), together, as the “transferred business”). The assets we purchased include certain ATLS subsidiaries (referred to as the “purchased entities”) and certain other assets relating to the transferred business, including the names and marks of ATLS and its subsidiaries (which we refer to as the “purchased assets”). ATLS also transferred certain current liabilities that were assumed by us in the Asset Acquisition subject to post-closing.

As consideration for the Asset Acquisition, we paid to ATLS $30 million in cash, issued 23,379,384 new common units and assumed all of the historical and future liabilities associated with the transferred business. In addition, we repaid the $36.0 million outstanding under our amended and consolidated note owed to ATLS.

In connection with the Asset Acquisition, ATLS contributed our general partner, Atlas Pipeline Holdings GP, LLC to us, so that Atlas Pipeline Holdings GP became our wholly-owned subsidiary, our limited partnership agreement was amended and restated, and our new long-term equity incentive plan for employees became effective. ATLS distributed to its stockholders all our common units that it held, including the newly issued common units that it received in the Asset Acquisition. As a result, ATLS no longer owns any of our common units.

 

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New Credit Facility

We financed the cash portion of Asset Acquisition consideration and the repayment of the ATLS note by drawing on a $70 million revolving credit facility, administered by Citibank, N.A. that we entered into at closing. Our credit facility matures in February 2012 and bears interest, at our option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Citibank, N.A. prime rate (each plus the applicable margin). Borrowings under our credit facility are secured by a first-priority lien on a security interest in substantially all of our other assets, including a pledge of 3,500,000 of our APL common units, and are guaranteed by Atlas Pipeline Holdings GP and our operating subsidiaries (excluding Atlas Pipeline GP and APL and its subsidiaries). Our credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries; and requirements that we maintain certain financial ratios. The events which constitute an event of default under our credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against us in excess of a specified amount, and a change of control. We may borrow under our credit facility for working capital and general business purposes.

Laurel Mountain Sale

Concurrently with our completion of the Asset Acquisition, APL completed its sale to Atlas Energy Resources of its 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from Laurel Mountain after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of Laurel Mountain entitling APL Laurel Mountain to receive all payments made under a note issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of Laurel Mountain.

Atlas Energy, Inc. Merger

Concurrently with our completion of the Asset Acquisition and APL’s completion of the Laurel Mountain Sale, ATLS completed its merger transaction with Chevron Corporation, pursuant to which, among other things, ATLS became a wholly-owned subsidiary of Chevron (the “Chevron Merger”).

Atlas Pipeline Holdings, L.P. Name Change

On February 18, 2011, subsequent to the Asset Acquisition and the Chevron Merger, we changed our name to Atlas Energy, L.P.

Significant Acquisitions

In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) 100% interest in the Chaney Dell natural gas gathering systems and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas.

Contractual Revenue Arrangements

APL’s principal revenue is generated from the gathering and sale of natural gas, NGLs and condensate. Variables that affect its revenue are:

 

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the volumes of natural gas APL gathers and processes, which in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas, NGLs and condensate;

 

   

the price of the natural gas APL gathers and processes and the NGLs and condensate it recovers and sells, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;

 

   

the NGL and BTU content of the gas that is gathered and processed;

 

   

the contract terms with each producer; and

 

   

the efficiency of APL’s gathering systems and processing plants.

APL’s revenue consists of the sale of natural gas and liquids and the fees earned from its gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems and then sells the natural gas and NGLs off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas (See “Item 8. Financial Statements and Supplementary Data –Note 2 -Revenue Recognition” for further discussion of contractual revenue arrangements).

In APL’s Appalachia segment, substantially all of the natural gas Laurel Mountain gathers is for Atlas Energy Resources under contracts in which Laurel Mountain earns a fee equal to a percentage, generally 16%, of the gross sales price for natural gas, inclusive of the effects of financial and physical hedging, subject, in most cases, to a minimum of $0.35 per MCF, depending on the ownership of the well. The balance of the natural gas gathered by Laurel Mountain is for third-party operators generally under fixed-fee contracts.

Recent Trends and Uncertainties

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

APL faces competition for in obtaining natural gas supplies for its processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas-gathering facilities and gas-processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, quality of assets, flexibility, service history and maintenance of high-quality customer relationships. Many of APL’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, APL. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows APL to compete more effectively for new natural gas supplies in its regions of operations.

