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, 2013

OR

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

For the transition period from                      to                     

Commission file number: 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):

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2013, was approximately $2.4 billion.

The number of outstanding common units of the registrant on February 25, 2014 was 51,486,558.

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		8
	Item 1A:	Risk Factors		26
	Item 1B:	Unresolved Staff Comments		60
	Item 2:	Properties		61
	Item 3:	Legal Proceedings		68
	Item 4:	Mine Safety Disclosures		68
PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		68
	Item 6:	Selected Financial Data		69
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		72
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk		111
	Item 8:	Financial Statements and Supplementary Data		116
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		198
	Item 9A:	Controls and Procedures		198
	Item 9B:	Other Information		200
PART III	Item 10:	Directors, Executive Officers and Corporate Governance		201
	Item 11:	Executive Compensation		211
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		239
	Item 13:	Certain Relationships and Related Transactions, and Director Independence		243
	Item 14:	Principal Accountant Fees and Services		245
PART IV	Item 15:	Exhibits and Financial Statement Schedules		245
SIGNATURES				254

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GLOSSARY OF TERMS

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

Bbl. 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. An exploratory, development or extension well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

Dth. One dekatherm, equivalent to one million British thermal units.

Dth/d. Dekatherms per day.

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.

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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 producing well or well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

Proved developed reserves. Reserves of any category 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, which, 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 of any category 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.

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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 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.

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FORWARD-LOOKING STATEMENTS

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

• the demand for natural gas, 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 our and 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;

• impact fees and severance taxes;

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

6

• 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;

• 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;

• 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 our, ARP and APL’s business and operations;

• ability to integrate operations and personnel from acquired businesses;

• 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.

7

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:

• 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;

• 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 primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services in the southwestern region of the United States;

• Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) 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, 2013, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot; and

• Certain natural gas and oil producing assets.

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

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 at that time and the partnership management business to ARP on March 5, 2012.

Our ownership in ARP consists of the following:

• all of the outstanding Class A units, representing 1,368,058 units at December 31, 2013, 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

• an approximate 36.9% limited partner ownership interest (20,962,485 common units and 3,749,986 preferred limited partner units) in ARP at December 31, 2013.

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;

• 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.

8

ARP’s primary business objective is to generate growing yet stable cash flows through the development and acquisition of mature, long-lived natural gas, oil and natural gas liquids properties. As of December 31, 2013, ARP’s estimated proved reserves were 1,169 Bcfe, including reserves net to ARP’s equity interest in its tax-advantaged investment partnerships (“Drilling Partnerships”). Of ARP’s estimated proved reserves, approximately 68% were proved developed and approximately 83% were natural gas. For the year ended December 31, 2013, ARP’s average daily net production was approximately 187.7 MMcfe. Through December 31, 2013, ARP owns production positions in the following areas:

• ARP’s Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas. ARP has ownership interests in approximately 620 wells in the Barnett Shale and Marble Falls play and 484 Bcfe of total proved reserves with average daily production of 86.4 MMcfe for the year ended December 31, 2013;

• ARP’s coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. ARP has ownership interests in approximately 2,950 wells in the Raton, Black Warrior and County Line areas and 433 Bcfe of total proved reserves with average daily production of 47.8 MMcfe for the year ended December 31, 2013;

• ARP’s Appalachia Basin, including the Marcellus Shale and the Utica Shale. ARP has ownership interests in approximately 8,170 wells primarily in the Appalachian Basin, including approximately 270 wells in the Marcellus Shale and 160 Bcfe of total proved reserves with average daily production of 38.8 MMcfe for the year ended December 31, 2013;

• ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma. ARP owns 76 Bcfe of total proved reserves with average daily production of 7.8 MMcfe for the year ended December 31, 2013; and

• ARP’s other operating areas, including the Chattanooga Shale in northeastern Tennessee, the New Albany Shale in southwestern Indiana and the Niobrara Shale in northeastern Colorado in which ARP has an aggregate 17 Bcfe of total proved reserves with average daily production of 6.8 MMcfe for the year ended December 31, 2013.

ARP seeks to create substantial value by executing a 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 Acquisition – 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 (the “Carrizo Acquisition”). The assets included 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 Acquisition – 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 $208.6 million (the “Titan Acquisition”). 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 over 300 potential undeveloped drilling locations on the Titan acreage.

• Equal Mississippi Lime Acquisition – 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 $18.0 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 (the “Equal Acquisition”). The transaction increased ARP’s position in the Mississippi Lime play to 19,800 net acres in Alfalfa, Grant and Garfield counties in Oklahoma.

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• DTE Fort Worth Basin Acquisition – 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 spud approximately 70 vertical wells during 2013 and plans to continue its development during 2014. ARP believes that there are further potential development opportunities through vertical down-spacing and horizontal drilling in the Marble Falls formation. The assets acquired from DTE are in close proximity to ARP’s other assets in the Barnett Shale.

• EP Energy Raton Basin, Black Warrior Basin and County Line Acquisition. On July 31, 2013, ARP completed the acquisition of certain assets from EP Energy E&P Company, L.P (“EP Energy”) for approximately $709.6 million in net cash (the “EP Energy Acquisition”). Pursuant to the purchase and sale agreement, ARP acquired interests in approximately 3,000 producing wells generating net production of approximately 119 MMcfed on the date of acquisition from EP Energy on approximately 700,000 net acres. ARP believes there are approximately 1,600 potential undeveloped drilling locations on the acreage acquired. The ARP assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming.

• GeoMet West Virginia and Virginia Acquisition. On February 13, 2014, ARP entered into a definitive asset purchase and sale agreement to acquire certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014, subject to certain purchase price adjustments. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. The closing of the acquisition is subject to certain closing conditions, including a vote by GeoMet’s stockholders to approve the transaction.

Atlas Pipeline Partners Overview

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 6.1% 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.

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.

APL’s gathering and processing segment consists of its (1) SouthOK, SouthTX, WestOK and WestTX operations, which are comprised of natural gas gathering, processing and treating assets servicing drilling activity in the Anadarko, Arkoma and Permian Basins and the Eagle Ford Shale play in south Texas, and (2) natural gas gathering assets located in the Barnett Shale play in Texas and the Appalachian Basin in Tennessee. Gathering and processing revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas. During 2014, APL plans to expand the gathering infrastructure of its SouthOK system by connecting the Velma and Arkoma systems, which are both located in the Woodford Shale region of southern Oklahoma.

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Within its gathering and processing operations, APL has ownership interests in and operates fourteen natural gas processing plants with aggregate capacity of approximately 1,500 MMcfd located in Oklahoma and Texas; a gas treating facility located in Oklahoma; and approximately 11,200 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 and 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; the Eagle Ford Shale; and the Barnett Shale. APL’s gathering systems are connected to 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 segment 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. The contract gas treating operations are located in various shale plays including the Avalon, Eagle Ford, Granite Wash, Haynesville, Fayetteville and Woodford. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation (NYSE: CVX; “Chevron”), which owns the remaining 80% interest.

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

• WestOK Gas Gathering System Acquisition – 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. 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 Acquisition – 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 Acquisition – In December 2012, APL acquired 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.9 million in cash, including final purchase price adjustments (the “Cardinal Acquisition”). The assets of these companies represented the majority of the operating assets of Cardinal and 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 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 is in process, with anticipated processing capacity of 120 MMcfd; and

• 15 miles of NGL pipeline.

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• TEAK Midstream Acquisition – In May 2013, APL completed the acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) for $974.7 million in cash, including final purchase price adjustments, less cash received within working capital (the “TEAK Acquisition”). The assets acquired, which are referred to as the South TX assets, include the following gas gathering and processing facilities in the Eagle Ford shale region of south Texas:

• the Silver Oak I plant, which is a 200 MMcfd cryogenic processing facility;

• a second 200 MMcfd cryogenic processing facility, the Silver Oak II plant, expected to be in service the second quarter of 2014;

• 265 miles of primarily 20-24 inch gathering and residue lines;

• approximately 275 miles of low pressure gathering lines;

• a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), which owns a 62 mile, 24 inch gathering line;

• a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), which owns a 45 mile, 16 inch gathering pipeline; a 71 mile, 24 inch gathering line; and a 50 mile residue pipeline; and

• a 50% interest in T2 EF Cogeneration Holdings L.L.C.(“T2 Co-Gen”), which owns a cogeneration facility.

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

Lightfoot Overview

At December 31, 2013, we owned an approximate 12% interest in Lightfoot LP and an approximate 16% interest in Lightfoot GP, the general partner of Lightfoot L.P. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. On November 6, 2013, Arc Logistics Partners, L.P. (“ARCX”), a master limited partnership owned and controlled by Lightfoot L.P., began trading publicly on the NYSE under the ticker symbol “ARCX”. ARCX is focused on the terminalling, storage, throughput and transloading of crude oil and petroleum products in the East Coast, Gulf Coast and Midwest regions of the United States. ARCX’s cash flows are primarily fee-based under multi-year contracts.

Our Exploration and Production Operations Overview

On July 31, 2013, we completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of our term loan facility. As a result of Arkoma Acquisition, we have ownership interests in approximately 600 wells in the Arkoma Basin in eastern Oklahoma with average daily production of 5.1 MMcfe for the year ended December 31, 2013.

During the year ended December 31, 2013, we formed a new subsidiary partnership to conduct natural gas and oil operations initially in the mid-continent region of the United States, specifically in the Marble Falls formation in the Fort Worth Basin and the Mississippi Lime area of the Anadarko Basin in Oklahoma (our “Development Subsidiary”). At December 31, 2013, our Development Subsidiary had completed two wells in the Marble Falls play. At December 31, 2013, we owned an 18.3% limited partner interest in our Development Subsidiary and 83.1% of its outstanding general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions.

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Contractual Revenue Arrangements

Natural Gas and Oil Production

Natural Gas. We and ARP market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. 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 indices for the majority of our and ARP’s production areas are as follows:

• Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline, Transco Leidy Line;

• Mississippi Lime - Southern Star;

• Barnett Shale and Marble Falls- primarily Waha but with smaller amounts sold into a variety of north Texas outlets;

• Raton – ANR, Panhandle, and NGPL;

• Black Warrior Basin – Southern Natural;

• Arkoma – Enable Gas; and

• Other regions - primarily the Texas Gas Zone SL spot market (New Albany Shale) and the Cheyenne Hub spot market (Niobrara).

We and ARP attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

Crude Oil. Crude oil produced from our and 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. We and ARP do 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 to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as described above and the NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. 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 percentage retention by the processing and fractionation facility. We and ARP do 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, 2013, Enterprise Products Operating LLC, Chevron and Empire Pipeline Corporation accounted for approximately 19%, 11% and 10% of ARP’s total natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Drilling Partnerships

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

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

• Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $400,000, depending on the type of well drilled. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the well;

• Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by its proportionate interest in the wells; and

• Gathering. Each royalty owner, Drilling 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 Drilling 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 in Drilling Partnerships by approximately 3%.

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Gathering and Processing

APL’s principal revenue is generated from the gathering, processing and treating of natural gas, the sale of natural gas, NGLs and condensate; the transportation of NGLs; and the leasing of gas treating facilities. APL’s profitability is a function of the difference between the revenues it receives and the costs associated with conducting its operations, including the cost of natural gas, NGLs and condensate APL purchases as well as operating and general and administrative costs and the impact of APL’s commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in APL’s revenues alone are not necessarily indicative of increases or decreases in its profitability. Variables that affect its profitability are:

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

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

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

• the contract terms with each producer; and

• the efficiency of APL’s gathering systems and processing 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 has a 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. On APL’s SouthTX system, its primary producers, Talisman and Statoil, both have fixed-fee long-term agreements with volume commitments extending into 2022. 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.

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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, APL sells swing gas, which is natural gas sold on a daily basis at various Platt’s Gas Daily midpoint prices. The SouthOK system has access to Enogex, LLC; MarkWest Energy Partners, L.P.’s Arkoma Connector Pipeline; Natural Gas Pipeline Company of America; ONEOK Gas Transportation, LLC and Southern Star Central Gas Pipeline, Inc. Through its Section 311 intrastate transmission pipeline, the SouthTX system has access to Enterprise Intrastate, LLC; Kinder Morgan Tejas Pipeline LLC; Natural Gas Pipeline Company of America; Tennessee Gas Pipeline Company, LLC; Texas Eastern Transmission, LLC; and Transcontinental Gas Pipe Line. 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 Atmos Energy Corporation; El Paso Natural Gas Company; Kinder Morgan Tejas Pipeline, LLC; and Northern Natural Gas Company.

APL sells its NGL production at SouthOK and WestOK, to ONEOK Hydrocarbon, L.P. (“ONEOK”) under three separate agreements. The WestOK agreement has a term expiring in 2014; the Velma agreement within SouthOK has a term expiring at the end of 2016; and the Arkoma agreement within SouthOK has a term expiring in 2024. APL sells its NGL production at SouthTX, WestTX and the Chaney Dell plant in WestOK to DCP NGL Services, LLC, a subsidiary of DCP Midstream, LLC (“DCP”). We also sell our NGL production at SouthTX to Crosstex Energy Services, L.P. APL has signed agreements with DCP to sell its NGL production from its WestOK and Velma processing facilities upon the expiration of each of the ONEOK agreements. The DCP agreements each have a term of fifteen years. 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 fractionation fees and, if applicable, quality adjustment fees.

Condensate collected at the SouthOK gas plants and gathering systems is currently sold to EnerWest Trading Company, LLC and Enterprise Products Partners, L.P. Condensate collected at the SouthTX gas plant and gathering systems is currently sold to High Sierra Energy, L.P. and Superior Crude Gathering, Inc. Condensate collected at the WestOK plants and gathering systems is currently sold to JP Energy Partners, L.P. and Plains Marketing, L.P. Condensate collected at the WestTX plants and gathering systems is currently sold to Occidental Energy Marketing, Inc. and Plains Marketing, L.P.

For the year ended December 31, 2013, ONEOK, Tenaska Marketing Ventures, Inc. and DCP accounted for approximately 29%, 17%, and 14%, respectively, 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

Natural Gas and Oil Production

We and ARP seek to provide greater stability in our and ARP’s cash flows through the use of financial hedges for our natural gas, oil and natural gas liquids production. 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 us or ARP and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us and 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 our and ARP’s secured credit facilities do not require cash margin and are secured by our and 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, we and ARP have a management committee to assure that all financial trading is done in compliance with our and ARP’s hedging policies and procedures. We and ARP do not intend to contract for positions that we and ARP cannot offset with actual production.

Gathering and Processing

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.

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

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

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

APL manages the positions for natural gas on a net basis, netting its physical long positions against its physical short positions. Normally, APL is in a net long position on its 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

Natural Gas and Oil Production

The energy industry is intensely competitive in all of its aspects. We and ARP operate in a highly competitive environment for acquiring properties and other energy companies, attracting capital for ARP’s Drilling Partnerships, contracting for drilling equipment and securing trained personnel. We and ARP also compete 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. Our and 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 our and 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 our and 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 Drilling Partnerships. As a result, competition for investment capital to fund Drilling Partnerships is intense.

Gathering and Processing

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, L.P.; Caballo Energy, LLC; Carrera Gas Company; Crosstex Energy Services; L.P., DCP Midstream, LLC; Devon Energy Corporation; Duke Energy Corporation; Energy Transfer Partners, L.P.; Enable Midstream Partners, L.P.; Enterprise Products Partners, L.P.; Howard Energy Partners, LLC; Kinder Morgan Energy Partners, L.P.; Lumen Midstream Partners LLC; Mustang Fuel Corporation; ONEOK Field Services Company, LLC; Regency Energy Partners, L.P.; SemGas, L.P.; Southcross Energy Partners, L.P.; Superior Pipeline Company, LLC; Targa Resources Partners L.P.; TexStar Midstream Services, L.P. and West Texas Gas, Inc.

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

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

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

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

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

APL believes that it has good relationships with operators connected to its system and that it presents an attractive alternative for producers. However, if APL cannot compete successfully through pricing or services offered, 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; 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 Allied Equipment, Inc.; Kinder Morgan Energy Partners, L.P.; Spartan Energy Partners LLC; TransTex Hunter, LLC and Zephyr Gas Services LLC.

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

• fees charged under its contracts;

• the quality and efficiency of its operations;

• its responsiveness to a customer’s needs; and

• with respect to transportation services, location of its transportation systems relative to its competitors.

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 our 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, we, ARP and APL 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:

• restricting the way waste disposal is handled;

• 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;

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

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

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

• requiring 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;

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

• imposing substantial liabilities for pollution resulting from operations; and

• 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.

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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 our, ARP and APL’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 our, ARP and APL’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 our and ARP’s proposed exploration and production activities on federal lands, if any, 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 our, ARP and APL’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 we and our subsidiaries do not believe the current costs of managing wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase the 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.

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Our and 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 we, ARP and APL each believe that we 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 us, ARP or APL. However, none of these spills or releases appears 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 our, ARP or APL’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 our, ARP and APL’s operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. Our, ARP and APL’s operations are subject to the federal Clean Air Act, as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including 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.

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 our, ARP or APL’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. Our, ARP or APL’s failure to comply with these requirements could subject them to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We and our subsidiaries each believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

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

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OSHA and other regulations. We, ARP and APL 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 our, ARP or APL’s operations. We and our subsidiaries believe that we 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 our, ARP or APL’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 our, ARP and APL’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”, or “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 by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us, ARP and APL 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 our, ARP and APL’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 our, ARP or APL’s businesses, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

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Endangered Species Act. The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Endangered species are located in various states in which APL operates include, without limitation, the American Burying Beetle. If endangered species are located in areas where APL proposes to construct new gathering or processing facilities, such work could be prohibited or delayed or expensive mitigation may be required. Existing laws, regulations, policies and guidance relating to protected species may also be revised or reinterpreted in a manner that further increases its construction and mitigation costs or restricts its construction activities. Additionally, construction and operational activities could result in inadvertent impact to habitats of listed species and could result in alleged takings under the ESA, exposing the Partnership to civil or criminal enforcement actions and fines or penalties. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where APL conducts operations or plans to construct pipelines or facilities could cause APL to incur increased costs arising from species protection measures or could result in delays in the construction of its facilities or limitations on its customer’s exploration and production activities, which could have an adverse impact on demand for its midstream operations.

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, 15 U.S.C. § 717(b), exempts natural gas gathering facilities from the jurisdiction of 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.

Transportation and 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.

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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.

Regarding market transparency and manipulation, the Energy Policy Act amended the Natural Gas Act 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. In this regard, 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.

The provisions of the Energy Policy Act have only limited applicability to APL, primarily in its capacity as a seller of natural gas, as the operator of interstate natural gas pipelines subject to limited jurisdiction certificates, and as operator of an intrastate natural gas pipeline offering interstate service under Section 311 of the NGPA. As such, APL is subject to the Energy Policy Act, as the owner of facilities and therefore is subject to FERC’s Natural Gas Act, imposing civil penalties for violations of the Natural Gas Act, the NGPA or FERC regulations or orders issued under those laws, and for conduct determined to constitute market manipulation. The penalties associated with any violations of the Energy Policy Act could be substantial.

Much of our and 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 submitted its draft guidance to the White House Office of Management and Budget in September 2013. The draft guidance submitted to the White House Office of Management and Budget was not published by the EPA, so it is not clear what changes may have been made to the guidance by the EPA as a result of the comments received during the 2012 public comment period. The EPA has not provided a specific timeframe for the release of the final guidance.

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 have repealed the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act” (“Frac Act”), the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. In 2013, the Frac Act was re-introduced in the 113^th Session of Congress. If enacted into law, the legislation as proposed could potentially result in significant regulatory oversight, which may include additional permitting, monitoring, recording, and recordkeeping requirements for us and ARP.

We and ARP believe our 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.

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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. On September 25, 2013, PHMSA issued a final rule implementing changes in its administrative procedures required by the Act, but the rulemaking process is continuing with respect to aspects of the Act related to pipeline safety regulations. 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.

The state of Texas adopted House Bill 2982, effective on September 1, 2013. This bill requires the Texas Railroad Commission to establish safety standards and practices for gathering facilities and transportation activities. Before September 1, 2015, the Texas Railroad Commission must implement rules for the commission to investigate an accident, an incident, threats to public safety, and complaints related to operational safety and to require an operator to submit a plan to remediate an accident, incident, threat, or complaint; to require filing of reports with respect to any accidents, incidents, threats to public safety, or complaints, or to require operators to provide information requested by the commission.

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. ARP conducts its natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. Both APL and ARP employ numerous safety precautions at their respective operations to ensure the safety of their employees. There are various federal and state environmental and safety requirements for handling sour gas, and APL and ARP are 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. 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 APL is currently in compliance with the Department’s requirements. None of APL’s affected facilities are considered high security risks by DHS at this time and no specific security plans for such per DHS regulations are required.

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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 we or ARP can produce from our or its wells or limit the number of wells or the locations at which we or ARP 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, 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 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well, while the impact fee for unconventional vertical wells was $10,000 per well. 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 an unconventional horizontal well and 10 years for an unconventional 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 our and 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 we and ARP 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 and $.00625 per barrel of crude. New Mexico imposes a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax equal to 0.19% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas. Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% of oil or gas. 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.

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 we and ARP believe we have 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. The Department of Interior’s Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands on May 24, 2013, and a final rule is expected to be issued in 2014.

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:

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

• 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;

• replacement/remediation of contaminated water assets; and

• minimum depth of hydraulic fracturing.

Local regulations, which may be preempted by state and federal regulations, have included, but have not been limited to, the following which may extend to all operations including those beyond hydraulic fracturing:

• noise control ordinances;

• traffic control ordinances;

• limitations on the hours of operations; and

• 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. Our, ARP and APL’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, 2013, we employed 1,074 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.

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ITEM 1A: RISK FACTORS

Partnership interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Relating to Our Business

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:

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

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

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

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

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

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

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

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

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

• our unitholders’ proportionate ownership interest in us will decrease;

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

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

• the ratio of taxable income to distributions may increase; and

• the market price of the common units may decline.

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

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

• an increase in our operating expenses;

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• an increase in general and administrative expenses;

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

• an increase in working capital requirements.

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

Our credit facilities contain various restrictive covenants that limit our ability to, among other things:

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

• pay distributions or redeem or repurchase our securities;

• prepay, redeem or repurchase debt;

• make loans, investments and acquisitions;

• enter into hedging arrangements;

• sell assets;

• enter into certain transactions with affiliates; and

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

In addition, our credit facilities require 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 facilities. Upon the occurrence of an event of default under one of our credit facilities, the lenders under either or both of our credit facilities 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 facilities. If the lenders under our credit facilities accelerate the repayment of borrowings, we may not have sufficient assets to repay our credit facilities and our other liabilities. Our borrowings under our credit facilities 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 facilities and make distributions to our unitholders.

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Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our 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.

A weakening of the current economic situation 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, NGLs and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we and our subsidiaries may use financial and physical hedges for 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. We and our subsidiaries generally limit these arrangements to smaller quantities than those projected to be available at any delivery point.

In addition, we and 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 in compliance with the Dodd-Frank Wall Street Reform and Consumer Protection Act. The futures contracts are commitments to purchase or sell hydrocarbons at future dates and generally cover one-month periods for up to six years in the future. The over-the-counter derivative contracts are typically cash settled by determining the difference in financial value between the contract price and settlement price and do not require physical delivery of hydrocarbons.

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

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Regulations adopted by the Commodity Futures Trading Commission could have an adverse effect on our and our subsidiaries’ ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our and 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 adopted by the Commodity 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 we, ARP and APL encounter; reduce our, ARP’s and APL’s ability to monetize or restructure our, ARP’s and APL’s derivative contracts in existence at that time; and increase our, ARP’s and APL’s exposure to less creditworthy counterparties. If we, ARP and APL reduce or change the way we use derivative instruments as a result of the legislation or regulations, our, ARP’s and APL’s results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our, 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. Our, 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 our, 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 or our subsidiaries making acquisitions may prove greater than estimated at the time of the acquisition.

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

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

• an inability to successfully integrate the businesses acquired;

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

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

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

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

• 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;

• unforeseen difficulties encountered in operating in new geographic areas;

• customer or key employee losses at the acquired businesses; and

• the failure to realize expected growth or profitability.

The scope and cost of these risks may be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely affect future growth and the ability to make or increase distributions.

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We and our subsidiaries may be unsuccessful in integrating the operations from prior and any future acquisitions with 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 we or our subsidiaries may acquire in the future, include, among other things:

• operating a significantly larger combined entity;

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

• integrating personnel with diverse business backgrounds and organizational cultures;

• consolidating operational and administrative functions;

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

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

• customer or key employee loss from the acquired businesses;

• a significant increase in indebtedness; and

• 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:

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

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

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

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

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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 per share 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.

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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 our, 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, our, ARP or APL’s operations could face additional costs for emissions control and higher costs of doing business.

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Risks Related to Our Exploration and Production Operations

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, natural gas liquids 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, natural gas liquids and oil prices will have a significant impact on the value of our and ARP’s reserves and on our cash flow. Prices for natural gas, natural gas liquids and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, natural gas liquids or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the level of domestic and foreign supply and demand;

• the price and level of foreign imports;

• the level of consumer product demand;

• weather conditions and fluctuating and seasonal demand;

• overall domestic and global economic conditions;

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

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

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

• technological advances affecting energy consumption;

• domestic and foreign governmental relations, regulations and taxation;

• the impact of energy conservation efforts;

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

• the price and availability of alternative fuels.

In the past, the prices of natural gas, natural gas liquids and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2013, the NYMEX Henry Hub natural gas index price ranged from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl. Between January 1, 2014 and February 25, 2014, the NYMEX Henry Hub natural gas index price ranged from a high of $6.15 per MMBtu to a low of $4.01 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $103.31 per Bbl to a low of $91.66 per Bbl.

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

We and ARP operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through Drilling Partnerships, contracting for drilling equipment and securing trained personnel. Our and ARP’s competitors may be able to pay more for natural gas, natural gas liquids and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our or ARP’s 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 we or ARP have. All of these challenges could make it more difficult for us and ARP to execute our and its growth strategy. We and ARP may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

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

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

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our and 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 our and ARP’s ability to drill the wells and conduct the operations that we or it currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our and ARP’s revenues.

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

Our and ARP’s key operated project areas are located in active drilling areas in the Arkoma Basin, Mississippi Lime, Marble Falls, Utica Shale and Marcellus Shale, and many of our and ARP’s leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our and ARP’s ability to find economically recoverable quantities of natural gas in these areas.

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

The natural gas and oil industry is capital intensive. If we or ARP are 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 Drilling Partnerships, we and ARP may be unable to increase or maintain our or its inventory of properties and reserve base, or be forced to curtail drilling or other activities. This could cause ARP’s and our revenues to decline and diminish its and our ability to service any debt that it or we may have at such time. If we or ARP do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we and ARP will be unable to expand our business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on its or our units.

We and ARP depend on certain key customers for sales of our and 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 or process from us or ARP, or cease to purchase or process natural gas, crude oil and natural gas liquids from us or ARP, our and ARP’s revenues and cash available for distribution could decline.

We and ARP market the majority of our and its natural gas production to gas marketers directly or to third party plant operators who process and market our and ARP’s gas. Crude oil produced from our and 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 to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. To the extent these and other key customers reduce the amount of natural gas, crude oil and natural gas liquids they purchase from us or ARP, our and ARP’s revenues and cash available for distributions to unitholders could temporarily decline in the event it is unable to sell to additional purchasers.

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

The prices that we or ARP receive for our or 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 we or it receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price that we or it receive could significantly reduce cash available for distribution to unitholders and adversely affect our or its financial condition. We and ARP use the relevant benchmark price to calculate hedge positions, and we and ARP do not have any commodity derivative contracts covering the amount of the basis differentials we or ARP experience in respect of production. As such, we and ARP will be exposed to any increase in such differentials, which could adversely affect results of operations.

