Form 10-K

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

10-K 1 d494287d10k.htm FORM 10-K Form 10-K

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, 2012

¨	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: 001-32953

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)


Delaware		43-2094238
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA		15275
(Address of principal executive offices)		Zip code

Registrant’s telephone number, including area code: 412-489-0006

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

Indicate by check mark whether the registrant is 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):

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

The aggregate market value of the voting and non-voting common units held by non-affiliates of the registrant, based on the closing price of such units on the last business day of the registrant’s most recently completed second quarter, June 30, 2012, was approximately $1.5 billion.

The number of outstanding common units of the registrant on February 25, 2013 was 51,370,560.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS


			Page
PART I	Item 1:	Business		7
	Item 1A:	Risk Factors		23
	Item 1B:	Unresolved Staff Comments		54
	Item 2:	Properties		54
	Item 3:	Legal Proceedings		59
	Item 4:	Mine Safety Disclosures		59

PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		59
	Item 6:	Selected Financial Data		60
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		64
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk		97
	Item 8:	Financial Statements and Supplementary Data		101
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		166
	Item 9A:	Controls and Procedures		166
	Item 9B:	Other Information		169

PART III	Item 10:	Directors, Executive Officers and Corporate Governance		169
	Item 11:	Executive Compensation		176
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		194
	Item 13:	Certain Relationships and Related Transactions, and Director Independence ...		197
	Item 14:	Principal Accountant Fees and Services		197

PART IV	Item 15:	Exhibits and Financial Statement Schedules		198

SIGNATURES				205

GLOSSARY OF TERMS

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

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl oil, condensate or natural gas liquids.

Bpd. Barrels per day.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. Acres spaced or assigned to productive wells.

Development well. A well drilled within a proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

EBITDA. Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined in this section.

FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Fractionation. The process used to separate an NGL stream into its individual components.

GAAP. Generally Accepted Accounting Principles.

GPM. Gallons per minute.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

MLP. Master Limited Partnership.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcfd. One MMcf per day.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

MMcfed. One MMcfe per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within gas.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil and condensate.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas that by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PV-10. Present value of future net revenues. See the definition of “standardized measure.”

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

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

SEC. Securities Exchange Commission.

Standardized Measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful well. A well capable of producing oil and/or gas in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Unproved reserves. Lease acreage on which wells have not been drilled and where it is either probable or possible that the acreage contains reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

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, oil, NGLs and condensate;

•

the price volatility of natural gas, oil, NGLs and condensate;

•

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

•

changes in the market price of our common units;

•

future financial and operating results;

•

economic conditions and instability in the financial markets;

•

resource potential;

•

realized natural gas and oil prices;

•

success in efficiently developing and exploiting Atlas Resource Partners, L.P.’s (“ARP”) reserves and economically finding or acquiring additional recoverable reserves;

•

the accuracy of estimated natural gas and oil reserves;

•

the financial and accounting impact of hedging transactions;

•

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

•

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

•

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

•

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

•

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

•

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

•

the ability to raise funds through the investment partnerships or through access to capital markets;

•

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

•

the introduction of Pennsylvania impact fees and severance taxes;

•

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

•

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

•

general market, labor and economic conditions and related uncertainties;

•

the ability to retain certain key customers;

•

dependence on the gathering and transportation facilities of third parties;

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the availability of drilling rigs, equipment and crews;

•

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

•

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

•

ability to identify all risks associated with the acquisition of oil and natural gas properties, pipeline, facilities or existing wells, and the sufficiency of indemnifications we receive from sellers to protect us from such risks;

•

expirations of undeveloped leasehold acreage;

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uncertainty regarding operating expenses, general and administrative expenses and finding and development costs;

•

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

•

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

•

exposure to new and existing litigations;

•

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

•

development of alternative energy resources.

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

statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

As used herein, “Atlas Energy,” “we,” “our,” and similar terms include Atlas Energy, L.P. and its subsidiaries, unless the context indicates otherwise.

PART I

ITEM 1:

BUSINESS

General

We are a publicly-traded Delaware master limited partnership whose common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “ATLS”. Our assets currently consist principally of our ownership interests in the following entities:

•

Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States;

•

Atlas Pipeline Partners, L.P. (“APL”), a publicly-traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in natural gas gathering, processing and treating services in the Anandarko and Permian Basins of the United States; and

•

Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At December 31, 2012, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot.

Our ownership in ARP consists of the following:

•

all of the outstanding Class A units, representing 975,708 units at December 31, 2012, which entitles us to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP;

•

all of the incentive distribution rights in ARP, which entitles us to receive increasing percentages, up to a maximum of 48%, of any cash distributed by ARP as it reaches certain target distribution levels in excess of $0.46 per ARP common unit in any quarter; and

•

20,962,485 common units, representing an approximate 43.0% limited partner ownership interest in ARP at December 31, 2012.

Our ownership of ARP’s incentive distribution rights entitle us to receive an increasing percentage of cash distributed by ARP as it reaches certain target distribution levels. The rights entitle us to receive the following:

•

13.0% of all cash distributed in any quarter after each ARP common unit has received $0.46 for that quarter;

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23.0% of all cash distributed in any quarter after each ARP common unit has received $0.50 for that quarter; and

•

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

Our ownership of APL consists of the following:

•

a 2.0% general partner interest, which entitles us to receive 2% of the cash distributed by APL;

•

all of the incentive distribution rights in APL, which entitles us to receive increasing percentages, up to a maximum of 48%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in 2007, we agreed to allocate up to $3.75 million of our incentive distribution rights per quarter back to

APL, after we receive an initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”); and

•

5,754,253 common units, representing an approximate 8.7% limited partner interest in APL.

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

•

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

•

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

•

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

In February 2012, the board of directors of our General Partner (“the Board”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of our natural gas and oil development and production assets and the partnership management business to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.24 million ARP common units to our unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of our common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.

On February 17, 2011, we acquired certain assets and liabilities (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner, including the following exploration and production assets that were transferred to ARP on March 5, 2012:

•

AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which ARP funds a portion of its natural gas and oil well drilling;

•

proved reserves located in the Appalachian Basin, the Niobrara formation in Colorado, the New Albany Shale of west central Indiana, the Antrim Shale of northern Michigan and the Chattanooga Shale of northeastern Tennessee;

•

certain producing natural gas and oil properties, upon which ARP is the developer and producer;

•

all of the ownership interests in Atlas Energy GP, LLC, our general partner; and

•

direct and indirect ownership interests in Lightfoot.

Our operations include three reportable operating segments: ARP, APL, and corporate and other (see “Item 8: Financial Statements and Supplementary Data”).

Atlas Resource Partners Overview

ARP’s primary business objective is to generate growing yet stable cash flows through the development and acquisition of mature, long-lived natural gas and oil properties. As of December 31, 2012, ARP’s estimated proved reserves were 723.4 Bcfe, including reserves net to its equity interest in its investment partnerships. Of ARP’s estimated proved reserves, approximately 56% were proved developed and approximately 79% were natural gas. For the year ended December 31, 2012, ARP’s average daily net production was approximately 77.2 MMcfe. Through December 31, 2012, ARP owns production positions in the following areas:

•

the Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas. ARP has ownership interests in over 525 wells in the Barnett Shale and Marble Falls play and 569.3 Bcfe of total proved reserves with average daily production of 31.9 MMcfe for the year ended December 31, 2012;

•

the Appalachia basin, including the Marcellus Shale and the Utica Shale. ARP has ownership interests in over 10,200 wells primarily in the Appalachian basin, including approximately 270 wells in the Marcellus Shale and 112.6 Bcfe of total proved reserves with average daily production of 35.6 MMcfe for the year ended December 31, 2012;

•

the Mississippi Lime and Hunton plays in northwestern Oklahoma. ARP owns 21.0 Bcfe of total proved reserves with average daily production of 1.9 MMcfe for the year ended December 31, 2012; and

•

the Chattanooga Shale in northeastern Tennessee, the Niobrara Shale in northeastern Colorado, the New Albany Shale in southwestern Indiana, and the Antrim Shale in Michigan, in which ARP has an aggregate 20.5 Bcfe of total proved reserves with average daily production of 7.8 MMcfe for the year ended December 31, 2012.

ARP seeks to create substantial value by executing its strategy of acquiring properties with stable, long-life production, relatively predictable decline curves and lower risk development opportunities. Overall, ARP has acquired significant net proved reserves and production through the following transactions:

•

Carrizo Barnett Shale Assets – On April 30, 2012, ARP acquired 277 Bcfe of proved reserves, including undeveloped drilling locations, in the core of the Barnett Shale from Carrizo Oil & Gas, Inc. (NASD: CRZO; “Carrizo”), for approximately $187.0 million, which was funded by $119.5 million through the private placement of 6.0 million of ARP’s common units and $67.5 million of borrowings under ARP’s revolving credit facility. The assets include 198 gross producing wells generating approximately 31 MMcfed of production at the date of acquisition on over 12,000 net acres, all of which are held by production.

•

Titan Barnett Shale Assets – On July 26, 2012, ARP acquired Titan Operating, L.L.C. (“Titan”), which owned approximately 250 Bcfe of proved reserves and associated assets in the Barnett Shale on approximately 16,000 net acres, which are 90% held by production, for approximately 3.8 million of ARP’s common units and approximately 3.8 million of its Class B convertible preferred units (which had an estimated collective value of $193.2 million based upon the closing price of its publicly-traded common units as of the acquisition closing date) and approximately $15.4 million in cash for closing adjustments. Titan’s assets are located in close proximity to the assets acquired from Carrizo in the Barnett Shale. Net production from these assets at the date of acquisition was approximately 24 MMcfed, including approximately 370 Bpd of natural gas liquids. ARP believes there are approximately 335 potential undeveloped drilling locations on the Titan acreage.

•

DTE Fort Worth Basin Assets – On December 20, 2012, ARP acquired 210 Bcfe of proved reserves in the Fort Worth basin from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million. The assets include 261 gross producing wells generating approximately 23 MMcfed of production at the date of acquisition on over 88,000 net acres, approximately 40% of which are held by production and approximately 33% are in continuous development. The acreage position includes approximately 75,000 net acres prospective for the oil and NGL-rich Marble Falls play, in which there are over 700 identified vertical drilling locations. ARP believes that there are further potential development opportunities through vertical down-spacing and horizontal drilling in the Marble Falls formation, in which it expects to commence drilling operations by early 2013. The assets acquired from DTE are in close proximity to ARP’s other assets in the Barnett Shale.

•

Equal Mississippi Lime Assets – On April 4, 2012, ARP entered into an agreement with Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equal”), to acquire a 50% interest in Equal’s approximately 14,500 net undeveloped acres in the core of the oil and liquids rich Mississippi Lime play in northwestern Oklahoma for approximately $18 million. On September 24, 2012, ARP acquired Equal’s remaining 50% interest in approximately 8,500 net undeveloped acres included in the joint venture, approximately 8 MMcfed of net production in the region at the date of acquisition and substantial salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. Both transactions were financed through borrowings under ARP’s revolving credit facility. The transaction increased ARP’s position in the Mississippi Lime play to 19,800 net acres in Alfalfa, Grant and Garfield counties in Oklahoma.

In addition to its acquisition strategy, ARP has targeted certain high-returning plays, including the Marcellus Shale in northeastern Pennsylvania and the Utica Shale in eastern Ohio, for organic leasing efforts and development. In the Marcellus Shale, ARP has leased acreage in Lycoming County in northeast Pennsylvania, a highly desirable and productive dry gas area, where it has completed three pad sites that will each accommodate multiple horizontal wells, of which eight wells are in various stages of drilling as of December 31, 2012. ARP also has prospective Utica Shale acreage in Harrison, Tuscarawas, and Stark counties, Ohio, highly desirable areas which have experienced escalated permitting and drilling activity, where it has five horizontal wells in Harrison County in various stages of drilling as of December 31, 2012. ARP currently has interests in approximately 2,500 wells in Ohio and operates three field offices, which it intends to use to manage future Utica Shale development. With over 1,250 attractive drilling locations at current commodity prices on approximately 144,000 undeveloped acres that it is actively developing, ARP believes it has significant organic growth opportunities.

Atlas Pipeline Partners Overview

APL conducts its business in the midstream segment of the natural gas industry through two reportable segments: gathering and processing; and transportation, treating and other.

The gathering and processing segment consists of (1) the Arkoma, WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko, Arkoma and Permian Basins; (2) natural gas gathering assets located in the Barnett Shale play in Texas and the Appalachian Basin in Tennessee; and (3) through the year ended December 31, 2011, the revenues and gain on sale related to its former 49% interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”). Gathering and processing revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas.

APL’s gathering and processing operations, own, have interests in and operate twelve natural gas processing plants with aggregate capacity of approximately 1,090 MMcfd located in Oklahoma and Texas; a gas treating facility located in Oklahoma; and approximately 10,100 miles of active natural gas gathering systems located in Oklahoma, Kansas, Tennessee and Texas. APL’s gathering systems gather natural gas from oil and natural gas wells and central delivery points and deliver this gas to processing plants, as well as third-party pipelines.

APL’s gathering and processing operations are all located in or near areas of abundant and long-lived natural gas production including the Golden Trend, Mississippian Limestone and Hugoton field in the Anadarko Basin; the Woodford Shale; the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin; and the Barnett Shale. APL’s gathering systems are connected to approximately 8,600 receipt points, consisting primarily of individual well connections and secondarily, central delivery points, which are linked to multiple wells. APL believes it has significant scale in each of its primary service areas. APL provides gathering, processing and treating services to the wells connected to its systems, primarily under long-term contracts. As a result of the location and capacity of its gathering, processing and treating assets, APL believes it is strategically positioned to capitalize on the drilling activity in its service areas.

APL’s transportation and treating operations consists of (1) seventeen gas treating facilities used to provide contract treating services to natural gas producers located in Arkansas, Louisiana, Oklahoma and Texas; and (2) a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), which owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation (NYSE: CVX; “Chevron”), which owns the remaining 80% interest. The contract gas treating operations are located in various shale plays including the Avalon, Eagle Ford, Granite Wash, Haynesville, Fayetteville and Woodford.

APL has expanded its business and created substantial value by executing its strategy of acquiring additional accretive assets, including the following transactions consummated during 2012:

•

WestOK Gas Gathering System – In February 2012, APL acquired a gas gathering system and related assets, at its WestOK region, for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts, subject to delivery of certain minimum volumes of natural gas from a specified area and within certain specified time periods (“Trigger Payments”). In connection with this acquisition, APL received assignment of the gas purchase agreements for natural gas then currently gathered on the acquired system.

•

Barnett Shale Gas Gathering System – In June 2012, APL acquired a gas gathering system and related assets in the Barnett Shale in Tarrant County, Texas for an initial net purchase price of $18.0 million. The system is used to facilitate gathering of newly acquired natural gas production of ARP.

•

Cardinal Midstream – In December 2012, APL acquired 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.5 million in cash, including preliminary purchase price adjustments. The assets of these companies include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas as follows:

•

the Tupelo plant, which is a 120 MMcfd cryogenic processing facility;

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approximately 60 miles of gathering pipeline;

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the East Rockpile treating facility, a 250 GPM amine treating plant;

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a fixed fee contract gas treating business that includes fifteen amine treating plants and two propane refrigeration

plants; and

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a 60% interest in Centrahoma Processing, LLC joint venture (“Centrahoma”). The remaining 40% interest is owned by MarkWest Oklahoma Gas Company, LLC, (“MarkWest”) a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). Centrahoma owns the following assets:

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the Coalgate and Atoka plants, which are cryogenic processing facilities with a combined current processing capacity of approximately 100 MMcfd;

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the prospective Stonewall plant, for which construction has been approved, with anticipated processing capacity of 120 MMcfd; and

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15 miles of NGL pipeline.

APL intends to continue to expand its business through strategic acquisitions and internal growth projects in efforts to increase distributable cash flow.

Contractual Revenue Arrangements

Atlas Resource Partners

Natural gas. ARP markets the majority of its natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indexes are as follows: Appalachian Basin and Mississippi Lime, primarily the New York Mercantile Exchange (“NYMEX”) spot market price; Barnett Shale and Marble Falls, primarily the Waha spot market price; New Albany Shale and Antrim Shale, primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation, primarily the Cheyenne Hub spot market price.

