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EX-32.2 - SECTION 906 CFO CERTIFICATION - ATLAS PIPELINE PARTNERS LPdex322.htm
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EX-31.2 - SECTION 302 CFO CERTIFICATION - ATLAS PIPELINE PARTNERS LPdex312.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - ATLAS PIPELINE PARTNERS LPdex311.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - ATLAS PIPELINE PARTNERS LPdex321.htm
EX-21.1 - SUBSIDIARIES OF REGISTRANT - ATLAS PIPELINE PARTNERS LPdex211.htm
EX-12.1 - STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - ATLAS PIPELINE PARTNERS LPdex121.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: 1-14998

 

 

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

DELAWARE   23-3011077

(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   x
Non-accelerated filer   ¨    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 $9.66 per common limited partner unit on June 30, 2010, was approximately $445.6 million.

The number of common units of the registrant outstanding on February 22, 2011 was 53,338,422.

 

 

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


Table of Contents

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

 

          Page  

PART I

     

Item 1:

   Business      5   

Item 1A:

   Risk Factors      25   

Item 1B:

   Unresolved Staff Comments      41   

Item 2:

   Properties      41   

Item 3:

   Legal Proceedings      41   

Item 4:

   [Removed and reserved]      41   

PART II

     

Item 5:

   Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities      42   

Item 6:

   Selected Financial Data      44   

Item 7:

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      49   

Item 7A:

   Quantitative and Qualitative Disclosures About Market Risk      69   

Item 8:

   Financial Statements and Supplementary Data      71   

Item 9:

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      120   

Item 9A:

   Controls and Procedures      120   

Item 9B:

   Other Information      123   

PART III

     

Item 10:

   Directors, Executive Officers and Corporate Governance      124   

Item 11:

   Executive Compensation      131   

Item 12:

   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters      151   

Item 13:

   Certain Relationships and Related Transactions, and Director Independence      156   

Item 14:

   Principal Accountant Fees and Services      158   

PART IV

     

Item 15:

   Exhibits and Financial Statement Schedules      159   

SIGNATURES

     161   

 

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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;

 

   

our ability to connect new wells to our gathering systems;

 

   

adverse effects of governmental and environmental regulation;

 

   

limitations on our access to capital or on the market for our common units; and

 

   

the strength and financial resources of our competitors.

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.

Residue gas

   The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.

SEC

   Securities Exchange Commission

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

Corporate Structure

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” We are 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.

Our general partner, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or the “General Partner”), manages our operations and activities through its ownership of our general partner interest. Atlas Pipeline GP is a wholly-owned subsidiary of Atlas Energy, L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy, L.P.” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) which owned a 10.8% limited partner interest, as well as the 2% general partner interest in us, at December 31, 2010. Atlas Energy, Inc. (“Atlas Energy, Inc.” or “ATLS”), a formerly publicly-traded company, owned 64.0% of the common units of AHD and also had a direct 2.1% interest in us through ownership in our common units, plus 8,000 $1,000 par value 12% Class C cumulative preferred limited partner units at December 31, 2010.

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

LOGO

 

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Recent Developments

Elk City Sale

On September 16, 2010, we completed the sale of our Elk City and Sweetwater, Oklahoma natural gas gathering systems, the related processing and treating facilities 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. We utilized the proceeds from the sale to repay our senior secured term loan and a portion of our indebtedness under the revolving credit facility.

Laurel Mountain Sale

On February 17, 2011, we completed a sale to Atlas Energy Resources LLC (“Atlas Energy Resources”) of our 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 million in cash, including adjustments based on certain capital contributions we made to and distributions we received from Laurel Mountain after January 1, 2011. We retained the preferred distribution rights under the limited liability company agreement of Laurel Mountain entitling APL Laurel Mountain LLC, our wholly-owned subsidiary, 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.

AHD Transaction Agreement

Concurrently with the Laurel Mountain Sale, AHD completed a transaction agreement (the “AHD Transaction Agreement” or “AHD Transactions”), with ATLS and Atlas Energy Resources, a wholly-owned subsidiary of ATLS, pursuant to which among other things (1) AHD purchased certain assets from ATLS; (2) ATLS contributed AHD’s general partner, Atlas Pipeline Holdings GP to AHD, so that Atlas Pipeline Holdings GP be AHD’s wholly-owned subsidiary; and (3) ATLS distributed to its stockholders all AHD common units that it held.

Atlas Energy, Inc. Merger

Concurrently with the AHD Transactions, ATLS completed an agreement and plan of merger with Chevron Corporation, a Delaware corporation (“Chevron”), pursuant to which, among other things, ATLS became a wholly-owned subsidiary of Chevron (the “Chevron Merger”). Our 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 AHD Transactions and the Chevron Merger, AHD changed its name to Atlas Energy, L.P.

 

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The following chart displays the corporate organizational structure subsequent to the Chevron Merger and AHD Transaction Agreement and related developments described above:

LOGO

The remainder of this “Business” section discusses our business as it existed on December 31, 2010, without giving effect to the Laurel Mountain Sale or AHD Transactions or the Chevron Merger.

General

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

In our Mid-Continent operations, we own and operate 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 our processing and treating plants, as well as third-party pipelines.

Our Appalachia operations are conducted principally through our 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. We also own and operate approximately 70 miles of active natural gas gathering pipelines located in Tennessee.

Our 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. In the Mid-Continent, our 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 that we have significant scale in our service areas. We provide gathering and processing services to the wells connected to our systems, primarily under long-term contracts. As a result of the location and capacity of our gathering and processing assets, we believe we are strategically positioned to capitalize on the

 

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drilling activity in our service areas. We intend to continue to expand our 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, we 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.

Business Strategy

The primary business objective of our management team is to provide stable long-term cash distributions to our unitholders. Our business strategies focus on creating value for our 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. We intend to accomplish our primary business objectives by executing on the following:

 

   

Increasing the profitability of our existing assets. In many cases, we can expand our gathering pipelines and processing plants and may have excess capacity, which provides us with opportunities to connect and process new supplies of natural gas with minimal additional capital requirements, also increasing plant efficiency and economics. We plan to accomplish this goal by providing excellent service to our existing customers, aggressively marketing our services to new customers and prudently expanding our existing infrastructure to ensure our services can meet the needs of potential customers. Our recent construction of the 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 our gathering systems.

 

   

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

 

   

Reducing the sensitivity of our cash flows through prudent economic risk management and contract arrangements. We attempt to structure our contracts in a manner that allows us to achieve our target rate of return goals while reducing our exposure to commodity price movements. We actively review our contract mix and seek to optimize a balance of cash flow stability with attractive economic returns. Our 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 us to meet our debt service requirements, fund our maintenance capital program and meet our distribution objectives.

 

   

Maintaining our financial flexibility. We intend to maintain a capital structure in which we do not significantly exceed equal amounts of debt and equity on a long-term basis, while not jeopardizing our ability to achieve our other business strategies. We believe that our revolving credit facility, our ability to issue additional long-term debt or partnership units and our relationships with our partners provide us with the ability to achieve this strategy. We will also consider alternative financing, joint venture

 

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arrangements and other means that allow us to achieve our 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 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 our 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

Our 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

 

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Revenue Arrangements”).

Our Mid-Continent Operations

We own and operate approximately 8,600 miles of intrastate natural gas gathering systems located in Oklahoma, Kansas, and Texas. We also own and operate five processing plants located in Oklahoma and Texas. Our gathering, processing and treating assets service long-lived natural gas regions, including the Permian and Anadarko Basins. Our 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, our 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. Our 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; ONEOK Gas Transportation, LLC; Panhandle Eastern Pipe Line Company, LP; and Southern Star Central Gas Pipeline, Inc. Our processing facilities are connected to NGL pipelines operated by ONEOK Hydrocarbon, L.P.

Mid-Continent Overview

We consider 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 our 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.

 

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LOGO

Midkiff/Benedum. The Midkiff/Benedum gathering system, which we operate and in which we have 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.

 

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LOGO

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. We transport and sell natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Waynoka and Chester plants and sell 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. Our Consolidator/Benedum processing operations have an aggregate processing capacity of approximately 195 MMCFD. We transport and sell natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Consolidator/Benedum plants and sell 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. We have 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 our competitors. We transport and sell natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Velma plant and sell NGL production to ONEOK Hydrocarbon, L.P.

Natural Gas Supply

In the Mid-Continent, we have 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 our processing plants. In addition,

 

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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.

We have long-term relationships with several of our Mid-Continent producers. For instance, we have producer relationships going back over 20 years on our Velma System. Several of our top producers, which accounted for a significant portion of our 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 our gathering systems have evergreen term extensions. When we acquired control of the Midkiff/Benedum system in July 2007, we 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, we anticipate that we 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

We typically sell natural gas to purchasers downstream of our 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 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.