As a result of APL’s POP and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil (see “Item 8. Financial Statements and Supplementary Data –Note 2 –Revenue Recognition”). APL believes that future natural gas prices will be

 

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influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which APL believes will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the recent past. Lower drilling levels and shut in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

APL is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. APL closely monitors the risks associated with commodity price changes on APL’s future operations and, where appropriate, uses various commodity-based derivative instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of APL’s assets and operations from such price risks. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk -Commodity Price Risk” for further discussion of commodity price risk.

Currently, there is a significant level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us and APL. These risks include the availability and costs associated with our and APL’s borrowing capabilities and APL’s ability to raise additional capital, and an increase in the volatility of the price of our and APL’s common units. While we and APL have no definitive plans to access the capital markets, should we or APL decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

Results of Operations

The following table illustrates selected pricing and volumetric information related to APL’s reportable segments for the periods indicated:

 

     Years Ended December 31,  
     2010      2009      2008  

Pricing:

        

Mid-Continent Weighted Average Prices:

        

NGL price per gallon – Conway hub

   $ 0.92       $ 0.68       $ 1.19   

NGL price per gallon – Mt. Belvieu hub

     1.03         0.77         1.29   

Natural gas sales ($/Mcf):

        

Velma

     4.14         3.24         7.38   

Chaney Dell

     4.13         3.25         6.98   

Midkiff/Benedum

     4.10         3.35         7.44   

Weighted Average

     4.12         3.28         7.19   

NGL sales ($/gallon):

        

Velma

     0.90         0.69         1.23   

Chaney Dell

     0.94         0.69         1.23   

Midkiff/Benedum

     1.02         0.83         1.27   

Weighted Average

     0.97         0.73         1.25   

Condensate sales ($/barrel):

        

Velma

     78.28         59.80         100.65   

Chaney Dell

     72.67         55.07         97.29   

Midkiff/Benedum

     75.57         60.35         105.44   

Weighted Average

     75.08         58.21         100.85   

 

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     Years Ended December 31,  
     2010      2009      2008  

Operating data:

        

Appalachia:

        

Laurel Mountain system:

        

Average throughput volumes (MCFD)

     109,480         96,975         85,348   

Tennessee system:

        

Average throughput volumes (MCFD)

     8,740         7,907         1,951   

Mid-Continent:

        

Velma system:

        

Gathered gas volume (MCFD)

     84,455         76,378         63,196   

Processed gas volume (MCFD)

     78,606         73,940         60,147   

Residue Gas volume (MCFD)

     64,138         58,350         47,497   

NGL volume (BPD)

     9,218         8,232         6,689   

Condensate volume (BPD)

     416         377         280   

Chaney Dell system:

        

Gathered gas volume (MCFD)

     228,684         270,703         276,715   

Processed gas volume (MCFD)

     214,695         215,374         245,592   

Residue Gas volume (MCFD)

     193,200         228,261         239,498   

NGL volume (BPD)

     12,395         13,418         13,263   

Condensate volume (BPD)

     697         824         791   

Midkiff/Benedum system:

        

Gathered gas volume (MCFD)

     178,111         159,568         144,081   

Processed gas volume (MCFD)

     163,475         149,656         135,496   

Residue Gas volume (MCFD)

     105,982         101,788         92,019   

NGL volume (BPD)

     26,678         21,261         19,538   

Condensate volume (BPD)

     1,289         1,265         1,142   

Financial Presentation

On September 16, 2010, APL completed the sale of APL’s Elk City (see “–Recent Events”). As such, we have adjusted the prior period consolidated financial information presented to reflect the amounts related to the operations of APL’s Elk City as discontinued operations.

We have reclassified a portion of our historical income, within our consolidated statements of operations, to “Transportation, Processing and Other Fees” for fee-based revenues which were previously reported within “Natural Gas and Liquids” and “Other income (loss), net. This reclassification was made in order to provide clarity between commodity-based and fee-based revenues.

We have reclassified “Equity income in joint venture” and “Gain (loss) on asset sales and other” to line items separate from “Total revenue and other income (loss) net.”