ARP does not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of its other operating areas, ARP occasionally commits a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

Crude oil. Crude oil produced from ARP’s wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. ARP does not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural gas liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas (low Btu content) to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as described above and our NGLs are generally priced using the Mont Belvieu (TX) regional processing hub. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. ARP does not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2012, Chevron and Atmos Energy Marketing, LLC accounted for approximately 43% and 11% of ARP’s total natural gas and oil production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Investment partnerships. ARP generally has funded a portion of its drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for its drilling activities, its investment partnerships are a source of fee-based revenues, which are not directly dependent on commodity prices. As managing general partner of the investment partnerships, ARP receives the following fees:

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Well construction and completion. For each well that is drilled by an investment partnership, ARP receives a 15% to 18% mark-up on those costs incurred to drill and complete the well;

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Administration and oversight. For each well drilled by an investment partnership, ARP receives a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the partnership pays ARP a monthly per

well administrative fee of $75 for the life of the well. Because ARP coinvests in the partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the well; and

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Well services. Each partnership pays ARP a monthly per well operating fee, currently $100 to $2,000, for the life of the well. Because ARP coinvests in the partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the wells.

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Gathering. Each royalty owner, partnership and certain other working interest owners pay ARP a gathering fee, which in general is equivalent to the fees ARP remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective investment partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses within its partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from Drilling Partnerships by approximately 3%.

Atlas Pipeline Partners

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

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

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

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

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the contract terms with each producer; and

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

APL has natural gas purchase, gathering and processing agreements with approximately 600 producers. These agreements provide for the purchase or gathering of natural gas under Fee-Based, Percentage of Proceeds (“POP”) or Keep-Whole arrangements. Many of the agreements provide for compression, processing and/or low volume fees. Producers generally provide, in-kind, their proportionate share of compressor and plant fuel required to gather the natural gas and to operate APL’s processing plants. In addition, the producers generally bear their proportionate share of gathering system line loss and, except for Keep-Whole arrangements, bear natural gas plant “shrinkage” for the gas consumed in the production of NGLs.

APL has long-term, service-driven relationships with its producing customers, who comprise some of the largest producers in its areas. Several of APL’s top producers have contracts with primary terms running into 2020 and beyond. At the end of the primary terms, most of the contracts with producers on its gathering systems have evergreen term extensions. On APL’s WestTX system, it has a gas sales and purchase agreement with Pioneer with a term extending into 2022. The gas sales and purchase agreement requires all Pioneer wells within an “area of mutual interest” be dedicated to that system’s gathering and processing operations in return for specified natural gas processing rates. Through this agreement, APL anticipates it will continue to provide gathering and processing for the majority of Pioneer’s wells in the Spraberry Trend of the Permian Basin. On APL’s WestOK system, it recently entered into a new contract with SandRidge with a term currently extending through 2017. As part of the agreement SandRidge has agreed to dedicate the majority of its developed acreage covering the Mississippian Lime formation. APL believes that its relationships with these key producers will provide it with a competitive advantage in adding new natural gas supplies, retaining previously connected volumes and continuing to increase its scale and presence in its operating area.

APL typically sells natural gas to purchasers downstream of its processing plants priced at various first-of-month indices as published in Inside FERC. Additionally, swing gas, which is natural gas sold during the current month, is sold daily at various Platt’s Gas Daily midpoint prices. The Arkoma system has access to Centerpoint Energy, Inc.; Enogex LLC; and MarkWest Energy Partner’s Arkoma connector pipeline. The Velma system has access to ONEOK Gas Transportation, LLC, Southern Star Central Gas Pipeline, Inc. and Natural Gas Pipeline Company of America. The WestOK system has access to Enogex LLC, Panhandle Eastern Pipe Line Company, LP and Southern Star Central Gas Pipeline, Inc. The WestTX system has access to Kinder Morgan Texas Pipeline, Northern Natural Gas Company and El Paso Natural Gas Company.

APL sells most of its NGL production to ONEOK Hydrocarbon, L.P. (“ONEOK”) under four separate agreements. The WestTX agreement has a term expiring in 2013; the WestOK agreement has a term expiring in 2014; the Velma agreement has a term expiring at the end of 2016; and the Arkoma agreement has a term expiring in 2024. APL has signed agreements with DCP NGL Services, LLC (“DCP”), a subsidiary of DCP Midstream, LLC, to sell its NGL production from its WestOK, WestTX and Velma processing facilities upon the expiration of each of the ONEOK agreements. The DCP agreements each have a term of fifteen years. DCP has agreed to purchase NGL production from APL’s WestTX processing facilities, on an interim basis, under the same terms as the new agreement with DCP, for those volumes which are in excess of the volumes sold under the ONEOK agreement. At WestOK, APL sells NGL production at the Chaney Dell plant to Murphy Energy Corporation. All NGL agreements are priced at the average daily Oil Price Information Service (“OPIS”) price for the month for the selected market, subject to reduction by a “Base Differential” for transportation and/or fractionation fees and/or quality adjustment fees.

Condensate is collected at the Arkoma plants and gathering systems and currently sold to Enterprise Products Partners, L.P. Condensate is collected at the Velma gas plants and gathering systems and currently sold to EnerWest Trading Company, LLC. Condensate collected at the WestOK plants and gathering systems is currently sold to Plains Marketing, L.P. Condensate collected at the WestTX plants and gathering systems is currently sold to Plains Marketing, L.P. and Occidental Energy Marketing, Inc.

For the year ended December 31, 2012, Oneok Hydrocarbon, LP and Tenaska Marketing Ventures accounted for approximately 48% and 15% of APL’s consolidated total third-party revenues, respectively, excluding the impact of all financial derivative activity, with no other single customer accounting for more than 10% for this period.

Commodity Risk Management

Atlas Resource Partners

ARP seeks to provide greater stability in its cash flows through its use of financial hedges. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ARP and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow ARP to mitigate hydrocarbon price risk, and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with ARP’s secured credit facility do not require cash margin and are secured by ARP’s natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, ARP has a management committee to assure that all financial trading is done in compliance with its hedging policies and procedures. ARP does not intend to contract for positions that it cannot offset with actual production.

Atlas Pipeline Partners

APL’s gathering and processing operations are exposed to certain commodity price risks. These risks result from either taking title to natural gas, NGLs and condensate, or being obligated to purchase natural gas to satisfy contractual obligations with certain producers. APL attempts to mitigate a portion of these risks through a commodity price risk management program, which employs a variety of financial tools. The resulting combination of the underlying physical business and the commodity price risk management program attempts to convert the physical price environment that consists of floating prices to a risk-managed environment characterized by (1) fixed prices; (2) floor prices on products where APL is long the commodity; and (3) ceiling prices on products where APL is short the commodity. There are also risks inherent within risk management programs, including among others, deterioration of the price relationship between the physical and financial instrument; and changes in projected physical volumes.

APL is exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of APL’s contractual relationships with natural gas producers or, alternatively, a function of cost

of sales. APL is therefore exposed to price risk at a gross profit level rather than at a revenue level. These cost-of-sales or contractual relationships are generally of two types:

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

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

APL manages a portion of these risks by using fixed-for-floating swaps, which result in a fixed price for the products it buys or sells or by utilizing the purchase of put or call options, which result in floor prices or ceiling prices for the products it buys or sells. APL utilizes natural gas swaps and options to manage its natural gas price risks. APL utilizes NGL and crude oil swaps and options to manage its NGL and condensate price risks.

APL generally realizes gains and losses from the settlement of its derivative instruments at the same time it sells the associated physical residue gas or NGLs. APL also records the unrealized gains and losses for the mark-to-market valuation of derivative instruments prior to settlement. APL determines gains or losses on open and closed derivative transactions as the difference between the derivative contract price and the physical price. This mark-to-market methodology uses (1) daily closing NYMEX prices; (2) third party sources and/or (3) an internally-generated algorithm, utilizing third party sources, for commodities not traded on an open market. To ensure these derivative instruments will be used solely for managing price risks and not for speculative purposes, APL has established a committee to review its derivative instruments for compliance with its policies and procedures.

Competition

Atlas Resource Partners

The energy industry is intensely competitive in all of its aspects. ARP operates in a highly competitive environment for acquiring properties and other energy companies, attracting capital through its investment partnerships, contracting for drilling equipment and securing trained personnel. ARP also competes with the exploration and production divisions of public utility companies for mineral property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of hydrocarbons in commercial quantities. ARP’s competitors may be able to pay more for hydrocarbon properties and to evaluate, bid for and purchase a greater number of properties than ARP’s financial or personnel resources permit. Furthermore, competition arises not only from numerous domestic and foreign sources of hydrocarbons but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling natural gas, crude oil, and natural gas liquids.

Many of ARP’s competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their hydrocarbon production more effectively than we do. Moreover, ARP also competes with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

Atlas Pipeline Partners

In APL’s gathering and processing segment, it competes for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by Access Midstream Partners, LP; Caballo Energy, LLC, Carrera Gas Company; Copano Energy, LLC; Crosstex Energy Services, L.P.; DCP Midstream, LLC; Energy Transfer Partners, LP.; Enogex, LLC; Lumen Midstream Partners, LLC; MarkWest Energy Partners, L.P.; Mustang Fuel Corporation; ONEOK Field Services Company, LLC; Scissor Tail Energy, LLC; SemGas, L.P.; Southern Union Company; Superior Pipeline Company, LLC; Targa Resources Partners LP; and West Texas Gas, Inc.

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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;

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

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

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

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

In APL’s transportation and treating segment, APL competes with other intrastate and interstate pipeline companies that transport NGLs in the southwestern region of the United States. These operations include NGL pipelines operated by DCP NGL Services, LLC; Enterprise Partners, L.P.; Lonestar NGL, LLC; and ONEOK Partners, L.P. APL also competes for gas treating services provided on gas gathering lines, including gas treating services provided by Kinder Morgan Energy Partners, L.P.; Spartan Energy Partners LLC; Zephyr Gas Services LLC; and TransTex Hunter, LLC.

The factors that typically affect our ability to compete for NGL supplies and or gas treating services are:

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fees charged under its contracts;

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the quality and efficiency of its operations;

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location of its transportation systems relative to its competitors; and

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the responsiveness to a customer’s needs.

Environmental Matters and Regulation

Overview. APL’s operations of pipelines, plant and other facilities for gathering, compressing, treating, processing, or transporting natural gas, NGLs and other products, and ARP’s operations relating to drilling and waste disposal, are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, APL and ARP must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact their business activities in many ways, such as by:

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restricting the way waste disposal is handled;

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

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requiring the acquisition of various permits before the commencement of drilling;

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requiring the installation of expensive pollution control equipment and water treatment facilities;

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restricting the types, quantities and concentration of various substances that can be released into the environment in connection with drilling, completion and production activities;

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require remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;

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

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imposing substantial liabilities for pollution resulting from operations; and

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with respect to operations affecting federal lands or leases, requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

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. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would

otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

We believe that APL and ARP’s operations are in substantial compliance with applicable environmental laws and regulations, and 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 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.

Environmental laws and regulations that could have a material impact on APL’s and ARP’s operations include the following:

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of ARP’s proposed exploration and production activities on federal lands require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil and natural gas constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as solid waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

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

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

ARP’s operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. APL currently owns or leases, and has in the past owned or leased, numerous properties that for many years were used for the measurement, gathering, field compression and processing of natural gas. Although APL and ARP each believe that they utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by them or on or under other locations, including off-site locations, where such substances have been taken for disposal. There may be

evidence that petroleum spills or releases have occurred at some of the properties owned or leased by APL or ARP. However, none of these spills or releases appear to be material to our financial condition and we believe all of them have been or will be appropriately remediated. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under APL or ARP’s 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 substances and 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 remedial plugging or pit closure operations to prevent future contamination.

Water discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, much of ARP’s natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that APL and ARP’s operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. APL and ARP’s operations are subject to the federal Clean Air Act, as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require obtaining 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. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Various air quality regulations are periodically reviewed by the EPA and are amended as deemed necessary. The EPA may also issue new regulations based on changing environmental concerns. Recently, the EPA issued amended regulations that will affect operation of a portion of APL’s compressor engine fleet by requiring implementation of new monitoring requirements in calendar year 2013.

In 2012, specific federal regulations applicable to the natural gas industry were finalized under the New Source Performance Standards (“NSPS”) program along with National Emissions Standards for Hazardous Air Pollutants (“NESHAP”). These new regulations impose additional emissions control requirements and practices on our operations. Some of APL or ARP’s new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities. APL or ARP’s failure to comply with these requirements could subject them to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. APL and ARP each believe that its operations are in substantial compliance with the requirements of the Clean Air Act.

While APL and ARP will likely 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, APL and ARP believe that their operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to them than other similarly situated companies.

OSHA and other regulations. APL and ARP are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in APL and ARP’s operations. APL and ARP believe that they are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Greenhouse gas regulation and climate change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on APL or ARP’s businesses. However, Congress has been actively considering

climate change legislation. More directly, the EPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts V. EPA, 549 U.S. 497 (2007)(holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will impact APL and ARP’s businesses.

First, the EPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31514 (June 3, 2010). Both the federal preconstruction review program (Prevention of Significant Deterioration; “PSD”) and the operating permit program (“Title V”) are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain Title V operating permits.

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions, and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported for 2012 no later than April 1, 2013. This rule imposes additional obligations on APL and ARP to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussion intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements that could have an impact on APL and ARP’s businesses.

Finally, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe that these conditions are having any material current adverse impact on APL or ARP’s businesses, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

Rates, Terms, and Conditions of Service for Gathering Pipelines. 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 FERC. APL owns a number of intrastate natural gas gathering lines in Kansas, Oklahoma and Texas that it believes meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated natural gas transportation facilities and federally-unregulated natural gas gathering facilities is the subject of regular litigation, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC and the courts.

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

APL’s gathering operations could be adversely affected should it be subject in the future to the application of state or federal regulation of rates and services. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. APL 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 APL’s revenue is tied to the price of natural gas and NGLs. The wholesale price of natural gas and NGLs is not currently subject to federal regulation and, for the most part, is not subject to state regulation. Sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation of natural gas and NGLs are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the segments of the natural gas industry, most notably interstate natural gas transportation companies that remain subject to FERC’s jurisdiction. While FERC is less active in proposing changes in the manner in which it regulates the transportation of NGLs under the Interstate Commerce Act, it does nevertheless have authority to address the rates, terms and conditions under which NGLs are transported. FERC initiatives could, therefore, affect the intrastate transportation of natural gas and NGLs under certain circumstances. APL cannot predict the ultimate impact of any regulatory changes that could result from such FERC initiatives on its 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 promote deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the provisions of primary interest to APL as an operator of natural gas gathering lines and sellers of natural gas focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement.

Regarding infrastructure development, the Energy Policy Act includes provisions confirming FERC has exclusive jurisdiction over the siting of liquefied natural gas (“LNG”) terminals; provides for market-based rates for certain new underground natural gas storage facilities placed into service after the date of enactment; shortens depreciable life for gathering facilities; statutorily designates FERC as the lead agency for federal authorizations and permits relating to interstate natural gas pipelines and LNG terminals; provides for the assembly of a consolidated record for all federal decisions relating to necessary authorizations and permits with respect to interstate natural gas pipelines and LNG terminals; and provides for expedited judicial review of any agency action involving the permitting of such facilities and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act on a permit relating to an interstate natural gas pipeline or LNG terminal by a deadline set by FERC as lead agency. Such provisions, however, do not apply to review and authorization under the Coastal Zone Management Act of 1972.

Regarding market transparency and manipulation, the Natural Gas Act has been amended to prohibit market manipulation and directs FERC to prescribe rules designed to encourage the public provision of data and reports regarding the price of natural gas in wholesale markets. The Natural Gas Act and the Natural Gas Policy Act were also amended to increase monetary criminal penalties to $1,000,000 from the $5,000 amount specified under prior law and to add and increase civil penalty authority to be administered by FERC to $1,000,000 per day per violation without any limitation as to total amount.

At present, APL does not believe that its gathering lines qualify as interstate natural gas transmission systems subject to FERC regulation under the Natural Gas Act. Accordingly, the provisions of the Energy Policy Act have only limited applicability to APL, primarily in its capacity as a seller of natural gas.

Much of ARP’s natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974 (“SDWA”). This amendment effectively excluded hydraulic fracturing for oil, gas, or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on ARP’s business and operations. For instance, the U.S. EPA published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” (“Draft Diesel Guidance”) on May 10, 2012 for public comment through August 23, 2012. In that Draft Diesel Guidance, the EPA asserts SDWA permitting authority over hydraulic fracturing activities that employ the injection of diesel fuel. The EPA is in the process of reviewing the comments to the Draft Diesel Guidance, and at present we are not aware of EPA’s timeframe to respond to the comments it received from the public.

The U.S. Senate and House of Representatives considered legislative bills in the 111^th and 112^th Sessions of Congress that, if enacted, would repeal the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act” (“Frac Act”), the proposed legislative bills as proposed could potentially lead to significant oversight of hydraulic fracturing activities by federal and state agencies. These legislative bills, if re-introduced, or any similar legislation introduced in the 113^th Session of Congress could potentially result in significant

regulatory oversight if enacted into law, which may include additional permitting, monitoring, recording, and recordkeeping requirements for ARP.