We sell our 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

Our 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. We attempt 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 the physical price environment that consists of floating prices to a risk-managed environment that is characterized by fixed prices; floor prices on products where we are long the commodity price; and ceiling prices on products where we are 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.

 

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

We are exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of our contractual relationships with natural gas producers or, alternatively, a function of cost of sales. We are 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 us to pay a percentage of revenue to the producer. This results in our being net long physical natural gas and NGLs.

 

   

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

We manage 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 or ceiling prices. We utilize natural gas swaps and options to manage our natural gas price risks. We utilize NGL and crude oil swaps and options to manage our NGL and condensate price risks.

We generally realize gains and losses from the settlement of our derivative instruments in other income at the same time we sell the associated physical residue gas or NGLs. We determine 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, we have established a committee to review our derivative instruments for compliance with our policies and procedures.

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

Our Appalachia Operations

Our Appalachia operations are principally conducted through our 49% non-controlling interest in Laurel Mountain, which we 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. We also own and operate 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. Our 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. These 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, the 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

 

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

Natural Gas Revenue

Our Appalachia revenue is determined primarily by the amount of natural gas flowing through Laurel Mountain’s and our 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 we do not buy or sell gas in connection with our Appalachia operations, we do 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.

Our Relationship with Atlas Energy, Inc.

We began our operations in January 2000 by acquiring the Appalachia gathering systems of ATLS In May, 2009, we contributed the majority of our Appalachia gathering system assets to Laurel Mountain, a joint venture in which we have a 49% non-controlling ownership interest. ATLS owned 64.0% of AHD, the parent of our general partner, which owned a 10.8% limited partner interest and a 2% general partner interest in us 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.

 

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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).

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.

Competition

Acquisitions. We have encountered competition in acquiring midstream assets owned by third parties. In several instances we submitted bids in auction situations and in direct negotiations for the acquisition of such assets and were either outbid by others or were unwilling to meet the sellers’ expectations. In the future, we expect 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 our Mid-Continent service area, we compete 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.

We believe 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

 

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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.

We believe that our relationships with operators connected to our system are good and that we present an attractive alternative for producers. However, if we cannot compete successfully, we may be unable to obtain new well connections.

Appalachia. The assets operated in the Appalachian Basin by Laurel Mountain and us do not encounter direct competition in our 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, we are affected by competitive factors affecting Atlas Energy Resources’ ability to obtain properties and drill wells, which affects our 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 our gathering systems. These delays would 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, we seek to connect wells operated by third parties. As of December 31, 2010, these systems are connected to approximately 250 third party wells.

Seasonality

Our 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 our gathering process, which could adversely affect our 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”). We own a number of intrastate natural gas gathering lines in Kansas, Oklahoma and Texas that we believe 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 our, 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, our operating costs could increase and our transportation fees could be adversely affected, thereby reducing our net revenues and ability to fund our operations, pay required debt service on our credit facilities and make distributions to our General Partner and common unitholders.

We are currently subject to state ratable take, common purchaser and/or similar statutes in one or more jurisdictions in which we operate. Common purchaser statutes generally require gatherers to purchase without

 

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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, our revenues could decrease. Collectively, any of these laws may restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Our 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. Our 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 our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas and NGLs. A portion of our 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 such FERC initiatives on our 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 us 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.

 

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At present, we believe none of our 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 us, primarily in our 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, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 

   

restricting the way we can handle or dispose of our 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;

 

   

requiring remedial action to mitigate pollution conditions caused by our 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 our 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 our 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 us to incur significant costs.

Hazardous Waste. Our 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.

 

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We believe that our 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 our 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 our 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 our ordinary operations we 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 they incur. Under CERCLA, we 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.

We currently own or lease, 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 we 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 us 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 us. However, none of these spills or releases were material and we believe 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, we 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. Our 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 our processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we 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. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We 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 our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Water Discharges. Our 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.

 

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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 our 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 our operations.

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

Our 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 our 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. We are 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 our 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 our Velma gas plant contains high levels of hydrogen sulfide, and we employ numerous safety precautions at the system to ensure the safety of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in substantial compliance with all such requirements.

Chemicals of Interest. We operate 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

 

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and registered with DHS. These registration requirements for Chemical of Interest were first promulgated by DHS in 2008 and we are currently in compliance with the Department’s requirements. None of our 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. We could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels we process. In addition, our operations could face additional costs for emissions control and higher costs of doing business. Although we 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. However, we are currently unable to assess the timing and effect of the pending legislation.

Properties

As of December 31, 2010, our 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 our gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. As of December 31, 2010, our principal facilities in Appalachia include approximately 70 miles of 2 to 12 inch diameter pipeline operated by our 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 our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

 

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The following tables set forth certain information relating to our 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   

Our 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 our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the rights-of-way grants. In a few instances, our rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the 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, and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

Certain of our rights to lay and maintain pipelines are derived from recorded gas well leases, 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 or operations. In general, employees of ATLS and its affiliates manage our gathering systems and operate our business. ATLS employed approximately 270 people at December 31, 2010 who provided direct support to our operations.

 

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

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, AHD consummated the AHD Transactions with ATLS and Atlas Energy Resources and subsequent to such transaction, AHD or one of its 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.atlaspipeline.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 Our Business

The amount of cash we generate depends, in part, on factors beyond our control.

The amounts of cash that we generate may not be sufficient for us to pay distributions in the future. Our ability to make cash distributions depends primarily on our cash flow. Cash distributions do not depend directly on our profitability, which is affected by non-cash items. Therefore, cash distributions may be made during periods when we record losses and may not be made during periods when we record profits. The actual amounts of cash we generate will depend upon numerous factors relating to our business which may be beyond our 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 we process;

 

   

the volume of natural gas we gather;

 

   

efficiency of our gathering systems and processing plants;

 

   

expiration of significant contracts;

 

   

continued development of wells for connection to our gathering systems;

 

   

our ability to connect new wells to our gathering systems;

 

   

our ability to integrate newly formed ventures or acquired businesses with our existing operations;

 

   

the availability of local, intrastate and interstate transportation systems;

 

   

the availability of fractionation capacity;

 

   

the expenses we incur in providing our gathering services;

 

   

the cost of acquisitions and capital improvements;

 

   

our issuance of equity securities;

 

   

required principal and interest payments on our debt;

 

   

fluctuations in working capital;

 

   

prevailing economic conditions;

 

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fuel conservation measures;

 

   

alternate fuel requirements;

 

   

the strength and financial resources of our competitors;

 

   

the effectiveness of our hedging program and the creditworthiness of our 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 we will have available for distribution will depend on other factors, including:

 

   

the level of capital expenditures we make;

 

   

the sources of cash used to fund our acquisitions;

 

   

limitations on our access to capital or the market for our common units and notes;

 

   

our debt service requirements and requirements to pay dividends on our outstanding preferred units; and

 

   

the amount of cash reserves established by our General Partner for the conduct of our business.

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

We cannot borrow under our credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” under our partnership agreement. Because we cannot borrow money to pay distributions unless we establish a facility that meets the definition contained in our partnership agreement, our ability to pay a distribution in any quarter is solely dependent on our ability to generate sufficient operating surplus with respect to that quarter.

Economic conditions and instability in the financial markets could negatively impact our business.

Our 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 service area and in wells currently connected to our pipeline system being shut in by their operators until prices improved. Any of these events may adversely affect our revenues and our 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.

 

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Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact our access to liquidity needed for our business and impact our flexibility to react to changing economic and business conditions. We may be unable to execute our growth strategy, 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 our lenders, producers, key suppliers or other customers, causing them to fail to meet their obligations to us. Market conditions could also impact our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our cash flow and ability to make required debt service payments on our credit facility and pay distributions could be impacted. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

We are affected by the volatility of prices for natural gas, NGL and crude oil products.

We derive a majority of our gross margin from POP and Keep-Whole contracts. As a result, our income depends to a significant extent upon the prices at which we buy and sell natural gas and at which we sell 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 for the twelve-month period ended December 31, 2011 by approximately $13.5 million. Additionally, changes in natural gas prices may indirectly impact our profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to our pipeline system or that we expect will be connected to our system to shut in their production until prices improve, thereby affecting the volume of gas we gather and process. Historically, the prices 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 our control, including those we describe in “––The amount of cash we generate depends, in part, on factors beyond our control,” above. 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, during the same time period. We expect this volatility to continue. This volatility may cause our gross margin and cash flows to vary widely from period to period. Our 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 “— Our price risk management strategies may fail to protect us and could reduce our gross margin and cash flow.”

Our price risk management strategies may fail to protect us and could reduce our gross margin and cash flow.