 

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Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenue. The following table details the variances between the years ended 2010 and 2009 for revenues (in thousands):

 

     Years Ended December 31,              
     2010      2009(1)     Variance     Percent
Variance
 

Revenue:

         

Natural gas and liquids

   $ 890,048       $ 636,231      $ 253,817        39.9

Transportation, compression and other fee revenue

     41,093         59,075        (17,982     (30.4 )% 

Other income (loss), net

     4,422         (23,061     27,483        119.2
                                 

Total Revenue and other income (loss), net

   $ 935,563       $ 672,245      $ 263,318        39.2
                                 

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids revenue for the year ended December 31, 2010 increased primarily due to a favorable price change as a result of higher realized commodity prices, combined with lower qualified hedge losses. Gains and losses within other comprehensive income (loss), related to previously designated hedges, are recorded within natural gas and liquids revenue, while all other gains and losses related to derivative instruments are recorded within other income (loss), net. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales and natural gas purchases against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Midkiff/Benedum system’s NGL production volume for the year ended December 31, 2010 increased when compared to the prior year period, representing an increase in production efficiency primarily due to the start-up of the new Consolidator plant, which provides greater recoveries increasing the liquid volumes extracted from the natural gas stream. NGL production volume on APL’s Chaney Dell system decreased for the year ended December 31, 2010 compared to the prior year due to a decreased number of well connects over the past year, resulting from lower capital spending. NGL production on APL’s Velma system increased for the year ended December 31, 2010 when compared to the prior year period primarily due to increased gathered gas volume resulting from the completion of the Madill-to-Velma gas gathering pipeline.

Transportation, processing and other fee revenue decreased primarily due to a $16.9 million decrease from APL’s Appalachia system as a result of APL’s May 2009 contribution of the majority of the system to Laurel Mountain, a joint venture in which APL has a 49% non-controlling ownership interest. After the contribution, we recognized APL’s ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations.

Other income (loss), net, including the impact of certain gains and losses recognized on derivatives, had a favorable movement for the year ended December 31, 2010 due primarily to a $63.6 million favorable variance in non-cash mark-to-market adjustments on derivatives, offset by $32.3 million unfavorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts (see “Item 8: “Financial Statements and Supplementary Data –Note 11”).

 

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Costs and Expenses. The following table details the variances between the years ended 2010 and 2009 for costs and expenses (in thousands):

 

     Years Ended December 31,               
     2010      2009(1)      Variance     Percent
Variance
 

Costs and Expenses:

          

Natural gas and liquids

   $ 720,215       $ 527,730       $ 192,485        36.5

Plant operating

     48,670         45,566         3,104        6.8

Transportation and compression

     1,061         6,657         (5,596     (84.1 )% 

General and administrative

     36,394         38,931         (2,537     (6.5 )% 

Depreciation and amortization

     74,897         75,684         (787     (1.0 )% 

Goodwill and other asset impairment loss

     —           10,325         (10,325     (100.0 )% 

Acquisition costs

     1,167         —           1,167        100.0

Interest expense

     94,807         106,531         (11,724     (11.0 )% 
                                  

Total Costs and Expenses

   $ 977,211       $ 811,424       $ 165,787        20.4
                                  

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids cost of goods sold for the year ended December 31, 2010 increased primarily due to an increase in average commodity prices in comparison to the prior year period, as discussed above in revenues.

Transportation and compression expenses for the year ended December 31, 2010 decreased due to APL’s contribution of the Appalachia system to Laurel Mountain.

Goodwill and other asset impairment loss for the year ended December 31, 2009 was due to an impairment of certain gas plant and gathering assets as a result of APL’s annual review of long-lived assets.

Acquisition costs for the year ended December, 31, 2010 represents costs related to the pending acquisition of assets from ATLS. (see “–Subsequent Events”).

Interest expense for the year ended December 31, 2010 decreased primarily due to a $9.5 million decrease in APL’s interest rate swap expense due to the interest rate swaps expiring in April 2010 and due to a $5.8 million decrease in interest expense associated with APL’s term loan, partially offset by a $2.6 million higher amortization of deferred finance costs. The lower interest expense on APL’s term loan is due to the retirement of the term loan in September 2010 with proceeds from the sale of APL’s Elk City (see “–Recent Events”). The increased amortization of deferred finance costs was due principally to accelerated amortization associated with the retirement of APL’s term loan.

Other income items. The following table details the variances between the years ended 2010 and 2009 for other income items (in thousands):

 

     Years Ended December 31,              
     2010     2009(1)     Variance     Percent
Variance
 

Equity income in joint venture

   $ 4,920      $ 4,043      $ 877        21.7

Gain (loss) on asset sales and other

     (10,729     108,947        (119,676     (109.8 )% 

Income from discontinued operations

     321,155        84,148        237,007        281.7

Income attributable to non-controlling interests

     (4,738     (3,176     (1,562     (49.2 )% 

Income attributable to non-controlling interests in APL

     (241,026     (50,748     (190,278     (374.9 )% 

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

 

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Equity income represents APL’s ownership interest in the net income of Laurel Mountain and it increased for the year ended December 31, 2010 as a result of the prior year including only seven months of operations.