ARP believes its operations are in substantial compliance with existing SDWA requirements. However, future compliance with the SDWA could result in additional requirements and costs due to the possibility that new or amended laws, regulations, or policies could be implemented or enacted in the future.

Pipeline Safety. Some of APL’s pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”), under the pipeline safety laws, 49 U.S.C. §§ 60101 et seq. The pipeline safety laws authorize DOT to regulate pipeline facilities and persons engaged in the transportation by pipeline of gas, i.e., natural gas, flammable gas, or gas that is toxic or corrosive, and hazardous liquids, i.e., petroleum or petroleum products, including NGLs, and other designated substances that pose an unreasonable risk to life or property when transported in liquid state. The DOT Secretary has delegated that authority to one of the Department’s modal administrations, the Pipeline and Hazardous Material Safety Administration (“PHMSA”). Acting primarily through the Office of Pipeline Safety (“OPS”), PHMSA administers the national regulatory program to ensure the safety of transportation-related gas and hazardous liquid pipeline facilities.

As part of that national program, PHMSA has established minimum federal safety standards for the design, construction, testing, operation, and maintenance of gas and hazardous liquid pipeline facilities. These safety standards apply to most pipeline facilities in the United States, including gathering lines, transmission lines, and distribution lines, and are the only safety requirements that apply to interstate pipeline facilities. PHMSA has also promulgated a series of reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, OPS performs pipeline safety inspections and has the authority to initiate enforcement actions, which can lead to the assessment of administrative civil penalties of up to $200,000 per day, per violation, not to exceed $2,000,000 for any related series of violations.

PHMSA also oversees a program that allows the states to submit an annual certification to regulate intrastate pipeline facilities. States that participate in the program can apply additional or more stringent safety standards to the pipeline facilities under their certifications, so long as those standards are compatible with the minimum federal requirements. States can also enter into agreements with PHMSA to participate in the oversight of intrastate or interstate pipelines, primarily by performing inspections for compliance with preemptive federal safety standards. The Kansas Corporation Commission, the Oklahoma Corporation Commission, and the Texas Railroad Commission all participate in the federal gas pipeline safety program and have a certification to regulate intrastate gas pipeline facilities. The Oklahoma Corporation Commission and the Texas Railroad Commission also have a certification to regulate intrastate hazardous liquid pipeline facilities.

APL’s operations are required to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation and appropriate state authorities. APL believes its pipeline operations are in substantial compliance with the federal pipeline safety laws and regulations and any state laws and regulations that apply to its pipeline facilities. However, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, the activities needed to ensure future compliance could result in additional costs.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Act”) was signed into law. The Act requires DOT and the U.S. Government Accountability Office to complete a number of reviews, studies, evaluations, and reports in preparation for potential rulemakings applicable to pipeline facilities. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. PHMSA is considering these and other provisions in the Act and has sought public comment on changes to a number of regulations related to pipeline safety. At this time, APL cannot predict what effect, if any, the future application of such regulations might have on its operations, but the midstream natural gas industry could be required as a result to incur additional capital expenditures and increased operating costs.

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

Chemicals of Interest. APL operates several facilities registered with the U.S. Department of Homeland Security (“DHS”), in order to identify the quantities of various chemicals 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 recovered and stored as a result of facility processing activities, and various chemicals utilized within the processes, have been identified and registered with DHS. These registration requirements for Chemical of Interest were first promulgated by DHS in 2008 and we are currently in compliance with the Department’s requirements. None of APL’s affected facilities are considered high security risks by DHS at this time and no specific security plans for such per DHS regulations are required.

Drilling and production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil ARP can produce from its wells or limit the number of wells or the locations at which it can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

State regulation and taxation of drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Michigan imposes a 5% severance tax on natural gas and a 6.6% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.025 per Mcf of natural gas and $0.10 per bbl of oil, Indiana imposes a severance tax of $0.03 per Mcf on natural gas and $0.24 per bbl of oil, Colorado imposes a severance tax up to 5% of the value of oil and gas severed from earth, in addition to other applicable taxes, while West Virginia imposes a 5% severance tax on oil and gas. Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2012, the impact fee for qualifying unconventional horizontal wells spudded during 2012 was $45,000 per well, while the impact fee for unconventional vertical wells was reduced to twenty percent of the horizontal well fee. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for a horizontal well and 10 years for a vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from ARP’s wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which it can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and a fee of $0.000667 per Mcf of gas produced. Oklahoma imposes a gross production tax of 7% per bbl of oil, 7% per Mcf of natural gas and a petroleum excise tax of $0.095 on the gross production of oil and gas. Texas imposes a severance tax of 7.5% on the market value of gas produced and saved and 4.6% on the market value of condensate and oil produced.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Oil spills and hydraulic fracturing. The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While ARP believes it has been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

A number of federal agencies, including but not limited to the EPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, EPA is conducting a study that evaluates any potential impacts of hydraulic fracturing on drinking water and ground water. EPA released a progress report on this study on December 21, 2012 that did not present any conclusions, but notes that results will be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board.

In addition, state, local conservancy districts and river basin commissions have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. State regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include, but not be limited to, the following:

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requirement that logs and pressure test results are included in disclosures to state authorities;

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disclosure of hydraulic fracturing fluids and chemicals, and the ratios of same used in operations;

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specific disposal regimens for hydraulic fracturing fluids;

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replacement/remediation of contaminated water assets; and

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minimum depth of hydraulic fracturing.

Local regulations, which may be preempted by state and federal regulations, have included the following which may extend to all operations including those beyond hydraulic fracturing:

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noise control ordinances;

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traffic control ordinances;

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limitations on the hours of operations; and

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mandatory reporting of accidents, spills and pressure test failures.

Other regulation of the natural gas and oil industry. The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. APL and ARP’s operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Employees

As of December 31, 2012, we employed 832 persons.

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, our current reports on Form 8-K, and any amendments to those reports, available through our website at www.atlasenergy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). 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 Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, Pennsylvania 15275, telephone number (412) 489-0006. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

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

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

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

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the level of domestic and foreign supply and demand;

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the price and level of foreign imports;

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the level of consumer product demand;

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weather conditions and fluctuating and seasonal demand;

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overall domestic and global economic conditions;

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

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

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

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technological advances affecting energy consumption;

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domestic and foreign governmental relations, regulations and taxation;

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the impact of energy conservation efforts;

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

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the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2012, the NYMEX Henry Hub natural gas index price ranged from a high of $3.90 per MMBtu to a low of $1.91 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $109.77 per Bbl to a low of $77.69 per Bbl. Between January 1, 2013 and February 25, 2013, the NYMEX Henry Hub natural gas index price ranged from a high of $3.57 per MMBtu to a low of $3.11 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $97.94 per Bbl to a low of $92.84 per Bbl.

We may not have sufficient cash to pay distributions.

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

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

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

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

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

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

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

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

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

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

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

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our unitholders’ proportionate ownership interest in us will decrease;

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

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

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the ratio of taxable income to distributions may increase; and

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the market price of the common units may decline.

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

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

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an increase in our operating expenses;

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an increase in general and administrative expenses;

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

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an increase in working capital requirements.

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

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

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

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pay distributions or redeem or repurchase our securities;

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prepay, redeem or repurchase debt;

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make loans, investments and acquisitions;

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enter into hedging arrangements;

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sell assets;

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enter into certain transactions with affiliates; and

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

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

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

Our and our subsidiaries’ 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 subsidiaries’ service areas and in wells currently connected to APL’s pipeline system being shut in by their operators until prices improved. Any of these events may adversely affect our and our subsidiaries’ revenues and ability to fund capital expenditures and, in the future, may impact the cash that we have available to fund our operations, pay required debt service on our credit facility and make distributions to our unitholders.

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

Economic situations could have an adverse impact on producers, key suppliers or other customers, or on our or our subsidiaries’ lenders, causing them to fail to meet their obligations. Market conditions could also impact our or our subsidiaries’ derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and our subsidiaries’ cash flow and ability to pay distributions could be impacted which in turn affects the amount of distributions that we are able to make to our unitholders. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

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

Pricing for natural gas and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, our subsidiaries use financial and physical hedges for their production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. Our subsidiaries generally limit these arrangements to smaller quantities than those projected to be available at any delivery point.

In addition, our subsidiaries may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future.

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on cash flow from operations for the periods covered by the hedging arrangement. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit potential gains if commodity prices were to rise substantially over the price established by the hedge. If, among other circumstances, production is substantially less than expected, the counterparties to the futures contracts fail to perform under the contracts or a sudden, unexpected event materially changes commodity prices, our subsidiaries may be exposed to the risk of financial loss. In addition, it is not always possible to engage in a derivative transaction that completely mitigates exposure to commodity prices and interest rates. The financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which our subsidiaries are unable to enter into a completely effective hedge transaction.

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

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

Regulations promulgated by the Commodities Futures Trading Commission could have an adverse effect on our subsidiaries’ ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with their business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act is intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. These statutory requirements must be implemented through regulation, primarily through rules to be adopted by the Commodities Futures Trading Commission (“CFTC”). Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements. The new regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities. As a commercial end-user which uses swaps to hedge or mitigate commercial risk, rather than for speculative purposes, we are permitted to opt out of the clearing and exchange trading requirements. However, we could be exposed to greater liquidity and credit risk with respect to our hedging transactions if we do not use cleared and exchange-traded swaps. Counterparties to our derivative instruments which are federally insured depository institutions are required to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new regulations could significantly increase the cost of derivative contracts; materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks ARP and APL encounter; reduce ARP’s and APL’s ability to monetize or restructure ARP’s and APL’s derivative contracts in existence at that time; and increase ARP’s and APL’s exposure to less creditworthy counterparties. If ARP and APL reduce or change the way we use derivative instruments as a result of the legislation or regulations, ARP’s and APL’s results of operations may become more volatile and cash flows may be less predictable, which could adversely affect ARP’s and APL’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. ARP’s and APL’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on ARP’s and APL’s consolidated financial position, results of operations and/or cash flows.

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

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

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the validity of our assumptions about reserves, future production, revenues, capital expenditures and operating costs;

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an inability to successfully integrate the businesses acquired;

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a decrease in liquidity by using a portion of available cash or borrowing capacity under respective revolving credit facilities to finance acquisitions;

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a significant increase in interest expense or financial leverage if additional debt to finance acquisitions is incurred;

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the assumption of unknown environmental and other liabilities, losses or costs for which our subsidiary is not indemnified or for which the indemnity is inadequate;

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the diversion of management’s attention from other business concerns and increased demand on existing personnel;

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the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges;

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unforeseen difficulties encountered in operating in new geographic areas; and

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customer or key employee losses at the acquired businesses.

The scope and cost of these risks may be materially greater than estimated at the time of the acquisition. Any of these factors could adversely affect future growth and the ability to make or increase distributions.

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

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

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operating a significantly larger combined entity;

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

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integrating personnel with diverse business backgrounds and organizational cultures;

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consolidating operational and administrative functions;

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

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

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customer or key employee loss from the acquired businesses;

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a significant increase in indebtedness; and

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potential environmental or regulatory liabilities and title problems.

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

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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

Our limited partnership agreement contains provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include:

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

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

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

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

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

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

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

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

We are entitled to receive incentive distributions from ARP, through our ownership of Atlas Resource Partners GP, with respect to any particular quarter only if ARP distributes more than $0.46 per common unit for such quarter. Atlas Resource Partners GP’s incentive distribution rights entitle it to receive percentages increasing up to 48% of all cash distributed by ARP. Distribution by ARP above $0.60 per common unit per quarter would result in Atlas Resource Partners GP’s incremental cash distributions to be the maximum 48%. Atlas Resource Partners GP’s percentage of the incremental cash distributions reduces from 48% to 23% if ARP’s distribution is between $0.51 and $0.60, and to 13% if ARP’s distribution is between $0.47 and $0.50.

We are entitled to receive incentive distributions from APL, through our ownership of Atlas Pipeline GP, with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Atlas Pipeline GP agreed

to allocate up to $3.75 million of incentive distributions per quarter back to APL. Atlas Pipeline GP’s incentive distribution rights entitle it to receive percentages increasing up to 48% of all cash distributed by APL, subject to the IDR Adjustment Agreement. Distribution by APL above $0.60 per common unit per quarter would result in Atlas Pipeline GP’s incremental cash distributions to be the maximum 48%. Atlas Pipeline GP’s percentage of the incremental cash distributions reduces from 48% to 23% if APL’s distribution is between $0.53 and $0.60, and to 13% if APL’s distribution is between $0.43 and $0.52, subject in both cases to the effect of the IDR Adjustment Agreement.

As a result, lower quarterly cash distributions from ARP or APL have the effect of disproportionately reducing the amount of all incentive distributions that Atlas Resource Partners GP or Atlas Pipeline GP receives as compared to cash distributions it receives on its 2.0% general partner interest in ARP or APL.

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

We own ARP’s and APL’s general partner, which owns the incentive distribution rights in ARP and APL that entitle us to receive increasing percentages, of any cash distributed by them as they reach certain target distribution levels in any quarter. In July 2007, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after it receives the initial $7.0 million per quarter of incentive distribution rights.

In order to facilitate acquisitions by ARP or APL, the general partners may elect to limit the incentive distributions we are entitled to receive with respect to a particular acquisition or unit issuance contemplated by ARP or APL. This is because a potential acquisition might not be accretive to ARP’s or APL’s common unitholders as a result of the significant portion of that acquisition’s cash flows which would be paid as incentive distributions to us. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of ARP or APL, the cash flows associated with that acquisition could be accretive to ARP’s or APL’s common unitholders as well as substantially beneficial to us. In doing so, the board of ARP’s general partner or the managing board of APL’s general partner would be required to consider both its fiduciary obligations to its investors as well as to us.

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

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

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

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

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

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

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for ARP or APL’s services.

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA adopted regulations under existing provisions of the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. Additionally, the EPA adopted rules to regulate GHG emissions through traditional major source construction and operating permit programs. The EPA confirmed the permitting thresholds established in the 2010 rule in July 2012. These permitting programs require consideration of and, if deemed necessary, implementation of best available control technology to reduce GHG emissions. As a result, ARP or APL’s operations could face additional costs for emissions control and higher costs of doing business.

Risks Related to ARP

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

ARP operates in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through its investment partnerships, contracting for drilling equipment and securing trained personnel. ARP’s competitors may be able to pay more for natural gas and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than its financial or personnel resources permit. Moreover, competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than ARP does. All of these challenges could make it more difficult for ARP to execute its growth strategy. ARP may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

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

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

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in ARP’s primary operating areas or otherwise, can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict ARP’s ability to drill the wells and conduct the operations that it currently has planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce ARP’s revenues.

Many of ARP’s leases are in areas that have been partially depleted or drained by offset wells.

ARP’s key project areas are located in active drilling areas in the Appalachian Basin, and many of its leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit ARP’s ability to find economically recoverable quantities of natural gas in these areas.

ARP’s operations require substantial capital expenditures to increase its asset base. If it is unable to obtain needed capital or financing on satisfactory terms, ARP’s asset base will decline, which could cause its revenues to decline and affect its ability to pay distributions.

The natural gas and oil industry is capital intensive. If ARP is unable to obtain sufficient capital funds on satisfactory terms with capital raised through equity and debt offerings, cash flow from operations, bank borrowings and the investment partnerships, it may be unable to increase or maintain its inventory of properties and reserve base, or be forced to curtail drilling or other activities. This could cause ARP’s revenues to decline and diminish its ability to service any debt that it may have at such time. If ARP does not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, it will be unable to expand its business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on its units.

ARP depends on certain key customers for sales of its natural gas, crude oil and natural gas liquids. To the extent these customers reduce the volumes of natural gas, crude oil and natural gas liquids they purchase from ARP, or cease to purchase natural gas, crude oil and natural gas liquids from ARP, ARP’s revenues and cash available for distribution could decline.

ARP markets the majority of its natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. Crude oil produced from ARP’s wells flow directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. Natural gas liquids are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas (low Btu content) to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. For the year ended December 31, 2012, Chevron and Atmos Energy Marketing, LLC accounted for approximately 43% and 11% of ARP’s total natural gas, crude oil and natural gas liquids production revenue, respectively, with no other single customer accounting for more than 10% for this period. To the extent these and other key customers reduce the amount of natural gas, crude oil and natural gas liquids they purchase from ARP, ARP’s revenues and cash available for distributions to unit holders could temporarily decline in the event it is unable to sell to additional purchasers.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price that ARP receives for its production could significantly reduce its cash available for distribution and adversely affect its financial condition.

The prices that ARP receives for its oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price that it receives is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price that it receives could significantly reduce its cash available for distribution to its unitholders and adversely affect its financial condition. ARP uses the relevant benchmark price to calculate its hedge positions, and ARP does not have or plan to have any commodity derivative contracts covering the amount of the basis differentials ARP experiences in respect of its production. As such, ARP will be exposed to any increase in such differentials, which could adversely affect its results of operations.