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

As of December 31, 2013, leases covering approximately 22,558 of ARP’s 911,354 net undeveloped acres, or 2.5%, are scheduled to expire on or before December 31, 2014. An additional 4.0% and 0.5% are scheduled to expire in each of the years 2015 and 2016, respectively. Leases covering approximately 407 of our 29,012 net undeveloped acres, or 1.4%, are scheduled to expire on or before December 31, 2014. If we or ARP are unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, we or ARP will lose the right to develop the acreage that is covered by an expired lease, which would reduce our or ARP’s cash flows from operations.

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

Our and ARP’s drilling activities are subject to many risks, including the risk that we or 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, our and ARP’s drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

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

• unexpected operational events and drilling conditions;

• adverse weather conditions;

• facility or equipment malfunctions;

• title problems;

• pipeline ruptures or spills;

• compliance with environmental and other governmental requirements;

• unusual or unexpected geological formations;

• formations with abnormal pressures;

• injury or loss of life;

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

• fires, blowouts, craterings and explosions; and

• uncontrollable flows of natural gas or well fluids.

Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our or ARP’s earnings, and could reduce revenues in one or more of ARP’s Drilling Partnerships, which may make it more difficult to finance its 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.

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

The physical effects of climatic change have the potential to damage facilities, disrupt operations and production activities and cause us and 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, 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 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 financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we or ARP have a business relationship. We and 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 we and ARP replace our and its oil and natural gas reserves, the reserves and production will decline, which would reduce 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. Our and 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. Our and 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, for ARP, principally from the sponsorship of new Drilling Partnerships, all of which are subject to the risks discussed elsewhere in this section.

A decrease in natural gas prices could subject our and 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. We and ARP test our and 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 our and ARP’s economic interests and our 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. We and ARP estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published future prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, further declines in the price of natural gas may cause the carrying value of our and 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.

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

Both we and ARP may acquire properties with 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 we or ARP inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our or ARP’s financial condition and results of operations.

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

Our and ARP’s acquisitions may prove to be worth less than we or 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. Our and ARP’s estimates of future reserves and estimates of future production for its 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 our and ARP’s assessments, we and ARP perform a review of the acquired properties that we believe are generally consistent with industry practices. However, such a review may not permit us or ARP to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Neither we nor ARP inspect every well. Even when we or ARP inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we or ARP pay to acquire oil and natural gas properties may exceed the value we or ARP realize.

Also, reviews of the properties included in the 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.

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

We and ARP have acquired and 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 us or ARP to review in detail every individual property involved in a potential acquisition. In making acquisitions, we and ARP generally focus most of the title, environmental and valuation efforts on the properties that we or ARP believe 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 us or ARP to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. In addition, neither we nor ARP inspect in detail every well that we or ARP 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 it performs a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively impact our or ARP’s financial condition and results of operations.

Even if we or ARP are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable 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 our or ARP’s financial condition and results of operations.

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Ownership of our and ARP’s oil, gas and natural gas liquids production depends on good title to our property.

Good and clear title to our and ARP’s oil and gas properties is important. Although we and ARP will generally conduct title reviews before the purchase of most oil, gas, natural gas liquids 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 us or ARP from such properties.

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:

• New York has imposed a de facto moratorium on the issuance of permits for high volume, horizontal hydraulic fracturing until state administered environmental and public health studies are finalized. The Department of Environmental Conservation (the “NYDEC”), accepted comments on its revised proposal to amend state regulations to address high-volume hydraulic fracturing through January 11, 2013, and NYDEC has not issued final regulations. In October 2012, the NYDEC asked the New York Department of Health (the “NYDH”), to assess the health impacts of high volume hydraulic fracturing. The NYDH has not completed its assessment, nor has not set a deadline by which it will complete its review. New York is not expected to take any final action or make any decision regarding hydraulic fracturing until after the health review is completed by NYDH and the NYDEC, through the environmental impact statement, is satisfied that hydraulic fracturing can be done safely in New York State.

• Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. On February 14, 2012, legislation was passed in Pennsylvania (“2012 Oil and Gas Act”) requiring, among other things, disclosure of chemicals used in hydraulic fracturing. To implement the new legislative requirements, on December 14, 2013 the Pennsylvania Department of Environmental Protection (“PADEP”) proposed amendments to its environmental regulations at 25 PA. Code Chapter 78, Subchapter C, pertaining to environmental protection performance standards for surface activities at oil and gas well sites. According to PADEP, the conceptual changes would include updates existing requirements regarding containment of regulated substances, waste disposal, site restoration and reporting releases, and it would establish new planning, notice, construction, operation, reporting and monitoring standards for surface activities associated with the development of oil and gas wells. PADEP has also proposed to add new requirements for addressing impacts to public resources, identifying and monitoring orphaned and abandoned wells during hydraulic fracturing activities, and the submitting water withdrawal information necessary to secure a required Water Management Plan.

• 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.

• 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. In June 2013, the SEC adopted amendments to the Texas Administrative Code regarding casing, cementing, drilling, completion and well control.

• On April 12, 2013, the West Virginia Legislature passed a legislative rule titled “Rules Governing Horizontal Well Development,” which became effective on July 1, 2013. The rule imposes more stringent regulation of horizontal drilling and was promulgated to provide further direction in the implementation and administration of the Natural Gas Horizontal Well Control Act that became effective on December 14, 2011.

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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. A recent update regarding local land use restrictions in Pennsylvania occurred on December 19, 2013, when the Pennsylvania Supreme Court issued its Robinson Township v. Commonwealth of Pennsylvania ruling, which invalidated a key section of the 2012 Oil and Gas Act that placed limits on the regulatory authority of local governments. While the total impact of the Pennsylvania Supreme Court’s ruling is not clear and will occur over an extended period of time, an immediate impact of the ruling may be increased regulatory impediments and disputes at the local government level. 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, which were due by August 23, 2012, the EPA submitted its draft guidance to the White House Office of Management and Budget in September 2013. EPA’s draft guidance submitted to the White House Office of Management and Budget was not published, so it is not clear what changes may have been made to the guidance by EPA as a result of the comments received during the 2012 public comment period. At present, we are not aware of EPA’s timeframe to release the final guidance. 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. On December 9, 2013, EPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. 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 summer 2014, 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. On May 24, 2013, the Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A final rule is expected to be issued in 2014.

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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. On December 16, 2013, the U.S. Energy Information Administration published an abridged version of its Annual Energy Outlook 2014 with projections to 2040 report, with the full report to be released in Spring 2014. 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 we or ARP rely 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 we or ARP rely 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 we or ARP pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we or ARP rely could have a material adverse effect on our or ARP’s business, financial condition, results of operations and ability to make distributions to unitholders.

Our and ARP’s drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of flowback and produced water. If we or ARP are unable to dispose of the flowback and produced water from the strata at a reasonable cost and within applicable environmental rules, our and ARP’s ability to produce gas economically and in commercial quantities could be impaired.

A significant portion of our and 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 our or ARP’s operations and financial performance. For example, Pennsylvania requires the development, submission and approval of a Water Management Plan before hydraulically fracturing an unconventional well. The requirements of these plans continue to be modified by proposed amendments to state regulations and PADEP’s policies and guidance. For Pennsylvania operations located in the Susquehanna River Basin, the Susquehanna River Basin Commission (“SRBC”) regulates consumptive water uses, water withdrawals, and the diversions of water into and out of the Susquehanna River Basin, and specific SRBC approvals are required prior to initiating drilling activities. 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.

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Our and ARP’s ability to collect and dispose of water will affect production, and potential increases in the cost of water treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could include restrictions on our or 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, the Ohio Department of Natural Resources promulgated amendments to the regulations governing disposal wells in Ohio. The 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 us and 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 our and 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 our and ARP’s businesses.

States are also proposing more stringent requirements in air permits for well sites and compressor stations. For example, Pennsylvania recently revised its list of sources exempt from air permitting requirements such that previously exempted types of sources associated with oil and gas exploration and production now are 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 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well and the impact fee for unconventional vertical wells was $10,000 per well. 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 $1.7 million for the year ended December 31, 2013.

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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. The Governor’s proposal was rejected by the General Assembly, and not included in the State’s biennial budget bill (H.B. 59) adopted on June 30, 2013. The General Assembly is considering an alternative bill, H.B.375, introduced on December 4, 2013, that would significantly change Ohio’s severance tax on the production of oil and gas. The tax on the production of oil and gas from conventional wells would be lowered to $0.10/Bbl oil and $0.015/Mcf natural gas. The tax on the production of oil and gas from unconventional wells would become 1% of net proceeds at the wellhead for both oil and gas for the first five years of production, increasing to 2% thereafter, but dropping again to 1% when production falls below 17 barrels of oil per day per quarter or 100 Mcf gas per day per quarter.

President Obama’s budget proposals for 2014 included proposed provisions with significant tax consequences. If enacted, U.S. tax laws could be amended to eliminate certain deductions for drilling, exploration and development and the mandatory funding of certain public lands and research and development of transportation alternatives.

Because we and ARP handle natural gas, natural gas liquids and oil, we and ARP 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.

How we and ARP plan, design, drill, install, operate and abandon 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:

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

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

• The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our and ARP’s facilities;

• The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us, ARP and AEI or at locations to which we, ARP and AEI have sent waste for disposal; and

• 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 we or 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 us or 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. The EPA, the United States Army Corps of Engineers’ and the United States Department of Justice have been actively pursuing instances of unpermitted stream and wetland impacts. 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.

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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 our or 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 we or ARP may incur environmental costs and liabilities due to the nature of the businesses and the substances handled. For example, an accidental release from one of our or 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 our or ARP’s compliance costs and the cost of any remediation that may become necessary. Neither we nor ARP may be able to recover remediation costs under our insurance policies.

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

Our and ARP’s operations are regulated extensively at the federal, state and local levels. The regulatory environment in which we and ARP operate include, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our and ARP’s activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our and ARP’s operations and limit the quantity of natural gas we 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, known as the 2012 Oil and Gas Act, 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. Proposed regulations associated with this legislation have been released for public comment by the PADEP and, if finalized, will impact how natural gas operations are conducted in Pennsylvania. Similarly, West Virginia promulgated regulations associated with its existing Horizontal Well Control Act and is signaling that additional regulations are on the horizon. We and 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.

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 our and 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. Our and ARP’s engineers prepare estimates of our proved reserves. Over time, our and ARP’s internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our and 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, we and 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. Our and 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 our and ARP’s reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we and ARP ultimately recover being different from the reserve estimates.

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The present value of future net cash flows from our and ARP’s proved reserves is not necessarily the same as the current market value of the estimated natural gas reserves. We and ARP base the estimated discounted future net cash flows from 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:

• actual prices received for natural gas;

• the amount and timing of actual production;

• the amount and timing of capital expenditures;

• supply of and demand for natural gas; and

• 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 that we and ARP use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the company or the natural gas and oil industry in general.

Any significant variance in our or ARP’s assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and standardized measure, and the financial condition and results of operations. In addition, our and 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 our or ARP’s production can reduce the estimated volumes of reserves because the economic life of the wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our or ARP’s PV-10 and standardized measure.

Risks Related to ARP’s Drilling Partnerships

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

ARP or ones of its subsidiaries serves as the managing general partner of the Drilling Partnerships and will be the managing general partner of new Drilling 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 Drilling Partnerships from any liability that exceeds such partner’s share of the Drilling Partnership’s assets.

ARP may not be able to continue to raise funds through its Drilling 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 $150.0 million, $127.1 million and $141.9 million in calendar years 2013, 2012 and 2011, respectively. In the future, ARP may not be successful in raising funds through these Drilling 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 Drilling 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 Drilling Partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, ARP may have difficulty in maintaining or increasing the level of Drilling 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 Drilling Partnerships, or it may determine to reduce drilling activity.

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

Under current federal tax laws, there are tax benefits to investing in Drilling Partnerships, including deductions for intangible drilling costs and depletion deductions. However, both the Obama Administration’s budget proposal for fiscal year 2014 and other recently introduced legislation include proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and certain environmental clean-up costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. 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 Drilling Partnerships. These or other changes to federal tax law may make investment in the Drilling 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 Drilling Partnerships.

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

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

ARP has agreed to subordinate a portion of its share of production revenues, net of corresponding production costs, to specified returns to the investor partners in the Drilling Partnerships, typically 10% to 12% per year for the first five to eight years of distributions. Thus, ARP’s revenues from a particular Drilling Partnership will decrease if the Drilling Partnership does not achieve the specified minimum return. For the years ended December 31, 2013, 2012 and 2011, $9.6 million, $6.3 million and $4.0 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced ARP’s cash distributions received from the Drilling Partnerships.

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:

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

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

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

• the volume of natural gas APL gathers;

• efficiency of APL’s gathering systems and processing plants;

• expiration of significant contracts;

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

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

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

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• the availability of local, intrastate and interstate transportation systems;

• the availability of fractionation capacity;

• the expenses incurred in providing its gathering services;

• the cost of acquisitions and capital improvements;

• required principal and interest payments on APL’s debt;

• fluctuations in working capital;

• prevailing economic conditions;

• fuel conservation measures;

• alternate fuel requirements;

• the strength and financial resources of APL’s competitors;

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

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

• technical advances in fuel economy and energy generation devices.

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

• the level of capital expenditures APL makes;

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

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

• APL’s debt service requirements; and

• 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.

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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. Furthermore, although APL evaluates the creditworthiness of its counterparties, it may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose APL to an increased risk of nonpayment or other default under its contracts and other arrangements with them. 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.

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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 2013, Atoka Midstream, LLC; Chesapeake Energy Corporation; COG Operating LLC; Endeavor Energy Resources LP; Energen Resources Corporation; Laredo Petroleum Inc.; Parsley Energy, LP; Pioneer; SandRidge Exploration and Production, LLC; Vanguard Permian, 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.

• Carrera Gas Company; DCP Midstream, LLC; Devon Energy Corporation; Enable Midstream Partners, L.P.; Energy Transfer Partners, L.P.; Kinder Morgan Energy Partners, L.P.; and ONEOK Field Services Company, operate competing gathering systems and processing plants in APL’s SouthOK service areas.

• DCP Midstream Partners, LLC; Energy Transfer Partners, L.P.; Enterprise Products Partners, L.P.; Howard Energy Partners, LLC; Kinder Morgan Energy Partners, L.P.; Regency Energy Partners, L.P.; Southcross Energy Partners, L.P.; and TexStar Midstream Services, L.P. operate competing gathering systems and processing plants in APL’s SouthTX service area.

• Access Midstream Partners, L.P.; Caballo Energy, LLC.; Duke Energy Corporation; 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.

• Crosstex Energy Services; DCP Midstream, LLC; Energy Transfer Partners, L.P; Regency Energy Partners, L.P.; Targa Resources Partners; and West Texas Gas, Inc. operate competing gathering systems and processing plants in APL’s WestTX 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. In addition, customers who are significant producers of natural gas may develop their own gathering and processing systems in lieu of using those operated by APL. 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 and the APL SouthTex Ttransmission Section 311 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.

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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 Natural Resources Company 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.

A change in the regulations related to a state’s use of eminent domain could inhibit APL’s ability to secure rights-of way for future pipeline construction projects.

Certain states where APL operates are considering the adoption of laws and regulations that would limit or eliminate a state’s ability to exercise eminent domain over private property. This, in turn, could make it more difficult or costly for APL to secure rights-of-way for future pipeline construction and other projects. Further, states may amend their procedures for certain entities within the state to use eminent domain.

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. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. If endangered species are located in areas where APL proposes to construct new gathering or processing facilities, such work could be prohibited or delayed or expensive mitigation may be required. 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.

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

• difficulties in obtaining capital for additional construction and operating costs;

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

• additional construction and operating costs exceeding budget estimates;

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

• difficulties in obtaining consistent supplies of natural gas; and

• terms in operating agreements that are not favorable to APL.

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

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

• inability to identify suitable acquisition candidates;

• 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;

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

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

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

• difficulties in integrating operations and systems; and

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

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.

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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 and may limit APL’s ability to capitalize on acquisitions and other business opportunities.

An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce APL’s earnings.

In connection with APL’s acquisitions in fiscal years 2007, 2012 and 2013, APL has recorded goodwill and identifiable intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires APL to test goodwill and intangible assets with indefinite useful lives for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments APL accounts for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. If APL determines that an impairment is indicated, APL would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. APL recorded an impairment charge of $43.9 million with respect to the Cardinal Acquisition during the year ended December 31, 2013. Although APL has not experienced any other events or circumstances that indicate that the carrying amounts of its other intangible assets and goodwill were impaired, APL could experience future events that result in impairments. An impairment of the value of its existing goodwill and intangible assets could have a significant negative impact on APL’s future operating results and could have an adverse impact on its ability to satisfy the financial ratios or other covenants under its existing or future debt agreements.

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 and the SouthTX 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.

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

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

• perform ongoing assessments of pipeline integrity;

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

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventative and mitigating actions.

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.

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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, as well as certain operations and maintenance practices. 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 gas industry. The outcomes of such activities can impact operations.

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:

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

• inadvertent damage from construction and farm equipment;

• leakage of natural gas, NGLs and other hydrocarbons;

• fires and explosions;

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

• nuisance and other landowner claims arising from APL’s operations; and

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

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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 in recent years, and could escalate further. APL’s existing insurance coverage does not cover all potential losses, costs, or liabilities and APL could suffer losses in amounts in excess of its existing insurance coverage. Moreover, in some instances, its insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers require 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.

Disruption due to political uncertainties, civil unrest or 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.

Political uncertainties, civil unrest and terrorist attacks or the threat of terrorist attacks cause instability in the global financial markets and other industries, including the energy industry. Such disruptions could adversely affect APL’s operations and the markets for its products and services, including through increased volatility in crude oil and natural gas prices, or the possibility that its infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. In addition, instabilities in the financial and insurance markets caused by such disruptions may make it more difficult for APL to access capital and may increase insurance premiums or make it difficult to obtain the insurance coverage that APL considers adequate.

APL owns and operates certain of its systems through joint ventures, and its control of such systems is limited by provisions of the agreements it has entered into with its joint venture partners and by its percentage ownership in such joint venture entities.

Certain of APL’s joint ventures are structured so that a subsidiary of APL is the managing member of the limited liability company that owns the system being operated. However, the operational agreements applicable to such joint venture entities generally require consent of APL’s joint venture partner for specified extraordinary transactions, such as admission of new members, engaging in transactions with our affiliates not approved by the company conflicts committee, incurring debt outside the ordinary course of business and disposing of company assets above specified thresholds. In addition, certain of APL’s systems are operated by joint venture entities that it does not operate, or in which APL does not have an ownership stake that permits it to control the business activities of the entity. APL has limited ability to influence the business decisions of such joint venture entities, and it may be unable to control the amount of cash it will receive from the operation and could be required to contribute significant cash to fund its share of their operations, which could adversely affect APL’s ability to distribute cash to its unitholders.

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:

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

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

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

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• changes in market valuations of similar companies;

• departures of key personnel;

• commencement of or involvement in litigation;

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

• variations in the amount of our cash distributions;

• future issuances and sales of our units; and

• 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 are continuing to experience low 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 distributions from us.

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

• We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our current and future outstanding debt, elimination of future distributions from 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;

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

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

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

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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

• Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (“Delaware 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 cash distribution policy limits our ability to grow.

Because we distribute our available cash rather than reinvesting it in our business, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. If we issue additional common units or incur debt to fund acquisitions and expansion and investment capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units.

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:

• 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

• 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 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.

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Risks Related to Our Conflicts of Interest

Although we control ARP, APL and our new Development Subsidiary through our ownership of their general partners, each entity’s general partner owes fiduciary duties to them 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, APL and our new Development Subsidiary, on the one hand, and ARP, APL and our Development Subsidiary and their respective limited partners, on the other hand. The directors and officers of the general partners have fiduciary duties to manage these Partnerships in a manner beneficial to us, its owner. At the same time, these directors and officers have a fiduciary duty to manage these Partnerships in a manner beneficial to it and its limited partners. The boards of directors of ARP, APL and our Development subsidiary 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:

• the allocation of shared overhead expenses;

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

• the determination and timing of the amount of cash to be distributed to our subsidiaries’ partners and the amount of cash reserved for the future conduct of their businesses;

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

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

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, APL and our new Development Subsidiary’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, APL and our new Development Subsidiary’s general partner, and, as a result, have fiduciary duties to manage these businesses in a manner beneficial to them and their partners. For example, our Executive Chairman, Chief Executive Officer, President, Chief Financial Officer, Chief Accounting Officer and Chief Legal Officer, among others, have positions with ARP. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to one or more of our subsidiaries, 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 units, options to purchase units or other equity awards which may be significant or some of these persons. Their positions, 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 such subsidiaries 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 facilities or making distributions.

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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.

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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.

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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 Alabama, New Mexico, 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 allocate 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.

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ITEM 2: PROPERTIES

Natural Gas, Oil and NGL Reserves

The following tables summarize information regarding our and ARP’s estimated proved natural gas and oil reserves as of December 31, 2013. 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 our and ARP’s direct ownership interests in oil and gas properties as well as the reserves attributable to ARP’s percentage interests in the oil and gas properties owned by Drilling Partnerships in which ARP owns partnership interests. All of the reserves are located in the United States. We and ARP base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared by Wright & Company, Inc., an independent third-party engineer. We and ARP have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our and ARP’s estimated proved reserves at December 31, 2013 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we and ARP make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our and 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 during the years ended December 31, 2013 and 2012, and are listed below as of the dates indicated:

	December 31,
Unadjusted Prices(1)	2013		2012
Natural gas (per Mcf)	$	3.67	$	2.76
Oil (per Bbl)	$	96.78	$	94.71
Natural gas liquids (per Bbl)	$	30.10	$	33.91
Average Realized Prices, Before Hedge(1) (2)
Natural gas (per Mcf)	$	3.25	$	2.53
Oil (per Bbl)	$	95.86	$	92.26
Natural gas liquids (per Bbl)	$	29.43	$	31.97

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

(2) Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for years ended December 31, 2013 and 2012. Including the effect of this subordination, the average realized gas sales price was $3.00 per Mcf before the effects of financial hedging and $2.08 per Mcf before the effects of financial hedging for years ended December 31, 2013 and 2012, respectively.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas, oil and NGL 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, oil and NGLs 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 our and ARP’s natural gas, oil and NGL reserve estimates were completed in accordance with prescribed internal control procedures by 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. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our and 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 our and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our and ARP’s senior engineering staff and management, with final approval by the Chief Operating Officer and President.

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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, oil and NGLs 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. Our and ARP’s estimated standardized measure values may not be representative of the current or future fair market value of proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas, oil and NGL 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 Our Exploration and Production Operations”).

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

	Proved Reserves at December 31,
Atlas Energy:	2013		2012
Proved reserves:
Natural gas proved developed reserves (MMcf) (1):		38,941		—
Oil proved developed reserves (MBbl)(1):		—		—
NGL proved developed reserves (MBbl):		—		—
Total developed proved reserves (MMcfe)(1) (2)		38,941		—
Standardized measure of discounted future cash flows (in thousands)(4)	$	40,099	$	—
	Proved Reserves at December 31,
Atlas Resource:	2013		2012
Proved reserves:
Natural gas reserves (MMcf)(1):
Proved developed reserves		727,927		338,655
Proved undeveloped reserves(3)		236,907		235,119
Total proved reserves of natural gas		964,834		573,774
Oil reserves (MBbl)(1):
Proved developed reserves		3,458		3,400
Proved undeveloped reserves(3)		11,530		5,469
Total proved reserves of oil		14,988		8,869
NGL reserves (MBbl):
Proved developed reserves		7,676		7,885
Proved undeveloped reserves(3)		11,281		8,177
Total proved reserves of NGL		18,957		16,062
Total proved reserves (MMcfe)(1)		1,168,507		723,359
Standardized measure of discounted future cash flows (in thousands)(4)	$	1,039,192	$	623,676

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(1) “MMcf” represents million cubic feet; “MMcfe” represents million cubic feet equivalents; and “MBbl” represents thousand barrels. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.

(2) At December 31, 2013, there were no proved undeveloped reserves related to our oil and gas properties.

(3) 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 Drilling Partnerships in exchange for an equity interest in these partnerships, which is approximately 30%, which effectively will reduce ARP’s ownership interest in these reserves from 100% to its respective ownership interest as ARP makes these contributions.

(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 we and ARP are limited partnerships, no provision for federal or state income taxes has been included in the December 31, 2013 and 2012 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

Proved developed reserves are those reserves of any category 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 th time of the reserve estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells on which a relatively major expenditure is required for recompletion.

Proved Undeveloped Reserves (“PUDS”)

PUD Locations. As of December 31, 2013, there were no PUD locations related to our natural gas and oil reserves and ARP had 598 PUD locations totaling approximately 373,773 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 our acquisition in the Arkoma Basin and ARP’s acquisitions in the Barnett Shale and Marble Falls play, the Mississippi Lime play, and the Raton Basin, the Black Warrior Basin and the County Line area of Wyoming during the years ended December 31, 2013 and 2012, we and ARP will continue to integrate those areas and increase our and ARP’s proved reserves through organic leasing as well as drilling on our and ARP’s existing undeveloped acreage.

Our and ARP’s organic growth will focus on expanding acreage positions in our and ARP’s target areas, including our operations in the Arkoma Basin and ARP’s operations in the Marcellus Shale, Utica Shale, Barnett Shale and Marble Falls play, the Mississippi Lime play and the Raton Basin, the Black Warrior Basin and the County Line area of Wyoming. Through our and ARP’s previous drilling in these regions, as well as geologic analyses of these areas, we and ARP are expecting these expansion locations to have a significant impact on our and ARP’s proved reserves.

Changes in PUDs. Changes in PUDS that occurred during the year ended December 31, 2013 were due to the following:

Atlas Resource

• addition of approximately 158.6 Bcfe due to ARP’s drilling activity in the Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls play;

• addition of approximately 34.6 Bcfe due to ARP’s acquisition of acreage in the Raton and Black Warrior Basins; partially offset by

• negative revisions of approximately 77.5 Bcfe in PUDs primarily due to the reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions.

Development Costs. We did not incur any costs related to the development of PUDs and no reserves were converted from PUDs to proved developed reserves during the year ended December 31, 2013. ARP’s costs incurred related to the development of PUDs were approximately $103.3 million, $83.5 million, and $40.5 million for the years ended December 31, 2013, 2012 and 2011, respectively. During the years ended December 31, 2013, 2012 and 2011, approximately 117.2 Bcfe, 71.5 Bcfe and 8.1 Bcfe of ARP’s reserves, respectively, were converted from PUDs to proved developed reserves. As of December 31, 2013, there were no PUDs that had remained undeveloped for five years or more for us or ARP.

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Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which we and ARP have a working interest as of December 31, 2013. 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 we and ARP have an interest, directly or through ARP’s ownership interests in Drilling Partnerships, and net wells are the sum of our and ARP’s fractional working interests in gross wells, based on the percentage interest ARP owns in the Drilling Partnership that owns the well:

	Number of productive wells(1)(2)
Atlas Energy:	Gross		Net
Barnett/Marble Falls:
Gas wells		2		1
Oil wells		—		—
Total		2		1
Coal-bed Methane(3):
Gas wells		584		451
Oil wells		—		—
Total		584		451
Total:
Gas wells		586		452
Oil wells		—		—
Total		586		452
	Number of productive wells(1)(2)
Atlas Resource:	Gross		Net
Appalachia:
Gas wells		7,681		3,767
Oil wells		495		355
Total		8,176		4,122
Coal-bed Methane(3):
Gas wells		2,955		2,172
Oil wells		—		—
Total		2,955		2,172
Barnett/Marble Falls:
Gas wells		569		470
Oil wells		52		35
Total		621		505
Mississippi Lime/Hunton:
Gas wells		66		47
Oil wells		—		—
Total		66		47
Other operating areas(4):
Gas wells		782		240
Oil wells		2		1
Total		784		241
Total:
Gas wells		12,053		6,696
Oil wells		549		391
Total		12,602		7,087

(1) There were no exploratory or dry wells drilled by us during the years ended December 31, 2013, 2012 and 2011. There were no exploratory wells drilled by ARP during the years ended December 31, 2013, 2012 and 2011; there were no gross or net dry wells within ARP’s operating areas during the year ended December 31, 2013. During the year ended December 31, 2012, there were 8 gross (3 net) ARP dry wells drilled in the Niobrara shale. During the year ended December 31, 2011, there were 14 gross (5 net) ARP dry wells drilled in the Niobrara shale.