Our operations expose us to fluctuations in commodity prices. We utilize derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of our cash flows due to fluctuations in commodity prices. To the extent we protect our commodity price using certain derivative contracts we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. Our commodity price risk management activity may fail to protect or could harm us 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 we seek protection;

 

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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 are 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.

Due to the accounting treatment of our 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 enter into natural gas, natural gas liquids and crude oil derivative contracts. We account for these derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We 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 our 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 may be required to make cash payments upon the termination of any of these derivative contracts.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could negatively impact our business.

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

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

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

The amount of natural gas we gather will decline over time unless we are able to attract new wells to connect to our gathering systems.

Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to our gathering

 

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systems could, therefore, result in the amount of natural gas we gather declining substantially over time and could, upon exhaustion of the current wells, cause us to abandon one or more of our gathering systems and, possibly, cease operations. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing wells that are not committed to other systems, the level of drilling activity near our gathering systems and, in the Mid-Continent region, our ability to attract natural gas producers away from our 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 our gathering and processing facilities could result if there is a sustained decline in natural gas prices which, in turn, would lead to a reduced utilization of these 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. We have no control over the level of drilling activity in our service areas, the amount of reserves underlying wells that connect to our systems and the rate at which production from a well will decline. In addition, we have 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 our systems until prices improve. Because our operating costs are fixed to a significant degree, a reduction in the natural gas volumes we gather or process would result in a reduction in our gross margin and cash flows.

The amount of natural gas we gather or process may be reduced if the natural gas liquids pipelines or fractionation facilities to which we deliver NGLs cannot or will not accept the NGLs.

If one or more of the pipelines or fractionation facilities to which we deliver NGLs has service interruptions, capacity limitations or otherwise does not accept the NGLs we sell to or transport on, and we cannot arrange for delivery to other pipelines or facilities, the amount of NGLs we process, sell or transport may be reduced. Since our revenues depend upon the volumes of NGLs we sell or transport, this could result in a material reduction in our gross margin and cash flows.

The amount of natural gas we gather, treat or process may be reduced if the intrastate and interstate pipelines to which we deliver gas cannot or will not accept the gas.

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

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then our cash flows could be reduced.

The construction of additions to our existing gathering assets may require us to obtain new rights-of-way before constructing new pipelines. We may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us 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 our cash flows could be reduced.

 

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The success of our Mid-Continent operations depends upon our ability to continually find and contract for new sources of natural gas supply from.

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

Our 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 our 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 our Mid-Continent operations natural gas supply. If these producers reduce the volumes of natural gas that they supply to us, our gross margin and cash flows would be reduced unless we obtain comparable supplies of natural gas from other producers.

The curtailment of operations at, or closure of, any of our processing plants could harm our business.

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

We may face increased competition in the future in our Mid-Continent operations.

Our 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 our Velma service area. DCP Midstream, Hiland Partners, Mustang Fuel Corporation, ONEOK Partners and SemGas, L P operate competing gathering systems and processing plants in our Chaney Dell service area. DCP Midstream, Southern Union Company, Targa Resources and West Texas Gas operate competing gathering systems and processing plants in our Midkiff/Benedum service area. Some of our competitors have greater financial and other resources than we do. If these companies become more active in our Mid-Continent service area, we may not be able to compete successfully with them in securing new well connections or retaining current well connections. If we do not compete successfully, the amount of natural gas we gather, process and treat will decrease, reducing our 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 our indebtedness and working capital requirements;

 

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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

 

   

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. Any of these factors could adversely impact our future growth and our ability to make or increase distributions.

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

We have an active, on-going program to identify potential acquisitions. Our integration of previously independent operations with our own can be a complex, costly and time-consuming process. The difficulties of combining these systems with 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.

Our investment and the additional overhead costs we incur to grow our 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 our operations could harm our business or future prospects, and result in significant decreases in our gross margin and cash flows.

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

One of the ways we may grow our business is through the construction of new assets. The construction of additions or modifications to our existing systems and facilities, and the construction of new assets, involve

 

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numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. Any projects we undertake may not be completed on schedule at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a gathering system, the construction may occur over an extended period of time, and we will not receive any material increase in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which growth does not materialize. Since we are not engaged in the exploration for, and development of, natural gas reserves, we often do not have access to estimates of potential reserves in an area before constructing facilities in the area. To the extent we rely on estimates of future production in our decision to construct additions to our 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 our expected investment return, which could impair our results of operations and financial condition. In addition, our 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.

We continue to expand the natural gas gathering systems surrounding our 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 us.

We may not be able to execute our growth strategy successfully.

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

 

   

we may not be able to identify suitable acquisition candidates;

 

   

we 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;

 

   

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

 

   

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

 

   

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

 

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we may encounter difficulties in integrating operations and systems; and

 

   

any additional debt we incur to finance an acquisition may impair our ability to service our existing debt.

Limitations on our access to capital or the market for our common units will impair our ability to execute our growth strategy.

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

Our debt levels and restrictions in our credit facility could limit our ability to fund operations, pay required debt service on our credit facility and make distributions to our unitholders.

We will need a portion of our cash flow to make principal and interest payments on our indebtedness, which will reduce the funds that would otherwise be available for operations, future business opportunities and distributions to our unitholders. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms, or at all.

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

If we do not pay distributions on our common units with respect to any fiscal quarter, our unitholders are not entitled to receive distributions for such prior periods in the future.

Our distributions to our unitholders are not cumulative. Consequently, if we do not pay distributions on our common units with respect to any quarter, our unitholders are not entitled to receive such payments in the future.

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

We have wide discretion to issue additional units, including units that rank senior to our common units as to quarterly cash distributions, on the terms and conditions established by our General Partner. The payment of distributions on these additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on the common units.

Regulation of our gathering operations could increase our operating costs, decrease our revenues, or both.

Currently we believe our 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 our gathering and processing operations to regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. We expect that any such regulation could increase our costs, decrease our gross margin and cash flows, or both.

 

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Even if our gathering and processing operations are not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect our business and the market for our 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 our business. Matters subject to such regulation include conditions of access, rates, terms of service and safety. For example, our gathering lines are subject to ratable take, common purchaser, and similar statutes in one or more jurisdictions in which we operate. 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, our revenues could decrease. Collectively, all of these statutes may restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather 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;

 

   

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 our pipeline should not have a material effect on our 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.

Our 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 our 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 our business activities in many ways, including restricting the manner in which we dispose of substances,

 

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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 our business due to our 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 our pipelines or processing facilities could subject us 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 our compliance costs, and the cost of any necessary remediation. We may not be able to recover some or any of these costs from insurance.

Our 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 our operations or from combustion of fuels we process. In addition, our operations could face additional taxes and higher costs of doing business. Although we 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.

Our operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and penalties in connection with any pollution caused by their pipelines. We may also be held liable for clean-up costs resulting from pollution which occurred before our acquisition of a gathering system. In addition, we are 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 us.

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

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

 

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We are subject to operating and litigation risks that may not be covered by insurance.

Our 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 our pipeline infrastructure, production facilities and surrounding properties.

As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for some of our 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 we were to incur a significant liability for which we were not fully insured, our gross margin and cash flows would be materially reduced.

Risks Related to Our Ownership Structure

AHD has conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.

AHD owns and controls our General Partner. We do not have any employees and, subsequent to the AHD Transaction, rely solely on employees of AHD, who serve as our agents, including all of the senior managers who operate our business. A number of officers and employees of AHD also own interests in us. Conflicts of interest may arise between AHD, our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests and the interests of our unitholders. These conflicts could include, among others, the following situations:

 

   

Employees of AHD who provide services to us may also devote time to the businesses of AHD in which we have no economic interest. If these separate activities are greater than our activities, there could be material competition for the time and effort of the employees who provide services to our General Partner, which could result in insufficient attention to the management and operation of our business.

 

   

Our General Partner is allowed to take into account the interests of parties other than us, such as AHD, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us.

 

   

Our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates.

 

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Conflicts of interest with AHD and its affiliates, including the foregoing factors, could exacerbate periods of lower or declining performance, or otherwise reduce our gross margin and cash flows.

Our 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 our subsidiary. However, the consent of Anadarko is required for specified extraordinary transactions, such as admission of new members, engaging in transactions with our 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 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.

Tax Risks of Unit Ownership

If we were treated as a corporation for federal income tax purposes, or if we were to become subject to entity-level taxation for federal or state income tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

We are currently treated as a partnership for federal income tax purposes, which requires that 90% or more of our 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). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

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 unitholders would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders 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.

Current law may change, causing us to be treated as a corporation for federal and/or state income tax purposes or otherwise subjecting us 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 as an entity, the cash available for distribution to our unitholders 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

 

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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.

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.

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 capital and profits interest within a 12-month period will result in the termination of our 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. The termination would, among other things, result in the closing of our 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 do business or own property now or in the future, even if our unitholders do

 

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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 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 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.