Some of ARP’s undeveloped leasehold acreage is subject to leases that may expire in the near future.

As of December 31, 2012, leases covering approximately 49,786 of ARP’s 321,642 net undeveloped acres, or 15.5%, are scheduled to expire on or before December 31, 2013. An additional 10% are scheduled to expire in each of the years 2014 and 2015. If ARP is unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, ARP will lose the right to develop the acreage that is covered by an expired lease, which would reduce ARP’s cash flows from operations.

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

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

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

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unexpected operational events and drilling conditions;

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adverse weather conditions;

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facility or equipment malfunctions;

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title problems;

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pipeline ruptures or spills;

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compliance with environmental and other governmental requirements;

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unusual or unexpected geological formations;

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formations with abnormal pressures;

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injury or loss of life;

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

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fires, blowouts, craterings and explosions; and

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uncontrollable flows of natural gas or well fluids.

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

Although ARP maintains insurance against various losses and liabilities arising from its operations, insurance against all operational risks are not available to it. Additionally, ARP may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce ARP’s results of operations.

The physical effects of climatic change have the potential to damage facilities, disrupt operations and production activities and cause ARP to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, ARP’s exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to facilities from powerful winds or rising waters in low lying areas, disruption of production activities either because of climate-related damages to facilities or ARP’s costs of operation potentially rising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on ARP’s financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom ARP has a business relationship. ARP may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Unless ARP replaces its oil and natural gas reserves, its reserves and production will decline, which would reduce its cash flow from operations and income.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. ARP’s natural gas reserves and production and, therefore, its cash flow and income are highly dependent on its success in efficiently developing and exploiting reserves and economically finding or acquiring additional recoverable reserves. ARP’s ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on generating sufficient cash flow from operations and other sources of capital, principally from the sponsorship of new investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

A decrease in natural gas prices could subject ARP’s oil and gas properties to a non-cash impairment loss under U.S. generally accepted accounting principles.

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

Properties that ARP acquires may not produce as projected and it may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of ARP’s growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, reviews of acquired properties are often incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties also may not necessarily reveal existing or potential problems, and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when ARP inspects a well. Any unidentified problems could result in material liabilities and costs that negatively affect ARP’s financial condition and results of operations.

ARP’s 2012 acquisitions may prove to be worth less than it paid, or provide less than anticipated proved reserves, because of uncertainties in evaluating recoverable reserves, well performance, and potential liabilities as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs.

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. ARP’s estimates of future reserves and estimates of future production for its 2012 acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by its internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain; thus, proved reserves estimates may exceed actual acquired proved reserves. In connection with ARP’s assessments, it performs a review of the acquired properties that it believes is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, ARP’s review may not permit it to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. ARP does not inspect every well. Even when it inspects a well, it does not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price ARP pays to acquire oil and natural gas properties may exceed the value it realizes.

Also, ARP’s reviews of the properties included in the 2012 acquisitions are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given the time constraints imposed by the applicable acquisition agreement. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.

ARP may not identify all risks associated with the acquisition of oil and natural gas properties, or existing wells, and any indemnifications it receives from sellers may be insufficient to protect it from such risks, which may result in unexpected liabilities and costs to ARP.

ARP’s business strategy focuses on acquisitions of undeveloped oil and natural gas properties that it believes are capable of production. ARP may make additional acquisitions of undeveloped oil and gas properties from time to time, subject to available resources. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and other liabilities and other factors. Generally, it is not feasible for ARP to review in detail every individual property involved in a potential acquisition. In making acquisitions, ARP generally focuses most of its title, environmental and valuation efforts on the properties that it believes to be more significant, or of higher-value. Even a detailed review of properties and records may not reveal all existing or potential problems, nor would it permit ARP to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. In addition, ARP does not inspect in detail every well that it acquires. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when it performs a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively impact ARP’s financial condition and results of operations.

Even if ARP is able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable or may be limited by floors and caps, and the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on our ability to recover the costs related any potential problem could materially impact ARP’s financial condition and results of operations.

Ownership of ARP’s oil and gas production depends on good title to its property.

Good and clear title to ARP’s oil and gas properties is important. Although ARP will generally conduct title reviews before the purchase of most oil, gas and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat a claim, which could result in a reduction or elimination of the revenue received by ARP from such properties.

ARP or its subsidiaries may be exposed to financial and other liabilities as the managing general partner in investment partnerships.

ARP or ones of its subsidiaries serves as the managing general partner of the investment partnerships and will be the managing general partner of new investment partnerships that it sponsors. As a general partner, ARP or one of its subsidiaries will be contingently liable for the obligations of the partnerships to the extent that partnership assets or insurance proceeds are insufficient. ARP has agreed to indemnify each investor partner in the investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions or by state environmental agencies.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example:

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New York has imposed a de facto moratorium on the issuance of permits for high volume, horizontal hydraulic fracturing until state administered environmental studies are finalized. The Department of Environmental Conservation, or the NYDEC, accepted comments on its revised proposal to amend state regulations to address high-volume hydraulic fracturing through January 11, 2013. Final Regulations have not yet been issued. In October 2012, the New York Department of Environmental Conservation asked the New York Health Department to assess the health impacts of high volume hydraulic fracturing. The Health Department has not completed its assessment. NYDEC is not expected to take any final action or make any decision regarding hydraulic fracturing until after the health review is completed and the Department of Environmental Conservation, through the environmental impact statement, is satisfied that hydraulic fracturing can be done safely in New York State.

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Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. In February 2012, legislation was passed in Pennsylvania requiring, among other things, disclosure of chemicals used in hydraulic fracturing. To implement the new legislative requirements, in August of 2012 the Pennsylvania

Department of Environmental Protection issued proposed conceptual changes to its environmental regulations governing oil and gas operations. The conceptual changes would include requiring secondary containment for tanks associated with hydraulic fracturing and the submission of increased water withdrawal information necessary to secure required Water Management Plans.

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In June 2012, Ohio passed legislation that made several significant amendments to the state’s oil and gas law, including additional permitting requirements, chemical disclosure requirements, and site investigation requirements for horizontal wells.

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In September 2012, the Texas Railroad Commission approved new proposed regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid.

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In June 2012, the West Virginia Department of Environmental Protection introduced a proposed legislative rule titled “Rules Governing Horizontal Well Development,” which imposes more stringent regulation of horizontal drilling. The proposed rule was developed to provide further direction in the implementation and administration of the Natural Gas Horizontal Well Control Act that became effective on December 14, 2011.

In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. If state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. Generally, federal, state and local restrictions and requirements are applied consistently to similar types of producers (e.g., conventional, unconventional, etc.), regardless of size of the producing company.

Although, to date, the hydraulic fracturing process has not generally been subject to regulation at the federal level, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. A few of these initiatives are listed here, although others may exist now or be implemented in the future. In April 2012, President Obama established an Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources with the purpose of coordinating the policies and activities of agencies regarding unconventional gas development. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act. In May 2012, the EPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. After reviewing comments submitted on the draft guidance in September 2012, the EPA is considering withdrawing the draft guidance and reissuing the policies contained therein as a proposed rulemaking. In addition, legislation that would provide for increased federal regulation of hydraulic fracturing and require disclosure of the chemicals used in the hydraulic fracturing process could be introduced in the future. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, the EPA is currently studying the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA issued a progress report regarding the hydraulic fracturing study on December 21, 2012. However, the progress report did not provide any results or conclusions. Research results are expected to be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board. The EPA has not provided an anticipated date for completion of the report after peer review. The EPA is also proposing to issue a draft criteria document updating the water quality criteria for chloride in early 2013, and a proposed rule regarding effluent limitation guidelines for natural gas extraction from shale gas in 2014. On May 4, 2012, the U.S. Department of the Interior, Bureau of Land Management proposed a rule that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands.

Certain members of U.S. Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, and Congress has asked the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing. In addition, Congress requested, the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could result in initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or one or more other regulatory mechanisms. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform hydraulic fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives

by the EPA or other federal agencies, our fracturing activities could be significantly affected. Some of the potential effects of changes in Federal, state or local regulation of hydraulic fracturing operations could include, but are not limited to, the following: additional permitting requirements, permitting delays, increased costs, changes in the way operations, drilling and/or completion must be conducted, increased recordkeeping and reporting, and restrictions on the types of additives that can be used, among other potential effects that are not listed here. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that ARP is ultimately able to produce from its reserves.

The third parties on whom ARP relies for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting its business.

The operations of the third parties on whom ARP relies for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that ARP pays for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom ARP relies could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to unitholders.

ARP’s drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water. If ARP is unable to dispose of the water it uses or removes from the strata at a reasonable cost and within applicable environmental rules, its ability to produce gas commercially and in commercial quantities could be impaired.

A significant portion of ARP’s natural gas extraction activity utilizes hydraulic fracturing, which results in water that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on ARP’s operations and financial performance. For example, Pennsylvania requires the development of a Water Management Plan before hydraulically fracturing an unconventional well. The requirements of these plans continue to be modified by state laws and Pennsylvania Department of Environmental Protection (“PADEP”) policies. In June 2012, Ohio passed legislation that established a water withdrawal and consumptive use permit program in the Lake Erie watershed. If certain withdrawal thresholds are triggered due to water needs for a particular project, ARP will be required to develop a Water Conservation Plan and obtain a withdrawal permit for that project.

ARP’s ability to collect and dispose of water will affect its production, and the cost of water treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could include restrictions on ARP’s ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil. For example, in July 2012, pursuant to an Executive Order by Governor Kasich, the Ohio Department of Natural Resources promulgated emergency amendments to the regulations governing disposal wells in Ohio. The emergency rules provide the Department with the authority to require certain testing as part of the process for obtaining a permit for the underground injection of produced water, and require all new disposal wells to be equipped with continuous pressure monitors and automatic shut off devices.

Recently promulgated rules regulating air emissions from oil and natural gas operations could cause ARP to incur increased capital expenditures and operating costs.

In August 2012, the EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards, which we refer to as the NSPS, to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The NSPS require operators, starting in 2015, to reduce VOC emissions from oil and natural gas production facilities by conducting “green completions” for hydraulic fracturing, that is, recovering rather than venting the gas and natural gas liquids that come to the surface during completion of the fracturing process. The NSPS also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, effective in 2012, the rules establish new notification requirements before conducting hydraulic fracturing and more stringent leak detection requirements for natural gas processing plants. The NSPS became effective October 15, 2012 and will likely require a number of modifications to ARP’s operations including the installation of new equipment. Compliance with the new rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact ARP’s businesses.

States are also proposing more stringent requirements in air permits for well sites and compressor stations. For example, Pennsylvania has proposed to revise a list of sources exempt from air permitting requirements such that previously exempted types of sources associated with oil and gas exploration and production would be required to: (1) obtain an air permit or (2) satisfy specific requirements (emission limits, monitoring and recordkeeping) in order to claim the permit exemption. In conjunction with this proposal, Pennsylvania has finalized revisions to its General Permit for Natural Gas Production Facilities to impose additional and more stringent requirements and emission limits. Ohio is also considering revising its current General Permit for Natural Gas Production Operations to cover emissions from completion activities.

Impact fees and severance taxes could materially increase liabilities.

In an effort to offset budget deficits and fund state programs, many states have imposed impact fees and/or severance taxes on the natural gas industry. In February 2012, Pennsylvania implemented an impact fee for unconventional wells drilled in the Commonwealth. An unconventional gas well is a well that is drilled into an unconventional formation, which would include the Marcellus shale. The impact fee, which changes from year to year, is computed using the prior year’s trailing 12 month NYMEX natural gas price and is based upon a tiered pricing matrix. For example, based upon natural gas prices for 2012, the impact fee for qualifying unconventional horizontal wells spudded during 2012 was $45,000 per well and the impact fee for unconventional vertical wells was reduced to twenty percent of the horizontal well fee. The impact fee is due by April 1 of the year following the year that a horizontal unconventional well is spudded or a vertical unconventional well is put into production. The fee will continue for 15 years for a horizontal unconventional well and 10 years for a vertical unconventional well. ARP estimates that the impact fee for its wells including the wells in its Drilling Partnerships will be in excess of $2 million for the year ended December 31, 2012.

Ohio Governor John Kasich has proposed a severance tax on gas, oil and natural gas liquids produced from high-volume producing formations that are recovered through hydraulic fracturing. Under the proposed tax plan, oil and natural gas liquids recovered through hydraulic fracturing in the Utica and Marcellus shales would be taxed at 1.5% of annual gross sales in the first year and 4% per year for each year thereafter. Natural gas would be taxed yearly at 1% of gross sales. The proposed plan also levies a $25,000 up front impact fee for each well drilled in the state.

President Obama’s Fiscal Year 2013 Budget Proposal also includes provisions with significant tax consequences. If enacted, U.S. tax laws would be amended to eliminate the immediate deduction for intangible drilling and development costs and to eliminate the deduction from income for domestic production activities relating to oil and natural-gas exploration and development.

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

The planning, design, drilling, installation, operation and abandonment of natural gas wells and associated facilities are matters subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

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

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The federal Clean Water Act and comparable state laws and regulations that impose obligations related to spills, releases, streams, wetlands and discharges of pollutants into regulated bodies of water;

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RCRA and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from ARP’s facilities;

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CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by ARP and AEI or at locations to which ARP and AEI have sent waste for disposal; and

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Wildlife protection laws and regulations such as the Migratory Bird Treaty Act that requires operators to cover reserve pits during the cleanup phase of the pit, if the pit is open more than 90 days.

Complying with these requirements is expected to increase costs and prompt delays in natural gas production. There can be no assurance that ARP will be able to obtain all necessary permits and, if obtained, that the costs associated with obtaining such permits will not exceed those that previously had been estimated. It is possible that the costs and delays

associated with compliance with such requirements could cause ARP to delay or abandon the further development of certain properties.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. These enforcement actions may be handled by the EPA and/or the appropriate state agency. In some cases, the EPA has taken a heightened role in oil and gas enforcement activities. For example, in 2011, EPA Region III requested the lead on all oil and gas related violations in the United States Army Corps of Engineers’ Pittsburgh District. We also understand that the EPA has taken an increased interest in assessing operator compliance with the Spill Prevention, Control and Countermeasures regulations, set forth at 40 CFR Part 112.

Certain environmental statutes, including RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where certain substances have been disposed of or otherwise released, whether caused by ARP’s operations, the past operations of its predecessors or third parties. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

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

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

ARP’s operations are regulated extensively at the federal, state and local levels. The regulatory environment in which it operates includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, ARP’s activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect ARP’s operations and limit the quantity of natural gas it may produce and sell. A major risk inherent in a drilling plan is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our respective properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. For example, Pennsylvania’s General Assembly approved legislation in February 2012 that imposes significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for gas wells, based on the price of natural gas and the age of the well. Draft regulations associated with this legislation have been released by the PADEP and, if finalized, will impact how natural gas operations are conducted in Pennsylvania. Similarly, West Virginia has proposed regulations associated with its existing Horizontal Well Control Act and is signaling that additional regulations are on the horizon. ARP may be put at a competitive disadvantage to larger companies in the industry that can spread these additional costs over a greater number of wells and these increased regulatory hurdles over a larger operating staff.

ARP may not be able to continue to raise funds through its investment partnerships at desired levels, which may in turn restrict its ability to maintain drilling activity at recent levels.

ARP has sponsored limited and general partnerships to finance certain of its development drilling activities. Accordingly, the amount of development activities that ARP will undertake depends in large part upon its ability to obtain investor subscriptions to invest in these partnerships. ARP has raised $127.1 million, $141.9 million and $149.3 million in calendar years 2012, 2011 and 2010, respectively. In the future, ARP may not be successful in raising funds through these investment partnerships at the same levels, and it also may not be successful in increasing the amount of funds it raises. ARP’s ability to raise funds through its investment partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by ARP’s historical track record of generating returns and tax benefits to the investors in its existing partnerships.

In the event that ARP’s investment partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, ARP may have difficulty in maintaining or increasing the level of investment partnership fundraising. In this

event, ARP may need to seek financing for drilling activities through alternative methods, which may not be available, or which may be available only on a less attractive basis than the financing it realized through these investment partnerships, or it may determine to reduce drilling activity.

Changes in tax laws may impair ARP’s ability to obtain capital funds through investment partnerships.

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

Fee-based revenues may decline if ARP is unsuccessful in sponsoring new investment partnerships.

ARP’s fee-based revenues are based on the number of investment partnerships it sponsors and the number of partnerships and wells it manages or operates. If ARP is unsuccessful in sponsoring future investment partnerships, its fee-based revenues may decline.

ARP’s revenues may decrease if investors in the investment partnerships do not receive a minimum return.