(2) Includes ARP’s proportionate interest in wells owned by 86 Drilling Partnerships for which it serves as managing general partner and various joint ventures. This does not include royalty or overriding interests in 610 ARP wells and 14 of our wells.

(3) Our coal-bed methane includes our production in the Arkoma Basin in eastern Oklahoma. Coal-bed methane for ARP includes its production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming.

(4) Other operating areas include ARP’s production located in the Chattanooga, New Albany and Niobrara shales.

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Developed and Undeveloped Acreage

The following tables set forth information about our and ARP’s developed and undeveloped natural gas and oil acreage as of December 31, 2013. The information in ARP’s table includes ARP’s proportionate interest in acreage owned by Drilling Partnerships.

	Developed acreage (1)				Undeveloped acreage(2)
Atlas Energy:	Gross (3)		Net (4)		Gross (3)		Net (4)
Oklahoma		143,195		97,194		67,640		28,481
Arkansas		1,016		439		368		334
Texas		320		63		1,005		197
Total		144,531		97,696		69,013		29,012
	Developed acreage (1)				Undeveloped acreage(2)
Atlas Resource:	Gross (3)		Net (4)		Gross (3)		Net (4)
Pennsylvania		152,297		75,439		2,918		2,918
New Mexico		124,862		124,862		447,713		447,713
Ohio(5)		110,297		100,044		103,313		100,870
Texas		86,097		59,489		69,259		57,532
Alabama		57,097		51,897		39,994		37,173
Indiana		32,969		24,533		134,084		73,086
Wyoming		29,737		5,677		830		156
Colorado		24,851		18,242		20,278		20,278
Tennessee		20,463		8,471		148,103		145,923
Oklahoma		19,366		15,737		3,325		2,012
New York		13,254		11,965		22,278		20,256
Other		3,291		675		3,625		3,437
Total		674,581		497,031		995,720		911,354

(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 we or ARP own a working interest. The number of gross acres is the total number of acres in which we or ARP own 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 ARP’s Utica Shale natural gas and oil rights on approximately 2,735 acres under new leases taken in Ohio that remain undeveloped.

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The leases for our and ARP’s developed acreage generally have terms that extend for the life of the wells, while the leases on our and ARP’s 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, 2013. As of December 31, 2013, leases covering approximately 407 of our 29,012 net undeveloped acres, or 1.4%, are scheduled to expire on or before December 31, 2014 while leases covering approximately 22,558 of ARP’s 911,354 net undeveloped acres, or 2.5%, are scheduled to expire on or before December 31, 2014. An additional 4.0% and 0.5% of ARP’s net undeveloped acres are scheduled to expire in each of the years 2015 and 2016, respectively.

We believe that we and ARP hold good and indefeasible title related to producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us and ARP in the various areas in which we and ARP conduct activities. We do not believe that these exceptions detract substantially from our and ARP’s use of any property. As is customary in the natural gas industry, we and ARP conduct only a perfunctory title examination at the time we or it acquire a property. Before commencing drilling operations, we and ARP conduct an extensive title examination and perform curative work on defects that we and ARP deem significant. We and ARP have obtained title examinations for substantially all of our and ARP’s managed producing properties. No single property represents a material portion of our or ARP’s holdings.

Our and ARP’s properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our and 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. We do not believe that any of these burdens will materially interfere with the use of our and ARP’s properties.

Atlas Pipeline Partners

APL’s principal facilities consist of 14 natural gas processing plants; 18 gas treating facilities; approximately 11,200 miles of active 2 inch 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 and natural gas gathering systems:

Gas Processing Facilities

Facility	Location	Year Constructed	Design Throughput Capacity (MMcfd)		2013 Average Utilization Rate
Atoka plant	Atoka County, OK	2006		20
Coalgate plant	Coal County, OK	2007		80
Tupelo plant	Coal County, OK	2011		120
Velma plant	Stephens County, OK	Updated 2003		100
Velma V-60 plant	Stephens County, OK	2012		60
Total SouthOK				380		100	%(1)
Silver Oak I	Bee County, TX	2012		200
Total SouthTX				200		66	%
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

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Facility	Location	Year Constructed		Design Throughput Capacity (MMcfd)		2013 Average Utilization Rate
Total WestOK					458		100	%(1)
Consolidator plant	Reagan County, TX		2009		150
Driver plant	Midland County, TX		2013		200
Midkiff plant	Reagan County, TX		1990		60
Benedum plant	Upton County, TX		Updated 1981		45
Total WestTX					455		72	%
Total					1,493		88	%(1)

(1) Certain processing facilities in these business units are capable of processing more than their name-plate capacity and when capacity is exceeded, APL will off-load volumes to other processors, as needed. The calculation of the total average utilization rate for the year includes these off-loaded volumes.

Of the 18 gas treating facilities APL owns, 17 are used to provide contract treating services to natural gas producers located in Arkansas, Louisiana, Oklahoma and Texas. Two of APL’s contract gas treating facilities are refrigeration facilities and the other 15 are amine facilities. The remaining treating facility is a 250 GPM amine treating plant which is used in APL’s processing operations in the Arkoma system and is included in APL’s gathering and processing segment. APL’s 17 contract gas treating facilities are included in its transportation and treating segment.

Natural Gas Gathering Systems

System	Location	Approximate Active Miles of Pipe
SouthOK	Southern Oklahoma and Northern Texas		1,300
SouthTX	Southern Central Texas		500
WestOK	North Central Oklahoma and Southern Kansas		5,700
WestTX	West Texas		3,600
Tennessee	Tennessee		70
Barnett Shale	Central Texas		20
Total			11,190

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.

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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

We and our subsidiaries are 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 14”.

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, 2014, the closing price of our common limited partner units was $40.64, and there were 189 holders of record of our common limited partner 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, 2013 and 2012:

	High		Low		Cash Distribution per Common Limited Partner Declared(1)
Year ended December 31, 2013:
Fourth quarter	$	55.89	$	41.79	$	0.46
Third quarter	$	55.70	$	44.80	$	0.46
Second quarter	$	53.60	$	43.13	$	0.44
First quarter	$	44.56	$	34.74	$	0.31
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

(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 and Related Unitholder Matters – Equity Compensation Plan Information”.

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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, 2013, 2012 and 2011, with the exception of consolidated balance sheet data for the year ended December 31, 2011, from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the years ended December 31, 2010 and 2009, as well as consolidated balance sheet data for the year ended December 31, 2011, from our consolidated financial statements, which are not included in this report.

The consolidated financial statements include our accounts and that of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2013, except for ARP, APL and our Development Subsidiary, which we control (see “Item 8: Financial Statements and Supplementary Data – Note 2”). Due to the structure of our ownership interests in ARP, APL and our Development Subsidiary, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP, APL and our Development Subsidiary into our consolidated financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP, APL and our Development Subsidiary are reflected as income (loss) attributable to non-controlling interests in our consolidated statements of operations and as a component of partners’ capital on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of ARP, APL and our Development Subsidiary, adjusted for non-controlling interests.

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 acquisition method of accounting, whereby the results of operations and the financial position of the Transferred Business would have been included in our consolidated 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 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 balance sheets, our consolidated statements of operations, our consolidated statements of partners’ capital, our consolidated statements of comprehensive income (loss) and our consolidated statements of cash flows to reflect our results consolidated with the results of the Transferred Business as of or at the beginning of the respective period;

• Adjusted the presentation of our consolidated 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.

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.

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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,
	2013			2012			2011			2010			2009
Statement of operations data:	(in thousands, except per unit data)
Revenues:
Gas and oil production	$	273,906		$	92,901		$	66,979		$	93,050		$	112,979
Well construction and completion		167,883			131,496			135,283			206,802			372,045
Gathering and processing		2,139,694			1,219,815			1,329,418			944,609			714,145
Administration and oversight		12,277			11,810			7,741			9,716			15,554
Well services		19,492			20,041			19,803			20,994			17,859
Gain (loss) on mark-to-market derivatives		(28,764	)		31,940			(20,453	)		(5,944	)		(35,815	)
Other, net		(6,973	)		13,440			31,803			17,437			15,295
Total revenues		2,577,515			1,521,443			1,570,574			1,286,664			1,212,062
Costs and expenses:
Gas and oil production		100,178			26,624			17,100			23,323			25,557
Well construction and completion		145,985			114,079			115,630			175,247			315,546
Gathering and processing		1,802,618			1,009,100			1,123,051			789,548			605,222
Well services		9,515			9,280			8,738			10,822			9,330
General and administrative		197,976			165,777			80,584			37,561			38,932
Chevron transaction expense		—			7,670			—			—			—
Depreciation, depletion and amortization		308,533			142,611			109,373			115,655			119,396
Asset impairment		81,880			9,507			6,995			50,669			166,684
Total costs and expenses		2,646,685			1,484,648			1,461,471			1,202,825			1,280,667
Operating income (loss)		(69,170	)		36,795			109,103			83,839			(68,605	)
Gain (loss) on asset sales and disposal		(2,506	)		(6,980	)		256,292			(13,676	)		108,947
Interest expense		(132,581	)		(46,520	)		(38,394	)		(90,448	)		(104,053	)
Loss on early extinguishment of debt		(26,601	)		—			(19,574	)		(4,359	)		(2,478	)
Income (loss) from continuing operations before tax		(230,858	)		(16,705	)		307,427			(24,644	)		(66,189	)
Income tax (benefit) expense		(2,260	)		176			—			—			—
Income (loss) from continuing operations		(228,598	)		(16,881	)		307,427			(24,644	)		(66,189	)
Income (loss) from discontinued operations		—			—			(81	)		321,155			84,148
Net income (loss)		(228,598	)		(16,881	)		307,346			296,511			17,959

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	Years Ended December 31,
	2013			2012			2011			2010			2009
Statement of operations data:	(in thousands, except per unit data)
(Income) loss attributable to non-controlling interests		153,231			(35,532	)		(257,643	)		(245,764	)		(53,924	)
Net income (loss) after non-controlling interests		(75,367	)		(52,413	)		49,703			50,747			(35,965	)
(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
Net income (loss) attributable to common limited partners.	$	(75,367	)	$	(52,413	)	$	44,992		$	27,934		$	4,035
Allocation of net income (loss) attributable to common limited partners:
Continuing operations	$	(75,367	)	$	(52,413	)	$	45,002		$	(11,994	)	$	(7,287	)
Discontinued operations		—			—			(10	)		39,928			11,322
	$	(75,367	)	$	(52,413	)	$	44,992		$	27,934		$	4,035
Net income (loss) attributable to common limited partners per unit:
Basic:
Income (loss) from continuing operations attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.91		$	(0.43	)	$	(0.26	)
Income (loss) from discontinued operations attributable to common limited partners		—			—			—			1.44			0.41
Net income (loss) attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.91		$	1.01		$	0.15
Diluted(1):
Income (loss) from continuing operations attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.88		$	(0.43	)	$	(0.26	)
Income (loss) from discontinued operations attributable to common limited partners		—			—			—			1.44			0.41
Net income (loss) attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.88		$	1.01		$	0.15
Balance sheet data (at period end):
Property, plant and equipment, net	$	4,910.875		$	3,502,609		$	2,093,283		$	1,849,486		$	1,831,090
Total assets		6,792,641			4,597,194			2,684,771			2,435,262			2,838,007
Total debt, including current portion		2,889,044			1,540,343			524,140			601,389			1,262,183
Total partners’ capital		3,222,876			2,479,848			1,744,081			1,406,123			1,053,855
Cash flow data:
Net cash provided by operating activities	$	37,608		$	70,276		$	88,195		$	157,253		$	236,664
Net cash provided by (used in) investing activities		(2,496,607	)		(1,650,505	)		14,159			502,330			142,637
Net cash provided by (used in) financing activities		2,445,720			1,539,633			(25,225	)		(660,439	)		(385,483	)
Capital expenditures		(718,040	)		(500,759	)		(292,750	)		(139,360	)		(209,576	)

(1) For the year ended December 31, 2013, approximately 3,995,000 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, 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 units 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 units 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.

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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 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 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 (“NYSE”) under the symbol “ATLS”.

At December 31, 2013, our operations primarily consisted of our ownership interests in the following:

• Atlas Resource Partners, L.P. (“Atlas Resources” or “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 (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities. At December 31, 2013, we owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 36.9% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) 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 primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services in the southwestern region of the United States. At December 31, 2013, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 6.1% limited partner interest in APL;

• Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) 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, 2013, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot; and

• Certain natural gas and oil producing assets.

In February 2012, the board of directors (the “Board”) of our General Partner (the “General Partner”) approved the formation of ARP as a newly created exploration and production MLP 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.

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; and

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

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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 financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2013, except for ARP, APL and our newly formed subsidiary partnership (our “Development Subsidiary”), which we control (see “Recent Developments”). Due to the structure of our ownership interests in ARP, APL and our Development Subsidiary, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP, APL and our Development Subsidiary into our consolidated financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP, APL and our Development Subsidiary are reflected as income attributable to non-controlling interests in our consolidated statements of operations and as a component of partners’ capital on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP, APL and our Development Subsidiary, adjusted for non-controlling interests in ARP, APL and our Development Subsidiary. All significant intercompany transactions and balances have been eliminated in the consolidation of our financial statements. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

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 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 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 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 financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect our results on a consolidated 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 statements of operations for any date prior to February 17, 2011 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 (“Chevron”) in February 2011 and not activities related to the Transferred Business.

SUBSEQUENT EVENTS

Distribution. On January 29, 2014, we declared a cash distribution of $0.46 per unit on our outstanding common units, representing the cash distribution for the quarter ended December 31, 2013. The $23.7 million distribution was paid on February 19, 2014 to unitholders of record at the close of business on February 10, 2014.

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Atlas Resource

Distribution. On February 24, 2014, ARP declared its initial monthly distribution of $0.1933 per common unit for the month of January 2014, which is payable on March 17, 2014 to holders of record as of March 7, 2014. In January 2014, ARP’s board of directors had approved the modification of its distribution payment practice to a monthly distribution program.

GeoMet Acquisition. On February 13, 2014, ARP entered into a definitive asset purchase and sale agreement to acquire certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014, subject to certain purchase price adjustments. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. The closing of the acquisition is subject to certain closing conditions, including a vote by GeoMet’s stockholders to approve the transaction.

Distribution. On January 29, 2014, ARP 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, 2013. The $41.8 million distribution, including $2.9 million and $4.4 million to us, as general partner, and preferred limited partners, respectively, was paid on February 14, 2014 to unitholders of record at the close of business on February 10, 2014.

Atlas Pipeline

Distribution. On January 28, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2013. The $56.1 million distribution, including $6.1 million to us as general partner, was paid on February 14, 2014 to unitholders of record at the close of business on February 7, 2014. Based on this declaration, APL also issued approximately 274,785 Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution for the quarter ended December 31, 2013. The in kind distribution was issued on February 14, 2014 to the preferred unitholders of record at the close of business on February 7, 2014 (see “Issuances of Units”).

RECENT DEVELOPMENTS

Arc Logistics Partners IPO. Lightfoot LP, a privately managed partnership in which we own an approximate 12% interest as well as an approximate 16% interest in its general partner (an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board) owns and controls the general partner of Arc Logistics Partners, L.P. (“ARCX”), an MLP. On November 6, 2013, ARCX began trading publicly on the NYSE under the ticker symbol “ARCX”. ARCX is focused on the terminalling, storage, throughput and transloading of crude oil and petroleum products in the East Coast, Gulf Coast and Midwest regions of the United States. ARCX’s cash flows are primarily fee-based under multi-year contracts.

Formation of our Development Subsidiary. During the year ended December 31, 2013, we formed our Development Subsidiary, a new subsidiary to conduct natural gas and oil operations initially in the mid-continent region of the United States, specifically in the Marble Falls formation in the Fort Worth Basin and the Mississippi Lime area of the Anadarko Basin in Oklahoma. At December 31, 2013, our Development Subsidiary had completed two wells in the Marble Falls play. At December 31, 2013, we owned an 18.3% limited partner interest in our Development Subsidiary and 83.1% of its outstanding general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions.

Arkoma Acquisition. On July 31, 2013, we completed the acquisition of certain natural gas and oil producing assets in the Arkoma basin from EP Energy E&P Company, L.P. (“EP Energy”). Pursuant to the purchase and sale agreement with EP Energy, we acquired the Arkoma basin assets for approximately $64.5 million in cash, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of our term loan facility (see “Term Loan Facility”). The Arkoma Acquisition had an effective date of May 1, 2013.

Term Loan Facility. On July 31, 2013, in connection with the Arkoma Acquisition, we entered into a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at our election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (“ABR”) (as defined in the Term Facility) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by us. We are required to repay principal at the rate of $0.6 million per quarter until the maturity date when the balance is due (see “Term Loan Facility”).

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Credit Facility. On July 31, 2013, in connection with the Arkoma Acquisition, we entered into an amended credit facility with a syndicate of banks that matures in July 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. Our obligations under the credit facility are secured by first priority security interests in substantially all of our assets, including all of our ownership interests in our material subsidiaries and our ownership interests in APL and ARP. Additionally, our obligations under the credit facility are guaranteed by our material wholly-owned subsidiaries, (excluding Atlas Pipeline Partners GP, LLC), and may be guaranteed by future subsidiaries. Any of our subsidiaries, other than the subsidiary guarantors, are minor. At our election, interest on borrowings under the credit agreement is determined by reference to either an adjusted LIBOR rate plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by us for LIBOR loans. We are required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility (see “Credit Facilities”).

Purchase of ARP Preferred Units. In July 2013, in connection with ARP’s acquisition of assets from EP Energy, we purchased 3,749,986 of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). Upon issuance of the Class C preferred units, we also received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units (see “Issuance of Units”).

Atlas Resource

EP Energy Acquisition. On July 31, 2013, ARP completed its acquisition of assets from EP Energy for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of its 9.25% senior notes due August 15, 2021 (“9.25% ARP Senior Notes”), the issuance of 14,950,000 ARP common limited partner units, and the sale to us of ARP’s newly created Class C convertible preferred units. The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013.

Issuance of Preferred Units. On July 31, 2013, in connection with ARP’s EP Energy Acquisition, ARP issued 3,749,986 newly created Class C convertible preferred units to us, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 which became exercisable, at our option, beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ending September 30, 2013. In connection with the issuance of the Class C preferred units, ARP also issued to us a warrant to purchase 562,497 of ARP’s common units (representing 15% of the Class C preferred units issued) (see “Issuance of Units”).

Credit Facility Amendment. On July 31, 2013, in connection with the EP Energy Acquisition, ARP entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”). The ARP Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks. ARP’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. On December 6, 2013, ARP entered into the First Amendment to the Credit Agreement (the “ARP Amendment”). The ARP Amendment redetermined the borrowing base to $735.0 million and set the ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended December 31, 2013, March 31, 2014, and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ended September 30, 2014, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter (see “Credit Facilities”).

9.25% ARP Senior Notes. On July 30, 2013, in connection with its EP Energy Acquisition, ARP issued $250.0 million of its 9.25% ARP Senior Notes, due 2021, in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million. The net proceeds were used to partially fund the EP Energy Acquisition. The 9.25% ARP Senior Notes were presented net of a $1.7 million unamortized discount as of December 31, 2013. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date being February 15, 2014 (see “Senior Notes”).

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Common Unit Offering. In June 2013, in connection with the EP Energy Acquisition, ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million (see “Issuance of Units”). ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see “Credit Facilities”).

Equity Distribution Program. In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. Sales of common limited partner units, if any, could be made in negotiated transactions or transactions that were deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the NYSE, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP paid each of the agents a commission, which in each case was not more than 2.0% of the gross sales price of common limited partner units sold through such agent. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions and other offering costs paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated its equity distribution agreement effective December 27, 2013 (see “Issuance of Units”).

7.75% ARP Senior Notes. On January 23, 2013, ARP issued $275.0 million of 7.75% senior unsecured notes due January 15, 2021 (“7.75% ARP Senior Notes”) in a private placement transaction at par. ARP used the net proceeds of approximately $267.6 million, to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility (see “Credit Facilities”). In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the year ended December 31, 2013. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15 (see “Senior Notes”).

Atlas Pipeline

Senior Note Offering. On May 10, 2013, APL issued $400.0 million of 4.75% unsecured senior notes due November 15, 2021 (“4.75% APL Senior Notes”) in a private placement transaction. The 4.75% APL Senior Notes were issued at par. APL received net proceeds of $391.2 million after underwriting commissions and other transaction costs. APL utilized the proceeds repay a portion of its outstanding indebtedness under its revolving credit agreement. The registration statement APL filed with the SEC for the exchange offer for $400.0 million of the 4.75% APL Senior Notes in satisfaction of the registration requirements of the registration rights agreement was declared effective on December 9, 2013. APL commenced an exchange offer for the 4.75% APL Senior Notes on December 10, 2013 and the exchange offer was consummated on January 9, 2014 (see “Senior Notes”).

TEAK Acquisition. On May 7, 2013, APL completed the acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) for $974.7 million in cash, including final purchase price adjustments, less cash received (the “TEAK Acquisition”). The assets acquired, which are referred to as the SouthTX assets, include the following gas gathering and processing facilities in the Eagle Ford shale region of south Texas:

• the Silver Oak I plant, which is a 200 MMcfd cryogenic processing facility;

• a second 200 MMcfd cryogenic processing facility, the Silver Oak II plant, expected to be in service the second quarter of 2014;

• 265 miles of primarily 20-24 inch gathering and residue lines;

• approximately 275 miles of low pressure gathering lines;

• a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), which owns a 62 mile, 24 inch gathering line;

• a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), which owns a 45 mile, 16 inch gathering pipeline; a 71 mile 24 inch gathering line; and a 50 mile residue pipeline; and

• a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”), which owns a cogeneration facility.

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Credit Facility Amendment. On April 19, 2013, APL entered into an amendment to its revolving credit agreement, which among other changes,

• allowed the TEAK Acquisition to be a Permitted Investment, as defined in the credit agreement;

• did not require the joint venture interests acquired in the TEAK Acquisition to be guarantors;

• permitted the payment of cash distributions, if any, on the Class D convertible preferred units (“Class D Preferred Units”) so long as we have a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million; and

• modified the definition of Consolidated Funded Debt Ratio, Interest Coverage Ratio and Consolidated EBITDA to allow for an Acquisition Period whereby the terms for calculating each of these ratios have been adjusted.

Common Unit Offering. On April 17, 2013, APL sold 11,845,000 common units in a registered public offering at a price to the public of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from us, as general partner, of $8.3 million to maintain our 2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see “Issuance of Units”).

Preferred Unit Offering. On May 7, 2013, APL issued $400.0 million of its Class D Preferred Units in a private placement transaction, at a negotiated price per unit of $29.75, for net proceeds of $397.7 million. APL also received a capital contribution from us, as general partner, of $8.2 million to maintain our 2% general partnership interest in APL, upon the issuance of the Class D Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see “Issuance of Units”).

Cryogenic Processing Plant. On April 12, 2013, APL placed in service a new 200 MMcfd cryogenic processing plant, known as the Driver Plant in its WestTX system in the Permian Basin of Texas, increasing the WestTX system capacity to 455 MMcfd.

Senior Notes Redemptions. On March 12, 2013, APL paid $105.6 million to redeem the remaining $105.6 million of the $365.8 million 8.75% senior unsecured notes due on June 15, 2018 (“8.75% APL Senior Notes”) including a $6.3 million make-whole premium and $2.0 million in accrued interest. APL commenced a cash tender offer for any and all of the 8.75% APL Senior Notes on January 28, 2013. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) (see “Senior Notes”).

Senior Notes Issuance. On February 11, 2013, APL issued $650.0 million of 5.875% APL Senior Notes, due 2023, in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million and utilized the proceeds to redeem its outstanding 8.75% APL Senior Notes and repay a portion of its outstanding indebtedness under its revolving credit facility. APL commenced an exchange offer for the 5.875% APL Senior Notes on December 10, 2013 and the exchange offer was consummated on January 9, 2014 (see “Senior Notes”).

Acquisition of Gas Gathering Systems and Related Assets. On January 7, 2013, APL paid $6.0 million for the first of two contingent 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, 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 contingent payment.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas and Oil Production

Natural Gas. We and ARP market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our and ARP’s gas. 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 indices for the majority of our and ARP’s production areas are as follows:

• Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline, Transco Leidy Line;

• Mississippi Lime - Southern Star;

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• Barnett Shale and Marble Falls- primarily Waha but with smaller amounts sold into a variety of north Texas outlets;

• Raton – ANR, Panhandle, and NGPL;

• Black Warrior Basin – Southern Natural;

• Arkoma – Enable Gas; and

• Other regions - primarily the Texas Gas Zone SL spot market (New Albany Shale) and the Cheyenne Hub spot market (Niobrara).

We and ARP attempt to sell the majority of natural gas produced at monthly, fixed index prices and a smaller portion at index daily prices.

ARP holds firm transportation obligations on Colorado Interstate Gas as a result of the EP Energy Acquisition for the benefit of production from the Raton Basin in the New Mexico/Colorado Area. The total of firm transportation held is approximately 82,500 dth/d at a weighted average rate of $0.2575/MMBtu under contracts expiring in 2014 and 2016.

Crude Oil. Crude oil produced from our and 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. We and ARP do 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 to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as mentioned above and our and ARP’s NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. 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 percentage retention by the processing and fractionation facility. We and ARP do 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, 2013, Enterprise Products Operating LLC, Chevron and Empire Pipeline Corporation accounted for approximately 19%, 11% and 10% of ARP’s total natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Atlas Resources’ Drilling Partnerships

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

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

• Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $400,000, depending on the type of well drilled. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by ARP’s proportionate interest in the well;

• Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, for the life of the well. Because ARP coinvests in the Drilling Partnerships, the net fee that it receives is reduced by its proportionate interest in the wells; and

• Gathering. Each royalty owner, Drilling 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 Drilling 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 in Drilling Partnerships by approximately 3%.

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Gathering and Processing

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

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

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

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

• the contract terms with each producer; and

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

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.

Natural Gas and Oil Production

The areas in which we and ARP operate 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 we and ARP anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our and ARP’s future gas and oil reserves, production, cash flow, the ability to make payments on debt and the ability to make distributions to unitholders, including ARP’s ability to make distributions to us, depend on our and ARP’s success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. We and ARP face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas production from particular wells decrease. We and ARP attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced.

Gathering and Processing

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

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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, NGL 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, 2013, our consolidated gas and oil production revenues and expenses consists of our and ARP’s gas and oil production activities. Currently, our gas and oil production entails the production generated by our assets acquired in the Arkoma Acquisition and our wells drilled in the Marble Falls play. ARP has focused its natural gas, crude oil and NGL production operations in various shale plays throughout the United States. ARP had certain agreements which restricted its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale, which expired on February 17, 2014. Through December 31, 2013, we and ARP have established production positions in the following operating areas:

• our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma, where we established a position following our acquisition of certain assets from EP Energy during 2013 (see “Recent Developments”);

• our Marble Falls play in the Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which we established a position following our acquisition of leasehold acreage in August 2013;

• ARP’s 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 Oil & Gas, Inc. (“Carrizo”), Titan Operating, LLC (“Titan”) and DTE Energy Company (“DTE”) during 2012;

• ARP’s coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming, where ARP established a position following its acquisition of certain assets from EP Energy during 2013 (see “Recent Developments”);

• ARP’s 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;

• ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area, in which ARP established a position following its acquisition from Equal in 2012; and

• ARP’s 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; and the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas.