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.

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

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our General Partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our 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 our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our General Partner and certain of our 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. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

 

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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 AHD and we agreed to enter into separate transactions with ATLS relating to certain ATLS natural gas reserves and other assets and fee revenues, and our 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 AHD and us and alleges that the ATLS directors violated their fiduciary duties in connection with the proposed Merger and that AHD, we 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 AHD 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 us and names ATLS, the General Partner, and members of the Managing Board of the General Partner as defendants (“Defendants”) and alleges that Defendants have violated their fiduciary duties in connection with the proposed sale to ATLS of our 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 claims in another forum. 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 “APL.” At the close of business on February 22, 2011, the closing price for the common units was $27.69 and there were 97 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

   $ 25.80       $ 17.43       $ 0.37   

Third Quarter

     18.92         8.98         0.35   

Second Quarter

     14.99         8.35         0.00   

First Quarter

     14.71         9.63         0.00   

2009

        

Fourth Quarter

   $ 10.25       $ 6.55       $ 0.00   

Third Quarter

     8.31         5.44         0.00   

Second Quarter

     9.38         3.52         0.00   

First Quarter

     10.75         2.36         0.15   

Our Cash Distribution Policy

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

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

 

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Available cash is initially distributed 98% to our common limited partners and 2% to our General Partner. These distribution percentages are modified to provide for incentive distributions to be paid to our General Partner if quarterly distributions to common unitholders exceed specified targets, as follows:

 

Minimum Distributions

Per Unit Per Quarter

     Percent of Available  Cash
in Excess of Minimum Allocated
to 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.

We make 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 our General Partner that are in excess of 2% of the aggregate amount of cash being distributed. In July 2007, our General Partner, the holder of all of our incentive distribution rights, agreed to allocate a portion of its incentive distribution rights back to us as defined in the IDR Adjustment Agreement. There were no General Partner incentive distributions declared for the years ended December 31, 2010 and 2009.

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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ITEM 6. SELECTED FINANCIAL DATA

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, we completed the sale of our Elk City and Sweetwater, Oklahoma natural gas gathering systems (collectively “Elk City”). We have retrospectively adjusted our prior period consolidated financial statements to reflect the amounts related to the operations of 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 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

     4,447        (22,701     36,585        (99,272     6,121   
                                        

Total revenue and other income (loss), net

     935,588        672,605        1,202,741        478,517        211,605   
                                        

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)

     34,021        37,280        (2,933     59,600        19,127   

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     —          —     

Interest

     91,632        103,787        89,869        63,989        25,521   
                                        

Total costs and expenses

     970,496        807,029        1,713,637        595,245        213,156   
                                        

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

     (40,717     (21,434     (510,896     (116,728     (1,551

Income (loss) from discontinued operations

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

Net income (loss)

     280,438        62,714        (604,698     (140,369     33,783   

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

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

Preferred unit dividend effect

     —          —          —          (3,756     —     

Preferred unit imputed dividend cost

     —          —          (505     (2,494     (1,898

Preferred unit dividends

     (780     (900     (1,769     —          —     
                                        

Net income (loss) attributable to common limited partners and the General Partner

   $ 274,920      $ 58,638      $ (584,191   $ (150,559   $ 31,767   
                                        

Allocation of net income (loss) attributable to:

          

Common Limited Partner interest:

          

Continuing operations

   $ (45,347   $ (24,997   $ (503,533   $ (139,905   $ (17,950

Discontinued operations

     315,021        82,457        (91,917     (23,166     34,508   
                                        
     269,674        57,460        (595,450     (163,071     16,558   

General Partner interest:

          

Continuing operations

     (888     (513     13,144        12,987        14,501   

Discontinued operations

     6,134        1,691        (1,885     (475     708   
                                        
     5,246        1,178        11,259        12,512        15,209   

Net income (loss) attributable to:

          

Continuing operations

     (46,235     (25,510     (490,389     (126,918     (3,449

Discontinued operations

     321,155        84,148        (93,802     (23,641     35,216   
                                        
   $ 274,920      $ 58,638      $ (584,191   $ (150,559   $ 31,767   
                                        

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

          

Basic:

          

Continuing operations

   $ (0.85   $ (0.52   $ (11.80   $ (5.74   $ (1.40

Discontinued operations

     5.92        1.71        (2.16     (0.95     2.68   
                                        
   $ 5.07      $ 1.19      $ (13.96   $ (6.69   $ 1.28   
                                        

Diluted(5):

          

Continuing operations

   $ (0.85   $ (0.52   $ (11.80   $ (5.74   $ (1.40

Discontinued operations

     5.92        1.71        (2.16     (0.95     2.68   
                                        
   $ 5.07      $ 1.19      $ (13.96   $ (6.69   $ 1.28   
                                        

 

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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

     1,764,848        2,137,963        2,413,196        2,875,451        786,884   

Total debt, including current portion

     565,974        1,254,183        1,493,427        1,229,426        324,083   

Total Equity

     1,041,647        723,527        650,842        1,271,797        379,134   

Cash flow data:

          

Net cash provided by (used in):

          

Operating activities

   $ 106,427      $ 55,853      $ (59,194   $ 100,444      $ 60,920   

Investing activities

     594,753        241,123        (292,944     (2,024,643     (104,499

Financing activities

     (702,037     (297,400     341,242        1,935,059        27,028   

Other financial data (unaudited):

          

Gross margin from continuing operations (6)

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

EBITDA (7)

     454,902        258,846        (406,950     (31,801     82,321   

Adjusted EBITDA (7)

     209,799        174,808        322,515        183,496        87,140   

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 our sale of Elk City.
(2) Includes our 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 $3.5 million, $0.7 million, ($34.0) million, $36.3 million, and $6.3 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 we acquired on July 27, 2007.
(5) For the years ended December 31, 2008, 2007 and 2006, potential common limited partner units issuable upon conversion of our $1,000 par value Class A and Class B cumulative convertible preferred limited partner units were excluded from the computation of diluted net income (loss) attributable to common limited partners as the impact of the conversion would have been anti-dilutive.

 

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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 we purchase 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 our financial covenants under our credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of Elk City; (ii) the unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition, and (iii) other non-cash items specifically excluded under our 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)

   $ 280,438      $ 62,714      $ (604,698   $ (140,369   $ 33,783   

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

     91,632        103,787        89,869        63,989        25,521   

Other interest

     604        443        —          —          —     

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

   $ 454,902      $ 258,846      $ (406,950   $ (31,801   $ 82,321   
                                        

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

     (10,166     74,644        (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

     3,484        701        (34,010     36,306        6,315   

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

   $ 209,799      $ 174,808      $ 322,515      $ 183,496      $ 87,140   
                                        

 

(8) Volumetric data for the 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 our acquisition, through December 31, 2007.
(9) During 2006, we identified measurement reporting inaccuracies on three newly installed pipeline meters. To adjust for such inaccuracies, which relate to natural gas volume gathered during 2005, we recorded an adjustment to increase natural gas and liquids cost of goods sold.
(10) Includes the non-cash impact of commodity price movements on pipeline linefill.
(11) The acquisition of the Chaney Dell and Midkiff/Benedum systems was consummated on July 27, 2007, although the acquisition’s effective date was July 1, 2007. As such, we receive the economic benefits of ownership of the assets as of July 1, 2007. However, in accordance with generally accepted accounting principles, we have only recorded the results of the acquired assets commencing on the closing date of the acquisition. The economic benefits of ownership we 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 Elk City and expenses related to the pending sale of our non-controlling interest in Laurel Mountain. For the year ended December 31, 2009, includes the gain on the sale of assets to the Laurel Mountain joint venture and the gain on sale of the NOARK gas gathering and interstate pipeline system.
(13) During the years ended December 31, 2010, 2009 and 2008, we 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 our acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The 2008 settlements were funded through our 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 AHD and ATLS in a private placement. In connection with this transaction, we also entered into an amendment to our 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 our 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

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” We are 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.

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

Our Mid-Continent operations, as of December 31, 2010, own, have interests in and operate 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 our natural gas processing and treating plants, as well as third-party pipelines.

Our Appalachia operations are conducted principally through our 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. We also own and operate 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).

Recent Events

On January 7, 2010, we executed amendments to warrants previously issued, along with our 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 common units and net cash proceeds to us of approximately $15.3 million. We utilized the net proceeds from the common unit offering to repay a portion of our indebtedness under our senior secured term loan and credit facility (see “–Term Loan and 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, we and Atlas Pipeline Operating Partnership, L.P. amended our respective partnership agreements to temporarily waive the requirement that the General Partner make aggregate cash

 

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contributions of approximately $0.3 million, which was required in connection with our issuance of an aggregate of 2,689,765 of our common units upon the exercise of certain warrants in January 2010. The waiver remained in effect until the General Partner received aggregate distributions from us sufficient to fund the required capital contribution. During the waiver period, the aggregate ownership percentage attributable to the General Partner’s general partner interest in us was reduced to 1.9%. Both amendments were approved by our conflicts committee and managing board, and were effective as of January 11, 2010. On November 30, 2010, we received a capital contribution from the General Partner of $0.3 million for the General Partner to increase its general partner interest in us back to 2.0%.