ARP has agreed to subordinate up to 50% of its share of production revenues, net of corresponding production costs, to specified returns to the investor partners in the investment partnerships, typically 10% per year for the first five years of distributions. ARP’s revenues from a particular investment partnership will therefore decrease if the investment partnership does not achieve the specified minimum return. For the years ended December 31, 2012, 2011 and 2010, $6.3 million, $4.0 million and $10.9 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced ARP’s cash distributions received from the investment partnerships.

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

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

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

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actual prices received for natural gas;

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the amount and timing of actual production;

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the amount and timing of capital expenditures;

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supply of and demand for natural gas; and

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changes in governmental regulations or taxation.

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

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

Certain of ARP’s officers and directors are subject to non-competition agreements that may effectively restrict its ability to expand its business in the Marcellus Shale.

Edward Cohen, who serves as ARP’s Chairman and Chief Executive Officer, and Jonathan Cohen, who serves as its Vice Chairman of the board of its general partner, are each parties to a non-competition and non-solicitation agreement with Chevron. These agreements restrict each such individual, until February 17, 2014, from engaging in any capacity (whether as officer, director, owner, partner, stockholder, investor, consultant, principal, agent, employee, coventurer or otherwise) in a business engaged in the exploration, development or production of hydrocarbons in certain designated counties within the States of Pennsylvania, West Virginia and New York, and from engaging in certain solicitation activities with respect to oil and gas leases, customers, suppliers and contractors of AEI. The foregoing restrictions are subject to certain limited exceptions, including exceptions permitting Jonathan Cohen and Edward Cohen in certain circumstances to engage in the businesses conducted by ARP (including with respect to the operation of the assets acquired from AEI in February 2011) and APL.

Therefore, ARP’s ability to expand its business in the Marcellus Shale may be limited.

Risks Related to APL

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

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

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

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

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

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the volume of natural gas APL gathers;

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efficiency of APL’s gathering systems and processing plants;

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expiration of significant contracts;

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

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

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

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the availability of local, intrastate and interstate transportation systems;

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the availability of fractionation capacity;

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the expenses incurred in providing our gathering services;

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the cost of acquisitions and capital improvements;

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required principal and interest payments on APL’s debt;

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fluctuations in working capital;

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prevailing economic conditions;

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fuel conservation measures;

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alternate fuel requirements;

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the strength and financial resources of APL’s competitors;

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the effectiveness of APL’s commodity price risk management program and the creditworthiness of its derivatives counterparties;

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

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technical advances in fuel economy and energy generation devices.

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

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the level of capital expenditures APL makes;

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the sources of cash used to fund APL’s acquisitions;

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

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APL’s debt service requirements; and

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the amount of cash reserves established by APL’s General Partner for the conduct of its business.

APL’s ability to make payments on and to refinance its indebtedness will depend on its financial and operating performance, which may fluctuate significantly from quarter to quarter, and is subject to prevailing economic and industry conditions and financial, business and other factors, many of which are beyond APL’s control. APL cannot assure you that it will continue to generate sufficient cash flow or that it will be able to borrow sufficient funds to service its indebtedness, or to meet its working capital and capital expenditure requirements. If APL is not able to generate sufficient cash flow from operations or to borrow sufficient funds to service its indebtedness, it may be required to sell assets or equity, reduce capital expenditures, refinance all or a portion of its existing indebtedness or obtain additional financing. APL cannot assure you that it will be able to refinance its indebtedness, sell assets or equity, or borrow more funds on terms acceptable to it, or at all.

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

APL has historically experienced minimal collection issues with its counterparties; however its revenue and receivables are highly concentrated in a few key customers and therefore it is subject to risks of loss resulting from nonpayment or nonperformance by key customers. In an attempt to reduce this risk, APL has established credit limits for each counterparty and it attempts to limit its credit risk by obtaining letters of credit or other appropriate forms of security. Nonetheless, APL has key customers whose credit risk cannot realistically be otherwise mitigated. Any material nonpayment or nonperformance by its key customers could impact its cash flow and ability to make required debt service payments and pay distributions.

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

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

The amount of natural gas APL gathers will decline over time unless it is able to attract new wells to connect to its gathering systems.

Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to APL’s gathering systems could, therefore, result in the amount of natural gas it gathers declining substantially over time and could, upon exhaustion of the current wells, cause APL to abandon one or more of its gathering systems and, possibly, cease operations. The primary factors affecting APL’s ability to connect new supplies of natural gas to its gathering systems include its success in contracting for existing wells not committed to other systems, the level of drilling activity near its gathering systems and APL’s ability to attract natural gas producers away from its competitors’ gathering systems.

Over time, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. A decrease in exploration and development activities in the fields served by APL’s gathering, processing and treating facilities could result if there is a sustained decline in natural gas, crude oil and/or NGL 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 commodity prices may result in a reduction of producers’ exploratory drilling. APL has no control over the level of drilling activity in its service areas, the amount of reserves underlying wells that connect to APL’s systems and the rate at which production from a well will decline. In addition, APL has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, drilling costs, geological considerations, governmental regulation and the availability and cost of capital. In a low price environment, producers may determine to shut in wells already connected to APL’s systems until prices improve. Because APL’s operating costs are fixed to a significant degree, a reduction in the natural gas volumes it gathers or processes would result in a reduction in its gross margin and cash flow.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in reduced volumes available for APL to gather and process.

Various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts of hydraulic fracturing, a process that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. The adoption of any future federal, state or local laws or regulations imposing additional permitting, disclosure or regulatory obligations related to, or otherwise restricting or increasing costs regarding the use of hydraulic fracturing could make it more difficult to drill certain oil and natural gas wells. As a result, the volume of natural gas APL gathers and processes from wells that use hydraulic fracturing could be substantially reduced, which could adversely affect APL’s gross margin and cash flow.

APL currently depends on certain key producers for their supply of natural gas; the loss of any of these key producers could reduce revenues.

During 2012, Chesapeake Energy Corporation; COG Operating LLC; Endeavor Energy Resources LP; Energen Resources Corporation; Laredo Petroleum Inc.; Parsley Energy, LP; Pioneer; Range Resources Corporation; SandRidge Exploration and Production, LLC; Woolsey Operating Company LLC; and XTO Energy Inc. accounted for a significant amount of APL’s natural gas supply. If these producers reduce the volumes of natural gas they supply to APL, its gross margin and cash flow could be reduced unless it obtains comparable supplies of natural gas from other producers.

APL may face increased competition in the future.

APL faces competition for well connections.

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Carrera Gas Company; Copano Energy, LLC; DCP Midstream, LLC; Energy Transfer Partners, LP; Enogex, LLC and ONEOK Field Services Company, operate competing gathering systems and processing plants in APL’s Velma service area.

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Access Midstream Partners, LP; DCP Midstream, LLC; Caballo Energy, LLC.; Lumen Midstream Partners, LLC; Mustang Fuel Corporation; ONEOK Field Services Company; SemGas, L. P.; and Superior Pipeline Company, LLC operate competing gathering systems and processing plants in APL’s WestOK service area.

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Crosstex Energy Services; DCP Midstream, LLC; Southern Union Company; Targa Resources Partners; and West Texas Gas, Inc. operate competing gathering systems and processing plants in APL’s WestTX service area.

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Enogex, LLC; MarkWest Energy Partners, L.P.; and Scissor Tail Energy LLC operate competing gathering systems and processing plants in APL’s Anadarko service area.

Some of APL’s competitors have greater financial and other resources than it does. If these companies become more active in APL’s service areas, APL may not be able to compete successfully with them in securing new well connections or retaining current well connections. If APL does not compete successfully, the amount of natural gas it gathers and processes will decrease, reducing its gross margin and cash flow.

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

APL’s gathering systems principally serve as intermediate transportation facilities between wells connected to APL’s systems and the intrastate or interstate pipelines to which it delivers natural gas. APL’s plant tailgate pipelines, including the Driver Residue Pipeline, provide essential links between APL’s processing plants and intrastate and interstate pipelines that move natural gas to market. APL delivers NGLs to intrastate or interstate pipelines at the tailgates of the plants. If one or more of the pipelines or fractionation facilities to which APL delivers natural gas and NGLs has service interruptions, capacity limitations or otherwise cannot or do not accept natural gas or NGLs from APL, and APL cannot arrange for delivery to other pipelines or fractionation facilities, the amount of natural gas APL gathers and processes may be reduced. Since APL’s revenues depend upon the volumes of natural gas it gathers and natural gas and NGLs it sells or transports, this could result in a material reduction in APL’s gross margin and cash flow.

Failure of the natural gas or NGLs APL delivers to meet the specifications of interconnecting pipelines could result in curtailments by the pipelines.

The pipelines to which APL delivers natural gas and NGLs typically establish specifications for the products they are willing to accept. These specifications include requirements such as hydrocarbon dew point, compositions, temperature, and foreign content (such as water, sulfur, carbon dioxide, and hydrogen sulfide), and these specifications can vary by product or pipeline. If the total mix of a product that we deliver to a pipeline fails to meet the applicable product quality specifications, the pipeline may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to handle the out-of-specification products. In those circumstances, APL may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas causing the products to be out of specification, potentially reducing APL’s through-put volumes or revenues.

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

APL’s agreements with most producers with which it does business generally do not require producers to dedicate significant amounts of undeveloped acreage to APL’s systems. While APL does have some undeveloped acreage dedicated on its systems, most notably with its partner Pioneer on the WestTX system, APL does not have assured sources to provide it with new wells to connect to its gathering systems. Failure to connect new wells to APL’s operations could reduce APL’s gross margin and cash flow.

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

APL does not own all the land on which its pipelines are constructed. APL obtains the rights to construct and operate its pipelines on land owned by third parties. In some cases, these rights expire at a specified time. Therefore APL is subject to the possibility of more onerous terms or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. A loss of these rights, through APL’s inability to renew right-of-way contracts or otherwise, could have a material adverse effect on its business, results of operations and financial condition. APL may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other

attractive expansion opportunities. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then APL’s cash flow could be reduced.

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

APL is actively growing its business through the construction of new assets. The construction of additions or modifications to its existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond APL’s control and require the expenditure of significant amounts of capital. Any projects APL undertakes may not be completed on schedule, at the budgeted cost or at all. Moreover, APL’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if APL expands a gathering system, the construction may occur over an extended period of time, and it will not receive any material increase in revenues until the project is completed. Moreover, APL is constructing facilities to capture anticipated future growth in production in a region in which growth may not materialize. Since APL is not engaged in the exploration for, and development of, natural gas reserves, it often does not have access to estimates of potential reserves in an area before constructing facilities in the area. To the extent APL relies on estimates of future production in its decision to construct additions to its systems, the estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve expected investment return, which could impair APL’s results of operations and financial condition. In addition, APL’s actual revenues from a project could materially differ from expectations as a result of the volatility in price of natural gas, the NGL content of the natural gas processed and other economic factors described in this section.

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

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difficulties in obtaining capital for additional construction and operating costs;

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

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additional construction and operating costs exceeding budget estimates;

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

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difficulties in obtaining consistent supplies of natural gas; and

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terms in operating agreements that are not favorable to APL.

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

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

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inability to identify suitable acquisition candidates;

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inability 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;

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potentially material costs in seeking to make acquisitions, even if APL cannot complete any acquisition it has pursued;

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

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delays in receiving regulatory approvals or the receipt of approvals that are subject to material conditions;

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difficulties in integrating operations and systems; and

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

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

APL’s ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, APL has financed its acquisitions and expansions through bank credit facilities and the proceeds of public and private debt and equity offerings. If APL is unable to access the capital markets, it may be unable to execute its growth strategy.

APL’s debt levels and restrictions in its revolving credit facility and the indentures governing its senior notes could limit APL’s ability to fund operations and pay required debt service.

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

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

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

APL’s gathering and processing of natural gas is exempt from regulation by the FERC under the Natural Gas Act of 1938. While gas transmission activities conducted through APL’s plant tailgate pipelines, such as the Driver Residue Pipeline, are subject to FERC’s Natural Gas Act jurisdiction, FERC may limit the extent to which it regulates those activities. The way APL operates, the implementation of new laws or policies (including changed interpretations of existing laws) or a change in facts relating to APL’s plant tailgate pipeline operations could subject its operations to more extensive regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. APL expects that any such regulation could increase its costs, decrease its gross margin and cash flow, or both.

Even if APL’s gathering and processing of natural gas is not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect its business and the market for APL’s products. FERC’s policies and practices affect a range of natural gas pipeline activities, including, for example, its 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. There can be no assurance that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

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

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perform ongoing assessments of pipeline integrity;

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

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventative and mitigating actions.

While APL does not believe that the cost of implementing integrity management program testing along segments of its pipeline will have a material effect on its results of operations, the costs of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program could be substantial.

APL’s midstream natural gas operations could incur significant costs if the Pipeline and Hazardous Materials Safety Administration adopts more stringent regulations governing APL’s business.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the “Act,” was signed into law. The Act directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in natural gas and hazardous liquids pipeline safety rulemakings. These rulemakings will be conducted by PHMSA.

Since passage of the Act, PHMSA has published several notices of proposed rulemaking which propose a number of changes to regulations governing the safety of gas transmission pipelines, gathering lines and related facilities, including increased safety requirements and increased penalties.

The adoption of regulations that apply more comprehensive or stringent safety standards to gathering lines could require APL to install new or modified safety controls, incur additional capital expenditures, or conduct maintenance programs on an accelerated basis. Such requirements could result in APL’s incurrence of increased operational costs that could be significant; or if APL fails to, or is unable to, comply, APL may be subject to administrative, civil and criminal enforcement actions, including assessment of monetary penalties or suspension of operations, which could have a material adverse effect on its financial position or results of operations and its ability to make distributions to its unitholders.

APL’s midstream natural gas operations may incur significant costs and liabilities resulting from a failure to comply with new or existing environmental regulations or a release of regulated materials into the environment by APL or the producers in its service areas.

The operations of APL’s gathering systems, plants and other facilities, as well as the operations of the producers in its service areas, are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact APL’s business activities in many ways, including restricting the manner in which it, and its producers, dispose of substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, increased cost of operations, 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 and property damage allegedly caused by the release of regulated substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in APL’s business due to its handling of natural gas and other petroleum products, air emissions related to its operations, historical industry operations including releases of regulated substances into the environment, and waste disposal practices. For example, an accidental release from one of APL’s pipelines or processing facilities could subject it to substantial liabilities arising from (1) environmental cleanup, restoration costs and natural resource damages; (2) claims made by neighboring landowners and other third parties for personal injury and property damage; and (3) fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies, including those relating to emissions from production, processing and transmission activities, could significantly increase APL’s compliance costs and the cost of any remediation that may become necessary. Producers in APL’s service areas may curtail or abandon exploration and production activities if any of these regulations cause their operations to become uneconomical. APL may not be able to recover some or any of these costs from insurance.

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

APL’s operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and fines in connection with any pollution caused by their pipelines. APL may also be held liable for clean-up costs resulting from pollution that occurred before its acquisition of a gathering system. In addition, APL is subject to federal and state safety laws that dictate the type of pipeline, quality of pipe protection, depth of pipelines, methods of welding and other construction-related standards. Any violation of environmental, construction or safety laws could impose substantial liabilities and costs on APL.

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

Oil and gas operators can be impacted by litigation brought against the agencies which regulate the oil and industry. The outcomes of such activities can impact operations. For example, the Center for Biological Diversity (“CBD”) recently notified the U.S. Army Corp of Engineers (“Corp”) of its intent to file a lawsuit to challenge the Corp’s administration of the Nationwide Permit (“NWP”) program, a program used by the oil and gas industry to permit pipeline construction projects. Unless the Corp acts to correct alleged Endangered Species Act violations, the CBD has threatened further litigation to immediately suspend the NWP program.

APL cannot predict whether or in what form any new litigation or regulatory requirements might be enacted or adopted, nor can it predict its costs of compliance. In general, APL expects new regulations would increase its operating costs and, possibly, require it to obtain additional capital to pay for improvements or other compliance actions necessitated by those regulations.

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

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

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

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inadvertent damage from construction and farm equipment;

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leakage of natural gas, NGLs and other hydrocarbons;

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fires and explosions;

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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

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acts of terrorism directed at our pipeline infrastructure, production facilities and surrounding properties.

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

Catastrophic weather events may curtail operations at, or cause closure of, any of APL’s processing plants, which could harm its business.

APL’s assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures. If operations at any of APL’s processing plants were to be curtailed, or closed, whether due to natural catastrophe, accident, environmental regulation, periodic maintenance, or for any other reason, APL’s ability to process natural gas from the relevant gathering system and, as a result, its ability to extract

and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, its gross margin and cash flow could be materially reduced.

The threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact APL’s results of operations and its ability to raise capital.