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The following table presents the number of wells we and ARP drilled, both gross and for our and ARP’s interest, and the number of gross wells we and ARP turned in line during the years ended December 31, 2013, 2012 and 2011:

	Years Ended December 31,
	2013		2012		2011
Atlas Energy:
Gross wells drilled:		2		—		—
Our share of gross wells drilled:		1		—		—
Gross wells turned in line:		2		—		—
	Years Ended December 31,
	2013		2012		2011
Atlas Resource:
ARP gross wells drilled:		103		105		160
ARP’s share of gross wells drilled(1):		66		42		31
ARP gross wells turned in line:		117		154		99

(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 Drilling Partnerships.

Production Volumes. The following table presents total net natural gas, crude oil, and NGL production volumes and production per day for the years ended December 31, 2013, 2012 and 2011:

	Years Ended December 31,
	2013		2012		2011
Production:(1)(2)
Atlas Energy:
Natural gas (MMcf)		1,864		—		—
Oil (000’s Bbls)		3		—		—
Natural gas liquids (000’s Bbls)		1		—		—
Total (MMcfe)		1,885		—		—
Atlas Resource:
Natural gas (MMcf)		57,993		25,403		11,462
Oil (000’s Bbls)		485		121		112
Natural gas liquids (000’s Bbls)		1,268		357		162
Total (MMcfe)		68,511		28,267		13,108
Total production:
Natural gas (MMcf)		59,857		25,403		11,462
Oil (000’s Bbls)		488		121		112
Natural gas liquids (000’s Bbls)		1,269		357		162
Total (MMcfe)		70,396		28,267		13,108
Production per day:(1)(2)
Atlas Energy:
Natural gas (Mcfd)		5,106		—		—
Oil (Bpd)		7		—		—

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	Years Ended December 31,
	2013		2012		2011
Natural gas liquids (Bpd)		3		—		—
Total (Mcfed)		5,164		—		—
Atlas Resource:
Natural gas (Mcfd)		158,886		69,408		31,403
Oil (Bpd)		1,329		330		307
Natural gas liquids (Bpd)		3,473		974		444
Total (Mcfed)		187,701		77,232		35,912
Total production per day:
Natural gas (Mcfd)		163,992		69,408		31,403
Oil (Bpd)		1,336		330		307
Natural gas liquids (Bpd)		3,476		974		444
Total (Mcfed)		192,866		77,232		35,912

⁽¹⁾  Production quantities consist of the sum of (i) the proportionate share of production from wells in which we and ARP have a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling 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.

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas, which comprised all of our proved reserves and 83% of ARP’s proved reserves on an energy equivalent basis at December 31, 2013. The following table presents production revenues and average sales prices for our and ARP’s natural gas, oil, and natural gas liquids production for years ended December 31, 2013, 2012 and 2011, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

	Years Ended December 31,
	2013		2012		2011
Production revenues (in thousands):
Atlas Energy:
Natural gas revenue	$	6,849	$	—	$	—
Oil revenue		241		—		—
Natural gas liquids revenue		33		—		—
Total revenues	$	7,123	$	—	$	—
Atlas Resource:
Natural gas revenue	$	186,229	$	70,151	$	49,096
Oil revenue		44,160		11,351		10,057
Natural gas liquids revenue		36,394		11,399		7,826
Total revenues	$	266,783	$	92,901	$	66,979
Total production revenues:
Natural gas revenue	$	193,078	$	70,151	$	49,096

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	Years Ended December 31,
	2013		2012		2011
Oil revenue		44,401		11,351		10,057
Natural gas liquids revenue		36,427		11,399		7,826
Total revenues	$	273,906	$	92,901	$	66,979
Average sales price:
Natural gas (per Mcf):(1)
Total realized price, after hedge(2)	$	3.48	$	3.29	$	4.98
Total realized price, before hedge(2)	$	3.25	$	2.60	$	4.53
Oil (per Bbl):(1)
Total realized price, after hedge	$	91.02	$	94.02	$	89.70
Total realized price, before hedge	$	95.86	$	91.32	$	89.07
Natural gas liquids (per Bbl) total realized price:(1)	$	28.71	$	31.97	$	48.26
Production costs (per Mcfe):(1)
Atlas Energy:
Lease operating expenses	$	0.81	$	—	$	—
Production taxes		0.22		—		—
Transportation and compression		0.53		—		—
	$	1.56	$	—	$	—
Atlas Resource:
Lease operating expenses(3)	$	1.09	$	0.82	$	1.09
Production taxes		0.18		0.12		0.10
Transportation and compression		0.24		0.24		0.43
	$	1.50	$	1.19	$	1.61
Total production costs:
Lease operating expenses(3)	$	1.08	$	0.82	$	1.09
Production taxes		0.18		0.12		0.10
Transportation and compression		0.25		0.24		0.43
	$	1.50	$	1.19	$	1.61

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

⁽²⁾  Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for years ended December 31, 2013, 2012 and 2011. Including the effect of this subordination, the average realized gas sales price was $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) and $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging) for years ended December 31, 2013, 2012 and 2011, respectively.

⁽³⁾  Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for years ended December 31, 2013, 2012 and 2011. Including the effects of these costs, total lease operating expenses per Mcfe were $1.00 per Mcfe ($1.42 per Mcfe for total production costs), $0.58 per Mcfe ($0.94 per Mcfe for total production costs) and $0.80 per Mcfe ($1.41 per Mcfe for total production costs) for the years ended December 31, 2013, 2012 and 2011, respectively.

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Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total natural gas revenues were $193.1 million for the year ended December 31, 2013, an increase of $122.9 million from $70.2 million for year ended December 31, 2012. This increase consisted primarily of a $72.9 million increase attributable to natural gas revenue associated with our and ARP’s newly acquired coal-bed methane assets, a $44.6 million increase attributable to natural gas revenue associated with ARP’s Barnett Shale/Marble Falls assets, a $5.2 million increase attributable to ARP’s Mississippi Lime/Hunton assets and a $2.1 million increase primarily attributable to higher production volume on ARP’s legacy systems, partially offset by a $1.9 million increase in ARP’s gas revenues subordinated to the investor partners within its Drilling Partnerships. Total oil revenues were $44.4 million for the year ended December 31, 2013, an increase of $33.0 million from $11.4 million for the comparable prior year period due to a $25.7 million increase attributable to oil revenue associated with ARP’s Barnett Shale/Marble Falls assets, a $6.2 million increase attributable to ARP’s Mississippi Lime/Hunton assets, and a $0.9 million increase attributable to higher production volume on ARP’s legacy systems during the current year period. Total natural gas liquids revenues were $36.4 million for the year ended December 31, 2013, an increase of $25.0 million from $11.4 million for the comparable prior year period. This increase was primarily attributable to a $22.0 million increase of NGL revenue associated with ARP’s Barnett Shale/Marble Falls assets and a $4.0 million increase of NGL revenue attributable to ARP’s Mississippi Lime/Hunton assets.

Total production costs were $100.2 million for the year ended December 31, 2013, an increase of $73.6 million from $26.6 million for the year ended December 31, 2012. This increase was due primarily to a $39.8 million increase associated with ARP’s 2012 acquisitions in the Barnett Shale/Marble Falls and Mississippi Lime/Hunton plays, a $28.7 million increase associated with our and ARP’s current year acquisition of coal-bed methane assets, a $3.6 million increase in ARP’s Appalachia-based transportation, labor and other production costs, and a $1.4 million decrease in ARP’s credit received against its lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe increased to $1.50 per Mcfe for the year ended December 31, 2013 from $1.19 per Mcfe for the comparable prior year period primarily as a result of the increase in ARP’s oil natural gas liquids volumes during the current period.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Total natural gas revenues were $70.2 million for the year ended December 31, 2012, an increase of $21.1 million from $49.1 million for the year ended December 31, 2011. This increase consisted of a $25.6 million increase attributable to natural gas revenue associated with ARP’s Barnett Shale/Marble Falls assets acquired in 2012, a $1.8 million increase attributable to natural gas revenue associated with ARP’s Mississippi Lime/Hunton assets acquired in 2012 and an $11.3 million increase attributable to higher production volume on ARP’s legacy systems, partially offset by a $12.3 million decrease attributable to lower realized natural gas prices for production volume on ARP’s legacy systems and a $5.3 million increase in gas revenues subordinated to the investor partners within ARP’s Drilling Partnerships for the year ended December 31, 2012 compared with the prior year period. Total oil revenues were $11.4 million for the year ended December 31, 2012, an increase of $1.3 million from $10.1 million for the comparable prior year period due primarily to higher ARP production volume during the year ended December 31, 2012. Total natural gas liquids revenues were $11.4 million for the year ended December 31, 2012, an increase of $3.6 million from $7.8 million for the comparable prior year period. This increase is primarily attributable to $5.0 million of NGL revenue associated with ARP’s Barnett Shale/Marble Falls assets acquired in 2012, partially offset by lower realized prices.

Total production costs were $26.6 million for the year ended December 31, 2012, an increase of $9.5 million from $17.1 million for the year ended December 31, 2011. This increase was due primarily to an $11.7 million increase associated with ARP’s 2012 acquisitions in the Barnett Shale/Marble Falls and Mississippi Lime/Hunton plays, and a $0.9 million increase in ARP’s Appalachia-based labor and other costs, partially offset by a $2.9 million increase in ARP’s credit received against lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe decreased to $1.19 per Mcfe for the year ended December 31, 2012 from $1.61 per Mcfe for the comparable prior year period primarily as a result of ARP’s increase in natural gas volumes during the year ended December 31, 2012.

Well Construction and Completion

Drilling Program Results. At December 31, 2013, our consolidated well construction and completion revenues and expenses consist solely of ARP’s activities. The number of wells ARP drills will vary within ARP’s partnership management segment depending on the amount of capital it raises through its Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of Drilling Partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells ARP drilled for its Drilling Partnerships during years ended December 31, 2013, 2012 and 2011. There were no exploratory wells drilled during the years ended December 31, 2013, 2012 and 2011:

	Years Ended December 31,
	2013		2012		2011
Drilling partnership investor capital:
Raised	$	149,967	$	127,071	$	141,929

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	Years Ended December 31,
	2013		2012		2011
Deployed	$	167,883	$	131,496	$	135,283
Gross partnership wells drilled:
Marcellus Shale		—		10		14
Utica		3		5		—
Ohio		—		7		3
Barnett/Marble Falls		51		4		—
Mississippi Lime/Hunton		21		11		—
Chattanooga		—		—		5
Niobrara		—		51		138
Total		75		88		160
Net partnership wells drilled:
Marcellus Shale		—		10		11
Utica		3		5		—
Ohio		—		7		3
Barnett/Marble Falls		25		2		—
Mississippi Lime/Hunton		21		9		—
Chattanooga		—		—		5
Niobrara		—		51		138
Total		49		84		157

Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for Drilling Partnerships ARP sponsors. The following table sets forth information relating to these revenues and the related costs and number of net wells associated with these revenues during the periods indicated (dollars in thousands):

	Years Ended December 31,
	2013		2012		2011
Average construction and completion:
Revenue per well	$	3,276	$	1,444	$	886
Cost per well		2,849		1,253		757
Gross profit per well	$	427	$	191	$	129
Gross profit margin	$	21,898	$	17,417	$	19,653
Partnership net wells associated with revenue recognized(1):
Marcellus Shale		4		7		15
Utica		5		2		—
Ohio		—		8		2
Barnett/Marble Falls		24		2		—
Mississippi Lime/Hunton		18		7		—
Chattanooga		—		2		4
New Albany/Antrim		—		—		3
Niobrara		—		63		129
Total		51		91		153

(1) Consists of ARP’s Drilling Partnership net wells for which well construction and completion revenue was recognized on a percentage of completion basis.

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Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Well construction and completion segment margin was $21.9 million for the year ended December 31, 2013, an increase of $4.5 million from $17.4 million for the year ended December 31, 2012. This increase consisted of a $12.1 million increase associated with ARP’s higher gross profit margin per well, partially offset by a $7.6 million decrease related to a lower number of wells recognized for revenue within ARP’s Drilling Partnerships. Average revenue and cost per well increased between periods due primarily to higher capital deployed for Utica Shale, Mississippi Lime play, and Marble Falls play wells within ARP’s Drilling Partnerships during the year ended December 31, 2013, compared with higher capital deployed for lower cost Niobrara Shale wells during the prior year period. Since ARP’s drilling contracts with the Drilling Partnerships are on a “cost-plus” basis, an increase or decrease in ARP’s average cost per well also results in a proportionate increase or decrease in its average revenue per well, which directly affects the number of wells ARP drills.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Well construction and completion segment margin was $17.4 million for the year ended December 31, 2012, a decrease of $2.3 million from $19.7 million for the year ended December 31, 2011. This decrease consisted of a $7.9 million decrease related to a decreased number of wells recognized for revenue within ARP’s Drilling Partnerships, partially offset by a $5.6 million increase associated with higher gross profit margin per well. Average revenue and cost per well increased between periods due primarily to higher capital deployed for Marcellus Shale and Utica Shale wells within the drilling partnerships during 2012.

At December 31, 2013, our consolidated balance sheet includes $49.4 million of “liabilities associated with drilling contracts” for funds raised by ARP’s Drilling Partnerships that have not been applied to the completion of wells due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue on our consolidated statements of operations. ARP expects to recognize this amount as revenue during 2014.

Administration and Oversight

At December 31, 2013, our consolidated administration and oversight revenues and expenses consist solely of ARP’s activities. Administration and oversight fee revenues represent supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for ARP’s Drilling Partnerships. Typically, ARP receives a lower administration and oversight fee related to shallow, vertical wells it drills within the Drilling Partnerships, such as those in the Marble Falls and Niobrara Shale, as compared to deep, horizontal wells, such as those drilled in the Marcellus and Utica Shales.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Administration and oversight fee revenues were $12.3 million for the year ended December 31, 2013, an increase of $0.5 million from $11.8 million for the year ended December 31, 2012. This increase was due primarily to current year period increases in the number of wells drilled within the Mississippi Lime Shale and Marble Falls play, partially offset by a decrease in the number of Marcellus Shale wells drilled during the current year period.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Administration and oversight fee revenues were $11.8 million for the year ended December 31, 2012, an increase of $4.1 million from $7.7 million for the year ended December 31, 2011. This increase was primarily due to an increase in the number of horizontal wells drilled in both the Mississippi Lime and Utica Shale during the year ended December 31, 2012 and an increase in the number of Marcellus Shale wells drilled during the year ended December 31, 2012 in comparison to the prior year period.

Well Services

At December 31, 2013, our consolidated well services revenues and expenses consist solely of ARP’s activities. Well services revenue and expenses represent the monthly operating fees ARP charges and the work ARP’s service company performs, including work performed for ARP’s Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which ARP serves as operator.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Well services revenues were $19.5 million for the year ended December 31, 2013, a decrease of $0.5 million from $20.0 million for the year ended December 31, 2012. Well services expenses were $9.5 million for the year ended December 31, 2013, an increase of $0.2 million from $9.3 million for the year ended December 31, 2012. The decrease in well services revenue is primarily related to lower equipment rental revenue during the year ended December 31, 2013 as compared with the comparable prior year period. The increase in well services expense is primarily related to higher well labor costs.

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Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Well services revenues were $20.0 million for the year ended December 31, 2012, an increase of $0.2 million from $19.8 million for the year ended December 31, 2011. Well services expenses were $9.3 million for the year ended December 31, 2012, an increase of $0.6 million from $8.7 million for the year ended December 31, 2011. The increase in well services revenue is primarily related to higher equipment rental revenue during the year ended December 31, 2012 as compared with the comparable prior year period. The increase in well services expenses is primarily related to higher well labor costs.

Gathering and Processing

Gathering and processing margin includes the gathering and processing fees and related expenses for APL and ARP. The following table presents ARP’s and APL’s gathering and processing revenues and expenses for each of the respective periods:

	Years Ended December 31,
	2013			2012			2011
Gathering and Processing:
Atlas Resource:
Revenue	$	15,676		$	16,267		$	17,746
Expense(1)		(17,709	)		(19,056	)		(20,507	)
Gross Margin	$	(2,033	)	$	(2,789	)	$	(2,761	)
Atlas Pipeline:
Revenue(1)	$	2,124,018		$	1,203,548		$	1,311,672
Expense		(1,784,909	)		(990,044	)		(1,102,544	)
Gross Margin	$	339,109		$	213,504		$	209,128
Total: (1)
Revenue	$	2,139,694		$	1,219,815		$	1,329,418
Expense		(1,802,618	)		(1,009,100	)		(1,123,051	)
Gross Margin	$	337,076		$	210,715		$	206,367

(1) Revenues and expenses of ARP and APL are shown after elimination of $0.3 million, $0.4 million and $0.3 million for the years ended December 31, 2013, 2012 and 2011, respectively (see “Item 8: Financial Statements and Supplementary Data – Note 13”).

Generally, ARP charges a gathering fee to its Drilling Partnership wells equivalent to the fees it 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 Drilling 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 the Drilling Partnerships by approximately 3%.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. ARP’s net gathering and processing expense for the year ended December 31, 2013 was $2.0 million, a decrease of $0.8 million compared with net expense of $2.8 million for the year ended December 31, 2012. This favorable decrease was principally due to an increase in gathering fees associated with ARP’s new Marcellus wells in Northeastern Pennsylvania.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. ARP’s net gathering and processing expense for the year ended December 31, 2012 was $2.8 million, which was comparable for the year ended December 31, 2011.

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Production Profile. At December 31, 2013, APL’s gathering and processing volumes are generated through its operations in the following areas:

• APL’s SouthOk system, which includes its Velma and Arkoma systems. APL’s Velma system includes two processing plants and approximately 1,200 miles of active gathering pipelines. APL’s Arkoma system, which was acquired from Cardinal Midstream, LLC (“Cardinal”) in December 2012 (the “Cardinal Acquisition”), includes three processing plants and approximately 100 miles of active gathering pipelines.

• APL’s SouthTX system, which includes the assets acquired in the TEAK Acquisition. APL’s SouthTX system includes one processing plant and interests in approximately 670 miles of active gathering pipelines.

• APL’s WestOK system, which includes four processing plants and approximately 5,700 miles of active gathering pipelines.

• APL’s WestTX system, which includes four processing plants and approximately 3,600 miles of active gathering pipelines.

The following table presents APL’s production volumes per day and average sales prices for its natural gas, oil, and natural gas liquids production for the years ended December 31, 2013, 2012 and 2011:

	Years Ended December 31,
	2013		2012		2011
Pricing:(1)
Average sales price:
Natural gas sales ($/Mcf)	$	3.44	$	2.62	$	3.86
NGL sales ($/gallon)	$	0.91	$	0.90	$	1.20
Condensate sales ($/barrel)	$	91.90	$	87.88	$	90.65
Volumes:(1)
Gathered gas volume (Mcfd)		1,426,835		1,026,996		592,130
Processed gas volume (Mcfd)		1,314,596		922,715		548,932
Residue gas volume (Mcfd)		1,112,137		777,605		445,094
NGL volume (Bpd)		114,690		76,807		54,120
Condensate volume (Bpd)		4,146		3,415		2,821

(1) “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Gathering and processing margin for APL was $339.1 million for the year ended December 31, 2013 compared with $213.5 million for the year ended December 31, 2012. This increase was due principally to higher production volumes, including the new volumes from the Arkoma system due to the Cardinal Acquisition and from the SouthTX system due to the TEAK Acquisition.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Gathering and processing margin for APL was $213.5 million for the year ended December 31, 2012 compared with $209.1 million for the year ended December 31, 2011. This increase was due principally to higher production volumes, partially offset by lower natural gas and NGL sales prices.

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Gain (Loss) on Mark-to-Market Derivatives

Gain (loss) on mark-to-market derivatives principally reflects the change in fair value of APL’s commodity derivatives that will settle in future periods, as APL does not apply hedge accounting to its derivatives. While APL utilizes either quoted market prices or observable market data to calculate the fair value of its natural gas and crude oil derivatives, valuations of APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGLs for similar geographic locations, and valuations of its NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for APL’s fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact our net income, though it would have no impact on our liquidity or capital resources. We recognized a loss of $16.8 million, a gain of $27.3 million and a loss of $20.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, for APL’s mark-to-market gain (loss) on derivatives valued upon unobservable inputs.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Gain (loss) on mark-to-market derivatives was a loss of $28.8 million for the year ended December 31, 2013 as compared with a gain of $31.9 million for the year ended December 31, 2012. This unfavorable movement was primarily due to the non-cash fair value revaluation of APL’s commodity derivative contracts in the current period compared to the prior year period mainly due to a $20.9 million gain in the prior year period resulting from a decrease in prices during the prior year period; and a $28.4 million loss in the current year period resulting from an increase in prices during the current year period.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Gain on mark-to-market derivatives was $31.9 million for the year ended December 31, 2012 as compared with a $20.5 million loss for the year ended December 31, 2011. This favorable movement was primarily due to a $27.1 million favorable movement in realized settlements on net cash derivative expense related to APL’s commodity derivatives, mainly as a result of lower NGL prices and a $25.3 million favorable variance in non-cash mark-to-market adjustments on APL’s commodity derivatives in the current period compared to the prior period.

Other, Net

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Other, net for the year ended December 31, 2013 was expense of $7.0 million as compared with revenue of $13.4 million for the comparable prior year period. This decrease was primarily due to the $14.5 million of premium amortization associated with swaption derivative contracts for production volumes related to wells ARP acquired from EP Energy in the current year period, $11.1 million increase in APL’s loss from equity investments primarily due to a loss in the current year period from the SouthTX equity method investments and $2.3 million of our swaption amortization related to production volumes on wells acquired from EP Energy in the current period, partially offset by a $4.6 million premium amortization associated with ARP’s swaption derivative contracts for production volumes related to wells acquired from Carrizo in the prior year period, a $1.0 million settlement of APL’s business interruption insurance in the current year period, and a $0.3 million increase in income from the equity investment in Lightfoot.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Other, net revenue for the year ended December 31, 2012 was $13.4 million as compared with revenue of $31.8 million for the comparable prior year period. This decrease was primarily due to a $15.0 million decrease in our equity earnings from Lightfoot, the $4.6 million premium amortization associated with ARP’s derivative contracts for production volumes related to wells acquired from Carrizo and lower interest income of $1.1 million, partially due to APL’s December 2011 settlement of a note receivable related to APL’s 49% non-controlling ownership interest in Laurel Mountain, which was sold in February 2011. These unfavorable movements were partially offset by a $1.3 million increase in APL’s income from equity investments. During the year ended December 31, 2011, we recorded a gain of $15.0 million pertaining to our share of Lightfoot LP’s gain recognized on the sale of International Resource Partners LP in March 2011.

OTHER COSTS AND EXPENSES

General and Administrative Expenses

The following table presents our general and administrative expenses and those attributable to ARP and APL for each of the respective periods (in thousands):

	Years Ended December 31,
	2013		2012		2011
General and Administrative expenses:
Atlas Energy	$	39,052	$	34,048	$	16,694

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	Years Ended December 31,
	2013		2012		2011
Atlas Resource		78,063		69,123		27,536
Atlas Pipeline		80,861		62,606		36,354
Total	$	197,976	$	165,777	$	80,584

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total general and administrative expenses increased to $198.0 million for the year ended December 31, 2013 compared with $165.8 million for the year ended December 31, 2012. Our $39.1 million of general and administrative expenses for the year ended December 31, 2013 represents a $5.0 million increase from the comparable prior year period, which was primarily related to a $4.7 million increase in non-cash compensation expense and a $1.9 million increase in salaries, wages and other corporate activities, partially offset by a $1.6 million decrease in non-recurring transaction costs. ARP’s $78.1 million of general and administrative expenses for the year ended December 31, 2013 represents an $8.9 million increase from the comparable prior year period primarily due to a $7.7 million increase in non-recurring transaction costs related to ARP’s acquisitions and a $1.8 million increase in non-cash compensation expense, partially offset by a $0.5 million decrease in other corporate activities. APL’s $80.9 million of general and administrative expense for the year ended December 31, 2013 represents an increase of $18.3 million from the comparable prior year period, which was principally due to a $7.7 million increase in non-cash compensation expense, a $3.9 million increase in non-recurring transaction costs, and a $3.6 million increase in salaries and wages partially due to the increase in the number of employees as a result of the growth of its business.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Total general and administrative expenses increased to $165.8 million for the year ended December 31, 2012 compared with $80.6 million for the year ended December 31, 2011. Our $34.0 million of general and administrative expenses for the year ended December 31, 2012 represents a $17.4 million increase from the comparable year period primarily related to a $5.8 million unfavorable movement in non-recurring transaction costs, a $5.1 million increase in non-cash compensation expense, a $3.8 million increase in salaries and wages and a $2.7 million increase in other corporate activities. ARP’s $69.1 million of general and administrative expenses for the year ended December 31, 2012 represents a $41.6 million increase from the comparable prior year period primarily due to a $22.1 million increase in non-recurring transaction costs related to ARP’s 2012 acquisitions of assets, an $18.6 million unfavorable movement related to a decrease in net reimbursements ARP received under its transition services agreement with Chevron, which expired during the first quarter of 2012 and a $10.8 million increase in non-cash compensation expense, partially offset by a $9.9 million decrease in salaries and wages and other corporate activities. APL’s $62.6 million of general and administrative expense for the year ended December 31, 2012 represents an increase of $26.2 million from the comparable prior year period, which was principally due to a $15.4 million increase in non-recurring transaction costs, an $8.4 million increase of non-cash compensation expense, a $0.6 million increase in salaries and wages and a $1.8 million increase in other corporate activities.

Chevron Transaction Expense

During the year ended December 31, 2012, ARP recognized a $7.7 million charge regarding its reconciliation process with Chevron related to certain amounts included within the contractual cash transaction adjustment, which was settled in October 2012 (see “Item 8: Financial Statements and Supplementary Data – Note 3”).

Depreciation, Depletion and Amortization

The following table presents depreciation, depletion and amortization expense that was attributable to us, ARP and APL for each of the respective periods (in thousands):

	Year Ended December 31,
	2013		2012		2011
Depreciation, depletion and amortization:
Atlas Energy	$	3,153	$	—	$	—
Atlas Resource		136,763		52,582		31,938
Atlas Pipeline		168,617		90,029		77,435
Total	$	308,533	$	142,611	$	109,373

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Total depreciation, depletion and amortization increased to $308.5 million for the year ended December 31, 2013 compared with $142.6 million for the comparable prior year period, which was due to an $85.9 million increase in our and ARP’s depletion expense resulting from the acquisitions consummated during 2013 and 2012 and a $78.6 million increase in APL’s depreciation expenses, primarily due to $31.8 million in additional expense related to assets acquired in the Cardinal Acquisition, $26.9 million in additional expense related to assets acquired in the TEAK Acquisition and APL’s expansion capital expenditures incurred subsequent to December 31, 2012. Total depreciation, depletion and amortization increased to $142.6 million for the year ended December 31, 2012 compared with $109.4 million for the comparable prior year period primarily due to a $19.6 million increase in ARP’s depletion expense and a $12.6 million increase in APL’s depreciation expenses, principally associated with APL’s expansion capital expenditures incurred subsequent to December 31, 2011.

The following table presents our and ARP’s depletion expense per Mcfe for our and ARP’s operations for the respective periods (in thousands, except per Mcfe data):

	Years Ended December 31,
	2013			2012			2011
Depletion expense:
Total	$	132,860		$	47,000		$	27,430
Depletion expense as a percentage of gas and oil production revenue		49	%		51	%		41	%
Depletion per Mcfe	$	1.89		$	1.66		$	2.09

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Depletion expense varies from period to period and is directly affected by changes in gas and oil reserve quantities, production levels, product prices and changes in the depletable cost basis of gas and oil properties. Depletion expense was $132.9 million for the year ended December 31, 2013, an increase of $85.9 million compared with $47.0 million for the year ended December 31, 2012. Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 49% for the year ended December 31, 2013, compared with 51% for the year ended December 31, 2012, which was primarily due to an increase in ARP’s oil and natural gas liquids revenues as a result of ARP’s acquisitions in 2012, partially offset by a decrease in realized natural gas prices between the periods. Depletion expense per Mcfe was $1.89 for the year ended December 31, 2013, an increase of $0.23 per Mcfe from $1.66 per Mcfe for the year ended December 31, 2012, which was primarily related to the increase in ARP’s oil and natural gas liquids production between the periods. Depletion expense increased between periods principally due to an overall increase in production volume.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. For the year ended December 31, 2012, depletion expense was $47.0 million, an increase of $19.6 million in comparison with $27.4 million for the year ended December 31, 2011. ARP’s depletion expense of gas and oil properties as a percentage of gas and oil revenues increased to 51% for the year ended December 31, 2012, compared with 41% for the year ended December 31, 2011, which was primarily due to a decrease in realized natural gas prices between the periods. Depletion expense per Mcfe was $1.66 for the year ended December 31, 2012, a decrease of $0.43 per Mcfe from $2.09 for the year ended December 31, 2011, primarily related to lower depletion expense per Mcfe for the assets acquired from the Carrizo and Titan acquisitions and the addition of reserves for new Marcellus Shale wells, which began production during the year ended December 31, 2012. Depletion expense increased between periods principally due to an overall increase in production volume.