On June 15, 2010, our unitholders approved the terms of the 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 our common units that may be issued under the 2010 LTIP is 3,000,000 (see “Item 8. Financial Statements and Supplementary Data –Note 16”).

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

On September 1, 2010, we entered into an amendment to our 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 “–Term Loan and Revolving Credit Facility”).

On September 16, 2010, we completed the sale of our 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”). We utilized the proceeds from the sale to repay our senior secured term loan and a portion of our indebtedness under the revolving credit facility (see “–Term Loan and Revolving Credit Facility”).

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

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, we redeemed our 15,000 units of Class B Preferred Units held by AHD 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 Class B Preferred Units outstanding (See “–Preferred Units”).

On November 22, 2010, we completed our consent solicitation to amend certain provisions of the Indenture governing our 8.125% Senior Notes, dated as of December 20, 2005, by and among us, Atlas Pipeline Finance Corporation, the Subsidiary Guarantors party thereto and U.S. Bank National Association. After receiving the requisite consents, we 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 us, or our subsidiaries, to make capital contributions to Laurel Mountain through December 31, 2011.

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

 

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

 

   

reduced the 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 making investments in the Laurel Mountain joint venture if specified financial thresholds are not met;

 

   

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

 

   

eliminated the limits on 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

Laurel Mountain Sale

On February 17, 2011, we completed our sale to Atlas Energy Resources of our 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $413.5 million in cash, including adjustments based on certain capital contributions we made to and distributions we received from Laurel Mountain after January 1, 2011. We 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.

AHD Transaction Agreement

Concurrently with the Laurel Mountain Sale, AHD completed a transaction agreement (the “AHD Transaction Agreement” or “AHD Transactions”), with ATLS and Atlas Energy Resources, a wholly-owned subsidiary of ATLS, pursuant to which among other things (1) AHD purchased certain assets from ATLS; (2) ATLS contributed AHD’s general partner, Atlas Pipeline Holdings GP to AHD, so that Atlas Pipeline Holdings GP be AHD’s wholly-owned subsidiary; and (3) ATLS distributed to its stockholders all AHD common units that it held.

Atlas Energy, Inc. Merger

Concurrently with the AHD Transactions, ATLS completed an agreement and plan of merger with Chevron Corporation, a Delaware corporation (“Chevron”), pursuant to which, among other things, ATLS became a wholly-owned subsidiary of Chevron (the “Chevron Merger”). Our common units and 12% cumulative Class C preferred units held directly by ATLS were acquired by Chevron as part of the Chevron Merger.

Significant Acquisitions

In July 2007, we 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

Our principal revenue is generated from the gathering and sale of natural gas, NGLs and condensate. Variables that affect our revenue are:

 

   

the volumes of natural gas we gather and process, which in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas they produce, and the demand for natural gas, NGLs and condensate;

 

   

the price of the natural gas we gather and process and the NGLs and condensate we recover and sell, 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;

 

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the contract terms with each producer; and

 

   

the efficiency of our gathering systems and processing plants.

Revenue consists of the sale of natural gas and liquids and the fees earned from our gathering and processing operations. Under certain agreements, we purchase natural gas from producers and move it into receipt points on our pipeline systems and then sell the natural gas and NGLs off of delivery points on our systems. Under other agreements, we gather natural gas across our 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 our Appalachia segment, substantially all of the natural gas we gather via Laurel Mountain 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.

We face competition in obtaining natural gas supplies for our 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 our competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies in our regions of operations.

As a result of our POP and Keep-Whole contracts, our 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”). We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe 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.

We are 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. We closely monitor the risks associated with commodity price

 

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changes on our future operations and, where appropriate, use various commodity-based derivative instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of our 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. These risks include the availability and costs associated with our borrowing capabilities and ability to raise additional capital, and an increase in the volatility of the price of our common units. While we have no definitive plans to access the capital markets, should we 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 our 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, we completed the sale of 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 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,     Variance     Percent
Variance
 
     2010      2009(1)      

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

     4,447         (22,701     27,148        119.6
                                 

Total Revenue and other income (loss), net

   $ 935,588       $ 672,605      $ 262,983        39.1
                                 

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of 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. We enter into derivative instruments solely to hedge our 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.”

The 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 the 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 the 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 the Appalachia system as a result of our May 2009 contribution of the majority of the system to Laurel Mountain, a joint venture in which we have a 49% non-controlling ownership interest. After the contribution, we recognized our 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 our 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,      Variance     Percent
Variance
 
     2010      2009(1)       

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

     34,021         37,280         (3,259     (8.7 )% 

Depreciation and amortization

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

Goodwill and other asset impairment loss

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

Interest expense

     91,632         103,787         (12,155     (11.7 )% 
                                  

Total Costs and Expenses

   $ 970,496       $ 807,029       $ 163,467        20.3
                                  

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of 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 our 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 our annual review of long-lived assets.

Interest expense for the year ended December 31, 2010 decreased primarily due to a $9.5 million decrease in 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 our term loan, partially offset by a $2.6 million higher amortization of deferred finance costs. The lower interest expense on our term loan is due to the retirement of the term loan in September 2010 with proceeds from the sale of Elk City (see “–Recent Events”). The increased amortization of deferred finance costs was due principally to accelerated amortization associated with the retirement of our 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,     Variance     Percent
Variance
 
     2010     2009(1)      

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 )% 

 

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

Equity income represents our 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 the contribution of a 51% ownership interest in our Appalachia natural gas gathering system in 2009 and the pending sale of our 49% interest in Laurel Mountain in 2010 (See “–Subsequent Events”).

 

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Income from discontinued operations increased for the year ended December 31, 2010 primarily due to the $312.1 million gain on sale of Elk City in the current year period compared to the $51.1 million gain on sale of the 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 the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish our 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.

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,      Variance     Percent
Variance
 
     2009(1)     2008(1)       

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

     (22,701     36,585         (59,286     (162.1 )% 
                                 

Total Revenue and other income (loss), net

   $ 672,605      $ 1,202,741       $ (530,136     (44.1 )% 
                                 

 

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

Natural gas and liquids revenue for the year ended December 31, 2009 decreased primarily due to decreases in production revenue from the Chaney Dell system of $234.0 million, the Midkiff/Benedum system of $148.9 million, and the 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 primarily due to a $26.2 million decrease from the Appalachia system as a result of our May 2009 contribution of the majority of the system to Laurel Mountain, after which we recognized our 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 derivatives, offset by $101.6 million favorable variance of net cash derivative expense related to the early termination of a portion of our 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 our derivative contracts.

 

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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,     Variance     Percent
Variance
 
     2009(1)      2008(1)      

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

     37,280         (2,933     40,213        1371.1

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

     103,787         89,869        13,918        15.5

Gain on early extinguishment of debt

             (19,867     19,867        100.0
                                 

Total Costs and Expenses

   $ 807,029       $ 1,713,637      $ (906,608     (52.9 )% 
                                 

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of 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 our contribution of the 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 $34.7 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 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 our 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 a $9.1 million increase in interest expense associated with outstanding borrowings on our revolving credit facility, an $8.5 million increase in interest expense related to our additional senior notes issued during June 2008 (see “–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 our term loan with the proceeds from the sale of our NOARK system, partially offset by a $5.9 million decrease in interest expense associated with our senior secured term loan primarily due to the repayment of $273.7 million of indebtedness since December 2008 (see “–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 the prior year. The 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 our annual review of long-lived assets. The impairment loss for the year ended December 31, 2008 was due to an impairment charge to our goodwill from the reduction of our 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 our repurchase of approximately $60.0 million of our 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 our 8.125% Senior Notes and approximately $27.0 million of our 8.75% Senior Notes. All of

 

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the 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,           Percent
Variance
 
     2009(1)     2008(1)     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 )% 

 

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

Equity income of $4.0 million for the year ended December 31, 2009 represents our 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 our contribution of a 51% ownership interest in our Appalachia natural gas gathering system to Laurel Mountain.

Income from discontinued operations consists of amounts associated with the NOARK gas gathering and interstate pipeline system we sold on May 4, 2009 and Elk City we 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 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 the 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 the 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.