Terrorist attacks or the threat of terrorist attacks cause instability in the global financial markets and other industries, including the energy industry. Infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. APL’s insurance policies generally exclude acts of terrorism. Such insurance is not available at what APL believes to be acceptable pricing levels.

Risks Relating to the Ownership of Our Common Units

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

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

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

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

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

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changes in market valuations of similar companies;

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departures of key personnel;

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commencement of or involvement in litigation;

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

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variations in the amount of our quarterly cash distributions;

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future issuances and sales of our units; and

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

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

Increases in interest rates could adversely affect our unit price.

Credit markets recently have experienced record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our, ARP’s and APL’s financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our, ARP’s and APL’s cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units. A rising interest rate environment could have an adverse impact on our unit price and our, ARP’s and APL’s ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could impact our, ARP’s and APL’s ability to make cash distributions at our, ARP’s and APL’s intended levels.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a

result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

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

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

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

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

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

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

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

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

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

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business through our subsidiaries in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as it they were a general partner if, among other potential reasons:

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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them, or other liabilities with respect to ownership of our units.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (“Delaware Act”), we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of

determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.

Risks Related to Our Conflicts of Interest

Although we control ARP and APL through our ownership of their general partners, their general partner owes fiduciary duties to ARP, APL and their unitholders, which may conflict with our interests.

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

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

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the allocation of shared overhead expenses to ARP, APL and us;

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

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

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

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

Certain of the officers and directors of our general partner’s may have actual or potential conflicts of interest because of their positions and their fiduciary duties may conflict with those of ARP and APL’s general partner’s officers and directors.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, certain of our general partner’s executive officers and non-independent directors also serve as executive officers and directors of ARP and APL’s general partner, and, as a result, have fiduciary duties to manage the business of ARP and APL in a manner beneficial to ARP and APL and their partners. For example, our Executive Chairman, Chief Executive Officer, President, Chief Financial Officer and Chief Accounting Officer, among others, have positions with ARP. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to ARP or APL, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts of interest may not always be in our best interest or that of our unitholders. Additionally, some directors and officers may own ARP and APL common units, options to purchase common units or other equity awards which may be significant or some of these persons. Their position at ARP or APL and the ownership of such equity of equity awards creates, or may create the appearance of, conflicts of interest when they are faced with decisions that could have different implications for ARP or APL than the decisions have for us.

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

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

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

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

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to a material amount of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

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 be 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 U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to them. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. In addition, 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 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 will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on its share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in ARP or APL. Other holders of common units in ARP or APL will receive remedial allocations of deductions from ARP or APL. Although we will receive remedial allocations of deductions from ARP and APL, remedial allocations of deductions to us will be very limited. In addition, our ownership of ARP and APL incentive distribution rights will cause more taxable income to be allocated to us from ARP and APL than will be allocated to holders who hold only common units

in ARP or APL. If ARP and APL are successful in increasing their distributions over time, our income allocations from our ARP and APL incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in ARP or APL, our unitholders’ allocable taxable income will be significantly greater than that of a holder of common units in ARP or APL who receives cash distributions from ARP or APL equal to the cash distributions our unitholders would receive from us.

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.

A successful IRS contest of the U.S. federal income tax positions we take may harm the market for our common units, and the costs of any contest will reduce cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter that affects us. 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 the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may lower the price at which our common units trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

We treat each holder of our common units as having the same tax benefits without regard to the common units held. The IRS may challenge this treatment, which could reduce the value of the common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could reduce 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, ARP’s or APL’s capital and profits interest within a 12-month period will result in the termination of our, ARP’s or APL’s partnership for federal income tax purposes.

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

Tax gain or loss on the disposition of our common units could be more or less than expected because prior distributions in excess of allocations of income will decrease unitholders’ tax basis in their units.

If unitholders sell any of their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions, and the allocation of losses (including depreciation deductions), to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to them. The current maximum marginal federal income tax rates on ordinary income is 39.6% plus a 3.8% Medicare surtax on investment income. As a result, a unitholder may incur a tax liability in excess of the amount of cash it receives from the sale.

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 U.S. 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, ARP or APL do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We, ARP and APL presently anticipate that substantially all of our income will be generated in Oklahoma, Pennsylvania and Texas. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all U.S. federal, foreign, 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 U.S. Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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.

ITEM 1B:

UNRESOLVED STAFF COMMENTS

None.

ITEM 2:

PROPERTIES

Atlas Resource Partners

Natural Gas and Oil Reserves

The following tables summarize information regarding ARP’s estimated proved natural gas and oil reserves as of December 31, 2012. Proved reserves are the estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to ARP’s direct ownership interests in oil and gas properties as well as the reserves attributable to its percentage interests in the oil and gas properties owned by investment partnerships in which ARP owns partnership interests. All of the reserves are located in the United States. ARP bases these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc., an independent third-party engineer. ARP has adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to ARP’s estimated proved reserves at December 31, 2012 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, ARP makes the standardized measure estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. ARP’s estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month within the prior 12-month period, and are listed below as of the dates indicated:


	December 31,
	2012		2011
Unadjusted⁽¹⁾
Natural gas (per Mcf)	$	2.76	$	4.12
Oil (per Bbl)	$	94.71	$	96.19
Natural gas liquids (per Bbl)	$	56.83	$	57.71

Adjusted^{(1) (2)}
Natural gas (per Mcf)	$	2.53	$	4.42
Oil (per Bbl)	$	92.26	$	91.04
Natural gas liquids (per Bbl)	$	33.79	$	63.76

(1)	“Mcf” represents thousand cubic feet; and “Bbl” represents barrels.

(2)

The adjusted weighted average natural gas price is the Base product price, with the representative price of natural gas adjusted for basis premium and the Btu content to arrive at the appropriate net price. The adjusted weighted average oil and natural gas liquid price is the Base product price, adjusted for local contracted gathering arrangements. Amounts shown do not include financial hedging transactions.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of ARP’s natural gas and oil reserve estimates was completed in accordance with ARP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright and Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States, primarily in Ohio, Oklahoma, Pennsylvania and Texas. The independent reserves engineer’s evaluation was based on more than 36 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 14 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by ARP’s senior engineering staff and management, with final approval by ARP’s Senior Vice President.

Results of drilling, testing and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright & Company, Inc. in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. ARP’s estimated standardized measure values may not be representative of the current or future fair market value of its proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based (see “Item 1A: Risk Factors – Risks Relating to ARP”).

ARP evaluates natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. ARP deducts operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. ARP bases the estimates on operating methods and conditions prevailing as of the dates indicated:


	Proved natural gas and oil reserves at December 31,
	2012		2011
Proved reserves:
Natural gas reserves (MMcf)^(1):
Proved developed reserves		338,655		138,403
Proved undeveloped reserves⁽²⁾		235,119		19,273

Total proved reserves of natural gas		573,774		157,676
Oil reserves (MBbl)⁽¹⁾:
Proved developed reserves		3,400		1,638
Proved undeveloped reserves⁽²⁾		5,469		8

Total proved reserves of oil⁽³⁾		8,869		1,646

NGL reserves (MBbl):
Proved developed reserves		7,885		—
Proved undeveloped reserves⁽²⁾		8,177		—

Total proved reserves of NGL⁽³⁾		16,062		—

Total proved reserves (MMcfe)⁽¹⁾		723,359		167,552

Standardized measure of discounted future cash flows (in thousands)⁽⁴⁾	$	623,676	$	219,859

(1)	“MMcf” represents million cubic feet; “MMcfe” represents million cubic feet equivalents; and “MBbl” represents thousand barrels.

(2)

ARP’s ownership in these reserves is subject to reduction as it generally makes capital contributions, which includes leasehold acreage associated with ARP’s proved undeveloped reserves, to its investment partnerships in exchange for an equity interest in these partnerships, which historically ranges from 20% to 41%, which effectively will reduce ARP’s ownership interest in these reserves from 100% to its respective ownership interest as ARP makes these contributions.

(3)	Includes less than 500 MBbl of natural gas liquids proved reserves at December 31, 2011.

(4)

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because ARP is a limited partnership, no provision for federal or state income taxes has been included in the December 31, 2012 and 2011 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Proved Undeveloped Reserves (“PUDS”)

PUD Locations. As of December 31, 2012, ARP had 328 PUD locations totaling approximately 317.0 Bcfe’s of natural gas, oil and NGLs. These PUDS are based on the definition of PUD’s in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

Historically, the primary focus of ARP’s drilling operations has been in the Appalachian Basin. Subsequent to its acquisitions in the Barnett Shale/Marble Falls and Mississippi Lime play during the year ended December 31, 2012, ARP will continue to integrate these areas and increase its proved reserves through organic leasing as well as drilling on its existing undeveloped acreage.

ARP’s organic growth will focus on expanding its acreage position in its target areas, including ARP’s operations in the Marcellus Shale, Utica Shale, Barnett Shale/Marble Falls and Mississippi Lime play. Through its previous drilling in these regions, as well as its geologic analysis of these areas, ARP is expecting these expansion locations to have a significant impact on its proved reserves.

Changes in PUDs. Changes in PUDS that occurred during the year ended December 31, 2012 were due to the following:

•

Addition of approximately 311.0 Bcfe of Barnett Shale/Marble Fall and Mississippi Lime drilling locations acquired during 2012; and

•

Negative revisions of approximately 18.5 Bcfe in PUDs primarily due to the reduction of drilling plans in the New Albany Shale formation over the next five years.

Development Costs. ARP’s costs incurred related to the development of PUDs were approximately $83.5 million, $40.5 million, and $80.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which ARP has a working interest as of December 31, 2012. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which ARP has an interest, directly or through its ownership interests in investment partnerships, and net wells are the sum of ARP’s fractional working interests in gross wells, based on the percentage interest it owns in the investment partnership that owns the well:


	Number of productive wells⁽¹⁾
	Gross		Net
Appalachia:
Gas wells		7,674		3,601
Oil wells		499		357

Total		8,173		3,958


Barnett/Marble Falls:
Gas wells		552		455
Oil wells		—		—

Total		552		455


Mississippi Lime/Hunton:
Gas wells		45		37
Oil wells		—		—

Total		45		37


Other operating areas⁽²⁾:
Gas wells		839		254
Oil wells		2		1

Total		841		255


Total:
Gas wells		9,110		4,347
Oil wells		501		358

Total		9,611		4,705

(1)	Includes ARP’s proportionate interest in wells owned by 96 investment partnerships for which ARP serves as managing general partner and various joint ventures. This does not include royalty or overriding interests in 625 wells.

Developed and Undeveloped Acreage

The following table sets forth information about ARP’s developed and undeveloped natural gas and oil acreage as of December 31, 2012. The information in this table includes ARP’s proportionate interest in acreage owned by investment partnerships.


	Developed acreage ⁽¹⁾				Undeveloped acreage⁽²⁾
	Gross ⁽³⁾		Net ⁽⁴⁾		Gross ⁽³⁾		Net ⁽⁴⁾
Pennsylvania		138,852		133,347		3,430		3,427
Ohio⁽⁵⁾		82,566		81,206		31,408		31,399
Texas		61,348		56,443		73,367		60,717
Indiana		32,549		27,294		174,448		103,510
Oklahoma		32,438		12,186		2,235		1,161
Tennessee		19,691		19,315		97,603		95,339
New York		13,197		12,857		23,301		22,394
Other		17,390		15,693		3,900		3,695

Total		398,031		358,341		409,692		321,642

(1)	Developed acres are acres spaced or assigned to productive wells.

(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)	A gross acre is an acre in which ARP owns a working interest. The number of gross acres is the total number of acres in which ARP owns a working interest.

(4)	Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.

(5)	Includes Utica Shale natural gas and oil rights on approximately 1,300 developed acres and new leases for undeveloped acres in Ohio covering approximately 2,600 acres.

The leases for ARP’s developed acreage generally have terms that extend for the life of the wells, while the leases on its undeveloped acreage have terms that vary from less than one year to five years. There are no concessions for undeveloped acreage as of December 31, 2012.

ARP believes that it holds good and indefeasible title to its producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by ARP in the various areas in which it conducts its activities. ARP does not believe that these exceptions detract substantially from its use of any property. As is customary in the natural gas industry, ARP conducts only a perfunctory title examination at the time it acquires a property. Before it commences drilling operations, ARP conducts an extensive title examination and it performs curative work on defects that it deems significant. ARP or we as predecessors have obtained title examinations for substantially all of ARP’s managed producing properties. No single property represents a material portion of ARP’s holdings.

ARP’s properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. ARP’s properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. ARP does not believe that any of these burdens will materially interfere with its use of its properties.

Atlas Pipeline Partners

APL’s principal facilities consist of twelve natural gas processing plants; eighteen gas treating facilities; approximately 10,100 miles of active 2 to 30 inch diameter natural gas gathering lines; and approximately 2,200 miles of NGL transportation pipeline through its 20% interest in WTLPG. Substantially all of APL’s gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. In a few cases, property for gathering system purposes was purchased in fee. All of APL’s compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

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

Gas Processing Facilities


Facility	Location	Year Constructed	Design Throughput Capacity (MMcfd)		2012 Average Throughput (MMcfd)		2012 Average Utilization Rate
Waynoka I plant	Woods County, OK	2006		200
Waynoka II plant	Woods County, OK	2012		200
Chaney Dell plant	Major County, OK	2012		30
Chester plant	Woodward County, OK	1981		28

Total WestOK				458		348		76	%


Consolidator plant	Reagan County, TX	2009		150
Midkiff plant	Reagan County, TX	1990		60
Benedum plant	Upton County, TX	Updated 1981		45

Total WestTX				255		249		98	%


Velma plant	Stephens County, OK	Updated 2003		100
Velma V-60 plant	Stephens County, OK	2012		60

Total Velma				160		114		71	%


East Rockpile Treating	Pittsburg County, OK	2008
Atoka plant	Atoka County, OK	2006		20
Coalgate plant	Coal County, OK	2007		80
Tupelo plant	Coal County, OK	2011		120

Total Arkoma				220		211		96	%


Total				1,093		922		84	%

(1)	“MMcfd” represents million cubic feet per day.

Natural Gas Gathering Systems


System	Location	Approximate Active Miles of Pipe		Approximate Number of Receipt Points

WestOK	North Central Oklahoma and Southern Kansas		5,400		4,500
Velma	Southern Oklahoma and Northern Texas		1,200		600
WestTX	West Texas		3,300		3,100
Arkoma	Southern Oklahoma		60		130
Tennessee	Tennessee		70		200
Barnett Shale	Central Texas		20		20


Total			10,050		8,550

Natural Gas Treating Facilities


Location	Type	Number of Units

Oklahoma	Refrigeration		1
Texas	Refrigeration		1


Total Refrigeration			2


Arkansas	Amine		1
Texas	Amine		9
Louisiana	Amine		2
In inventory	Amine		3


Total Amine			15

APL’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not materially interfered, and APL does not expect they will materially interfere, with the conduct of its business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the rights-of-way grants. In a few instances, APL’s rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the rights-of-way

grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

Certain of APL’s rights to lay and maintain pipelines are derived from recorded gas well leases, with respect to wells currently in production; however, the leases are subject to termination if the wells cease to produce. Because many of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

ITEM 3:

LEGAL PROCEEDINGS

One of our subsidiaries entered into two agreements with the EPA, effective on September 25, 2012, to settle alleged violations in connection with a fire that occurred at a natural gas well and associated well pad site in Washington County, Pennsylvania in 2010. The EPA alleged non-compliance with the Clean Air Act, including with respect to the storage and handling of the natural gas condensate, as well as non-compliance with the Emergency Planning and Community Right-to-Know Act of 1986. The subsidiary agreed to a civil penalty of $84,506 under a consent agreement and agreed to upgrade its facility pursuant to an administrative settlement agreement.

On August 3, 2011, CNX Gas Company LLC (“CNX”), filed a lawsuit in the United States District Court for the Eastern District of Tennessee at Knoxville styled CNX Gas Company LLC vs. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC, and Scott Boruff, No. 3:11-cv-00362. On April 16, 2012, Atlas Energy Tennessee, LLC, one of our subsidiaries, was brought into the lawsuit by way of Amended Complaint. On April 23, 2012, the Court dismissed Chevron Appalachia, LLC as a party on the grounds of lack of subject matter jurisdiction over that entity.

The lawsuit alleges that CNX entered into a Letter of Intent with Miller Energy Resources, Inc. (“Miller Energy”), for the purchase by CNX of certain leasehold interests containing oil and natural gas rights, representing around 30,000 acres in East Tennessee. The lawsuit also alleges that Miller Energy breached the Letter of Intent by refusing to close by the date provided and by allegedly entertaining offers from third parties for the same leasehold interests. Allegations of inducement of breach of contract and related claims are made by CNX against the remaining defendants, on the theory that these parties knew of the terms of the Letter of Intent and induced Miller Energy to breach the Letter of Intent. CNX is seeking $15.5 million in damages. We assert that we acted in good faith and believe that the outcome of the litigation will be resolved in our favor.