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Asset Impairment

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Asset impairment for the year ended December 31, 2013 was $81.9 million as compared with $9.5 million for the comparable prior year period. During the year ended December 31, 2013, APL recognized goodwill impairment loss of $43.9 million related to an impairment of goodwill for its contract gas treating business acquired in December 2012. In addition, ARP recognized $38.0 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and its unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairment related to gas and oil properties within property, plant and equipment on our consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara shales. These impairments by ARP related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices in comparison to their carrying values at December 31, 2013 and 2012. The impairment by APL related to an impairment of goodwill for its contract gas treating business acquired during the Cardinal Acquisition due to lower forecasted cash flows as compared to original forecasts.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Asset impairment for the year ended December 31, 2012 was $9.5 million as compared with $7.0 million for the comparable prior year period. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairment related to gas and oil properties within property, plant and equipment on our consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment on our consolidated balance sheet for its shallow natural gas wells in the Niobrara Shale. These impairments related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair value at December 31, 2012 and 2011. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices in comparison to their carrying values at December 31, 2012 and 2011.

Gain (Loss) on Asset Sales and Disposals

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. During the year ended December 31, 2013 and 2012, gain (loss) on asset sales and disposals were losses of $2.5 million and $7.0 million, respectively. ARP recognized losses on asset sales and disposals of $1.0 million and $7.0 million, respectively. The $1.0 million loss on asset disposal for the year ended December 31, 2013 primarily pertained to a loss as a result of ARP’s sale of its Antrim assets in Michigan. During the year ended December 31, 2012, ARP recognized a $7.0 million loss on asset sales and disposal related to its decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling milestones which needed to be met in order for ARP to maintain ownership of the South Knox processing plant. During 2012, ARP management decided not to continue progressing towards these milestones due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and recorded a loss related to the net book value of the assets during the year ended December 31, 2012. APL’s $1.5 million loss on asset sales and disposal for the year ended December 31, 2013 primarily related to its decision not to pursue a project to lay pipe in an area where acquired rights of way had expired in its SouthOK system.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. During the year ended December 31, 2012, the loss on asset sales and disposal was $7.0 million, compared to a gain of $256.3 million for the year ended December 31, 2011. ARP recognized a $7.0 million loss on asset sales and disposal for the year ended December 31, 2012, which pertained to ARP’s decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling milestones which needed to be met in order for ARP to maintain ownership of the South Knox processing plant. During 2012, ARP management decided not to continue progressing towards these milestones due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and recorded a loss related to the net book value of the assets during the year ended December 31, 2012. During the year ended December 31, 2011 the $256.3 million gain on asset sales and disposal primarily related to APL’s gain on the sale of its 49% non-controlling interest in the Laurel Mountain joint venture which was finalized and recorded in February 2011.

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Interest Expense

The following table presents our interest expense and that which was attributable to ARP and APL for each of the respective periods:

	Years Ended December 31,
	2013		2012		2011
Interest Expense:
Atlas Energy	$	8,620	$	565	$	6,791
Atlas Resource		34,324		4,195		—
Atlas Pipeline		89,637		41,760		31,603
Total	$	132,581	$	46,520	$	38,394

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total interest expense increased to $132.6 million for the year ended December 31, 2013 as compared with $46.5 million for the year ended December 31, 2012. This $86.1 million increase was due to our $8.1 million increase, a $30.1 million increase related to ARP and a $47.9 million increase related to APL. The $8.1 million increase in our interest expense consisted of $6.7 million associated with our term loan facility, a $0.8 million increase in the amortization of deferred financing costs primarily associated with our term loan facility and a $0.6 million increase associated with our credit facility. The $30.1 million increase in ARP’s interest expense consisted of a $20.9 million increase associated with ARP’s issuance of its 7.75% ARP Senior Notes in January 2013, $10.1 million increase associated with the issuance of the 9.25% ARP Senior Notes in July 2013, a $7.8 million increase in the amortization of deferred financing costs and a $3.1 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility and a term loan credit facility which was retired in January 2013, partially offset by interest capitalized on ARP’s ongoing capital projects. The increase in amortization associated with deferred financing costs includes an increase of $5.3 million associated with ARP’s revolving credit facility, $3.2 million of accelerated amortization related to the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base subsequent to its issuance of the 7.75% ARP Senior Notes and $1.2 million associated with ARP’s issuance of senior notes, partially offset by a $1.9 million decrease in amortization expense related to the extension of ARP’s credit facility maturity date from 2016 to 2018. The $47.9 million increase in interest expense for APL was primarily due to $33.9 million in additional interest related to the 5.875% APL Senior Notes; a $26.7 million increase in interest expense associated with the 6.625% APL Senior Notes, and $12.1 million in additional interest related to the 4.75% APL Senior Notes, partially offset by $27.0 million in reduced interest on the 8.75% APL Senior Notes. The increase in the interest on the 5.875% APL Senior Notes and the 4.75% APL Senior Notes is due to their issuance after December 31, 2012. The increase in the interest on the 6.625% APL Senior Notes is due to an additional issuance of $175.0 million in December 2012. The decrease in the interest for the 8.75% APL Senior Notes is due to their redemption In February 2013 (see “APL Senior Notes”).

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Total interest expense increased to $46.5 million for the year ended December 31, 2012 as compared with $38.4 million for the year ended December 31, 2011. This $8.1 million increase was due to a $10.2 million increase related to APL and a $4.2 million increase related to ARP, partially offset by our $6.2 million decrease. Our $6.2 million decrease in interest expense was primarily due to $4.9 million of accelerated amortization of deferred financing costs for our bridge credit facility that was entered into in connection with our closing of the acquisition of the Transferred Business and $0.6 million in interest expense related to borrowings from affiliates during the prior year period. The bridge credit facility was replaced in March 2011 by our previous credit facility, which was transferred to ARP in March 2012. The $4.2 million increase in ARP’s interest expense was primarily associated with outstanding borrowings under the transferred credit facility and amortization of deferred financing costs associated with the credit facility. The $10.2 million increase in interest expense for APL was primarily due to a $10.8 million increase in interest expense associated with the 8.75% APL Senior Notes, a $5.8 million increase in interest expense associated with the 6.625% APL Senior Notes and a $2.7 million increase in interest associated with APL’s revolving credit facility, partially offset by a $6.0 million decrease in interest expense associated with APL’s 8.125% senior unsecured notes due on December 15, 2015 (“8.125% APL Senior Notes”) and a $3.5 million increase in APL’s capitalized interest. The increased interest expense on the 8.75% APL Senior Notes is due to the issuance of additional 8.75% APL Senior Notes in November 2011. The additional interest expense on the 6.625% APL Senior Notes is primarily due to the issuance of $325.0 million 6.625% APL Senior Notes in September 2012. The increased interest expense associated with APL’s revolving credit facility is due to additional borrowings. The lower interest expense on the 8.125% APL Senior Notes is due to the redemption of the 8.125% APL Senior Notes in April 2011 with proceeds from the sale of APL’s 49% non-controlling interest in Laurel Mountain. The increased capitalized interest is due to the increased capital expenditures during the year ended December 31, 2012.

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Loss on Early Extinguishment of Debt

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Loss on early extinguishment of debt for the year ended December 31, 2013 represented $17.5 million premiums paid, an $8.0 million consent payment made with respect to the extinguishment, and a $5.3 million write off of deferred financing costs, partially offset by a $4.2 million recognition of unamortized premium, related to the redemption of the 8.75% APL Senior Notes (see “APL Senior Notes”). There was no loss on early extinguishment of debt for the year ended December 31, 2012.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Loss on early extinguishment of debt of $19.6 million for the year ended December 31, 2011 represents the premium paid for the redemption of the 8.125% APL Senior Notes and APL’s recognition of deferred finance costs related to the redemption.

Loss (Income) Attributable to Non-Controlling Interests

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Loss attributable to non-controlling interests was $153.2 million for the year ended December 31, 2013 as compared with income of $35.5 million for the comparable prior year period. Loss (income) attributable to non-controlling interests includes an allocation of APL’s and ARP’s net income (loss) to non-controlling interest holders. The decrease between the year ended December 31, 2013 and the prior year comparable period was primarily due to the decrease in APL’s net earnings between periods, an increase in ARP’s net loss between periods and a decrease in our ownership interests in ARP and APL during the year ended December 31, 2013.

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011. Income attributable to non-controlling interests was $35.5 million for the year ended December 31, 2012 as compared with income of $257.6 million for the comparable prior year period. (Income) loss attributable to non-controlling interests includes an allocation of APL’s and ARP’s net income to non-controlling interest holders. The decrease between the year ended December 31, 2012 and the prior year comparable period was primarily due to the decrease in APL’s net earnings between periods, as a result of the gain from the sale of its investment in Laurel Mountain in 2011, as well as ARP’s net loss for the year ended December 31, 2012, partially offset by the gain on mark-to-market derivatives in the year ended December 31, 2012.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP and APL, our cash generated from operations and borrowings under our credit facilities (see “Credit Facilities”). Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and quarterly distributions to our common unitholders, which we expect to fund through operating cash flow, cash distributions received and cash on hand. Our subsidiaries’ sources of liquidity are discussed in more detail below.

Atlas Resource. ARP’s primary sources of liquidity are cash generated from operations, capital raised through Drilling Partnerships, and borrowings under its credit facility (see “Credit Facilities”). ARP’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and distributions to its unitholders and us as general partner. In general, ARP expects to fund:

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

• expansion capital expenditures and working capital deficits through cash generated from operations, additional borrowings and capital raised through Drilling Partnerships; and

• debt principal payments through additional borrowings as they become due or by the issuance of additional common units or asset sales.

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

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

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

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

ARP and APL rely on cash flow from operations and their credit facilities to execute their growth strategy and to meet their financial commitments and other short-term liquidity needs. ARP and APL cannot be certain that additional capital will be available to the extent required and on acceptable terms. We and our subsidiaries believe that we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period. However, we and our subsidiaries are subject to business, operational and other risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our, ARP’s and APL’s credit facilities and other borrowings, the issuance of additional limited partner units, the sale of assets and other transactions.

Cash Flows – Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012

Net cash provided by operating activities of $37.6 million for the year ended December 31, 2013 represented an unfavorable movement of $32.7 million from net cash provided by operating activities of $70.3 million for the comparable prior year period. The $32.7 million unfavorable movement was derived principally from a $122.8 million unfavorable movement in distributions paid to non-controlling interests and a $53.5 million unfavorable movement in working capital, partially offset by a $143.6 million favorable movement in net income (loss) excluding non-cash items. The movement in cash distributions to non-controlling interest holders was due principally to increases in cash distributions of ARP and APL. The movement in working capital was due to a $34.2 million unfavorable movement in accounts receivable, prepaid expenses and other and a $19.3 million unfavorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s and APL’s respective capital programs. The non-cash charges which impacted net income primarily included an increase of $165.9 million of depreciation, depletion and amortization, a favorable movement of $72.4 million in asset impairment, a favorable movement of $61.4 million in non-cash (gain)/loss on derivatives, a favorable movement of $26.6 million in loss on early extinguishment of debt, a favorable movement of $14.7 million in compensation expense, a favorable movement of $10.9 million in amortization of deferred financing costs and a favorable movement of $10.3 million in equity and distributions related to unconsolidated subsidiaries, partially offset by an unfavorable movement in net loss from continuing operations of $211.7 million, an unfavorable movement of $4.5 million in (gain)/loss on asset sales and disposal and an unfavorable movement of $2.4 million in APL’s deferred income tax (benefit) expense.

Net cash used in investing activities of $2,496.6 million for the year ended December 31, 2013 represented an unfavorable movement of $846.1 million from net cash used in investing activities of $1,650.5 million for the comparable prior year period. This unfavorable movement was principally due to a $606.6 million increase in cash paid for acquisitions, a $217.3 million unfavorable movement in capital expenditures, a $13.4 million increase in APL’s contributions to its joint ventures (see “Recent Developments”) and a $10.1 million unfavorable movement in other assets. See further discussion of capital expenditures under “Capital Requirements”.

Net cash provided by financing activities of $2,445.7 million for the year ended December 31, 2013 represented a favorable movement of $906.1 million from net cash provided by financing activities of $1,539.6 million for the comparable prior year period. This movement was principally due to a $1,043.1 million favorable movement in net proceeds from the issuance of ARP’s and APL’s long-term debt, a $640.7 million favorable movement in net proceeds from ARP’s and APL’s equity offerings, a $627.4 million favorable movement in our, ARP’s and APL’s borrowings under the respective revolving credit facilities and a $17.0 million favorable movement in contributions from APL’s non-controlling interests, partially offset by a $981.9 million unfavorable movement in repayments of our and our subsidiaries’ revolving and term loan credit facilities, a $365.8 million unfavorable movement in repayments of APL’s long-term debt, a $25.8 million increase in distributions paid to our limited partners, a $25.6 million unfavorable movement in payments of premium on the retirement of APL’s long-term debt and a $23.0 million unfavorable movement in deferred financing costs, distribution equivalent rights and other. The unfavorable movement in deferred financing costs, distribution equivalent rights and other is primarily due to the increase in deferred financing costs associated with our and ARP’s revolving and term loan credit facilities and APL’s revolving credit facility. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the consolidated statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities for us, ARP and APL, which is generally common practice for our and their industries.

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APL’s Class D Preferred Unit distributions paid in kind represented non-cash transactions during the year ended December 31, 2013.

Cash Flows – Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011

Net cash provided by operating activities of $70.3 million for the year ended December 31, 2012 represented an unfavorable movement of $17.9 million from net cash provided by operating activities of $88.2 million for the comparable prior year period. The $17.9 million decrease was derived principally from a $47.6 million unfavorable movement in non-cash gain (loss) on derivatives, a $35.3 million unfavorable movement in distributions paid to non-controlling interests and a $17.6 million unfavorable movement in net income excluding non-cash items, partially offset by an $82.6 million favorable movement in working capital. The non-cash charges which impacted net income included a $263.3 million favorable movement in gain (loss) on asset sales and disposal and a $43.4 million favorable movement in non-cash expenses including loss on early extinguishment of debt, depreciation, depletion and amortization, amortization of deferred financing costs, asset impairment, equity income and distributions from unconsolidated companies, compensation expense and deferred income tax expense, partially offset by a $324.3 million decrease in net income from continuing operations. The decrease in net income from continuing operations was primarily due to a $255.9 million net gain on the sale of APL’s interest in Laurel Mountain in the first quarter of 2011. The movement in cash distributions to non-controlling interest holders was due principally to increases in the cash distributions of ARP and APL. The movement in working capital was principally due to a $70.3 million favorable movement in accounts payable and other current liabilities, primarily due to ARP’s and APL’s respective capital programs and a favorable movement in accounts receivable and other current assets of $12.3 million.

Net cash used in investing activities of $1,650.5 million for the year ended December 31, 2012 represented an unfavorable movement of $1,664.7 million from net cash provided by investing activities of $14.2 million for the comparable prior year period. This unfavorable movement was principally due to a $1,150.1 million unfavorable increase in net cash paid for acquisitions, an unfavorable decrease of $403.7 million in net proceeds from asset disposals, a $208.0 million unfavorable movement in capital expenditures and an unfavorable movement in other assets of $0.1 million, partially offset by a $97.3 million favorable movement in APL’s investments in unconsolidated companies. The net cash paid for acquisitions included cash paid for ARP’s transactions related to the Carrizo, Titan, Equal and DTE acquisitions as well as APL’s Cardinal Acquisition. See further discussion of capital expenditures under “Capital Requirements”.

Net cash provided by financing activities of $1,539.6 million for the year ended December 31, 2012 represented a favorable movement of $1,564.8 million from net cash used in financing activities of $25.2 million for the comparable prior year period. This movement was principally due to a $611.6 million favorable movement in net proceeds from ARP’s equity offerings related to the Carrizo and DTE acquisitions as well as APL’s equity offerings related to the Cardinal Acquisition, a $343.0 million favorable movement in net proceeds from APL’s long-term debt, a $315.0 million favorable movement in APL’s repayment of long-term debt, a $261.1 million favorable movement in ARP’s and APL’s borrowings under their respective revolving credit facilities, a $178.3 million favorable movement in repayments of ARP’s and APL’s respective revolving credit facilities, a $14.3 million favorable movement for payments of premium on the retirement of APL’s long-term debt and an $8.0 million favorable movement due to the redemption of APL’s preferred equity, partially offset by a $111.2 million unfavorable movement in the non-cash transaction adjustment related to the acquisition of the Transferred Business on February 17, 2011, a $34.6 million unfavorable movement in deferred financing costs, distribution equivalent rights and other, primarily due to deferred financing costs paid in association with ARP’s and APL’s additional credit facilities as a result of the acquisitions in 2012, and a $20.7 million unfavorable movement in distributions paid to unitholders. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash used in financing activities in the consolidated combined statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facilities, and payments, which generally occur throughout the period and increase borrowings under the revolving credit facilities, for ARP and APL, which is generally common practice for their industries.

ARP’s July 2012 acquisition of 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 close date) represented a non-cash transaction during the year ended December 31, 2012.

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Capital Requirements

At December 31, 2013, our and our subsidiaries’ capital requirements are as follows:

Natural gas and oil production. The capital requirements of our and ARP’s natural gas and oil production consist primarily of:

• maintenance capital expenditures — oil and gas assets naturally decline in future periods and, as such, we and ARP recognize the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing our and ARP’s distributable cash flow and cash distributions, which we refer to as maintenance capital expenditures. We and ARP calculate the estimate of maintenance capital expenditures by first multiplying forecasted future full year production margin by expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. We and ARP do not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a subset of hypothetical wells we and ARP expect to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including historical costs of similar wells and characteristics of each individual well. First year margin from wells included within maintenance capital are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions; and

• expansion capital expenditures — we and ARP consider expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures – generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.

Gathering and processing. APL’s gathering and processing operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational and environmental regulations. APL’s capital requirements consist primarily of:

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

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

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

	Years Ended December 31,
	2013		2012		2011
Atlas Energy
Maintenance capital expenditures	$	600	$	—	$	—
Expansion capital expenditures		3,343		—		—
Total	$	3,943	$	—	$	—
Atlas Resources
Maintenance capital expenditures	$	31,500	$	10,200	$	9,833
Expansion capital expenditures		232,037		117,026		37,491
Total	$	263,537	$	127,226	$	47,324

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	Years Ended December 31,
	2013		2012		2011
Atlas Pipeline
Maintenance capital expenditures	$	21,919	$	19,021	$	18,247
Expansion capital expenditures		428,641		354,512		227,179
Total	$	450,560	$	373,533	$	245,426
Consolidated
Maintenance capital expenditures	$	54,019	$	29,221	$	28,080
Expansion capital expenditures		664,021		471,538		264,670
Total	$	718,040	$	500,759	$	292,750

Atlas Energy. During the year ended December 31, 2013, our total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs within our Development Subsidiary.

Atlas Resource Partners. During the year ended December 31, 2013, ARP’s $263.5 million of total capital expenditures consisted primarily of $110.8 million for wells drilled exclusively for its own account compared with $27.3 million for the comparable prior year period, $92.3 million of investments in its Drilling Partnerships compared with $54.4 million for the prior year comparable period, $20.9 million of leasehold acquisition costs compared with $35.6 million for the prior year comparable period, and $39.5 million of corporate and other costs compared with $9.9 million for the prior year comparable period, which primarily related to an increase in capitalized interest expense.

During the year ended December 31, 2012, ARP’s $127.2 million of total capital expenditures consisted primarily of $54.4 million of investments in its Drilling Partnerships compared with $28.2 million for the prior year comparable period, $27.3 million for wells drilled exclusively for its own account compared with $0.6 million for the prior year comparable period, $35.6 million of leasehold acquisition costs compared with $9.5 million for the prior year comparable period, and $9.9 million of corporate and other compared with $9.0 million for the prior year comparable period. The increase in investments in ARP’s Drilling Partnerships was principally the result of the cancellation of the Fall 2010 drilling program and the resulting reduction of partnership capital deployed during 2011. Capital expenditures related ARP’s investments in its Drilling Partnerships are generally incurred in the period subsequent to the period in which the funds were raised. The net increase in leasehold acquisition costs principally related to additional Marcellus Shale and Utica Shale acreage acquired through subsequent leasehold acquisitions in the region during the year ended December 31, 2012.

We and ARP continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, we and ARP believe we and it will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we or ARP will be successful in our and its efforts to obtain outside capital.

Atlas Pipeline Partners. APL’s capital expenditures increased to $450.6 million for the year ended December 31, 2013 compared with $373.5 million for the comparable prior year period. The increase was primarily due to the completion of the Driver Plant within WestTX in April 2013 (see “Recent Developments”) and construction costs for the Stonewall Plant within SouthOK, the Silver Oak II Plant within SouthTX and the Edward Plant within WestTX.

APL’s capital expenditures increased to $373.5 million for the year ended December 31, 2012 compared with $245.4 million for the comparable prior year period. The increase was primarily due to major processing facility expansions, compressor upgrades and pipeline projects, including the 60 MMcfd expansion of its SouthOK system, which was placed in service in June 2012; a 200 MMcfd expansion at the WestOK system placed in service in September 2012; and construction of the Driver Plant in the WestTX system.

As of December 31, 2013, we and our subsidiaries are committed to expending approximately $116.4 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

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OFF BALANCE SHEET ARRANGEMENTS

As of December 31, 2013, our off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of $3.6 million, APL’s letters of credit outstanding of $0.1 million and commitments to spend $116.4 million related to capital expenditures.

CASH DISTRIBUTIONS

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

• provide for the proper conduct of our business;

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

• provide funds for distributions to our unitholders for any one or more of the next four quarters.

These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our general partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our distributions to limited partners are not cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

Atlas Resource Partners’ Cash Distribution Policy: ARP’s partnership agreement requires that it distribute 100% of available cash to its common and preferred unitholders and general partner, our wholly-owned subsidiary, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of ARP’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments. We, as ARP’s general partner, are granted discretion under the partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated.

On January 29, 2014, ARP’s Board of Directors approved a modification to its distribution payment practice to a monthly distribution program. This new policy took effect for the month of January 2014, for which its monthly cash distribution will be paid in March 2014. Monthly cash distributions will be paid approximately 45 days following the end of each respective monthly period.

Available cash will generally be distributed: first, 98% to ARP’s Class B preferred unitholders and 2% to us as general partner until there has been distributed to each Class B preferred unit the greater of $0.40 and the distribution payable to common unitholders; second, 98% to ARP’s Class C preferred unitholders and 2% to us as general partner until there has been distributed to each outstanding Class C preferred unit the greater of $0.51 and the distribution payable to common unitholders; thereafter 98% to ARP’s common unitholders and 2% to us as general partner. These distribution percentages are modified to provide for incentive distributions to be paid to us, as ARP’s general partner, if quarterly distributions exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to ARP’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. The incentive distribution rights will entitle us to receive an increasing percentage of cash distributed by ARP as it reaches specified targets.

Atlas Pipeline Partners’ Cash Distribution Policy. APL’s partnership agreement requires that it distribute 100% of available cash, for each calendar quarter, to its common unitholders (subject to the rights of any other class or series of APL security with the right to share in APL’s cash distributions) and to the general partner, our wholly-owned subsidiary, within 45 days following the end of such calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of APL’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

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

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Available cash is initially distributed 98% to APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2.0% of the aggregate amount of cash being distributed. We, as general partner, agreed to allocate up to $3.75 million of incentive distribution rights per quarter back to APL after we receive the initial $7.0 million per quarter of incentive distribution rights.

APL’s Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods beginning with the distribution for the quarter ended June 30, 2013. Thereafter, the Class D Preferred Units will receive distributions in cash, Class D Preferred Units or a combination of cash and Class D Preferred Units, at the discretion of APL. Cash distributions will be paid prior to any other distributions of available cash.

CREDIT FACILITIES

Term Loan Facility

On July 31, 2013, in connection with the Arkoma Acquisition, we entered into a $240.0 million Term Facility. At December 31, 2013, $239.4 million was outstanding under the Term Facility. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at our election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the ABR (as defined in the Term Facility) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by us. We are required to repay principal at the rate of $0.6 million per quarter until the maturity date when the balance is due. At December 31, 2013, the weighted average interest rate on our outstanding Term Facility borrowings was 6.5%.

The Term Facility contains customary covenants, similar to those in our credit facility, that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 Term Facility also contains covenants that require us (i) to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) to enter into swap agreements with respect to the EP Energy and Arkoma acquisitions. At December 31, 2013, we were in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

Our obligations under the Term Facility are secured by first priority security interests in substantially all of our assets, including all of our ownership interests in our material subsidiaries and our ownership interests in APL and ARP. Additionally, our obligations under our Term Facility are guaranteed by our wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and our credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

Revolving Credit Facility

On July 31, 2013, in connection with the Arkoma Acquisition, we amended our credit facility with a syndicate of banks that matures on July 31, 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. At December 31, 2013, no amounts were outstanding under the credit facility. Our obligations under the credit facility are secured by first priority security interests in substantially all of our assets, including all of our ownership interests in our material subsidiaries and our ownership interests in APL and ARP. Additionally, our obligations under the credit facility are guaranteed by our material wholly-owned subsidiaries, (excluding Atlas Pipeline Partners GP, LLC), and may be guaranteed by future subsidiaries. Any of our subsidiaries, other than the subsidiary guarantors, are minor. At our election, interest on borrowings under the credit agreement is determined by reference to either an adjusted LIBOR rate plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by us for LIBOR loans. We are required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility.

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The credit facility contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 facility also contains covenants the same as those in our Term Facility with respect to (i) the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility), and (ii) entry into swap agreements. At December 31, 2013, we were in compliance with these covenants.

The credit agreement is subject to an intercreditor agreement as described above.

At December 31, 2013, we have not guaranteed any of ARP’s or APL’s debt obligations.

Atlas Resource

On July 31, 2013, in connection with the EP Energy Acquisition (see “Recent Developments”), ARP entered into the ARP Credit Agreement, which amended and restated its existing revolving credit facility. The ARP Credit Agreement provides for a senior secured revolving credit facility with a syndicate of banks scheduled to mature in July 2018. ARP’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. On December 6, 2013, ARP entered into the ARP Amendment. The ARP Amendment to the ARP Credit Agreement redetermined the borrowing base to $735.0 million and amended the ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable). The ARP Credit Agreement has a maximum facility amount of $1.5 billion. At December 31, 2013, $419.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $3.6 million was outstanding at December 31, 2013. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any of its non-guarantor subsidiaries are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.75% and 2.75% 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 0.75% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on our consolidated statements of operations.

The ARP Credit Agreement contains customary covenants that limit its ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of December 31, 2013. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended December 31, 2013, March 31, 2014, and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ended September 30, 2014, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

Atlas Pipeline

At December 31, 2013, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $152.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at December 31, 2013 was 4.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at December 31, 2013. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet at December 31, 2013. At December 31, 2013, APL had $477.9 million of remaining committed capacity under its credit facility, subject to covenant limitations.