Liquidity and Capital Resources

General

Our primary sources of liquidity are cash generated from operations and borrowings under our credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to our common unitholders and General Partner. In general, we expect 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

 

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

At December 31, 2010, we had $70.0 million of outstanding borrowings under our $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 “–Term Loan and Revolving Credit Facility”). We were in compliance with the credit facility’s covenants at December 31, 2010. At December 31, 2010, we had a working capital deficit of $36.6 million compared with a $30.6 million working capital deficit at December 31, 2009. We believe that we 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, we are subject to business, operational and other risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional limited partner units and sales of our 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 ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flow from operations and our credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We 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

   $ 106,427      $ 55,853      $ 50,574        90.6

Investing activities

     594,753        241,123        353,630        146.7

Financing activities

     (702,037     (297,400     (404,637     (136.1 )% 
                                

Net change in cash and cash equivalents

   $ (857   $ (424   $ (433     (102.1 )% 
                                

Net cash provided by operating activities for the year ended December 31, 2010 increased primarily due to a $48.8 million increase in net earnings from continuing operations, excluding non-cash charges, and a $20.6 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 Elk City in 2010 compared to $292.0 million received from the sale of the NOARK gas gathering and interstate pipeline system in the prior year period combined with the $89.5 million received from the sale of our 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 our revolving credit facility and a $159.8 million increase in repayments of our term loan. The increase in repayments on our term loan and

 

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revolving credit facility is principally due to the retirement of the term loan and a portion of our revolving credit facility with proceeds from the sale of Elk City.

Cash Flows – Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

The following table details the variances between the years ended 2009 and 2008 for cash flows (in thousands):

 

     Years Ended December 31,              
     2009     2008     Variance     Percent
Variance
 

Net cash provided by (used in):

        

Operating activities

   $ 55,853      $ (59,194   $ 115,047        194.4

Investing activities

     241,123        (292,944     534,067        182.3

Financing activities

     (297,400     341,242        (638,642     (187.2 )% 
                                

Net change in cash and cash equivalents

   $ (424   $ (10,896   $ 10,472        96.1
                                

Net cash provided by operating activities for the year ended December 31, 2009 increased due to a $265.2 million favorable movement in net earnings from continuing operations excluding non-cash charges, partially offset by a $127.7 million decrease in cash provided by discontinued operations and a $22.5 million decrease in cash flows from working capital changes. The increase in net earnings from continuing operations excluding non-cash charges was principally due to a $161.7 million decrease of net cash derivative expense, including expenses related to the early termination of a portion of our derivative contracts (see “Item 8: Financial Statements and Supplementary Data –Note 11”).

Net cash provided by investing activities for the year ended December 31, 2009 increased principally due to a $409.2 million increase in cash provided by discontinued operations, the net proceeds of $89.5 million received from the sale of our Appalachia system assets and a $71.4 million decrease in capital expenditures, partially offset by a 2008 receipt of a $30.2 million cash reimbursement for state sales tax paid on our 2007 transaction to acquire the Chaney Dell and Midkiff/Benedum systems and a 2008 period receipt of $1.3 million in connection with a post-closing purchase price adjustment of our 2007 acquisition of the Chaney Dell and Midkiff/Benedum systems (see further discussion of capital expenditures under “–Capital Requirements”).

Net cash used in financing activities for the year ended December 31, 2009 decreased principally due to $244.9 million of net proceeds from the issuance of 8.75% Senior Notes in 2008 (see “–Senior Notes”), a decrease of $240.9 million of net proceeds from the issuance of our common units, and a $173.0 million net decrease in borrowings under our revolving credit facility.

Capital Requirements

Our operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. Our capital requirements consist primarily of:

 

   

maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

 

   

expansion capital expenditures to acquire complementary assets and to expand the capacity of our existing operations.

The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

 

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     Years Ended December 31,  
     2010      2009(1)      2008(1)  

Maintenance capital expenditures

   $ 10,921       $ 3,750       $ 4,787   

Expansion capital expenditures

     35,715         106,524         176,869   
                          

Total

   $ 46,636         110,274       $ 181,656   
                          

 

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

Expansion capital expenditures decreased for the year ended December 31, 2010 primarily due to the completion of the Madill to Velma pipeline and the construction of the Consolidator gas plant in the prior year, compounded by a reduction of well connects in the current period. The increase in maintenance capital expenditures for the year ended December 31, 2010 was partially due to planned maintenance expense at the Waynoka plant plus fluctuations in the timing of other scheduled maintenance activity. As of December 31, 2010, we have approved expenditures of approximately $32.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Expansion capital expenditures decreased for the year ended December 31, 2009 due principally to the construction of the Madill to Velma pipeline during the year ended December 31, 2008 and decreases in capital expenditures related to the sale of the 51% ownership interest in the Appalachia system. The decrease in maintenance capital expenditures for the year ended December 31, 2009, compared with the prior year, was due to fluctuations in the timing of scheduled maintenance activity.

Partnership Distributions

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

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

Available cash is initially distributed 98% to our common limited partners and 2% to our General Partner. These distribution percentages are modified to provide for incentive distributions to be paid to our General Partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to our General Partner that are in excess of 2% of the aggregate amount of cash being distributed. During July 2007, our General Partner, holder of all of our incentive distribution rights, agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to us after the General Partner receives the initial $7.0 million per quarter. No incentive distributions were declared for the years ended December 31, 2010 and 2009.

Off Balance Sheet Arrangements

As of December 31, 2010, our off balance sheet arrangements are limited to our letters of credit, issued under the provisions of our revolving credit facility, totaling $3.2 million. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate, (ii) surety and (iii) counterparty support.

 

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Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments at December 31, 2010 (in thousands):

 

            Payments Due By Period  

Contractual cash obligations:

   Total      Less than
1 Year
     1 – 3
Years
     4 – 5
Years
     After 5
Years
 

Total debt

   $ 568,529       $ —         $ —         $ 345,479       $ 223,050   

Interest on total debt(1)

     270,608         44,539         89,078         89,012         47,979   

Derivative-based obligations

     10,172         4,564         5,608         —           —     

Capital leases

     838         258         516         64         —     

Operating leases

     10,156         4,737         5,295         124         —     
                                            

Total contractual cash obligations

   $ 860,303       $ 54,098       $ 100,497       $ 434,679       $ 271,029   
                                            

 

(1) Based on the interest rates of our respective debt components as of December 31, 2010.

 

     Total      Amount of Commitment Expiration Per Period  

Other commercial commitments:

      Less than
1 Year
     1 – 3
Years
     4 – 5
Years
     After 5
Years
 

Standby letters of credit

   $ 3,217       $ 3,217       $ —         $ —         $ —     
                                            

Total commercial commitments

   $ 3,217       $ 3,217       $ —         $ —         $ —     
                                            

Common Equity Offerings

In August 2009, we sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. We also received a capital contribution from the General Partner of $0.4 million for the General Partner to maintain its 2.0% general partner interest in us. In addition, we issued warrants granting investors in our private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. We utilized the net proceeds from the common unit offering to repay a portion of our indebtedness under our senior secured term loan and revolving credit facility (see “–Term Loan and Revolving Credit Facility”).

On January 7, 2010, we executed amendments to the warrants which were originally issued in August 2009. 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 net cash proceeds of approximately $15.3 million. On November 30, 2010, we received a capital contribution from the General Partner of $0.3 million for the General Partner to maintain its 2.0% general partner interest in us. We utilized the net proceeds from the common unit offering to repay a portion of our indebtedness under our senior secured term loan and credit facility (see “–Term Loan and Credit Facility”) and to fund the early termination of certain derivative agreements. See “Item 8. Financial Statements and Supplementary Data –Note 11”.

In June 2008, we sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, we sold 1,112,000 common units to ATLS and 278,000 common units to AHD in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. We also received a capital contribution from the General Partner of $5.4 million for the General Partner to maintain its 2.0% general partner interest in us. We utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements.

 

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Preferred Units

Class A Preferred Units

In December 2008, we redeemed 10,000 of the then-outstanding 40,000 cumulative convertible preferred units (“Class A Preferred Units”), owned by Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for $10.0 million in cash under the terms of the agreement. The redemption was classified as a reduction of Class A Preferred Equity within Equity on our consolidated balance sheets.

In January 2009, we and Sunlight Capital amended certain terms of the Class A Preferred Units. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, and (b) required that we issue Sunlight Capital $15.0 million of our 8.125% senior unsecured notes due 2015 (see “–Senior Notes”) to redeem 10,000 Class A Preferred Units. Our management estimated that the fair value of the $15.0 million 8.125% senior unsecured notes issued to redeem the Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded senior notes. As such, we recorded the redemption by recognizing a $10.0 million reduction of Class A Preferred equity within Equity, $15.0 million of additional long-term debt for the face value of the senior unsecured notes issued, and a $5.0 million discount on the issuance of the senior unsecured notes that is presented as a reduction of long-term debt on our consolidated balance sheets. The discount recognized upon issuance of the senior unsecured notes will be amortized to interest expense in our consolidated statements of operations over the term of the notes based upon the effective interest rate method.