We and our subsidiaries are also parties to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See “Item 8: Financial Statements and Supplementary Data – Note 15 to the Consolidated Combined Financial Statements”.

ITEM 4:

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5:

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

Our common units trade on the New York Stock Exchange under the symbol “ATLS.” At the close of business on February 25, 2013, the closing price of our units was $41.05, and there were 202 holders of record of our common units. The following table sets forth the high and low sales price per unit of our common limited partner units as reported by the New York Stock Exchange and the cash distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2012 and 2011:


	High		Low		Cash Distribution per Common Limited Partner Declared⁽¹⁾
Year ended December 31, 2012:
Fourth quarter	$	36.57	$	31.15	$	0.30
Third quarter	$	36.75	$	29.95	$	0.27
Second quarter	$	39.35	$	27.83	$	0.25
First quarter	$	35.40	$	23.51	$	0.25

Year ended December 31, 2011:
Fourth quarter	$	25.59	$	15.82	$	0.24
Third quarter	$	25.72	$	17.69	$	0.24
Second quarter	$	27.36	$	20.41	$	0.22
First quarter	$	23.24	$	13.11	$	0.11

(1)	The determination of the amount of future cash distributions declared, if any, is at the sole discretion of our General Partner’s board of directors and will depend on various factors affecting our financial conditions and other matters the board of directors deems relevant.

We have a cash distribution policy under which we distribute, within 50 days after the end of each quarter, all of our available cash (as defined in the partnership agreement) for that quarter to our common unitholders. See “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cash Distributions.”

For information concerning common units authorized for issuance under our long-term incentive plans, see “Item 12: Security Ownership of Certain Beneficial Owners and Management – Equity Compensation Plan Information”.

ITEM 6:

SELECTED FINANCIAL DATA

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2012, 2011 and 2010, with the exception of consolidated balance sheet data for the year ended December 31, 2010, from our consolidated combined 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, 2009 and 2008, as well as consolidated balance sheet data for the year ended December 31, 2010, from our consolidated financial statements, which are not included in this report.

The consolidated combined financial statements include our accounts and that of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2012, except for ARP and APL, which we control. Due to the structure of our ownership interests in ARP and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and APL are reflected as income (loss) attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us and our wholly-owned subsidiaries and the consolidated results of ARP and APL, adjusted for non-controlling interests in ARP and APL.

On February 17, 2011, we acquired certain producing natural gas and oil properties, an investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. In accordance with prevailing accounting literature, we determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the purchase method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

•

Recognized the assets and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital;

•

Retrospectively adjusted our consolidated combined balance sheets, our consolidated combined statements of operations, our consolidated combined statements of partners’ capital, our consolidated combined statements of comprehensive income (loss) and our consolidated combined statements of cash flows to reflect our results combined with the results of the Transferred Business as of or at the beginning of the respective period;

•

Adjusted the presentation of our consolidated combined statements of operations to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income (loss) to determine income (loss) attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron in February 2011 and not activities related to the Transferred Business.

The following table should be read together with our consolidated financial statements and notes thereto included within “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8: Financial Statements and Supplementary Data” of this report.


	Years Ended December 31,
	2012			2011			2010			2009			2008
	(in thousands, except per unit data)
Statement of operations data:
Revenues:
Gas and oil production	$	92,901		$	66,979		$	93,050		$	112,979		$	127,083
Well construction and completion		131,496			135,283			206,802			372,045			415,036
Gathering and processing		1,219,815			1,329,418			944,609			714,145			1,185,254
Administration and oversight		11,810			7,741			9,716			15,554			19,277
Well services		20,041			19,803			20,994			17,859			18,513
Gain (loss) on mark-to-market derivatives		31,940			(20,453	)		(5,944	)		(35,815	)		29,741
Other, net		13,440			31,803			17,437			15,295			7,330

Total revenues		1,521,443			1,570,574			1,286,664			1,212,062			1,802,234


Costs and expenses:
Gas and oil production		26,624			17,100			23,323			25,557			25,104
Well construction and completion		114,079			115,630			175,247			315,546			359,609
Gathering and processing		1,009,100			1,123,051			789,548			605,222			978,178
Well services		9,280			8,738			10,822			9,330			10,654
General and administrative		165,777			80,584			37,561			38,932			633
Chevron transaction expense		7,670			—			—			—			—
Depreciation, depletion and amortization		142,611			109,373			115,655			119,396			111,545
Goodwill and asset impairment		9,507			6,995			50,669			166,684			615,724

Total costs and expenses		1,484,648			1,461,471			1,202,825			1,280,667			2,101,447


Operating income (loss)		36,795			109,103			83,839			(68,605	)		(299,213	)

Gain (loss) on asset sales and disposal		(6,980	)		256,292			(13,676	)		108,947			—
Interest expense		(46,520	)		(38,394	)		(90,448	)		(104,053	)		(89,284	)
(Loss) gain on early extinguishment of debt		—			(19,574	)		(4,359	)		(2,478	)		17,420


Income (loss) from continuing operations before tax		(16,705	)		307,427			(24,644	)		(66,189	)		(371,077	)
Income tax expense		176			—			—			—			—

Income (loss) from continuing operations		(16,881	)		307,427			(24,644	)		(66,189	)		(371,077	)

Income (loss) from discontinued operations		—			(81	)		321,155			84,148			(93,802	)

Net income (loss)		(16,881	)		307,346			296,511			17,959			(464,879	)
(Income) loss attributable to non-controlling interests		(35,532	)		(257,643	)		(245,764	)		(53,924	)		536,455

Net income (loss) after non-controlling interests.		(52,413	)		49,703			50,747			(35,965	)		71,576
(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition).		—			(4,711	)		(22,813	)		40,000			(145,229	)

Net income (loss) attributable to common limited partners.	$	(52,413	)	$	44,992		$	27,934		$	4,035		$	(73,653	)


Allocation of net income (loss) attributable to common limited partners:
Continuing operations	$	(52,413	)	$	45,002		$	(11,994	)	$	(7,287	)	$	(62,331	)
Discontinued operations		—			(10	)		39,928			11,322			(11,322	)

	$	(52,413	)	$	44,992		$	27,934		$	4,035		$	(73,653	)


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

Income (loss) from continuing operations attributable to common limited partners	$	(1.02	)	$	0.91		$	(0.43	)	$	(0.26	)	$	(2.23	)
Income (loss) from discontinued operations attributable to common limited partners		—			—			1.44			0.41			(0.45	)

Net income (loss) attributable to common limited partners	$	(1.02	)	$	0.91		$	1.01		$	0.15		$	(2.68	)


Diluted⁽¹⁾:
Income (loss) from continuing operations attributable to common limited partners	$	(1.02	)	$	0.88		$	(0.43	)	$	(0.26	)	$	(2.23	)
Income (loss) from discontinued operations attributable to common limited partners		—			—			1.44			0.41			(0.45	)

Net income (loss) attributable to common limited partners	$	(1.02	)	$	0.88		$	1.01		$	0.15		$	(2.68	)


Balance sheet data (at period end):
Property, plant and equipment, net	$	3,502,609		$	2,093,283		$	1,849,486		$	1,831,090		$	2,031,774
Total assets		4,597,194			2,684,771			2,435,262			2,838,007			3,262,986
Total debt, including current portion		1,540,343			524,140			601,389			1,262,183			1,539,427
Total partners’ capital		2,479,848			1,744,081			1,406,123			1,053,855			1,135,216

Cash flow data:
Net cash provided by operating activities	$	70,276		$	88,195		$	157,253		$	236,664		$	108,844
Net cash provided by (used in) investing activities		(1,650,505	)		14,159			502,330			142,637			(555,123	)
Net cash provided by (used in) financing activities		1,539,633			(25,225	)		(660,439	)		(385,483	)		435,477
Capital expenditures		(500,759	)		(292,750	)		(139,360	)		(209,576	)		(340,975	)

(1)

For the year ended December 31, 2012, approximately 2,867,000 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the year ended December 31, 2010, approximately 180,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2009, approximately 187,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such

common limited partner units would have been anti-dilutive. For the year ended December 31, 2008, approximately 553,000 stock awards were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive.

ITEM 7:

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with “Item 6: – Selected Financial Data” and “Item 8: Financial Statements and Supplemental Data”, which contains our consolidated combined financial statements.

The following discussion may contain forward-looking statements that reflect our or our subsidiaries’ plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and in “Item 1A: Risk Factors”. We believe the assumptions underlying the consolidated combined financial statements are reasonable.

BUSINESS OVERVIEW

We are a publicly-traded Delaware master limited partnership, whose common units are listed on the New York Stock Exchange under the symbol “ATLS”.

At December 31, 2012, our operations primarily consisted of our ownership interests in the following entities:

•

Atlas Resource Partners, L.P. (“ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP), and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At December 31, 2012, we owned 100% of the general partner Class A units and incentive distribution rights, and common units representing an approximate 43.0% limited partner ownership interest in ARP;

•

Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the natural gas gathering, processing and treating services in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services throughout the southwestern region of the United States. At December 31, 2012, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 8.7% common limited partner interest; and

•

AEI’s investment management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, through which ARP funds a portion of its natural gas and oil well drilling;

•

certain producing natural gas and oil properties, upon which ARP is the developer and producer.

In addition to the exploration and production assets, the Transferred Business also included all of the ownership interests in Atlas Energy GP, LLC, our general partner, and a direct and indirect ownership interest in Lightfoot.

FINANCIAL PRESENTATION

Our consolidated combined financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2012, except for ARP and APL, which we control. Due to the structure of our ownership interests in ARP and APL, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and APL into our financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and APL are reflected as income attributable to non-controlling interests in our consolidated combined statements of operations and as a component of partners’ capital on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated combined financial statements, we are referring to the consolidated combined results for us, our wholly-owned subsidiaries and the consolidated results of ARP and APL, adjusted for non-controlling interests in ARP and APL. All significant intercompany transactions and balances have been eliminated in the consolidation of our financial statements.

On February 17, 2011, we acquired certain producing natural gas and oil properties, a partnership management business which sponsors tax-advantaged direct investment natural gas and oil partnerships, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of our general partner. Our management determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable assets and liabilities of the Transferred Business based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on our consolidated balance sheet. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated combined financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect of the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior year financial statements to furnish comparative information. As such, we reflected the impact of the acquisition of the Transferred Business on our consolidated combined financial statements in the following manner:

•

Recognized the assets acquired and liabilities assumed from the Transferred Business at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital;

•

Retrospectively adjusted our consolidated combined financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect our results on a consolidated combined basis with the results of the Transferred Business as of or at the beginning of the respective period; and

•

Adjusted the presentation of our consolidated combined statements of operations for the years ended December 31, 2011 and 2010 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation in February 2011 and not activities related to the Transferred Business.

SUBSEQUENT EVENTS

Cash Distribution. On January 24, 2013, we declared a cash distribution of $0.30 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $15.4 million distribution was paid on February 19, 2013 to unitholders of record at the close of business on February 6, 2013.

Atlas Pipeline

Senior Notes. On February 11, 2013, APL issued $650.0 million of 5.875% unsecured senior notes due 2023 (“5.875% APL Senior Notes”) in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.8 million and plans to utilize the proceeds to redeem any or all of its outstanding 8.75% senior unsecured notes due on June 15, 2018 (“8.75% APL Senior Notes”) and repay a portion of its outstanding indebtedness under its revolving credit facility. APL has agreed to file a registration statement with respect to the 5.875% Senior Notes. On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding $365.8 million 8.75% APL Senior Notes and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% Senior Notes, (representing approximately 73.4% of the outstanding 8.75% Senior Notes) were validly tendered as of the expiration date of the consent solicitation. On February 11, 2013, APL accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent solicitation and entered into a supplemental indenture amending and supplementing the 8.75% Senior Notes Indenture. APL also issued a notice to redeem all the 8.75% APL Senior Notes not purchased in connection with the tender offer. APL plans to fund the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes.

Cash Distribution. On January 23, 2013, APL declared a cash distribution of $0.58 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $40.6 million distribution, including $3.1 million to us, as general partner, was paid on February 14, 2013 to unitholders of record at the close of business on February 7, 2013.

Acquisition of Gas Gathering Systems and Related Assets. On January 7, 2013, APL paid $6.0 million for the first of two payments related to the acquisition of a gas gathering system and related assets in February 2012. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts (“Trigger Payments”), if certain volumes were achieved on the acquired gathering system within specified periods of time. Sufficient volumes were achieved in December 2012 to meet the required volumes for the first Trigger Payment (see “Recent Developments”).

Atlas Resource

Cash Distribution. On January 24, 2013, ARP declared a cash distribution of $0.48 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2012. The $23.6 million distribution, including $0.6 million to us, as general partner, and $1.8 million to its preferred limited partners, was paid on February 14, 2013 to unitholders of record at the close of business on February 6, 2013.

Senior Notes. On January 23, 2013, ARP issued $275.0 million of 7.75% senior unsecured notes due on January 15, 2021 (“7.75% ARP Senior Notes”). ARP used the net proceeds of approximately $268.3 million, net of underwriting fees and other offering costs of $6.7 million, to repay all of the indebtedness and accrued interest outstanding under its term loan credit facility and a portion of that outstanding under its revolving credit facility (see “Credit Facilities”). Under the terms of ARP’s revolving credit facility, the borrowing base was reduced by 15% of the 7.75% ARP Senior Notes to $368.8 million. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $2.2 million of amortization expense related to deferred financing costs in January 2013. The indenture governing the 7.75% ARP Senior Notes contains covenants, including limitations of ARP’s ability to incur certain liens, 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 ARP’s assets.

RECENT DEVELOPMENTS

New Credit Facility. In May 2012, we entered into a new credit facility with a syndicate of banks that matures in May 2016. The credit facility has maximum lender commitments of $50.0 million, and up to $5.0 million of the credit facility may be in the form of standby letters of credit. Our obligations under the credit facility are secured by substantially all of our assets, including our ownership interests in APL and ARP. Additionally, our obligations under the credit facility may be guaranteed by future subsidiaries. The credit agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a commitment deficiency exists or a default under the credit agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. The credit agreement also contains covenants that require us to maintain a ratio of Total Funded Debt (as defined in the credit agreement) to EBITDA (as defined in the credit agreement) not greater than 3.25 to 1.0 as of the last day of any fiscal quarter and a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) not less than 2.75 to 1.0 as of the last day of any fiscal quarter (see “Credit Facilities”).

Atlas Pipeline

Acquisition of Cardinal Midstream. In December 2012, APL acquired 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.5 million in cash, including preliminary purchase price adjustments (the “Cardinal Acquisition”). The assets of these companies include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas as follows:

•

the Tupelo plant, which is a 120 MMcfd cryogenic processing facility;

•

approximately 60 miles of gathering pipeline;

•

the East Rockpile treating facility, a 250 GPM amine treating plant;

•

a fixed fee contract gas treating business that includes fifteen amine treating plants and two propane refrigeration plants; and

•

a 60% interest in the Centrahoma Processing, LLC joint venture (“Centrahoma”). The remaining 40% interest is owned by MarkWest Oklahoma Gas Company, LLC, (“MarkWest”) a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). Centrahoma owns the following assets:

•

the Coalgate and Atoka plants, which are cryogenic processing facilities with a combined current processing capacity of approximately 100 MMcfd;

•

the prospective Stonewall plant, for which construction has been approved, with anticipated processing capacity of 120 MMcfd; and

•

15 miles of NGL pipeline.

Equity Offering. In December 2012, in connection with the Cardinal Acquisition, APL completed the sale of 10,507,033 APL common units in a public offering at an offering price of $31.00 per unit and received net proceeds of $319.3 million, including $6.7 million contributed by us to maintain our 2.0% general partner interest in APL. APL used the net proceeds from this offering to fund a portion of the Cardinal Acquisition. In November 2012, APL entered into an agreement to issue $200.0 million of newly created Class D convertible preferred units in a private placement in order to finance a portion of the Cardinal Acquisition. Under the terms of the agreement, the private placement of the Class D convertible preferred units was nullified upon APL’s issuance of common units in excess of $150.0 million prior to the closing date of the Cardinal Acquisition. As a result of APL’s December 2012 issuance of $319.3 million common units, the private placement agreement terminated without the issuance of the Class D preferred units, and APL paid a commitment fee equal to 2.0% of the $200.0 million offering amount, or $4.0 million (see “Issuance of Units”).

Equity Distribution Program. In November 2012, APL entered into an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL is authorized to, at its discretion, issue common units to investors through Citigroup at prevailing market prices, up to an aggregate value of $150.0 million. Citigroup is not required to sell any specific number or dollar amount of the common units, but will use its reasonable efforts, consistent with its normal trading and sales practices, to sell such units. APL intends to use the net proceeds from any such offering for general partnership purposes (see “Issuance of Units”).