In April 2013, APL entered into an amendment to its credit agreement, which among other changes, allowed the TEAK Acquisition to be a permitted investment and did not require the joint venture interests acquired in the TEAK Acquisition to be guarantors. The amendment also adjusted certain covenant ratio limits and adjusted the method of calculation in connection with the TEAK acquisition.

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Borrowings under APL’s credit facility are secured by (i) a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK and West TX entities in which APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies.

The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

The events which constitute an event of default under the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner.

ATLAS RESOURCE SECURED HEDGE FACILITY

At December 31, 2013, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility 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 its assets.

In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

SENIOR NOTES

Atlas Resource Senior Notes

On December 31, 2013, ARP had $275.0 million principal outstanding of 7.75% ARP Senior Notes and $250.0 million principal outstanding of 9.25% ARP Senior Notes. On July 30, 2013, ARP issued $250.0 million of 9.25% ARP Senior Notes, due 2021, in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million. The net proceeds were used to partially fund the EP Energy Acquisition (see “Recent Developments”). The 9.25% ARP Senior Notes were presented net of a $1.7 million unamortized discount as of December 31, 2013. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

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In connection with the issuance of the 9.25% ARP Senior Notes, ARP entered into a registration rights agreement, whereby it agreed to (i) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (ii) cause the exchange offer to be consummated by July 30, 2014. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 9.25% ARP Senior Notes. If ARP fails to comply with its obligations to register the 9.25% ARP Senior Notes within the specified time periods, the 9.25% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration statement is declared effective, as applicable.

On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes, due 2021, in a private placement transaction at par. ARP used the net proceeds of approximately $267.6 million to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the year ended December 31, 2013. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. On July 1, 2013, ARP filed a registration statement relating to the exchange offer for the 7.75% ARP Senior Notes and the exchange offer was completed on January 2, 2014.

ARP’s 9.25% Senior Notes and 7.75% Senior Notes are guaranteed by certain of its material subsidiaries. The guarantees under ARP 9.25% Senior Notes and 7.75% Senior Notes are full and unconditional and joint and several, and any of its subsidiaries, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

The indentures governing the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes contain 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.

Atlas Pipeline Senior Notes

At December 31, 2013, APL had $500.0 million principal outstanding of 6.625% APL Senior Notes due 2020, $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) and $400.0 million of 4.75% Senior Notes due 2021 (together with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”).

On May 10, 2013, APL issued $400.0 million of the 4.75% APL Senior Notes in a private placement transaction. The 4.75% APL Senior Notes were issued at par. APL received net proceeds of $391.2 million and utilized the proceeds repay a portion of the outstanding indebtedness under the revolving credit agreement as part of the TEAK Acquisition (see “Recent Developments”). Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% APL Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offering for the 4.75% APL Senior Notes on December 10, 2013 and the exchange offer was completed January 9, 2014.

On February 11, 2013, APL issued $650.0 million of 5.875% Senior Notes, due 2023, in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million and utilized the proceeds to redeem the 8.75% APL Senior Notes and repay a portion of its outstanding indebtedness under its revolving credit facility. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offering for the 5.875% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014.

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On September 28, 2012 and December 20, 2012, APL issued an aggregate of $500.0 million of its 6.625% APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes issued in September 2012 were issued at par while the 6.625% APL Senior Notes issued in December 2012 were issued at a premium of 103.0% of the principal amount for a yield of 6.0%. The 6.625% APL Senior Notes were presented combined with a net $4.6 million unamortized premium as of December 31, 2013. APL received net proceeds in aggregate of $495.0 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on its revolving credit facility and to partially finance the Cardinal Acquisition. Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% APL Senior Notes are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offer for the 6.625% APL Senior Notes on September 18, 2013 and the exchange offer was completed on October 16, 2013. APL consummated an exchange offer for the 6.625% APL Senior Notes and APL incurred a 0.25% interest penalty of $0.1 million from September 23, 2013 through consummation of the exchange offer on October 16, 2013.

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

Indentures governing the APL Senior Notes contain covenants, including limitations on APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all its assets. APL was in compliance with these covenants as of December 31, 2013.

Atlas Pipeline Senior Notes Redemptions

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, excluding unamortized premium, 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% APL Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% APL Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million make-whole premium, $3.7 million accrued interest and $8.0 million consent payment. APL entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture.

On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million 8.75% APL Senior Notes due 2018 not purchased in connection with the tender offer, plus a $6.3 million make-whole premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes due 2023. During the year ended December 31, 2013, APL recognized a loss of $26.6 million within loss on early extinguishment of debt on our consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid, $8.0 million consent payment and a $5.3 million write-off of deferred financing costs, partially offset by $4.2 million of unamortized premium recognized.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following tables summarize our, ARP’s and APL’s contractual obligations at December 31, 2013 (in thousands):

			Payments Due By Period
Contractual cash obligations:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
ATLS total debt	$	239,400	$	1,800	$	5,400	$	4,800	$	227,400
ARP total debt		944,000		—		—		419,000		525,000
APL total debt		1,702,000		—		—		152,000		1,550,000
ATLS interest on total debt		80,278		15,561		31,122		24,599		8,996
ARP interest on total debt		372,246		54,445		108,890		104,695		104,216
APL interest on total debt		759,897		96,317		192,634		183,127		287,819
ARP operating leases		18,790		3,903		5,685		4,062		5,140
APL operating leases		14,861		4,629		7,680		1,587		965
APL capital leases		754		524		230		—		—
Total contractual cash obligations(1)	$	4,132,226	$	177,179	$	351,641	$	893,870	$	2,709,536

⁽¹⁾  Excludes APL’s non-current deferred tax liabilities of $48.2 million due to uncertainty of the timing of future cash flows for such liabilities.

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			Amount of Commitment Expiration Per Period
Other commercial commitments:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
ARP standby letters of credit	$	3,562	$	3,562	$	—	$	—	$	—
APL standby letters of credit		75		75		—		—		—
APL purchase commitments		102,500		102,500		—		—		—
APL throughput contracts		25,091		9,520		7,006		6,157		2,408
ATLS other commercial commitments		2,049		2,049		—		—		—
ARP other commercial commitments(1)		27,840		13,104		12,985		1,388		363
Total commercial commitments	$	161,117	$	130,810	$	19,991	$	7,545	$	2,771

⁽¹⁾  ARP’s other commercial commitments include ARP’s share of drilling and completion commitments and ARP’s throughput contracts, including firm transportation obligations for natural gas as a result of ARP’s EP Energy Acquisition. See “Contractual Revenue Arrangements” for a description of ARP’s firm transportation obligations.

ISSUANCE OF UNITS

We recognize gains on ARP’s and APL’s equity transactions as credits to partners’ capital on our consolidated balance sheets rather than as income on our consolidated statements of operations. These gains represent our portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.

In February 2011, we paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on our common limited partner units’ February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million.

Atlas Energy

In July 2013, in connection with the closing of ARP’s EP Energy Acquisition (see “Recent Developments”), we purchased 3,746,986 of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ended September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, we, as purchaser of the Class C preferred units, received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of ARP common units, at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

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Atlas Resource Partners

Equity Offerings

Issuance of Preferred Units. In July 2013, in connection with ARP’s EP Energy Acquisition, ARP issued 3,749,986 newly created Class C convertible preferred units to us, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at our option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act.

In June 2013, in connection with the EP Energy Acquisition (see “Recent Developments”), ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see “Credit Facilities”).

In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. Sales of common limited partner units, if any, could be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the NYSE, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP paid each of the agents a commission, which in each case was not more than 2.0% of the gross sales price of common limited partner units sold through such agent. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated its equity distribution agreement effective December 27, 2013.

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 of 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 then-existing term loan credit facility.

In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million of ARP’s common units and 3.8 million newly-created ARP convertible Class B preferred units (which have an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments. The Class B preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On September 19, 2012, ARP filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on October 2, 2012.

In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo. To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain of our executives. The common units issued by ARP were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of the registration requirements of the registration rights agreement and on August 28, 2012, the registration statement was declared effective by the SEC.

In connection with the issuance of ARP’s common and preferred units during the years ended December 31, 2013 and 2012, we recorded gains of $27.3 million and $66.6 million within partners’ capital and a corresponding decrease in non-controlling interests on our consolidated balance sheets and consolidated statement of partners’ capital.

ARP Common Unit Distribution

In February 2012, the board of directors of our general partner approved the distribution of approximately 5.24 million ARP common units which were distributed on March 13, 2012 to our unitholders 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.

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Atlas Pipeline Partners

APL Equity Offerings

In April 2013, APL sold 11,845,000 of its common units to the public at a price of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from us, as general partner, of $8.3 million to maintain our 2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see “Recent Developments”).

In May 2013, APL issued $400.0 million of its Class D Preferred Units in a private placement transaction to third party investors, at a negotiated price per unit of $29.75, resulting in net proceeds of $397.7 million. We, as general partner, contributed $8.2 million to maintain our 2.0% general partnership interest in APL, upon the issuance of the Class D Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition.

The Class D Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. APL has the right to convert the Class D Preferred Units, in whole but not in part, beginning one year following their issuance, into common units, subject to customary anti-dilution adjustments. Unless previously converted, all Class D Preferred Units will convert into common units on May 7, 2015. In the event of any liquidation, dissolution or winding up of APL or the sale or other disposition of all or substantially all of the assets of APL, the holders of the Class D Preferred Units are entitled to receive, out of the assets of APL available for distribution to unitholders, prior and in preference to any distribution of any assets of APL to the holders of any other existing or subsequently issued units, an amount equal to $29.75 per Class D Preferred Unit plus any unpaid preferred distributions.

The fair value of APL’s common units on the Commitment Date of the Class D Preferred Units was $36.52 per unit, resulting in an embedded beneficial conversion discount on the Class D Preferred Units of $91.0 million. We recognized the fair value of the Class D Preferred Units with the offsetting intrinsic discount within non-controlling interests on our consolidated balance sheet as of December 31, 2013. The discount will be accreted and recognized by APL as imputed dividends over the term of the Class D Preferred Units as a reduction to APL’s net income attributable to the common limited partners and us, as general partner. For the year ended December 31, 2013, APL recorded $29.5 million within income (loss) attributable to non-controlling interests for the preferred unit imputed dividend effect on our consolidated statements of operations to recognize the accretion of the beneficial conversion discount. APL’s Class D Preferred Units are presented combined with a net $61.5 million unaccreted beneficial conversion discount within non-controlling interests on our consolidated balance sheet at December 31, 2013.

The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of us, as general partner. Cash distributions will be paid to the Class D Preferred Unitholders prior to any other distributions of available cash. Distributions will be determined based upon the cash distribution declared each quarter on APL’s common limited partner units plus a preferred yield premium. Class D Preferred Unit distributions, whether in kind units or in cash, will be accounted for as a reduction to APL’s net income attributable to the common limited partners and us, as general partner. For the year ended December 31, 2013, APL recorded costs related to preferred unit distributions of $23.6 million within income (loss) attributable to non-controlling interests on our consolidated statements of operations. During the years ended December 31, 2013, APL distributed 378,486 Class D Preferred Units to the holders of the Class D Preferred Units as a distribution in kind.

Upon the issuance of the Class D Preferred Units, APL entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class D Preferred Units. APL agreed to use its commercially reasonable efforts to have the registration statement declared effective within 180 days of the date of conversion.

APL had an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL offered and sold common units for $150.0 million. Sales were made at market prices prevailing at the time of the sale. During the years ended December 31, 2013 and 2012, APL issued 3,895,679 and 275,429 common units, respectively, under the equity distribution program for net proceeds of $137.8 million and $8.7 million, respectively, net of $2.8 million and $0.2 million, respectively, in commissions paid to Citigroup and other offering costs. APL also received a capital contribution from us of $2.9 million and $0.2 million during the years ended December 31, 2013 and 2012, respectively, to maintain our 2.0% general partner interest in APL. APL utilized the net proceeds from the common unit offering for general partnership purposes. As of December 31, 2013, APL utilized the full capacity under the equity distribution program.

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In December 2012, 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 a unit purchase agreement to issue $200.0 million of newly created Class D convertible preferred units in a private placement to third party investors 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%, or $4.0 million.

In connection with the issuance of APL’s common units during the years ended December 31, 2013 and 2012, we recorded an $11.9 million and $7.9 million gain within partner’s capital and a corresponding decrease in non-controlling interests on our consolidated statement of partners’ capital during the years ended December 31, 2013 and 2012, respectively.

ENVIRONMENTAL REGULATION

Our and our subsidiaries’ operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety (see “Item 1: Business - Environmental Matters and Regulation”). We believe that our and our subsidiaries’ operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; imposition of remedial requirements; issuance of injunctions affecting our operations; or other measures. We and our subsidiaries maintained and expect to continue to maintain environmental compliance programs. However, risks of accidental leaks or spills are associated with our and our subsidiaries’ operations. There can be no assurance that we and our subsidiaries will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our and our subsidiaries’ business. Moreover, it is possible other developments, such as increasingly strict federal, state and local environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us and our subsidiaries.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on activities, such as emissions of greenhouse gases and other pollutants; generation and disposal of wastes, including wastes that may have naturally occurring radioactivity; and use, storage and handling of chemical substances that may impact human health, the environment and/or threatened or endangered species. Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and our subsidiaries and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We and our subsidiaries will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we and our subsidiaries will identify and properly anticipate each such change, or that our and our subsidiaries’ efforts will prevent material costs, if any, from rising.

CHANGES IN PRICES AND INFLATION

Our and our subsidiaries’ revenues, the value of our and our subsidiaries’ assets, our and our subsidiaries’ ability to obtain bank loans or additional capital on attractive terms, and ARP’s ability to finance its drilling activities through its Drilling Partnerships, have been and will continue to be affected by changes in natural gas and oil market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our and our subsidiaries’ ability to control or predict.

Inflation affects the operating expenses of our and our subsidiaries’ operations. Inflationary trends may occur if commodity prices were to increase, since such an increase may cause the demand for energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services. Increases in those expenses are not necessarily offset by increases in revenues and fees that our and our subsidiaries’ operations are able to charge. While we anticipate that inflation will affect our and our subsidiaries’ future operating costs, we cannot predict the timing or amounts of any such effects.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated financial statements included in “Item 8: Financial Statements and Supplementary Data – Note 2” included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets and Goodwill

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

Long-lived assets, other than goodwill and intangibles with infinite lives, generally consist of natural gas and oil properties and pipeline, processing and compression facilities and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset, other than goodwill and intangibles with infinite lives, is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in “General Trends and Outlook” within this section, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to gas and oil properties within property, plant and equipment, net on our consolidated balance sheet for shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to gas and oil properties within property, plant and equipment, net on our consolidated balance sheet for shallow natural gas wells in the Niobrara Shale. These impairments related to the carrying amount of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, 2012 and 2011 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Item 1A: Risk Factors” in this report.

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

There were no goodwill impairments recognized by ARP during the years ended December 31, 2013, 2012 and 2011. During the year ended December 31, 2013, APL recorded goodwill impairment loss of $43.9 million related to an impairment of goodwill for its contract gas treating business acquired during the Cardinal Acquisition due to lower forecasted cash flows as compared to original forecasts. There were no goodwill impairments recognized by APL during the years ended December 31, 2012 and 2011.

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Fair Value of Financial Instruments

We and our subsidiaries have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

We use a fair value methodology to value the assets and liabilities for our and our subsidiaries’ outstanding derivative contracts. Our and our subsidiaries’ commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as Level 3 fair value measurements. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institution and therefore are defined as Level 3 fair value measurements.

Of the $14.9 million and $51.3 million of net derivative assets at December 31, 2013 and 2012, respectively, APL had net derivative liabilities of $11.8 million and net derivative assets of $23.1 million at December 31, 2013 and 2012, respectively, that were classified as Level 3 fair value measurements which rely on subjective forward developed price curves. Holding all other variables constant, a 10% change in the price APL utilized in calculating the fair value of derivatives at December 31, 2013 would have resulted in a $1.2 million non-cash change, excluding the effect of non-controlling interests, to net income (loss) for the year ended December 31, 2013.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations that are defined as Level 3. Estimates of the fair value of asset retirement obligations are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

During the year ended December 31, 2013, we completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2013, APL completed the TEAK Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, certain proved reserves and associated assets from Titan, Equal and DTE, while APL completed the Cardinal Acquisition. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under our and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of our and its gas and oil wells (see “Item 8: Financial Statements and Supplementary Data—Note 8”). These inputs require significant judgments and estimates by our, ARP’s and APL’s management at the time of the valuation and are subject to change.

Reserve Estimates

Estimates of proved natural gas, oil and natural gas liquids reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. We and ARP engaged Wright and Company, Inc., an independent third-party reserve engineer, to prepare a report of our and ARP’s proved reserves (see “Item 2: Properties”).

110

Any significant variance in the assumptions utilized in the calculation of reserve estimates could materially affect the estimated quantity of reserves. As a result, estimates of proved natural gas, oil and natural gas liquids reserves are inherently imprecise. Actual future production, natural gas, oil and natural gas liquids prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and natural gas liquids reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our and ARP’s ability to pay amounts due under our and ARP’s credit facilities or cause a reduction in our or ARP’s credit facilities. In addition, proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas, oil and natural gas liquids prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

Asset Retirement Obligations

We and our subsidiaries estimate the cost of future dismantlement, restoration, reclamation and abandonment of our operating assets.

We and ARP recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. We and ARP also recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. We and ARP also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Since there are many variables in estimating asset retirement obligations, we and ARP attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. Neither we nor ARP have any assets legally restricted for purposes of settling asset retirement obligations. Except for gas and oil properties, there are no other material retirement obligations associated with our and ARP’s tangible long lived assets.

Atlas Pipeline

APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations owned by APL and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, APL was not able to reasonably measure the fair value of the asset retirement obligation as of December 31, 2013 or 2012 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

ITEM 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

111

General

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

We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We and our subsidiaries manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2013. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

Current market conditions elevate our and our subsidiaries’ concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties related to our and our subsidiaries’ commodity derivative contracts are banking institutions or their affiliates, who also participate in our, ARP’s and APL’s revolving credit facilities. The creditworthiness of our and our subsidiaries’ counterparties is constantly monitored, and we and our subsidiaries currently believe them to be financially viable. We and our subsidiaries are not aware of any inability on the part of their counterparties to perform under their contracts and believe our and our subsidiaries’ exposure to non-performance is remote.

Interest Rate Risk. At December 31, 2013, we had $239.4 million of outstanding borrowings under our term loan facility, ARP had $419.0 million of outstanding borrowings under its revolving credit facility and APL had $152.0 million of outstanding borrowings under its senior secured revolving credit facility. At December 31, 2013, we had no borrowings outstanding under our revolving credit facility. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our consolidated interest expense for the twelve-month period ending December 31, 2014 by $8.1 million, excluding the effect of non-controlling interests.

Commodity Price Risk. Our and our subsidiaries’ market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our and our subsidiaries’ financial results. To limit the exposure to changing commodity prices, we and our subsidiaries use financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, we and our subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the twelve-month period ending December 31, 2014 of approximately $6.8 million, net of non-controlling interests.

Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years. To limit our and our subsidiaries’ exposure to changing natural gas, oil and natural gas liquids prices, we enter into natural gas and oil swap, put option and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter (“OTC”) futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. OTC contracts are generally financial contracts which are settled with financial payments or receipts and generally do not require delivery of physical hydrocarbons. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index. These contracts have qualified and been designated as cash flow hedges and been recorded at their fair values.

112

At December 31, 2013, we had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)(1)		(per MMBtu)(1)
2014		2,760,000	$	4.177
2015		2,280,000	$	4.302
2016		1,440,000	$	4.433
2017		1,200,000	$	4.590
2018		420,000	$	4.797

(1) “MMBtu” represents million British Thermal Units.

At December 31, 2013, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(MMBtu)(1)		(per MMBtu)(1)
2014		60,153,000	$	4.152
2015		51,474,500	$	4.236
2016		45,746,300	$	4.311
2017		24,840,000	$	4.532
2018		3,960,000	$	4.716

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(MMBtu)(1)		(per MMBtu)(1)
2014	Puts purchased		3,840,000	$	4.221
2014	Calls sold		3,840,000	$	5.120
2015	Puts purchased		3,480,000	$	4.234
2015	Calls sold		3,480,000	$	5.129

Natural Gas Put Options – Drilling Partnerships

Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price
		(MMBtu)(1)		(per MMBtu)(1)
2014	Puts purchased		1,800,000	$	3.800
2015	Puts purchased		1,440,000	$	4.000
2016	Puts purchased		1,440,000	$	4.150

Natural Gas Liquids Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)(1)		(per Bbl)(1)
2014		105,000	$	91.571
2015		96,000	$	88.550
2016		84,000	$	85.651
2017		60,000	$	83.780

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Natural Gas Liquids Ethane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2014		2,520,000	$	0.303

Natural Gas Liquids Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2014		12,348,000	$	0.996
2015		8,064,000	$	1.016

Natural Gas Liquids Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2014		1,512,000	$	1.308
2015		1,512,000	$	1.248

Natural Gas Liquids Iso Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Gal)(1)		(per Gal)(1)
2014		1,512,000	$	1.323
2015		1,512,000	$	1.263

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price
	(Bbl)(1)		(per Bbl)(1)
2014		552,000	$	92.668
2015		567,000	$	88.144
2016		225,000	$	85.523
2017		132,000	$	83.305

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap
		(Bbl)(1)		(per Bbl)(1)
2014	Puts purchased		41,160	$	84.169
2014	Calls sold		41,160	$	113.308
2015	Puts purchased		29,250	$	83.846
2015	Calls sold		29,250	$	110.654

⁽¹⁾  “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

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As of December 31, 2013, APL had the following commodity derivatives:

Fixed Price Swaps

Production Period	Purchased/ Sold	Commodity	Volumes(1)		Average Fixed Price
Natural Gas
2014	Sold	Natural Gas		12,900,000	$	3.984
2015	Sold	Natural Gas		16,960,000	$	4.225
2016	Sold	Natural Gas		6,150,000	$	4.302
Natural Gas Liquids
2014	Sold	Natural Gas Liquids		82,404,000	$	1.180
2015	Sold	Natural Gas Liquids		41,454,000	$	1.078
2016	Sold	Natural Gas Liquids		6,300,000	$	1.034
Crude Oil
2014	Sold	Crude Oil		312,000	$	92.368
2015	Sold	Crude Oil		60,000	$	85.130

Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes(1)		Average Strike Price
Natural Gas
2014	Purchased	Put	Natural Gas		600,000	$	4.125
Natural Gas Liquids
2014	Purchased	Put	Natural Gas Liquids		4,410,000	$	1.001
2015	Purchased	Put	Natural Gas Liquids		1,890,000	$	0.901
Crude Oil
2014	Purchased	Put	Crude Oil		448,500	$	94.685
2015	Purchased	Put	Crude Oil		270,000	$	89.175

⁽¹⁾  Volumes for natural gas are stated in MMBtu’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels.

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ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Energy, L.P. (a Delaware limited partnership) and subsidiaries (collectively the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in partners’ capital, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Energy, L.P. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2014 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 28, 2014

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	23,501	$	36,780
Accounts receivable		279,464		196,249
Current portion of derivative asset		2,066		35,351
Subscriptions receivable		47,692		55,357
Prepaid expenses and other		27,612		45,255
Total current assets		380,335		368,992
Property, plant and equipment, net		4,910,875		3,502,609
Intangible assets, net		697,234		200,680
Investment in joint ventures		248,301		86,002
Goodwill, net		400,356		351,069
Long-term derivative asset		30,868		16,840
Long-term derivative receivable from Drilling Partnerships		863		—
Other assets, net		123,809		71,002
	$	6,792,641	$	4,597,194
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	2,924	$	10,835
Accounts payable		149,279		119,028
Liabilities associated with drilling contracts		49,377		67,293
Accrued producer liabilities		152,309		109,725
Current portion of derivative liability		17,630		—
Current portion of derivative payable to Drilling Partnerships		2,676		11,293
Accrued interest		47,402		11,556
Accrued well drilling and completion costs		40,899		47,637
Accrued liabilities		84,759		103,291
Total current liabilities		547,255		480,658
Long-term debt, less current portion		2,886,120		1,529,508
Long-term derivative liability		387		888
Long-term derivative payable to Drilling Partnerships		—		2,429
Deferred income taxes, net		33,290		30,258
Asset retirement obligations and other		102,713		73,605
Commitments and contingencies
Partners’ Capital:
Common limited partners’ interests		361,511		456,171
Accumulated other comprehensive income		10,338		9,699
		371,849		465,870
Non-controlling interests		2,851,027		2,013,978
Total partners’ capital		3,222,876		2,479,848
	$	6,792,641	$	4,597,194

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Years Ended December 31,
	2013			2012			2011
Revenues:
Gas and oil production	$	273,906		$	92,901		$	66,979
Well construction and completion		167,883			131,496			135,283
Gathering and processing		2,139,694			1,219,815			1,329,418
Administration and oversight		12,277			11,810			7,741
Well services		19,492			20,041			19,803
Gain (loss) on mark-to-market derivatives		(28,764	)		31,940			(20,453	)
Other, net		(6,973	)		13,440			31,803
Total revenues		2,577,515			1,521,443			1,570,574
Costs and expenses:
Gas and oil production		100,178			26,624			17,100
Well construction and completion		145,985			114,079			115,630
Gathering and processing		1,802,618			1,009,100			1,123,051
Well services		9,515			9,280			8,738
General and administrative		197,976			165,777			80,584
Chevron transaction expense		—			7,670			—
Depreciation, depletion and amortization		308,533			142,611			109,373
Asset impairment		81,880			9,507			6,995
Total costs and expenses		2,646,685			1,484,648			1,461,471
Operating income (loss)		(69,170	)		36,795			109,103
Gain (loss) on asset sales and disposal		(2,506	)		(6,980	)		256,292
Interest expense		(132,581	)		(46,520	)		(38,394	)
Loss on early extinguishment of debt		(26,601	)		—			(19,574	)
Net income (loss) from continuing operations before tax		(230,858	)		(16,705	)		307,427
Income tax (benefit) expense		(2,260	)		176			—
Net income (loss) from continuing operations		(228,598	)		(16,881	)		307,427
Discontinued operations:
Loss from discontinued operations		—			—			(81	)
Net income (loss)		(228,598	)		(16,881	)		307,346
Loss (income) attributable to non-controlling interests		153,231			(35,532	)		(257,643	)
Net income (loss) after non-controlling interests		(75,367	)		(52,413	)		49,703
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of the acquisition (see Note 2))		—			—			(4,711	)
Net income (loss) attributable to common limited partners	$	(75,367	)	$	(52,413	)	$	44,992
Net income (loss) attributable to common limited partners per unit - basic:
Income (loss) from continuing operations attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.91
Loss from discontinued operations attributable to common limited partners		—			—			—
Net income (loss) attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.91
Net income (loss) attributable to common limited partners per unit - diluted:
Income (loss) from continuing operations attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.88
Loss from discontinued operations attributable to common limited partners		—			—			—
Net income (loss) attributable to common limited partners	$	(1.47	)	$	(1.02	)	$	0.88
Weighted average common limited partner units outstanding:
Basic		51,387			51,327			48,235
Diluted		51,387			51,327			49,676
Income (loss) attributable to common limited partners:
Income (loss) from continuing operations	$	(75,367	)	$	(52,413	)	$	45,002
Loss from discontinued operations		—			—			(10	)
Net income (loss) attributable to common limited partners	$	(75,367	)	$	(52,413	)	$	44,992

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

	Years Ended December 31,
	2013			2012			2011
Net income (loss)	$	(228,598	)	$	(16,881	)	$	307,346
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		15,828			10,921			35,156
Less: reclassifiÊtion adjustment for realized gains of cash flow hedges in net income (loss)		(10,216	)		(14,891	)		(3,708	)
Total other comprehensive income (loss)		5,612			(3,970	)		31,448
Comprehensive income (loss)		(222,986	)		(20,851	)		338,794
Comprehensive (income) loss attributable to non-controlling interests		148,258			(51,239	)		(263,597	)
Income not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of the acquisition (see Note 2))		—			—			(4,711	)
Comprehensive income (loss) attributable to common limited partners	$	(74,728	)	$	(72,090	)	$	70,486