In April 2009, we redeemed 10,000 of the Class A Preferred Units for cash at the liquidation value of $1,000 per unit, or $10.0 million and we converted 5,000 of the Class A Preferred Units into 1,465,653 common units, reclassifying $5.0 million from Class A preferred limited partner equity to common limited partner equity within Equity. In May 2009, we redeemed the remaining 5,000 Class A Preferred Units for cash at the liquidation value of $1,000 per unit, or $5.0 million plus $0.2 million, representing the quarterly dividend on the 5,000 Class A Preferred Units prior to our redemption. There are no longer any Class A Preferred Units outstanding.

Class B Preferred Units

In December 2008, we sold 10,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “Class B Preferred Units”) to AHD for cash consideration of $1,000 per Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “Class B Preferred Units Certificate of Designation”).

In March 2009, AHD purchased an additional 5,000 Class B Preferred Units at Face Value. We used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. Additionally, in March 2009, we and AHD agreed to amend the terms of the Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the Class B Preferred Units were not convertible into our common units. The cumulative sale of the Class B Preferred Units to AHD was exempt from the registration requirements of the Securities Act of 1933.

In November 2010, we redeemed the 15,000 units of Class B Preferred Units for cash, at the liquidation value of $1,000 per unit, or $15.0 million, plus $0.2 million accrued dividends representing the quarterly dividend on the 15,000 Class B Preferred Units prior to our redemption. There are no longer any Class B Preferred Units outstanding. See “Item 8. Financial Statements and Supplementary Data –Note 6”.

Class C Preferred Units

On June 30, 2010, we sold 8,000 newly-created 12% Cumulative Class C Preferred Units of limited partner interest (the “Class C Preferred Units”) to ATLS for cash consideration of $1,000 per Class C Preferred

 

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Unit, for total proceeds of $8.0 million. We used the proceeds from the sale of the Class C Preferred Units for general partnership purposes.

The sale of the Class C Preferred Units to ATLS was exempt from the registration requirements of the Securities Act of 1933 by reason of Section 4(2) thereunder and pursuant to SEC staff positions. The Class C Preferred Units receive distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for our common units. The record date for the determination of holders entitled to receive distributions will be the same as the record date for determination of common unit holders entitled to receive quarterly distributions. We have the right to redeem some or all of the Class C Preferred Units (but not less than 2,500 Class C Preferred Units) for an amount equal to the face value of the Class C Preferred Units being redeemed plus all accrued but unpaid dividends. See “Item 8. Financial Statements and Supplementary Data –Note 6”. The Class C Preferred Units are reflected on our consolidated balance sheets as Class C preferred equity within Equity.

Term Loan and Revolving Credit Facility

At December 31, 2010, we had a senior secured credit facility with a syndicate of banks which consisted of a $350.0 million revolving credit facility which matures in December 2015. The term loan, which was a part of the credit facility, was paid in full in September 2010. Borrowings under the revolving credit facility bear interest, at our option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% or (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on the outstanding revolving credit facility borrowings at December 31, 2010 was 3.8%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $3.2 million was outstanding at December 31, 2010. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheets.

Borrowings under the credit facility are secured by a lien on and security interest in all of our property and that of our subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures. Borrowings are also secured by the guaranty of each of our consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. We are also unable to borrow under our credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to our partnership agreement. We are in compliance with these covenants as of December 31, 2010.

The events which constitute an event of default for our revolving credit facility include 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 of our General Partner. As of December 31, 2010, we were in compliance with all covenants under the credit facility.

Senior Notes

At December 31, 2010, we had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“8.125% Senior Notes”; collectively, the “Senior Notes”). Our 8.125% Senior Notes are presented combined with a net $3.4 million of unamortized discount as of December 31, 2010. Interest on the Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The 8.75% Senior Notes are redeemable at any time after June 15, 2013, and the 8.125% Senior Notes are redeemable at any time after December 31, 2010, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, we may redeem up to 35% of the aggregate principal amount of the 8.75% Senior Notes with the proceeds of certain equity offerings at a stated

 

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redemption price. The Senior Notes in the aggregate are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to our secured debt, including our obligations under our credit facility.

In December 2008, we repurchased approximately $60.0 million in face amount of 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 in face amount of 8.125% Senior Notes and approximately $27.0 million in face amount of 8.75% Senior Notes. All of the Senior Notes repurchased have been retired and are not available for re-issue.

In January 2009, we issued Sunlight Capital $15.0 million of our 8.125% Senior Notes to redeem 10,000 Class A Preferred Units (see “–Preferred Units”). Our management estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, we recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on our consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense in our consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

Indentures governing the Senior Notes in the aggregate contain covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of our assets. We are in compliance with these covenants as of December 31, 2010.

In November 2010, we paid $1.3 million to the holders of the 8.125% Senior Notes in connection with a solicited consent received from the majority of holders of those notes to amend certain provisions of the Indenture governing the 8.125% Senior Notes. The amendment allows us to make capital contributions to Laurel Mountain Midstream, LLC through December 31, 2011.

Environmental Regulation

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

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on activities, such as emissions of greenhouse gases and other pollutants, generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/or endangered species. Related to greenhouse gas emissions, cap and trade programs or greenhouse gas permitting programs are being considered by Congress. Depending on the program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels we process. In addition, we could face additional taxes and higher costs of doing business. Although we would not be impacted to a

 

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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. However, we are currently unable to assess the timing and effect of the pending legislation.

We continue to monitor regulatory and legislative activities regarding greenhouse gas production, detection, reporting and mitigation issues. We recognize that greenhouse gas issues continue to be very dynamic topics of discussion within the scientific, business and political communities, and we are committed to staying abreast of developing rules and mandates that will affect our operations and business activities. We participate within industry organizations in order to contribute to consolidated initiatives that are continuously monitoring, addressing and contributing to these greenhouse gas issues, both during and following their development.

Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such charge, or that our efforts will prevent material costs, if any, from rising.

Inflation and Changes in Prices

Inflation affects the operating expenses of our operations due to the increase in costs of labor and supplies. While inflation did not have a material impact on our results of operations for the years ended December 31, 2010, 2009 and 2008, the energy sector realized increased costs during 2008, caused by the demand in energy equipment and services due to the increase in commodity prices. Commodity prices have decreased from their highs in 2008 and the related costs have also declined. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated financial statements included in Item 8, “Financial Statements and Supplementary Data.” The critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The cost of properties, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

Long-lived assets other than goodwill and intangibles with infinite lives are reviewed for impairment

 

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whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset other than goodwill and intangibles with infinite lives is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Forward Looking Statements” elsewhere in this document.

As discussed below, we recognized an impairment of goodwill at December 31, 2008. We believe this impairment of goodwill was an event that warranted assessment of our long-lived assets for possible impairment. During the year ended December 31, 2009, we completed an evaluation of certain assets based on the current operating conditions and business plans for those assets, including idle and inactive pipelines and equipment. Based on the results of this review, we recognized an impairment charge within goodwill and other asset impairments on our consolidated statements of operations of approximately $10.3 million for the year ended December 31, 2009. There were no long-lived asset impairments recognized by us during the years ended December 31, 2010 and 2008.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value.

As a result of our impairment evaluation at December 31, 2008, we recognized a $615.7 million non-cash impairment charge within our consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in our estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. Our estimated fair value of the reporting units 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 recognized by us during the years ended December 31, 2010 and 2009. See “Goodwill” in “Item 8: Financial Statements and Supplementary Data –Note 2” for information regarding our impairment of goodwill and other assets.

Fair Value of Financial Instruments

We use a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:

Level 1– Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

 

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We use a fair value methodology to value the assets and liabilities for our outstanding derivative contracts (see “Item 8. Financial Statements and Supplementary Data –Note 12”). At December 31, 2010, all of our derivative contracts are defined as Level 2, with the exception of our NGL fixed price swaps and NGL options. Our Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. Valuations for our NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations and therefore are defined as Level 3. Valuations for our NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than trading.

General

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

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodical use of derivative instruments. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2010. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties to our commodity-based derivatives are banking institutions currently participating in our revolving credit facility. We may choose to do business with counterparties outside of our credit facility in the future. The creditworthiness of our counterparties is constantly monitored, and we are not aware of any inability on the part of our counterparties to perform under our contracts.

Interest Rate Risk. At December 31, 2010, we had a $350.0 million senior secured revolving credit facility with $70.0 million outstanding. Borrowings under the revolving credit facility bear interest at our option at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% or (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for the revolving credit facility borrowings was 3.8% at December 31, 2010. At December 31, 2010, we had no interest rate derivative contracts. Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our annual interest expense by approximately $3.5 million.