Gain (loss) on asset sales and other for the years ended December 31, 2010 and 2009 includes amounts associated with APL’s contribution of a 51% ownership interest in its Appalachia natural gas gathering system in 2009 and the pending sale of APL’s 49% interest in Laurel Mountain in 2010 (See “–Subsequent Events”).

Income from discontinued operations increased for the year ended December 31, 2010 primarily due to the $312.1 million gain on sale of APL’s Elk City in the current year period compared to the $51.1 million gain on sale of APL’s NOARK gas gathering and interstate pipeline which was sold in May 2009.

Income attributable to non-controlling interests increased for the year ended December 31, 2010 primarily due to higher net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish APL’s acquisition of control of the respective systems. The increase in net income of the Chaney Dell and Midkiff/Benedum joint ventures was principally due to higher gross margins on the sale of commodities resulting from higher prices. The non-controlling interest expense represents Anadarko Petroleum Corporation’s interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Income attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, increased for the year ended December 31, 2010 due to an increase in APL’s net earnings between periods.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Revenue. The following table details the variances between the years ended 2009 and 2008 for revenues (in thousands):

 

     Years Ended December 31,               
     2009(1)     2008(1)      Variance     Percent
Variance
 

Revenue:

         

Natural gas and liquids

   $ 636,231      $ 1,078,714       $ (442,483     (41.0 )% 

Transportation, compression and other fee revenue

     59,075        87,442         (28,367     (32.4 )% 

Other income (loss), net

     (23,061     36,602         (59,663     (163.0 )% 
                                 

Total Revenue and other income (loss),net

   $ 672,245      $ 1,202,758       $ (530,513     (44.1 )% 
                                 

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids revenue for the year ended December 31, 2009 decreased primarily due to decreases in production revenue from APL’s Chaney Dell system of $234.0 million, APL’s Midkiff/Benedum system of $148.9 million, and APL’s Velma system of $95.0 million, which were all impacted by lower average commodity prices and changes in volumes in comparison to the prior year.

Processed natural gas volume on the Chaney Dell system decreased for the year ended December 31, 2009 compared to the prior year partially due to shut-in wells as a result of lower gas prices. The Chaney Dell system increased its NGL production volume for the year ended December 31, 2009 compared to the prior year, representing an increase in production efficiency. The Midkiff/Benedum system’s processed natural gas volume and NGL production volume for the year ended December 31, 2009 increased compared to the prior year, representing an increase in production efficiency partially due to the start-up of the new Consolidator plant. Processed natural gas volume and NGL production volume on the Velma system increased for the year ended December 31, 2009 from the prior year mainly due to the new gathering line from the Madill area.

Transportation, compression and other fee revenue for the year ended December 31, 2009 decreased

 

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primarily due to a $26.2 million decrease from APL’s Appalachia system as a result of APL’s May 2009 contribution of the majority of the system to Laurel Mountain, after which we recognized APL’s ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations.

Other loss, net, including the impact of certain gains and losses recognized on derivatives for the year ended December 31, 2009, had an unfavorable movement due primarily to a $219.5 million unfavorable variance in non-cash mark-to-market adjustments on APL’s derivatives offset by $101.6 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts (see “Item 8: “Financial Statements and Supplementary Data –Note 11”) and an $55.2 million favorable movement in non-cash derivative gains related to the early termination of a portion of APL’s derivative contracts.

Costs and Expenses. The following table details the variances between the years ended 2009 and 2008 for costs and expenses (in thousands):

 

     Years Ended December 31,              
     2009(1)      2008(1)     Variance     Percent
Variance
 

Costs and Expenses:

         