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands, except unit data)

	Common Limited Partners’ Capital					Accumulated Other Comprehensive			Non-Controlling			Total Partners’
	Units		Amount			Income			Interest			Capital
Balance at January 1, 2011		27,835,254	$	413,054		$	3,882		$	989,187		$	1,406,123
Issuance of common limited partner units related to the acquisition of the Transferred Business (see Note 3)		23,379,384		372,200			—			—			372,200
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)		—		(261,042	)		—			—			(261,042	)
Atlas Pipeline Partners, L.P. distributions to non-controlling interests		—		—			—			(87,094	)		(87,094	)
Unissued common units under incentive plans		—		13,101			—			3,003			16,104
Issuance of units under incentive plans		63,724		167			—			468			635
Distributions paid to common limited partners		—		(31,164	)		—			—			(31,164	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(1,020	)		—			(764	)		(1,784	)
Atlas Pipeline Partners, L.P. preferred unit distribution		—		—			—			(629	)		(629	)
Atlas Pipeline Partners, L.P. preferred unit redemption		—		—			—			(8,000	)		(8,000	)
Other comprehensive income		—		—			25,494			5,892			31,386
Income 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 (see Note 2))		—		4,711			—			—			4,711
Net income		—		44,992			—			257,643			302,635
Balance at December 31, 2011		51,278,362	$	554,999		$	29,376		$	1,159,706		$	1,744,081
Distribution of Atlas Resource Partners, L.P. units		—		(84,892	)		—			84,892			—
Distributions to non-controlling interests		—		—			—			(120,456	)		(120,456	)
Unissued common units under incentive plan		—		17,579			—			22,218			39,797
Issuance of units under incentive plans		87,220		258			—			128			386
Non-controlling interests’ capital contribution		—		—			—			804,768			804,768
Atlas Pipeline Partners L.P. purchase price allocation		—		—			—			89,440			89,440
Atlas Pipeline Partners L.P. purchase and retirement of treasury stock		—		—			—			(695	)		(695	)
Distributions paid to common limited partners		—		(51,837	)		—			—			(51,837	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(2,070	)		—			(2,715	)		(4,785	)
Gain on sale of subsidiary unit issuances		—		74,547			—			(74,547	)		—
Other comprehensive income (loss)		—		—			(19,677	)		15,707			(3,970	)
Net income (loss)		—		(52,413	)		—			35,532			(16,881	)
Balance at December 31, 2012		51,365,582	$	456,171		$	9,699		$	2,013,978		$	2,479,848
Distributions to non-controlling interests		—		—			—			(240,982	)		(240,982	)
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests		—		—			—			17,021			17,021
Unissued common units under incentive plan		—		22,465			—			31,614			54,079
Issuance of units under incentive plans		47,982		67			—			159			226
Distributions paid to common limited partners		—		(77,598	)		—			—			(77,598	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(3,473	)		—			(5,031	)		(8,504	)
Atlas Pipeline Partners, L.P. purchase price allocation		—		—			—			(30,535	)		(30,535	)
Gain on sale of subsidiary unit issuances		—		39,246			—			(39,246	)		—
Non-controlling interests’ capital contributions		—		—			—			1,252,307			1,252,307
Other comprehensive income		—		—			639			4,973			5,612
Net loss		—		(75,367	)		—			(153,231	)		(228,598	)
Balance at December 31, 2013		51,413,564	$	361,511		$	10,338		$	2,851,027		$	3,222,876

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(228,598	)	$	(16,881	)	$	307,346
Loss from discontinued operations		—			—			(81	)
Income (loss) from continuing operations		(228,598	)		(16,881	)		307,427
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		308,533			142,611			109,373
Asset impairment		81,880			9,507			6,995
Amortization of deferred financing costs		17,649			6,720			5,105
Non-cash (gain) loss on derivative value, net		30,089			(31,335	)		16,312
Non-cash compensation expense		55,008			40,300			16,104
(Gain) loss on asset sales and disposal		2,506			6,980			(256,292	)
Deferred income tax (benefit) expense		(2,260	)		176			—
Loss on early extinguishment of debt		26,601			—			19,574
Distributions paid to non-controlling interests		(246,013	)		(123,171	)		(87,857	)
Equity income in unconsolidated companies		2,142			(7,863	)		(21,582	)
Distributions received from unconsolidated companies		8,422			8,131			20,643
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(88,124	)		(53,973	)		(66,251	)
Accounts payable and accrued liabilities		69,773			89,074			18,725
Net cash provided by continuing operating activities		37,608			70,276			88,276
Net cash used in discontinued operating activities		—			—			(81	)
Net cash provided by operating activities		37,608			70,276			88,195
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(718,040	)		(500,759	)		(292,750	)
Net cash paid for acquisitions		(1,756,744	)		(1,150,150	)		—
Investment in unconsolidated companies		(13,366	)		—			(97,250	)
Net proceeds from asset disposals		1,236			—			403,668
Other		(9,693	)		404			491
Net cash provided by (used in) investing activities		(2,496,607	)		(1,650,505	)		14,159
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		2,474,000			1,846,599			1,585,500
Repayments under credit facilities		(2,317,025	)		(1,335,174	)		(1,513,500	)
Net proceeds from issuance of subsidiary long-term debt		1,538,488			495,374			152,366
Repayments of long-term debt		(365,822	)		—			(314,972	)
Net proceeds from subsidiary equity offerings		1,252,307			611,606			—
Redemption of Atlas Pipeline Partners, L.P. preferred units		—			—			(8,000	)
Distributions paid to unitholders		(77,598	)		(51,837	)		(31,164	)
Atlas Pipeline Partners, L.P. contributions received from non-controlling interests		17,021			—			—
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt		(25,581	)		—			(14,342	)
Net transaction adjustment related to the acquisition of the Transferred Business (see Note 3)		—			—			111,158
Deferred financing costs, distribution equivalent rights and other		(50,070	)		(26,935	)		7,729
Net cash provided by (used in) financing activities		2,445,720			1,539,633			(25,225	)
Net change in cash and cash equivalents		(13,279	)		(40,596	)		77,129
Cash and cash equivalents, beginning of year		36,780			77,376			247
Cash and cash equivalents, end of year	$	23,501		$	36,780		$	77,376

See accompanying notes to consolidated financial statements.

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ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BASIS OF PRESENTATION

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership (NYSE: ATLS). At December 31, 2013, the Partnership’s operations primarily consisted of its ownership interests in the following:

• 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 (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. At December 31, 2013, the Partnership owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 36.9% limited partner interest (20,962,485 common and 3,749,986 Class C preferred limited partner units) 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 gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States and in the Eagle Ford Shale play in south Texas; and NGL transportation services in the southwestern region of the United States. At December 31, 2013, the Partnership owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 6.1% limited partner interest in APL;

• Lightfoot Capital Partners, L.P. (“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, 2013, the Partnership had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot (see Note 7); and

• Certain natural gas and oil producing assets.

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

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at December 31, 2013, except for ARP, APL and the Partnership’s new subsidiary partnership (the “Development Subsidiary”), which are controlled by the Partnership. Due to the structure of the Partnership’s ownership interests in ARP, APL and the Development Subsidiary, the Partnership consolidates the financial statements of ARP, APL and the Development Subsidiary into its consolidated financial statements rather than present its ownership interest as equity investments. As such, the non-controlling interests in ARP, APL and the Development Subsidiary are reflected as (income) loss attributable to non-controlling interests in its consolidated statements of operations and as a component of partners’ capital on its consolidated balance sheets. All material intercompany transactions have been eliminated. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

During the year ended December 31, 2013, the Partnership formed its Development Subsidiary, a new subsidiary partnership to conduct natural gas and oil operations initially in the mid-continent region of the United States, specifically in the Marble Falls formation in the Fort Worth Basin and Mississippi Lime area of the Anadarko basin in Oklahoma. At December 31, 2013, the Partnership owned an 18.3% limited partner interest in its Development Subsidiary and 83.1% of its outstanding general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions.

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On February 17, 2011, the Partnership acquired certain producing natural gas and oil properties, the partnership management business, and other assets (the “Transferred Business”) from Atlas Energy, Inc. (“AEI”), the former owner of the Partnership’s general partner (see Note 3). Management of the Partnership 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 the Partnership’s consolidated balance sheets. 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 the Partnership’s consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to 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, the Partnership reflected the impact of the acquisition of the Transferred Business on its consolidated 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 its consolidated financial statements for any date prior to February 17, 2011, the date of acquisition, to reflect its results on a consolidated basis with the results of the Transferred Business as of or at the beginning of the respective period; and

• Adjusted the presentation of the Partnership’s consolidated statements of operations for the year ended December 31, 2011 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.

In accordance with established practice in the oil and gas industry, the Partnership’s consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.

The Partnership’s consolidated financial statements include APL’s 95% ownership interest in joint ventures, which individually own a 100% ownership interest in the WestOK natural gas gathering system and processing plants and a 72.8% undivided interest in the WestTX natural gas gathering system and processing plants. These joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which was reflected within non-controlling interests on the Partnership’s consolidated balance sheets.

The Partnership’s consolidated financial statements also include APL’s 60% interest in Centrahoma Processing LLC (“Centrahoma”), which was acquired on December 20, 2012 as part of the acquisition of assets from Cardinal Midstream, LLC (the “Cardinal Acquisition”) (see Note 4). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE).

APL consolidates 100% of these joint ventures and the non-controlling interest in the joint venture is reflected on the Partnership’s consolidated statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint venture as a component of partners’ capital on its consolidated balance sheets (see Note 5).

123

The West TX joint venture has a 72.8% undivided joint venture interest in the WestTX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD). Due to the WestTX system’s status as an undivided joint venture, the WestTX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the WestTX system.

Use of Estimates

The preparation of the Partnership’s consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of AEI in order to derive the historical financial statements of the Transferred Business prior to February 17, 2011, the date of acquisition. Actual results could differ from those estimates.

Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

Accounts receivable on the consolidated balance sheets consist primarily of the trade accounts receivable associated with the Partnership and its subsidiaries. In evaluating the realizability of its accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of customers’ credit information. The Partnership and its subsidiaries extend credit on sales on an unsecured basis to many of its customers. At December 31, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

Inventory

The Partnership had $19.7 million and $13.5 million of inventory at December 31, 2013 and 2012, respectively, which were included within prepaid expenses and other current assets on its consolidated balance sheets. The Partnership and its subsidiaries value inventories at the lower of cost or market. ARP’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. APL’s crude oil and refined product inventory costs consist of APL’s natural gas liquids line fill, which represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then current market price.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations. APL follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering, processing and treating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and treating components, is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s consolidated statements of operations.

124

The Partnership and ARP follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.

The Partnership and ARP’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Impairment of Long-Lived Assets

The Partnership and its subsidiaries review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated 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 the Partnership’s and ARP’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership and ARP estimate prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP their proportionate share of these expenses plus a profit margin. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership and ARP cannot predict what reserve revisions may be required in future periods.

125

ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partner agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Partnership and ARP will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. During the year ended December 31, 2013, ARP recognized $13.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet primarily for its unproved acreage in the Chattanooga and New Albany shales. There were no impairments of unproved gas and oil properties recorded on the Partnership’s consolidated statements of operations for the years ended December 31, 2012 and 2011.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, ARP recognized $24.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for its shallow natural gas wells in the New Albany Shale. During the year ended December 31, 2012, the Partnership recognized $9.5 million of asset impairments related to ARP’s gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, the Partnership recognized $7.0 million of asset impairment related to ARP’s gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the Niobrara Shale. These impairments related to the carrying amounts of these gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, 2012 and 2011 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Capitalized Interest

ARP and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP and APL in the aggregate were 5.9%, 5.8% and 7.0% for the years ended December 31, 2013, 2012 and 2011, respectively. The aggregate amounts of interest capitalized by ARP and APL were $21.7 million, $10.8 million and $5.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Intangible Assets

Customer contracts and relationships. APL amortizes intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions including the Cardinal and TEAK acquisitions (see Note 4), over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess of or less than the average length. As part of the acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) in 2013 (the “TEAK Acquisition”) (see Note 4), APL recognized $450.0 million of customer relationships with an estimated useful life of 13 years. As part of the Cardinal Acquisition, APL recognized $232.3 million of customer relationships with estimated useful lives of 8 to 15 years, and $0.4 million of customer contracts with an estimated useful life of 2 years.

126

Partnership management and operating contracts. ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at December 31, 2013 and 2012 (in thousands):

	December 31,						Estimated Useful Lives In Years
	2013			2012
Gross Carrying Amount:
Customer contracts and relationships	$	891,072		$	325,246		2–15
Partnership management and operating contracts		14,344			14,344		13
	$	905,416		$	339,590
Accumulated Amortization:
Customer contracts and relationships	$	(194,801	)	$	(125,886	)
Partnership management and operating contracts		(13,381	)		(13,024	)
	$	(208,182	)	$	(138,910	)
Net Carrying Amount:
Customer contracts and relationships	$	696,271		$	199,360
Partnership management and operating contracts		963			1,320
	$	697,234		$	200,680

Amortization expense on intangible assets was $69.3 million, $24.0 million and $23.8 million for the years ended December 31, 2013, 2012 and 2011 respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $78.3 million; 2015 - $73.0 million; 2016 - $72.9 million; 2017 - $66.9 million; and 2018 - $58.4 million.

Goodwill

At December 31, 2013, the Partnership had $400.4 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $368.6 million related to APL’s Cardinal and TEAK acquisitions (see Note 4). At December 31, 2012, the Partnership had $351.1 million of goodwill, which consisted of $31.8 million related to prior ARP consummated acquisitions and $319.3 million related to APL’s acquisitions during the year ended December 31, 2012, of which $310.9 million related to the Cardinal Acquisition (see Note 4). The change in goodwill is primarily related to an addition of $188.9 million of goodwill from the TEAK Acquisition, partially offset by a $96.7 million reduction in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the Cardinal Acquisition and a $43.9 million reduction in goodwill related to an impairment of goodwill recorded for APL’s Cardinal Acquisition. The goodwill related to APL’s Cardinal Acquisition is a result of the strategic industry position and potential future synergies. The goodwill related to the TEAK Acquisition is a result of the strategic industry position.

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ARP and APL test goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s and APL’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and the available market data of the respective industry group. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s and APL’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP and APL also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s and APL’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s and APL’s management will continue to evaluate goodwill at least annually or when impairment indicators arise.

Subsequent to recording the final estimated fair values of the assets acquired and liabilities assumed in the Cardinal Acquisition, APL determined that a portion of goodwill recorded in connection with the acquisition was impaired. APL performed a qualitative assessment for goodwill impairment of APL’s gas treating reporting unit. The assessment indicated the potential for goodwill to be impaired due to lower forecasted cash flows as compared to original forecasts. Using a combination of discounted cash flow models and market multiples for similar businesses, APL measured the amount of goodwill impairment to be $43.9 million, which was recorded within asset impairment on the Partnership’s consolidated statement of operations for the year ended December 31, 2013.

The valuation assessment for the TEAK acquisition has not been completed as of December 31, 2013. However, APL performed a review for triggering events for the goodwill recorded for the TEAK acquisition on December 31, 2013 and noted no impairment indicators. A full impairment evaluation of the goodwill recorded for the TEAK acquisition will be performed during 2014 once final purchase price adjustments have been made and the measurement period is closed. As a result, the estimated goodwill allocation as of December 31, 2013 is subject to change and may be material. There were no changes in the carrying amount of ARP’s goodwill for the years ended December 31, 2013 and 2012, and no changes to APL’s carrying amount of goodwill for the year ended December 31, 2012.

During the years ended December 31, 2013, 2012 and 2011, no impairment indicators arose and no goodwill impairments were recognized for ARP by the Partnership. During the years ended December 31, 2012 and 2011, no impairment indicators arose and no goodwill impairments were recognized for APL by the Partnership.

Equity Method Investments

The Partnership’s consolidated financial statements include APL’s previously owned 49% non-controlling interest in Laurel Mountain Midstream, L.L.C. joint venture (“Laurel Mountain”) until it was sold in February 2011, its 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) and its interests in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”) and T2 EF Cogenerations Holdings L.L.C. (“T2 Co-Gen”) (the “T2 Joint Ventures”), which were acquired as part of the TEAK Acquisition (see Notes 4 and 5). APL accounts for its investments in these joint ventures under the equity method of accounting. Under this method, APL records its proportionate share of the joint ventures’ net income (loss) as equity income in other, net on the Partnership’s consolidated statements of operations. Investments in excess of the underlying net assets of equity method investees identifiable to property, plant and equipment or finite lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to investment in joint ventures on the Partnership’s consolidated balance sheets with an offsetting reduction to equity income within other, net on the Partnership’s consolidated statements of operations. Equity method investments are subject to impairment evaluation. APL noted no indicators of impairment for its equity method investments as of December 31, 2013 or 2012.

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Capital Leases

Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated balance sheets. Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets. Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets (see Note 9).

Derivative Instruments

The Partnership and its subsidiaries enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 10). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

The Partnership and ARP recognize an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities (see Note 8). The Partnership and ARP also recognize a liability for their respective future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations it owns and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, APL was not able to reasonably measure the fair value of the asset retirement obligation as of December 31, 2013 or 2012 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2013, 2012 and 2011.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013, except for: 1) an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through 2011, and 2) an examination by the Internal Revenue Service related to APL’s subsidiary APL Arkoma Inc.’s Federal Corporate Return for the period ended December 31, 2012.

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Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. With the exception of a corporate subsidiary acquired by APL through the Cardinal Acquisition (see Note 4), the federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements as of December 31, 2013 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying consolidated financial statements. APL’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to APL earnings that are generally not subject to federal and state income taxes at the APL level (see Note 12).

Stock-Based Compensation

The Partnership recognizes all share-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their fair values (see Note 17).

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 17), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data):

	Years Ended December 31,
	2013			2012			2011
Continuing Operations:
Net income (loss)	$	(228,598	)	$	(16,881	)	$	307,427
Loss (income) attributable to non-controlling interests		153,231			(35,532	)		(257,714	)
Income 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 (see Note 2))		—			—			(4,711	)
Net income (loss) attributable to common limited partners		(75,367	)		(52,413	)		45,002
Less: Net income attributable to participating securities – phantom units(1)		—			—			(1,243	)
Net income (loss) utilized in the calculation of net income (loss) attributable to common limited partners per unit	$	(75,367	)	$	(52,413	)	$	43,759
Discontinued Operations:
Net loss	$	—		$	—		$	(81	)
Loss attributable to non-controlling interests		—			—			71
Net loss utilized in the calculation of net loss from discontinued operations attributable to common limited partners per unit	$	—		$	—		$	(10	)

⁽¹⁾  Net income attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the years ended December 31, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,278,000 and 2,058,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

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Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plans (see Note 17).

The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):

	Years Ended December 31,
	2013		2012		2011
Weighted average number of common limited partners per unit—basic		51,387		51,327		48,235
Add effect of dilutive incentive awards(1)		—		—		1,441
Weighted average number of common limited partners per unit—diluted		51,387		51,327		49,676

⁽¹⁾  For the years ended December 31, 2013 and 2012, approximately 3,995,000 units and 2,867,000 units, respectively, 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.

Environmental Matters

The Partnership and its subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s and its subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership and its subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. The Partnership and its subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2013 and 2011. During the year ended December 31, 2012, one of the Partnership’s subsidiaries entered into two agreements with the United States Environmental Protection Agency (the “EPA”) 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.

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Concentration of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership and its subsidiaries place its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2013 and 2012, the Partnership and its subsidiaries had $37.7 million and $51.4 million, respectively, in deposits at various banks, of which $34.6 million and $48.8 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

The Partnership and its subsidiaries sell natural gas, oil, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2013, ARP had three customers that individually accounted for approximately 19%, 11% and 10%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, ARP had two customers that individually accounted for approximately 43% and 11%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2011, ARP had three customers that individually accounted for approximately 17%, 14% and 10% respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.

For the year ended December 31, 2013, APL had three customers that individually accounted for approximately 29%, 17% and 14% of its consolidated total third-party revenues, respectively, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, APL had two customers that individually accounted for approximately 48% and 15% of its consolidated total third-party revenues, respectively, excluding the impact of all financial derivative activity. For the year ended December 31, 2011, APL had two customers that individually accounted for approximately 60% and 16% of its consolidated total third-party revenues, excluding the impact of all financial derivative activity.

Accrued Producer Liabilities

Accrued producer liabilities on the Partnership’s consolidated balance sheets represent APL’s accrued purchase commitments payable to producers related to the natural gas gathered and processed through its system under its Percentage of Proceeds (“POP”) and Keep-Whole contracts (see “Revenue Recognition”).

Revenue Recognition

Natural gas and oil production. The Partnership and ARP generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership or ARP has an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.

ARP’s Drilling Partnerships. Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay ARP the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, ARP classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. ARP recognizes well services revenues at the time the services are performed. ARP is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within the Partnership’s consolidated statements of operations.

ARP’s Gathering and processing revenue. Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

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Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing, treating and transportation operations. Under certain agreements, APL purchases natural gas from producers, moves it into receipt points on its pipeline systems and then sells the natural gas, or produced NGLs, if any, at 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 and NGLs is recognized upon physical delivery. In connection with its gathering, processing and transportation operations, APL enters into the following types of contractual relationships with its producers and shippers:

• Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas and for transporting NGLs. APL’s revenue is a function of the volume of natural gas that it gathers and processes or the volume of NGLs transported and is not directly dependent on the value of the natural gas or NGLs. However, sustained low commodity prices could result in a decline in volumes and a corresponding decrease in fee revenue. APL is also paid a separate compression fee on many of its gathering systems. The fee is dependent upon the volume of gas flowing through its compressors and the quantity of compression stages utilized to gather the gas.

• POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. POP contracts may include a fee component which is charged to the producer.

• Fixed Recoveries. Fee-based or POP contracts sometimes include fixed recovery terms, which mean that the prices paid or products returned to the producer are calculated using an agreed NGL recovery factor, regardless of the volumes of NGLs actually recovered through processing.

• Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBtu. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The Btu quantity of gas redelivered or sold at the tailgate of APL’s processing facility may be lower than the Btu quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. APL must make up or “keep the producer whole” for this loss in Btu quantity. To offset the make-up obligation, APL retains the NGLs which are extracted and sells them for its own account. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the Btu quantity of residue gas available for redelivery to the producer may be less than APL received from the producer; and/or (ii) aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. In order to help mitigate the risk associated with Keep-Whole contracts, APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under some Keep-Whole agreements are lower in Btu content and thus can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods when the processing margin is uneconomic.

The Partnership and its subsidiaries accrue unbilled revenue and APL accrues the related purchase costs due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership and its subsidiaries had unbilled revenues at December 31, 2013 and 2012 of $191.8 million and $134.2 million, respectively, which were included in accounts receivable within its consolidated balance sheets. APL’s accrued purchase costs at December 31, 2013 and 2012 are included within accrued producer liabilities within the Partnership’s consolidated balance sheets.

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Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 10). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Adopted Accounting Standards

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10, Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes (“Update 2013-10”), which amends Accounting Standards Codification Topic 815. Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, Topic 815 specifies that only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and receivables are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.

In July 2012, the FASB issued ASU 2012-02, Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment (“Update 2012-02”). The amendments in Update 2012-02 allow an entity to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. The “more likely than not” threshold is defined as having a likelihood of more than 50%. If, after assessing qualitative factors, an entity determines it is not likely that the indefinite-lived intangible asset is impaired, then no further action is required. If impairment is deemed more likely than not, the entity is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount of the asset. Additionally, under the amendments in Update 2012-02, an entity has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. An entity will be able to resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2012-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

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Recently Issued Accounting Standards

In July 2013, the FASB issued ASU 2013-11, Income Taxes (Topic 740) –Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption is permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The Partnership will apply the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement, and disclosure, of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – ACQUISITION FROM ATLAS ENERGY, INC.

On February 17, 2011, the Partnership acquired the Transferred Business from AEI, 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; and

• 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, the Partnership’s general partner, and a direct and indirect ownership interest in Lightfoot.

For the assets acquired and liabilities assumed, the Partnership issued approximately 23.4 million of its common limited partner units and paid $30.0 million in cash consideration. Based on the Partnership’s February 17, 2011 common unit closing price of $15.92, the common units issued to AEI were valued at approximately $372.2 million. Concurrent with the Partnership’s acquisition of the Transferred Business, AEI was sold to Chevron Corporation (NYSE: CVX) (“Chevron”). In connection with the transaction, the Partnership received $118.7 million with respect to a contractual cash transaction adjustment from AEI related to certain exploration and production liabilities assumed by the Partnership. Including the cash transaction adjustment, the net book value of the Transferred Business was approximately $522.9 million. Certain amounts included within the contractual cash transaction adjustment were subject to a reconciliation period with Chevron following the consummation of the transaction. Liabilities related to the cash transaction adjustment were assumed by ARP on March 5, 2012, as certain amounts included within the contractual cash transaction adjustment remained in dispute between the parties. During the year ended December 31, 2012, ARP recognized a $7.7 million charge on the Partnership’s consolidated combined statement of operations regarding its reconciliation process with Chevron, which was settled in October 2012.

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Concurrent with the Partnership’s acquisition of the Transferred Business on February 17, 2011, including assets and liabilities transferred to ARP on March 5, 2012, AEI completed its merger with Chevron, whereby AEI became a wholly owned subsidiary of Chevron. Also concurrent with the Partnership’s acquisition of the Transferred Business and immediately preceding AEI’s merger with Chevron, APL completed its sale to AEI of its 49% non-controlling interest in Laurel Mountain. APL received $409.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from the Laurel Mountain joint venture after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of the Laurel Mountain joint venture entitling APL to receive all payments made under the note receivable issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of the Laurel Mountain joint venture.

Management of the Partnership determined that the acquisition of the Transferred Business constituted a transaction between entities under common control. As such, the Partnership recognized the assets acquired and liabilities assumed at historical carrying value at the date of acquisition, with the difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital on its consolidated balance sheet. The Partnership recognized a non-cash decrease of $261.0 million in partners’ capital on its consolidated balance sheet based on the excess net book value above the value of the consideration paid to AEI. The following table presents the historical carrying value of the assets acquired and liabilities assumed by the Partnership, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

Cash	$	153,350
Accounts receivable		18,090
Accounts receivable – affiliate		45,682
Prepaid expenses and other		6,955
Total current assets		224,077
Property, plant and equipment, net		516,625
Goodwill		31,784
Intangible assets, net		2,107
Other assets, net		20,416
Total long-term assets		570,932
Total assets acquired	$	795,009
Accounts payable	$	59,202
Net liabilities associated with drilling contracts		47,929
Accrued well completion costs		39,552
Current portion of derivative payable to Drilling Partnerships		25,659
Accrued liabilities		25,283
Total current liabilities		197,625
Long-term derivative payable to Drilling Partnerships		31,719
Asset retirement obligations		42,791
Total long-term liabilities		74,510
Total liabilities assumed	$	272,135
Historical carrying value of net assets acquired	$	522,874

The Partnership reflected the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which the Transferred Business was acquired and retrospectively adjusted its prior year financial statements to furnish comparative information (see Note 2).

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NOTE 4 – ACQUISITIONS

ARP’s EP Energy Acquisition

On July 31, 2013, ARP completed an acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”) (see Note 9), and the issuance of 14,950,000 ARP common limited partner units and 3,749,986 newly created ARP Class C convertible preferred units (see Note 15). The assets acquired by ARP in the EP Energy Acquisition included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The accompanying consolidated financial statements reflect the operating results of the acquired business commencing July 31, 2013.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $12.1 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2013 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as ARP continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Property, plant and equipment	$	728,925
Liabilities:
Accounts payable		2,562
Asset retirement obligation		16,728
Total liabilities assumed		19,290
Net assets acquired	$	709,635

Revenues and net loss of $66.1 million and $5.2 million, respectively, have been included in the Partnership’s consolidated statements of operations related to the EP Energy Acquisition for the year ended December 31, 2013.