Commodity Price Risk. We are 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. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. We use a number of different derivative instruments in connection with our commodity price risk management activities. We enter into financial swap and option instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows

 

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attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. See “Item 8. Financial Statements and Supplementary Data –Note 11” for further discussion of our derivative instruments. Average estimated 2011 market prices for NGLs, natural gas and condensate, based upon New York Mercantile Exchange (“NYMEX”) forward price curves as of January 11, 2011, are $1.14 per gallon, $4.54 per million BTU and $92.77 per barrel. A 10% change in these prices would change our forecasted gross margin for the twelve-month period ended December 31, 2011 by approximately $13.5 million.

During the years ended December 31, 2010, 2009 and 2008, we made net payments of $25.3 million, $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. The terminated derivative contracts were to expire at various times through 2012. During the years ended December 31, 2010, 2009 and 2008, we recognized the following derivative activity related to the early termination of these derivative instruments within our consolidated statements of operations (in thousands):

Early termination of derivative contracts

 

     For the Years Ended December 31,  
     2010     2009(1)     2008(1)  

Cash paid for early termination

   $ (25,315   $ (5,000   $ (273,987

Deferred recognition of loss on early termination(2)

     —          —          76,345   

Equity applied to prior period early termination

     (8,421     —          —     
                        

Total realized loss at early termination(3)

   $ (33,736   $ (5,000   $ (197,642
                        

Net cash derivative expense included within natural gas and liquids revenue

   $ 12,198      $ —        $ 1,762   

Net cash derivative expense included within other loss, net

     (34,599     (2,260     (103,909

Net cash derivative expense included within discontinued operations

     (11,335     (2,740     (95,495
                        

Total realized loss at early termination(3)

     (33,736     (5,000     (197,642

Recognition of deferred hedge loss from prior periods included within natural gas and liquids revenue(4)

     (25,726     (43,112     (19,764

Recognition of deferred hedge gain (loss) from prior periods included within other income (loss), net(4)

     35,342        31,488        (23,716

Recognition of deferred hedge gain (loss) from prior periods included within discontinued operations(4)

     4,137        (11,994     (28,127
                        

Total realized loss from early termination recognized in current period(3)

   $ (19,983   $ (28,618   $ (269,249
                        

 

(1) Restated to reflect amounts reclassified to discontinued operations due to the sale of Elk City.
(2) Deferred recognition based upon effective portion of hedges deferred to other comprehensive income, plus theoretical premium related to unwound options which had previously been purchased or sold as part of costless collars.
(3) Realized gain (loss) represents the gain/loss recognized when the derivative contract is settled. A portion of realized gain (loss) recognized in other income (loss), net is a reclassification of unrealized gain (loss) previously recognized as a factor of recording the changes in the fair value of the derivatives prior to settlement.
(4) Non-cash recognition of deferred hedge gain (loss) includes (i) theoretical premiums related to calls sold in conjunction with puts purchased in costless collars in which the puts were sold as part of the equity unwinds in 2008 and (ii) the effective portion of hedges deferred to other comprehensive income.

In addition, we will recognize a total of $5.1 million of net income relating to derivative contracts terminated in 2008. This income will be recognized in our consolidated statements of operations during the periods for which the hedged physical transactions are forecasted to be settled, with $2.8 million and $2.3 million of net income to be recognized during the years ending December 31, 2011 and 2012, respectively.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline Partners, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Pipeline Partners, L.P. (a Delaware limited partnership) as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Pipeline Partners, L.P. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atlas Pipeline Partners, L.P.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 25, 2011 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 25, 2011

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

 

     December 31,
2010
    December 31,
2009
 
ASSETS     

Current assets:

    

Cash and cash equivalents

   $ 164      $ 1,021   

Accounts receivable

     99,759        80,019   

Current portion of derivative asset

     —          998   

Prepaid expenses and other

     15,118        13,360   

Current assets of discontinued operations

     —          22,746   
                

Total current assets

     115,041        118,144   

Property, plant and equipment, net

     1,341,002        1,327,704   

Intangible assets, net

     126,379        149,481   

Investment in joint venture

     153,358        132,990   

Long-term portion of derivative asset

     —          361   

Other assets, net

     29,068        30,253   

Long-term assets of discontinued operations

     —          379,030   
                

Total assets

   $ 1,764,848      $ 2,137,963   
                
LIABILITIES AND EQUITY     

Current liabilities:

    

Current portion of long-term debt

   $ 210      $ —     

Accounts payable – affiliates

     12,280        2,043   

Accounts payable

     29,382        19,556   

Accrued liabilities

     30,013        13,320   

Accrued interest payable

     1,921        9,652   

Current portion of derivative liability

     4,564        33,547   

Accrued producer liabilities

     72,996        57,430   

Distribution payable

     240        —     

Current liabilities of discontinued operations

     —          13,181   
                

Total current liabilities

     151,606        148,729   

Long-term portion of derivative liability

     5,608        11,126   

Long-term debt, less current portion

     565,764        1,254,183   

Other long-term liability

     223        398   

Commitments and contingencies

    

Equity:

    

General Partner’s interest

     20,066        15,853   

Class B preferred limited partner’s interest

     —          14,955   

Class C preferred limited partner’s interest

     8,000        —     

Common limited partners’ interests

     1,057,342        787,834   

Investment in Class B cumulative preferred member units of Atlas Pipeline Holdings II, LLC (reported as treasury units)

     —          (15,000

Accumulated other comprehensive loss

     (11,224     (49,190
                

Total partners’ capital

     1,074,184        754,452   

Non-controlling interests

     (32,537     (30,925
                

Total equity

     1,041,647        723,527   
                

Total liabilities and equity

   $ 1,764,848      $ 2,137,963   
                

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

 

     Years Ended December 31,  
     2010     2009     2008  

Revenue:

      

Natural gas and liquids

   $ 890,048      $ 636,231      $ 1,078,714   

Transportation, compression and other fees – third parties

     40,474        41,539        44,149   

Transportation, compression and other fees – affiliates

     619        17,536        43,293   

Other income (loss), net

     4,447        (22,701     36,585   
                        

Total revenue and other income (loss), net

     935,588        672,605        1,202,741   
                        

Costs and expenses:

      

Natural gas and liquids

     720,215        527,730        900,460   

Plant operating

     48,670        45,566        47,371   

Transportation and compression

     1,061        6,657        11,249   

General and administrative

     32,521        34,549        (4,420

Compensation reimbursement – affiliates

     1,500        2,731        1,487   

Depreciation and amortization

     74,897        75,684        71,764   

Goodwill and other asset impairment loss

     —          10,325        615,724   

Interest

     91,632        103,787        89,869   

Gain on early extinguishment of debt

     —          —          (19,867
                        

Total costs and expenses

     970,496        807,029        1,713,637   
                        

Equity income in joint venture

     4,920        4,043        —     

Gain (loss) on asset sales and other

     (10,729     108,947        —     
                        

Loss from continuing operations

     (40,717     (21,434     (510,896
                        

Discontinued operations:

      

Gain on sale of discontinued operations

     312,102        53,571        —     

Earnings (loss) of discontinued operations

     9,053        30,577        (93,802
                        

Income (loss) from discontinued operations

     321,155        84,148        (93,802
                        

Net income (loss)

     280,438        62,714        (604,698

(Income) loss attributable to non-controlling interests

     (4,738     (3,176     22,781   

Preferred unit dividends

     (780     (900     (1,769

Preferred unit imputed dividend cost

     —          —          (505
                        

Net income (loss) attributable to common limited partners and the General Partner

   $ 274,920      $ 58,638      $ (584,191
                        

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

 

     Years Ended December 31,  
     2010     2009     2008  

Allocation of net income (loss) attributable to:

      

Common limited partners’ interest:

      

Continuing operations

   $ (45,347   $ (24,997   $ (503,533

Discontinued operations

     315,021        82,457        (91,917
                        
     269,674        57,460        (595,450
                        

General Partner’s interest:

      

Continuing operations

     (888     (513     13,144   

Discontinued operations

     6,134        1,691        (1,885
                        
     5,246        1,178        11,259   
                        

Net income (loss) attributable to:

      

Continuing operations

     (46,235     (25,510     (490,389

Discontinued operations

     321,155        84,148        (93,802
                        
   $ 274,920      $ 58,638      $ (584,191
                        

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

      

Basic:

      

Continuing operations

   $ (0.85   $ (0.52   $ (11.80

Discontinued operations

     5.92        1.71        (2.16
                        
   $ 5.07      $ 1.19      $ (13.96
                        

Diluted:

      

Continuing operations

   $ (0.85   $ (0.52   $ (11.80

Discontinued operations

     5.92        1.71        (2.16
                        
   $ 5.07 <