Natural gas and liquids

   $ 527,730       $ 900,460      $ (372,730     (41.4 )% 

Plant operating

     45,566         47,371        (1,805     (3.8 )% 

Transportation and compression

     6,657         11,249        (4,592     (40.8 )% 

General and administrative

     38,931         633        38,298        6050.2

Depreciation and amortization

     75,684         71,764        3,920        5.5

Goodwill and other asset impairment loss

     10,325         615,724        (605,399     (98.3 )% 

Interest expense

     106,531         91,731        14,800        16.1

Gain on early extinguishment of debt

     —           (19,867     19,867        100.0
                                 

Total Costs and Expenses

   $ 811,424       $ 1,719,065      $ (907,641     (52.8 )% 
                                 

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Natural gas and liquids cost of goods sold for the year ended December 31, 2009 decreased primarily due to a decrease in average commodity prices and changes in volumes in comparison to the prior year as discussed above in revenues. Transportation and compression expenses decreased due to APL’s contribution of its Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, for the year ended December 31, 2009 increased primarily as a result of a $32.6 million increase in non-cash compensation expense primarily due to a $36.3 million net mark-to-market gain recognized during the year ended December 31, 2008 principally associated with the vesting of certain APL common unit awards that were based on the financial performance of certain assets during 2008. The mark-to-market gain was the result of a significant change in APL’s common unit market price at December 31, 2008 when compared with the December 31, 2007 price, which was utilized in the estimate of the non-cash compensation expense for these awards. These common unit awards were issued during the year ended December 31, 2009.

Interest expense for the year ended December 31, 2009 increased mainly due to an $9.1 million increase in interest expense associated with outstanding borrowings on APL’s revolving credit facility, an $8.5 million increase in interest expense related to APL’s additional senior notes issued during June 2008 (see “–APL Senior Notes”) and a $2.1 million increase in the amortization of deferred finance costs due principally to accelerated amortization associated with the retirement of a portion of APL’s term loan with the proceeds from the sale of APL’s NOARK system, partially offset by a $5.9 million decrease in interest expense associated with APL’s senior secured term loan primarily due to the repayment of $273.7 million of indebtedness since December 2008 (see “–APL Term Loan and Revolving Credit Facility”) and lower unhedged interest rates.

Goodwill and other asset impairment loss for the year ended December 31, 2009 decreased compared to

 

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the prior year. The asset impairment loss for the year ended December 31, 2009 was due to an impairment of certain APL gas plant and gathering assets as a result of APL’s annual review of long-lived assets. The impairment loss for the year ended December 31, 2008 was due to an impairment charge to APL’s goodwill from the reduction of APL’s estimate of the fair value of goodwill in comparison to its carrying amount at December 31, 2008. The estimate of fair value of goodwill was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. There were no goodwill impairments for the year ended December 31, 2009.

Gain on early extinguishment of debt for the year ended December 31, 2008 resulted from APL’s repurchase of approximately $60.0 million of its Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million of APL’s 8.125% Senior Notes and approximately $27.0 million of APL’s 8.75% Senior Notes. All of the APL Senior Notes repurchased have been retired and are not available for re-issue.

Other income items. The following table details the variances between the years ended 2009 and 2008 for other income items (in thousands):

 

     Years Ended December 31,              
     2009(1)     2008(1)     Variance     Percent
Variance
 

Equity income in joint venture

   $ 4,043      $ —        $ 4,043        100.0

Gain on asset sales and other

     108,947        —          108,947        100.0

Income (loss) from discontinued operations

     84,148        (93,802     177,950        189.7

(Income) loss attributable to non-controlling interests

     (3,176     22,781        (25,957     (113.9 )% 

(Income) loss attributable to non-controlling interests in APL

     (50,748     513,675        (564,423     (109.9 )% 

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of APL’s Elk City.

Equity income of $4.0 million for the year ended December 31, 2009 represents APL’s ownership interest in the net income of Laurel Mountain for the period from its formation on May 31, 2009 through December 31, 2009.

Gain on asset sales and other of $108.9 million for the year ended December 31, 2009 represents the gain recognized on APL’s contributions of a 51% ownership interest in its Appalachia natural gas gathering system to Laurel Mountain.

Income from discontinued operations consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system APL sold on May 4, 2009 and APL’s Elk City sold on September 16, 2010 (see “–Recent Events”). For the year ended December 31, 2009, income from discontinued operations increased due to a $114.3 million loss on APL’s Elk City operations in the prior year, primarily due to a $123.6 million dollar loss related to the early termination of certain derivatives in the prior year, and a $51.1 million gain recognized on the sale of APL’s NOARK system in 2009.

Income attributable to non-controlling interests for the year ended December 31, 2009 changed as a result of higher net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish APL’s acquisition of control of the respective systems. The increase in net income of the Chaney Dell and Midkiff/Benedum joint ventures was principally due to the goodwill impairment charge in 2008 of $613.4 million for the goodwill originally recognized upon acquisition of these systems. The non-controlling interest expense represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Income (loss) attributable to non-controlling interest in APL, which represents the allocation of APL’s

 

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earnings to its non-affiliated limited partners, increased for the year ended December 31, 2009 compared with the prior year due to an increase in APL’s net earnings between periods.