Senior Notes. In September 2012, APL issued $325.0 million of 6.625% senior unsecured notes due on October 1, 2020 (“6.625% APL Senior Notes”) in a private placement transaction. The 6.625% APL Senior Notes were issued at par. APL received net proceeds of $318.9 million and utilized the proceeds to reduce the outstanding balance on its revolving credit facility. APL has agreed to file a registration statement with respect to these 6.625% APL Senior Notes. In December 2012, APL issued $175.0 million of 6.625% APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes were issued at a premium of 103.0% of the principal amount for a yield of approximately 6.0%. APL received net proceeds of $176.5 million and utilized the proceeds to fund a portion of the purchase price of the Cardinal Acquisition.

Expansion Projects. In September 2012, APL completed construction of, and started processing through, a 200 MMcfd cryogenic processing plant, referred to as the Waynoka II plant, on APL’s WestOK gathering and processing system. This expansion brings the total name-plate processing capacity on the WestOK system to 458 MMcfd. In June 2012, APL completed construction of, and started processing through, a 60 MMcfd cryogenic facility at its Velma gas plant, increasing capacity at Velma to 160 MMcfd. This expansion supports APL’s long-term fee-based agreement with XTO Energy, Inc., a

subsidiary of ExxonMobil, to provide natural gas gathering and processing services for up to an incremental 60 MMcfd from the Woodford Shale.

Acquisition of Gas Gathering Systems and Related Assets. In June 2012, APL acquired a gas gathering system and related assets in the Barnett Shale in Tarrant County, Texas for an initial net purchase price of $18.0 million. The system is used to facilitate gathering of newly acquired natural gas production of ARP. In February 2012, APL acquired a gas gathering system and related assets, at their WestOK system, for an initial net purchase price of $19.0 million. APL agreed to pay up to an additional $12.0 million, payable in two equal amounts, subject to delivery of certain minimum volumes of natural gas from a specified area and within certain specified time periods (“Trigger Payments”). In connection with this acquisition, APL received assignment of gas purchase agreements for gas currently gathered on the acquired system.

Amended Credit Facility. In May 2012, APL entered into an amendment to its revolving credit facility agreement, which among other changes, increased the revolving credit facility from $450.0 million to $600.0 million and extended the maturity date from December 22, 2015 to May 31, 2017 (see “Credit Facilities”).

Atlas Resource

DTE Acquisition. On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, LLC from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million, subject to certain post-closing adjustments (the “DTE Acquisition”). The cash paid at closing was funded through $179.8 million of borrowings under ARP’s revolving credit facility and $77.6 million through borrowings under its term loan credit facility.

Amendment to revolving credit facility and new term loan credit facility. On December 20, 2012, in connection with the completion of the DTE Acquisition, ARP entered into an amendment to its revolving credit facility and a new term loan credit facility, which (i) increased the borrowing base from $310.0 million to $410.0 million, (ii) stated that borrowings under the revolving credit facility bear interest, at ARP’s election, are at either LIBOR plus an applicable margin between 2.00% and 3.25% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 1.00% and 2.25% per annum, (iii) revised the maturity date to be the earlier of March 22, 2016 or February 19, 2014 (the date that is 91 days before the May 19, 2014 maturity date of ARP’s term loan credit facility) if any portion of the term loan debt is outstanding on that date, and (iv) amended the financial covenants to require that ARP’s ratio of Total Funded Debt (as defined in the credit agreement) to four quarters of EBITDA (as defined in the credit agreement) not be greater than 4.25 to 1.0 as of the last day of fiscal quarters ending on or before June 30, 2013, 4.00 to 1.0 as of September 30, 2013 and December 31, 2013, and 3.75 to 1.0 as of the last day of fiscal quarters ending after that date. The new $77.6 million term loan credit facility matures May 19, 2014, and contains terms substantially similar to its revolving credit facility except (i) borrowings bear interest, at ARP’s option, at either the prime rate plus 6.5% or LIBOR plus 7.5%, (ii) ARP will be required to prepay borrowings with 100% of the net proceeds of any senior notes offering and 33% of the net proceeds from any equity offering, and (iii) requires ARP to maintain a ratio of Total Funded Debt to EBITDA 0.50 higher than that required under its revolving credit facility, a ratio of EBITDA to Consolidated Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0 as of the last day of any fiscal quarter, and a minimum asset coverage ratio (as defined in the credit agreement) of at least 1.5 to 1.0 (see “Subsequent Events – ARP Senior Notes” for further information).

Equity Offering. In November and December 2012, in connection with entering into a purchase agreement to acquire certain producing wells and net acreage from DTE, ARP sold an aggregate 7,898,210 of its common limited partner units in a public offering at a price of $23.01 per unit, yielding net proceeds of approximately $174.5 million. ARP utilized the net proceeds from the sale to repay a portion of the outstanding balance under its revolving credit facility and $2.2 million under its term loan credit facility.

Acquisition of Titan Operating, L.L.C. In July 2012, ARP completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million ARP common units and 3.8 million newly-created convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see “Issuance of Units”). The cash paid at closing was funded through borrowings under ARP’s credit facility (see “Credit Facilities”). The common units and preferred units were issued and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act (see “Issuance of Units”).

Acquisition of Assets from Carrizo Oil & Gas, Inc. In April 2012, ARP acquired certain oil and natural gas assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash. The purchase price was funded through borrowing under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of ARP’s common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain of

ARP’s executives. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see “Issuance of Units”).

Equal Acquisition. In April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equal”). The transaction was funded through borrowings under ARP’s revolving credit facility (see “Credit Facilities”). Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. Both transactions were funded through borrowings under ARP revolving credit facility (see “Credit Facilities”). As a result of ARP’s acquisition of Equal’s remaining interest in the undeveloped acres, the existing joint venture agreement between ARP and Equal in the Mississippi Lime position was terminated and all infrastructure associated with the assets, principally the salt water disposal system is operated by ARP.

CONTRACTUAL REVENUE ARRANGEMENTS

Atlas Resources

Natural Gas. ARP markets the majority of its natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indexes are as follows: Appalachian Basin and Mississippi Lime, primarily the New York Mercantile Exchange (“NYMEX”) spot market price; Barnett Shale and Marble Falls, primarily the Waha spot market price; New Albany Shale and Antrim Shale, primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation, primarily the Cheyenne Hub spot market price.

Crude Oil. Crude oil produced from ARP’s wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. ARP does not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGL’s are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas (low Btu content) to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as mentioned above and our NGLs are generally priced using the Mont Belvieu (TX) regional processing hub. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. ARP does not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

Investment Partnerships. ARP generally funds a portion of its drilling activities through sponsorship of tax-advantaged investment drilling partnerships. In addition to providing capital for its drilling activities, ARP’s investment partnerships are a source of fee-based revenues, which are not directly dependent on commodity prices. As managing general partner of the investment partnerships, ARP receives the following fees:

•

Well construction and completion. For each well that is drilled by an investment partnership, ARP receives a 15% to 18% mark-up on those costs incurred to drill and complete the well;

•

Administration and oversight. For each well drilled by an investment partnership, ARP receives a fixed fee between $15,000 and $400,000, depending on the type of well drilled. Additionally, the partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. Because ARP coinvests in the partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the well;

•

Atlas Pipeline

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

•

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

•

the contract terms with each producer; and

•

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

Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems and then sells the natural gas and NGLs off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. For the year ended December 31, 2012, Oneok Hydrocarbon, LP and Tenaska Marketing Ventures accounted for approximately 48% and 15% of APL’s consolidated total third-party revenues, respectively, excluding the impact of all financial derivative activity, with no other single customer accounting for more than 10% for this period.

GENERAL TRENDS AND OUTLOOK

We expect our and our subsidiaries’ businesses to be affected by the following key trends. Our expectations are based on assumptions made by us and our subsidiaries and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our and our subsidiaries’ actual results may vary materially from our expected results.

Atlas Resource

The areas in which ARP operates are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. The increase in the supply of natural gas has put a downward pressure on domestic natural gas prices. While ARP anticipates continued high levels of exploration and production activities over the long-term in the areas in which it operates, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas, oil and NGL reserves.

ARP’s future gas and oil reserves, production, cash flow, its ability to make payments on its revolving credit facility and its ability to make distributions to its unitholders, including us, depend on ARP’s success in producing its current reserves efficiently, developing its existing acreage and acquiring additional proved reserves economically. ARP faces the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases. ARP attempts to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than it produces.

Atlas Pipeline

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

As a result of APL’s Percentage of Proceeds (“POP”) and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil. APL management believes 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, APL management generally expects NGL prices to follow changes in crude oil prices over the long term, which management believes will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered, processed and treated.

RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. At December 31, 2012, our consolidated gas and oil production revenues and expenses consist solely of ARP’s gas and oil production activities. Currently, ARP has focused its natural gas, crude oil and NGL production operations in various shale plays throughout the United States. As part of our agreement with AEI to acquire the Transferred Business on February 17, 2011, ARP has certain agreements which restrict its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale, which will expire on February 17, 2014. Through December 31, 2012, ARP has established production positions in the following areas:

•

the Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which ARP established a position following its acquisitions of assets from Carrizo, Titan and DTE during 2012 (see “Recent Developments”);

•

the Appalachia basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas and the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region;

•

the Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area, in which ARP established a position following its acquisitions from Equal during 2012 (see “Recent Developments”); and

•

other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables ARP to access other formations in that region such as the Monteagle and Ft. Payne Limestone; the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile; the Antrim Shale in Michigan, where we produce out of the biogenic region of the shale similar to the New Albany Shale; and the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas.

The following table presents the number of wells ARP drilled, both gross and for its interest, and the number of gross wells it turned in line during the years ended December 31, 2012, 2011 and 2010:


	Years Ended December 31,
	2012		2011		2010
Gross wells drilled:
Appalachia		22		17		18
Barnett/Marble Falls		21		—		—
Mississippi Lime/Hunton		11		—		—
Tennessee		—		5		4
New Albany/Antrim		—		—		66
Niobrara		51		138		29

Total		105		160		117


Our share of gross wells drilled⁽¹⁾:
Appalachia		6		3		5
Barnett/Marble Falls		18		—		—
Mississippi Lime/Hunton		3		—		—
Tennessee		—		1		1
New Albany/Antrim		—		—		19
Niobrara		15		27		9

Total		42		31		34


Gross wells turned in line:
Appalachia		41		8		70
Barnett/Marble Falls		7		—		—
Mississippi Lime/Hunton		3		—		—
Tennessee		5		1		13
New Albany/Antrim		—		13		76
Niobrara		98		77		8

Total		154		99		167

(1)	Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) ARP’s percentage interest in the wells based on its percentage ownership in its investment partnerships.

Production Volumes. The following table presents ARP’s total net natural gas, crude oil, and NGL production volumes and production per day for the years ended December 31, 2012, 2011 and 2010:


	Years Ended December 31,
	2012		2011		2010
Production:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (MMcf)		12,403		9,597		11,596
Oil (000’s Bbls)		102		105		126
Natural gas liquids (000’s Bbls)		4		6		20

Total (MMcfe)		13,036		10,262		12,467

Barnett/Marble Falls:
Natural gas (MMcf)		10,561		—		—
Oil (000’s Bbls)		10		—		—
Natural gas liquids (000’s Bbls)		173		—		—

Total (MMcfe)		11,661		—		—

Mississippi Lime/Hunton:
Natural gas (MMcf)		510		—		—
Oil (000’s Bbls)		3		—		—
Natural gas liquids (000’s Bbls)		30		—		—

Total (MMcfe)		705		—		—

Other Operating Areas:⁽³⁾
Natural gas (MMcf)		1,929		1,866		1,491
Oil (000’s Bbls)		6		7		10
Natural gas liquids (000’s Bbls)		150		156		162

Total (MMcfe)		2,865		2,847		2,531

Total:
Natural gas (MMcf)		25,403		11,462		13,087
Oil (000’s Bbls)		121		112		136


Natural gas liquids (000’s Bbls)	357	162	182

Total (MMcfe)	28,267	13,108	14,998


Production per day:⁽¹⁾⁽²⁾
Appalachia:⁽³⁾
Natural gas (Mcfd)	33,889	26,292	31,771
Oil (Bpd)	278	287	344
Natural gas liquids (Bpd)	10	17	54

Total (Mcfed)	35,618	28,116	34,157

Barnett/Marble Falls:⁽⁴⁾
Natural gas (Mcfd)	28,855	—	—
Oil (Bpd)	28	—	—
Natural gas liquids (Bpd)	473	—	—

Total (Mcfed)	31,861	—	—

Mississippi Lime/Hunton:⁽⁴⁾
Natural gas (Mcfd)	1,392	—	—
Oil (Bpd)	8	—	—
Natural gas liquids (Bpd)	81	—	—

Total (Mcfed)	1,926	—	—

Other Operating Areas:⁽³⁾
Natural gas (Mcfd)	5,271	5,111	4,084
Oil (Bpd)	16	20	29
Natural gas liquids (Bpd)	410	427	445

Total (Mcfed)	7,827	7,796	6,933

Total:
Natural gas (Mcfd)	69,408	31,403	35,855
Oil (Bpd)	330	307	373
Natural gas liquids (Bpd)	974	444	499

Total (Mcfed)	77,232	35,912	41,090

⁽¹⁾

Production quantities consist of the sum of (i) ARP’s proportionate share of production from wells in which ARP has a direct interest, based on its proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the investment partnerships in which it has an interest, based on ARP’s equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

⁽²⁾

“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

⁽³⁾	Appalachia includes ARP’s production located in Pennsylvania, Ohio, New York and West Virginia. Other operating areas include ARP’s production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.

⁽⁴⁾	Total Barnett/Marble Falls and Mississippi Lime/Hunton production per day for the year ended December 31, 2012 represents volume production subsequent to the respective acquisition date over the full 366-day period (see “Recent Developments”).

Production Revenues, Prices and Costs. ARP’s production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised 79% of ARP’s proved reserves on an energy equivalent basis at December 31, 2012. The following table presents ARP’s production revenues and average sales prices for its natural gas, oil, and natural gas liquids production for the years ended December 31, 2012, 2011 and 2010, along with ARP’s average production costs, taxes, and transportation and compression costs in each of the reported periods:


	Years Ended December 31,
	2012		2011		2010
Production revenues (in thousands):
Appalachia:⁽¹⁾
Natural gas revenue	$	35,193	$	40,431	$	66,566
Oil revenue		9,678		9,415		9,732
Natural gas liquids revenue		223		323		845

Total revenues	$	45,094	$	50,169	$	77,143

Barnett/Marble Falls:
Natural gas revenue	$	25,545	$	—	$	—
Oil revenue		887		—		—
Natural gas liquids revenue		4,959		—		—


Total revenues	$	31,391	$	—	$	—

Mississippi Lime/Hunton:
Natural gas revenue	$	1,840	$	—	$	—
Oil revenue		241		—		—
Natural gas liquids revenue		1,140		—		—

Total revenues	$	3,221	$	—	$	—

Other Operating Areas:⁽²⁾
Natural gas revenue	$	7,573	$	8,665	$	9,064
Oil revenue		545		642		809
Natural gas liquids revenue		5,077		7,503		6,034

Total revenues	$	13,195	$	16,810	$	15,907

Total:
Natural gas revenue	$	70,151	$	49,096	$	75,630
Oil revenue		11,351		10,057		10,541
Natural gas liquids revenue		11,399		7,826		6,879

Total revenues	$	92,901	$	66,979	$	93,050


Average sales price:
Natural gas (per Mcf):⁽³⁾
Total realized price, after hedge⁽⁴⁾	$	3.29	$	4.98	$	7.08
Total realized price, before hedge⁽⁴⁾	$	2.60	$	4.53	$	4.60
Oil (per Bbl): ⁽³⁾
Total realized price, after hedge	$	94.02	$	89.70	$	77.31
Total realized price, before hedge	$	91.32	$	89.07	$	71.37

Natural gas liquids (per Bbl) total realized price:⁽³⁾	$	31.97	$	48.26	$	37.78

Production costs (per Mcfe):⁽³⁾
Appalachia:⁽¹⁾
Lease operating expenses⁽⁵⁾	$	1.02	$	1.20	$	1.37
Production taxes		0.08		0.11		0.03
Transportation and compression		0.38		0.50		0.73

	$	1.48	$	1.80	$	2.13

Barnett/Marble Falls:
Lease operating expenses	$	0.61	$	—	$	—
Production taxes		0.18		—		—
Transportation and compression		0.12		—		—

	$	0.90	$	—	$	—

Mississippi Lime/Hunton:
Lease operating expenses	$	1.38	$	—	$	—
Production taxes		0.29		—		—
Transportation and compression		—		—		—

	$	1.67	$	—	$	—