Liquidity and Capital Resources

General

As of December 31, 2010, our primary sources of liquidity are distributions received with respect to our ownership interests in APL and cash on hand. Our primary cash requirements are for our general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to APL to maintain or increase our ownership interest and quarterly distributions to our common unitholders. We expect to fund our general and administrative expenses through the retention of cash and we expect to fund our capital contributions to APL through the retention of cash from distributions received from APL. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Our credit facility terminated on April 13, 2010 (see “–Our Credit Facility”). In connection with our June 1, 2009 amendment to our credit facility, we were required to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility and were required to repay the balance of our outstanding borrowings by April 13, 2010. Payments were timely made by funding from ATLS under its guaranty of our obligations (see “–Our Demand Note with Atlas Energy, Inc.”). (See “Our Credit Facility” for a description of our new credit facility).

At December 31, 2010, we had a working capital deficit of $75.0 million compared with a working capital deficit of $63.5 million at December 31, 2009. We believe that we will have sufficient liquid assets, including our ownership of 5.8 million limited partner units in APL, to meet our financial commitments, debt service obligations, and possible contingencies for at least the next twelve-month period. However, we are subject to business and other risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including other borrowings and the issuance of additional limited partner units and the sale of our ownership interests in APL.

APL’s primary sources of liquidity are cash generated from operations and borrowings under its credit facility. APL’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to its common unitholders and general partner. In general, we expect APL to fund:

 

   

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

 

   

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

 

   

debt principal payments through operating cash flows and refinancings as they become due, or by the issuance of additional limited partner units or APL asset sales.

At December 31, 2010, APL had $70.0 million of outstanding borrowings under its $350.0 million senior secured credit facility and $3.2 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheets, with $276.8 million of remaining committed capacity under the credit facility, subject to covenant limitations (see “–APL Term Loan and Revolving Credit Facility”). APL was in compliance with its credit facility’s covenants at December 31, 2010. At December 31, 2010, APL had a working capital deficit of $36.6 million compared with a $30.6 million working capital deficit at December 31,

 

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2009. We believe that APL will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, APL is subject to business, operational and other risks that could adversely affect its cash flow. APL may need to supplement its cash generation with proceeds from financing activities, including borrowings under its credit facility and other borrowings, the issuance of additional limited partner units and sales of its assets.

Instability in the financial markets, as a result of recession or otherwise, may cause volatility in the markets and may impact the availability of funds from those markets. This may affect our and APL’s ability to raise capital and reduce the amount of cash available to fund our and APL’s operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. We or APL cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The following table details the variances between the years ended 2010 and 2009 for cash flows (in thousands):

 

     Years Ended December 31,              
      2010     2009     Variance     Percent
Variance
 

Net cash provided by (used in):

        

Operating activities

   $ 106,574      $ 53,507      $ 53,067        99.2

Investing activities

     594,753        241,030        353,723        146.8

Financing activities

     (702,183     (300,719     (401,464     (133.5 )% 
                                

Net change in cash and cash equivalents

   $ (856   $ (6,182   $ 5,326        86.2
                                

Net cash provided by operating activities for the year ended December 31, 2010 increased primarily due to a $47.0 million increase in net earnings from continuing operations, excluding non-cash charges, and a $24.9 million increase in cash flows from working capital changes, partially offset by an $18.8 million decrease in cash provided by discontinued operations. Net earnings from continuing operation, excluding non-cash charges, increased primarily due to a favorable gross margin in continuing operations of $46.9 million, mainly as a result of higher commodity prices.

Net cash provided by investing activities for the year ended December 31, 2010 increased as a result of the net proceeds of $676.8 million received from the sale of APL’s Elk City in 2010 compared to $292.0 million received from the sale of APL’s NOARK gas gathering and interstate pipeline system in the prior year period combined with the $89.5 million received from the sale of APL’s 51% interest in the Appalachia assets in the prior year period. Additionally, there was a $64.5 million decrease in capital expenditures compared to the prior year period (see further discussion of capital expenditures under “–Capital Requirements”).

Net cash used in financing activities for the year ended December 31, 2010 increased mainly due to a $280.0 million net increase in repayments of the outstanding principal balance on APL’s revolving credit facility and a $159.8 million increase in repayments of APL’s term loan. The increase in repayments of on APL’s term loan and revolving credit facility is principally due to the retirement of the term loan and a portion of APL’s revolving credit facility with proceeds from the sale of APL’s Elk City.

 

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Cash Flows - Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

The following table details the va