ARP’s DTE Acquisition

On December 20, 2012, ARP completed the acquisition of DTE Gas Resources, L.L.C. from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million (the “DTE Acquisition”). In connection with entering into a purchase agreement related to the DTE Acquisition, ARP issued approximately 7.9 million of its common limited partner units through a public offering in November 2012 for $174.5 million, which was used to partially repay amounts outstanding under its revolving credit facility prior to closing (see Note 15). 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 ARP’s then-existing term loan credit facility (see Note 9).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of common units associated with the acquisition, ARP recorded $0.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.

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The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Accounts receivable	$	10,721
Prepaid expenses and other		2,100
Total current assets		12,821
Property, plant and equipment		263,194
Other assets, net		273
Total assets acquired	$	276,288
Liabilities:
Accounts payable	$	7,760
Accrued liabilities		2,910
Total current liabilities		10,670
Asset retirement obligation and other		8,169
Total liabilities assumed		18,839
Net assets acquired	$	257,449

ARP’s Titan Acquisition

On July 25, 2012, ARP completed the acquisition of Titan Operating, L.L.C. (“Titan”) in exchange for 3.8 million 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 Note 15). The cash paid at closing was funded through borrowings under ARP’s credit facility. 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 of 1933, as amended (the “Securities Act”) (see Note 15). ARP’s acquisition of Titan in exchange for 3.8 million ARP common units and 3.8 million newly created convertible ARP Class B preferred units represented a non-cash transaction during the year ended December 31, 2012.

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with its issuance of common and preferred limited partner units associated with the acquisition, ARP recorded $3.5 million of transaction fees, which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.

The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Cash and cash equivalents	$	372
Accounts receivable		5,253
Prepaid expenses and other		131
Total current assets		5,756
Property, plant and equipment		208,491
Other assets, net		2,344
Total assets acquired	$	216,591
Liabilities:
Accounts payable	$	676
Revenue distribution payable		3,091
Accrued liabilities		1,816
Total current liabilities		5,583
Asset retirement obligation and other		2,418
Total liabilities assumed		8,001
Net assets acquired	$	208,590

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ARP’s Carrizo Acquisition

On April 30, 2012, ARP completed the acquisition of certain oil and natural gas assets from Carrizo Oil and Gas, Inc. (NASDAQ: CRZO; “Carrizo”) for approximately $187.0 million in cash (the “Carrizo Acquisition”). The purchase price was funded through borrowings under ARP’s credit facility and $119.5 million of net proceeds from the sale of 6.0 million of its common units at a negotiated purchase price per unit of $20.00, of which $5.0 million was purchased by certain executives of the Partnership. The common units were issued in a private transaction exempt from registration under Section 4(2) of the Securities Act (see Note 15).

ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $1.2 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2012 on the Partnership’s consolidated balance sheet. All other costs associated with ARP’s acquisition of assets were expensed as incurred.

The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Property, plant and equipment	$	190,946
Liabilities:
Asset retirement obligation		3,903
Net assets acquired	$	187,043

APL’s TEAK Acquisition.

On May 7, 2013, APL completed the acquisition of 100% of the equity interests of TEAK for $974.7 million in cash, including final purchase price adjustments, less cash received (the “TEAK Acquisition”), including $50.0 million placed in escrow to cover potential indemnity claims. The $50.0 million escrow was released during the three months ended December 31, 2013. Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in southern Texas, including two cryogenic processing facilities, related gathering pipelines, a 75% interest in T2 LaSalle, a 50% interest in T2 Eagle Ford, and a 50% interest in T2 Co-Gen.

APL funded the purchase price for the TEAK Acquisition through:

• the private placement of $400.0 million of its Class D convertible preferred units (“Class D Preferred Units”) for net proceeds of $397.7 million, including the Partnership’s general partner contribution of $8.2 million to maintain its 2.0% general partner interest in APL (see Note 15);

• the sale of 11,845,000 APL common limited partner units in a public offering at a purchase price of $34.00 per unit, generating net proceeds of approximately $388.4 million, plus the Partnership’s general partner contribution of $8.3 million to maintain its 2.0% general partner interest in APL (see Note 15); and

• borrowings under its senior secured revolving credit facility.

Subsequent to the closing of the TEAK Acquisition, APL issued $400.0 million of its 4.75% unsecured senior notes due November 15, 2021 (“4.75% APL Senior Notes”) on May 10, 2013 for net proceeds of $391.2 million to reduce the level of borrowings under its revolving credit facility, including amounts borrowed in connection with the TEAK Acquisition (see Note 9).

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APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11). In conjunction with the issuance of APL’s common and preferred limited partner units associated with the acquisition, $16.6 million of transaction fees were included in the net proceeds recorded within non-controlling interests on the Partnership’s consolidated balance sheet. In conjunction with APL’s issuance of the 4.75% APL Senior Notes and an amendment to its revolving credit facility (see Note 9), APL recorded $9.7 million of transaction fees as deferred financing costs, which are included in other assets, net on the Partnership’s consolidated balance sheet at December 31, 2013. All other costs associated with the acquisition were expensed as incurred.

Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate the facts and circumstances that existed as of the acquisition date.

The following table presents the preliminary values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

Assets:
Cash	$	8,074
Accounts receivable		11,055
Prepaid expenses and other		1,626
Total current assets		20,755
Property, plant and equipment		198,752
Intangible assets		450,000
Goodwill		188,859
Equity method investment in joint ventures		161,069
Total assets acquired	$	1,019,435
Liabilities:
Accounts payable and accrued liabilities		36,690
Total liabilities assumed		36,690
Net assets acquired		982,745
Less cash received		(8,074	)
Net cash paid for acquisition	$	974,671

Revenues and net loss of $97.4 million and $14.6 million, respectively, for the year ended December 31, 2013 from the acquisition date of May 7, 2013 have been included in the Partnership’s consolidated financial statements related to the TEAK Acquisition. Net income of $1.1 million which was contributed from the TEAK Acquisition from April 1, 2013 (the effective date) to May 7, 2013 (the closing date) was included as a reduction to the purchase price.

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APL’s Cardinal Acquisition

On December 20, 2012, APL completed the Cardinal Acquisition for $598.9 million in cash, including final purchase price adjustments. The assets from this acquisition (the “APL Arkoma assets”) include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas and a 60% interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by MarkWest Energy Partners, L.P. (NYSE: MWE). APL funded the purchase price for the Cardinal Acquisition in part from the private placement of $175.0 million of its 6.625% senior unsecured notes due October 1, 2020 (“6.625% APL Senior Notes”) at a premium of 3.0%, for net proceeds of $176.5 million (see Note 9); and from the sale of 10,507,033 APL common limited partner units in a public offering at a purchase price of $31.00 per unit, generating net proceeds of approximately $319.3 million, including the Partnership’s contribution of $6.7 million to maintain its 2.0% general partner interest in APL (see Note 15). APL funded the remaining purchase price from its senior secured revolving credit facility (see Note 9). As part of the Cardinal Acquisition, APL placed $25.0 million into escrow to cover potential indemnity claims within prepaid expenses and other on the Partnership’s consolidated balance sheet at December 31, 2012. The $25.0 million was released to the sellers in June 2013.

APL accounted for this transaction under the acquisition method of accounting. Accordingly, APL evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 11).

The following table presents the values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their estimated fair values at the date of the acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands):

Assets:
Cash	$	1,184
Accounts receivable		13,783
Prepaid expenses and other		1,289
Property, plant and equipment		246,787
Intangible assets		232,740
Goodwill		214,090
Total assets acquired		709,873
Liabilities:
Current portion of long-term debt		341
Accounts payable and accrued liabilities		14,596
Deferred tax liability, net		35,353
Long-term debt, less current portion		604
Total liabilities acquired		50,894
Non-controlling interest		58,905
Net assets acquired		600,074
Less cash received		(1,184	)
Net cash paid for acquisition	$	598,890

The fair value of MarkWest’s 40% non-controlling interest in Centrahoma was based upon the purchase price allocated to the 60% controlling interest APL acquired using an income approach. This measurement uses significant inputs that are not observable in the market and thus represents a fair value measurement categorized within Level 3 of the fair value hierarchy. The 40% non-controlling interest in Centrahoma was reduced by a 5% adjustment for lack of control that market participants would consider when measuring its fair value.

In 2013, subsequent to recording the final estimated fair values of the assets acquired and liabilities assumed in the Cardinal Acquisition, APL determined that a portion of goodwill recorded in connection with the acquisition was impaired (see Note 2 – Goodwill).

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Pro Forma Financial Information

The following data presents pro forma revenues, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the EP Energy, TEAK, DTE, Titan, and Carrizo acquisitions, including the related borrowings under the respective revolving credit facilities, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2012. The Partnership prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the EP Energy, TEAK, DTE, Titan and Carrizo acquisitions and related offerings, borrowings, and issuances had occurred on January 1, 2012 or the results that will be attained in future periods (in thousands, except per unit data; unaudited):

	Years Ended December 31,
	2013			2012
Total revenues and other	$	2,701,523		$	2,103,240
Net loss		(187,371	)		(115,926	)
Net loss attributable to common limited partners		(60,793	)		(86,815	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(1.18	)	$	(1.69	)

Other Acquisitions

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. (“Equal”) (NYSE: EQU; TSX: EQU). The transaction was funded through borrowings under ARP’s revolving credit facility. 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. Both transactions were funded through borrowings under ARP’s revolving credit facility. 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.

In July 2013, the Partnership completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of the Partnership’s term loan facility (see Note 9). The Arkoma Acquisition had an effective date of May 1, 2013.

In September 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013.

NOTE 5 — APL EQUITY METHOD INVESTMENTS

T2 Joint Ventures

On May 7, 2013, APL acquired a 75% interest in T2 LaSalle, a 50% interest in T2 Eagle Ford and a 50% interest in T2 Co-Gen as part of the TEAK Acquisition (see Note 4). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. The T2 Joint Ventures do meet the qualifications of a Variable Interest Entity (“VIE”), but APL does not meet the qualifications as the primary beneficiary even though APL owns a 50% or greater interest in the T2 Joint Ventures. Under the terms of the respective joint venture agreements, APL is not the operator, does not have a controlling financial interest and shares equal management rights with TexStar Midstream Services, L.P. (“TexStar”). APL’s maximum exposure to loss as a result of its involvement with the joint ventures is limited to its equity investment, additional capital contribution commitments and APL’s share of any operating expenses incurred by the joint venture. Therefore, APL accounts for its investments in the joint ventures under the equity method of accounting. APL’s proportionate share of the net losses of the joint ventures is included within other, net on the Partnership’s consolidated statement of operations for the year ended December 31, 2013.

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West Texas LPG Pipeline Limited Partnership

On May 11, 2011, APL acquired a 20% interest in WTLPG from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. WTLPG 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, which owns the remaining 80% interest. The Partnership recognizes APL’s 20% interest in WTLPG as an investment in joint venture on its consolidated balance sheets. At the acquisition date, the carrying value of the 20% interest in WTLPG exceeded APL’s share of the underlying net assets of WTLPG by approximately $49.9 million, which related to the fair value of the property, plant and equipment in excess of book value. This excess is being depreciated over approximately 38 years. APL has accounted for its ownership interest in WTLPG under the equity method of accounting, with recognition of its ownership interest in the income of WTLPG in other, net on the Partnership’s consolidated statements of operations. During the years ended December 31, 2013, 2012 and 2011, APL recognized equity income of $5.0 million, $6.3 million and $4.6 million, respectively, within other, net on the Partnership’s consolidated statements of operations related to APL’s WTLPG interest. APL’s equity method investments are subject to impairment evaluation. APL evaluated its investment in WTLPG as of December 31, 2013 and determined there was no impairment of the investment.

Laurel Mountain

On February 17, 2011, APL completed the sale of its 49% non-controlling interest in the Laurel Mountain joint venture to AEI (see Note 3). The Laurel Mountain joint venture was formed in May 2009 by APL and subsidiaries of the Williams Companies, Inc. (NYSE: WMB; “Williams”) to own and operate APL’s Appalachian Basin natural gas gathering system. APL used the proceeds from the sale to repay its indebtedness and for general corporate purposes. APL also retained its preferred distribution rights with respect to a remaining $8.5 million note receivable due from Williams, an investment grade rated entity, related to the formation of Laurel Mountain, including interest due on this note. APL accounted for its ownership of Laurel Mountain as an equity investment included within investment in joint venture on the Partnership’s consolidated balance sheet at fair value, based upon the value received for the 51% contributed to the Laurel Mountain joint venture during the year ended December 31, 2009. APL accounted for its ownership interest in the income of Laurel Mountain as other, net on the Partnership’s consolidated statements of operations. Since APL accounted for its ownership as an equity investment, it did not reclassify the earnings or the gain on sale related to Laurel Mountain to discontinued operations upon the sale of its ownership interest. The Partnership recognized a gain of $256.3 million during the year ended December 31, 2011, which is included in gain (loss) on asset sales and disposal within the Partnership’s consolidated statement of operations. The Partnership also reclassified the $8.5 million note receivable previously recorded to investment in joint venture to prepaid expenses and other on the Partnership’s consolidated balance sheets. In December 2011, Williams made a cash payment to APL to settle the remaining $8.5 million balance on the note receivable plus accrued interest of $0.2 million.

The following tables present the values of APL’s equity method investments as of December 31, 2013 and 2012 and equity income (loss) in joint ventures as of December 31, 2013, 2012 and 2011 (in thousands):

	Investment in Joint Venture
	December 31,
	2013		2012
WTLPG	$	85,790	$	86,002
T2 LaSalle		50,534		—
T2 Eagle Ford		97,437		—
T2 Co-Gen		14,540		—
Equity method investment in joint ventures	$	248,301	$	86,002

	Years Ended December 31,
	2013			2012		2011
Equity income in Laurel Mountain	$	—		$	—	$	462
Equity income in WTLPG		4,988			6,323		4,563
Equity loss in T2 LaSalle		(3,127	)		—		—
Equity loss in T2 Eagle Ford		(4,408	)		—		—
Equity loss in T2 Co-Gen		(2,189	)		—		—
Equity income (loss) in joint ventures	$	(4,736	)	$	6,323	$	5,025

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NOTE 6 — PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

	December 31,						Estimated Useful Lives in Years
	2013			2012
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	322,217		$	244,476
Pre-development costs		4,367			1,935
Wells and related equipment		2,231,213			1,222,475
Total proved properties		2,557,797			1,468,886
Unproved properties		211,851			292,053
Support equipment		23,258			13,110
Total natural gas and oil properties		2,792,906			1,774,049
Pipelines, processing and compression facilities		2,926,134			2,326,186		2–40
Rights of way		203,966			179,018		20–40
Land, buildings and improvements		30,216			25,609		3–40
Other		36,752			26,656		3–10
		5,989,974			4,331,518
Less – accumulated depreciation, depletion and amortization		(1,079,099	)		(828,909	)
	$	4,910,875		$	3,502,609

During the year ended December 31, 2013, the Partnership and its subsidiaries recognized $2.5 million of loss on asset sales and disposal, of which $1.0 million pertained to ARP, primarily pertaining to ARP’s loss on the sale of its Antrim assets. During the year ended December 31, 2013, APL recognized $1.5 million of loss on asset sales and disposal primarily related to its decision to not pursue a project to construct pipelines in an area where acquired rights of way had expired.

During the year ended December 31, 2012, ARP recognized a $7.0 million loss on asset sales and disposal pertaining to its decision to terminate a farm-out agreement with a third party for well drilling in the South Knox area of the New Albany Shale that was originally entered into in 2010. The farm-out agreement contained certain well drilling targets for ARP to maintain ownership of the South Knox processing plant, which ARP’s management decided in 2012 to not achieve due to the then current natural gas price environment. As a result, ARP forfeited its interest in the processing plant and related properties and recorded a loss related to the net book values of those assets during the year ended December 31, 2012.

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During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of asset impairments related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for ARP’s shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, ARP recognized $7.0 million of asset impairment related to its gas and oil properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet for ARP’s shallow natural gas wells in the Niobrara Shale.

These impairments related to the carrying amounts of gas and oil properties being in excess of ARP’s estimate of their fair values at December 31, 2013, 2012 and 2011 and ARP’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

APL owns and leases certain gas treating assets that are used to remove impurities from natural gas before it is delivered into gathering systems and transmission pipelines to ensure it meets pipeline quality specifications. These assets are included within pipelines, processing and compression facilities within property, plant and equipment, net on the Partnership’s consolidated balance sheets. Revenues from these lease arrangements are recorded within gathering and processing revenue on the Partnership’s consolidated statements of operations. Future minimum rental income related to these lease arrangements is estimated to be as follows for each of the next five calendar years: 2014 - $4.0 million; 2015 - $3.0 million; 2016 - $1.0 million; 2017 to 2018 – none.

NOTE 7 — OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

	December 31,
	2013		2012
Deferred financing costs, net of accumulated amortization of $43,702 and $26,053 at December 31, 2013 and 2012, respectively	$	86,617	$	45,629
Investment in Lightfoot		21,454		19,882
Security deposits		5,631		2,390
ARP notes receivable		3,978		—
Other		6,129		3,101
	$	123,809	$	71,002

Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 9). Amortization expense of the Partnership and its subsidiaries’ deferred financing costs was $14.4 million, $6.7 million and $5.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the year ended December 31, 2011, the Partnership recognized an additional $4.9 million of accelerated amortization of its deferred financing costs associated with the retirement of its $70.0 million credit facility, which was recorded within interest expense on the Partnership’s consolidated statement of operations. There was no accelerated amortization of deferred financing costs for the Partnership during the years ended December 31, 2013 and 2012.

During the year ended December 31, 2013, ARP recognized an additional $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its then-existing term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of senior unsecured notes due 2021 (“7.75% ARP Senior Notes”) (see Note 9). There was no accelerated amortization of deferred financing costs for ARP during the years ended December 31, 2012 and 2011.

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During the year ended December 31, 2013, APL recorded $5.3 million of accelerated amortization of deferred financing costs related to the retirement of its 8.75% senior unsecured notes due June 15, 2018 (“8.75% APL Senior Notes”) to loss on early extinguishment of debt on the Partnership’s consolidated statement of operations (see Note 9). During the year ended December 31, 2011, APL recognized $5.2 million of accelerated amortization of deferred financing costs associated with the retirement of its 8.125% senior unsecured notes due on December 15, 2015 (“8.125% APL Senior Notes”) and partial redemption of its 8.75% APL Senior Notes, which was recorded within loss on early extinguishment of debt on the Partnership’s consolidated combined statements of operations. There was no accelerated amortization of deferred financing costs for the APL during the year ended December 31, 2012.

ARP notes receivable. At December 31, 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets on the Partnership’s consolidated balance sheet. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. For the year ended December 31, 2013, $0.1 million of interest income was recognized within other, net on the Partnership’s consolidated statement of operations. There was no interest income recognized for the years ended December 31, 2012 and 2011. At December 31, 2013, ARP recorded no allowance for credit losses within the Partnership’s consolidated balance sheet based upon payment history and ongoing credit evaluations associated with the ARP notes receivable.

Investment in Lightfoot. At December 31, 2013, the Partnership owned an approximate 12% interest in Lightfoot L.P. and an approximate 16% interest in Lightfoot G.P., the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the General Partner’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. The Partnership accounts for its investment in Lightfoot under the equity method of accounting. During the years ended December 31, 2013, 2012 and 2011, the Partnership recognized equity income of approximately $2.6 million, $1.5 million and $16.6 million, respectively, within other, net on the Partnership’s consolidated statements of operations. During the year ended December 31, 2011, the Partnership recognized a gain associated with its equity ownership interest in Lightfoot of $15.0 million pertaining to its share of Lightfoot L.P.’s gain recognized on the sale of International Resource Partners L.P. (“IRP”), its metallurgical and steam coal business, in March 2011. During the years ended December 31, 2013, 2012 and 2011, the Partnership received net cash distributions of approximately $1.0 million, $0.9 million and $16.2 million, respectively. The net cash distributions received in 2011 included $14.2 million, representing its share of the cash distribution made to investors by Lightfoot L.P. with proceeds from the IRP sale.

On November 6, 2013, Arc Logistics Partners, L.P. (“ARCX”), an MLP, owned and controlled by Lightfoot, which is involved in terminalling, storage, throughput and transloading of crude oil and petroleum products, began trading publicly on the NYSE under the ticker symbol “ARCX”.

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

The Partnership and ARP recognized an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. The Partnership and ARP also recognized a liability for their respective future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership and its subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership and ARP have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership and ARP’s gas and oil properties, the Partnership and its subsidiaries determined that there were no other material retirement obligations associated with tangible long-lived assets.

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ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At December 31, 2013, the Drilling Partnerships had $59.7 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. During the year ended December 31, 2013, ARP withheld approximately $0.3 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. No amounts were withheld during the years ended December 31, 2012 and 2011. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners.

A reconciliation of the Partnership and ARP’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

	Years Ended December 31
	2013			2012			2011
Asset retirement obligations, beginning of year	$	64,794		$	45,779		$	42,673
Liabilities incurred		23,129			16,568			713
Liabilities settled		(1,188	)		(546	)		(209	)
Accretion expense		4,479			2,993			2,602
Asset retirement obligations, end of year	$	91,214		$	64,794		$	45,779

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Partnership’s consolidated balance sheets. During the year ended December 31, 2013, the Partnership incurred $1.3 million of future plugging and abandonment costs related to the Arkoma Acquisition it consummated during the period. During the year ended December 31, 2013, ARP incurred $16.7 million of future plugging and abandonment costs related to the EP Energy Acquisition it consummated during the period. During the year ended December 31, 2012, ARP incurred $15.6 million of future plugging and abandonment costs related to acquisitions it consummated during the period.

NOTE 9 — DEBT

Total debt consists of the following at the dates indicated (in thousands):

	December 31,
	2013			2012
Term loan facility	$	239,400		$	—
Revolving credit facility		—			9,000
ARP revolving credit facility		419,000			276,000
ARP term loan credit facility		—			75,425
ARP 7.75% Senior Notes – due 2021		275,000			—
ARP 9.25% Senior Notes – due 2021		248,334			—
APL revolving credit facility		152,000			293,000
APL 8.75% Senior Notes – due 2018		—			370,184
APL 6.625% Senior Notes – due 2020		504,556			505,231
APL 5.875% Senior Notes – due 2023		650,000			—
APL 4.750% Senior Notes – due 2021		400,000			—
APL capital leases		754			11,503
Total debt		2,889,044			1,540,343
Less current maturities		(2,924	)		(10,835	)
Total long-term debt	$	2,886,120		$	1,529,508

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Partnership’s Term Loan Facility.

On July 31, 2013, in connection with the Arkoma Acquisition (see Note 4), the Partnership entered into a $240.0 million secured term facility with a group of outside investors (the “Term Facility”). At December 31, 2013, $239.4 million was outstanding under the Term Facility. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at the Partnership’s election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by the Partnership. The Partnership is required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. At December 31, 2013, the weighted average interest rate on its outstanding Term Facility borrowings was 6.5%.

The Term Facility contains customary covenants, similar to those in the Partnership’s credit facility, that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 the Partnership’s assets. The Term Facility also contains covenants that require (i) the Partnership to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) the entry into swap agreements with respect to the assets acquired in the EP Energy and Arkoma acquisitions (see Note 4). At December 31, 2013, the Partnership was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control.

The Partnership’s obligations under the Term Facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under its Term Facility are guaranteed by its wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and the Partnership’s credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

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Partnership’s Revolving Credit Facility

On July 31, 2013, in connection with the Arkoma Acquisition (see Note 4), the Partnership amended its credit facility with a syndicate of banks that matures on July 31, 2018. The credit facility has a maximum credit amount of $50.0 million, of which up to $5.0 million may be in the form of standby letters of credit. At December 31, 2013, no amounts were outstanding under the credit facility. The Partnership’s obligations under the credit facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its ownership interests in APL and ARP. Additionally, the Partnership’s obligations under the credit facility are guaranteed by its material wholly-owned subsidiaries (excluding Atlas Pipeline Partners GP, LLC) and may be guaranteed by future subsidiaries. Any of the Partnership’s subsidiaries, other than the subsidiary guarantors, are minor. At the Partnership’s election, interest on borrowings under the credit agreement is determined by reference to either an adjusted LIBOR rate plus an applicable margin of 5.50% per year or the ABR plus an applicable margin of 4.50% per year. Interest is generally payable quarterly for ABR loans and at the interest payment periods selected by the Partnership for LIBOR loans. The Partnership is required to pay a fee between 0.5% and 0.625% per annum on the unused portion of the commitments under the credit facility.

The credit facility contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default 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 the Partnership’s assets. The credit facility also contains covenants the same as those in the Partnership’s Term Facility with respect to (i) the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility), and (ii) entry into swap agreements. At December 31, 2013, the Partnership was in compliance with these covenants. Based on the definition in the Partnership’s Term Facility and credit facility, the Partnership’s ratio of Total Funded Debt to EBITDA was 2.5 to 1.0.

The credit facility is subject to an intercreditor agreement as described above under the “Partnership’s Term Loan Facility”.

At December 31, 2013, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.

ARP’s Credit Facility

On July 31, 2013, in connection with the EP Energy Acquisition (see Note 4), ARP entered into a Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (“ARP Credit Agreement”), which amended and restated ARP’s existing revolving credit facility. The ARP Credit Agreement provides for a senior unsecured revolving credit facility with a syndicate of banks scheduled to mature in July 2018. ARP’s borrowing base is scheduled for redeterminations on May 1 and November 1 of each year. On December 6, 2013, ARP entered into the First Amendment to the Credit Agreement (“ARP Amendment”). The ARP Amendment redetermined the borrowing base to $735.0 million and amended the ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable). The ARP Credit Agreement has a maximum facility amount of $1.5 billion. At December 31, 2013, $419.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $3.6 million was outstanding at December 31, 2013. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.75% and 2.75% 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 0.75% and 1.75% per annum. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At December 31, 2013, the weighted average interest rate on outstanding borrowings under the credit facility was 2.4%.

149

The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of December 31, 2013. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to four quarters of EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended December 31, 2013, March 31, 2014 and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ended September 30, 2014 and 4.0 to 1.0 as of the last day of fiscal quarters ending thereafter and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. Based on the definitions contained in ARP’s credit agreement, at December 31, 2013, ARP’s ratio of current assets to current liabilities was 1.9 to 1.0 and its ratio of Total Funded Debt to EBITDA was 4.0 to 1.0.

ARP Senior Notes

On December 31, 2013, ARP had $275.0 million principal outstanding of 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) and $250.0 million principal outstanding of 9.25% Senior Notes due 2021 (“9.25% ARP Senior Notes”). On July 30, 2013, ARP issued $250.0 million of its 9.25% ARP Senior Notes in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million, net of underwriting fees and other offering costs of $5.5 million. The net proceeds were used to partially fund the EP Energy Acquisition (see Note 4). The 9.25% ARP Senior Notes were presented net of a $1.7 million unamortized discount as of December 31, 2013. Interest on the 9.25% ARP Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. In addition, at any time prior to August 15, 2016, ARP may redeem up to 35% of the 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.25%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.

In connection with the issuance of the 9.25% ARP Senior Notes, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, ARP has agreed to file a shelf registration statement with respect to the 9.25% ARP Senior Notes. If ARP fails to comply with its obligations to register the 9.25% ARP Senior Notes within the specified time periods, the 9.25% ARP Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration statement is declared effective, as applicable.

On January 23, 2013, ARP issued $275.0 million of its 7.75% ARP Senior Notes in a private placement transaction at par. ARP used the net proceeds of approximately $267.6 million to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. In connection with the retirement of ARP’s term loan credit facility and the reduction in its revolving credit facility borrowing base, ARP accelerated $3.2 million of amortization expense related to deferred financing costs during the year ended December 31, 2013 (see Note 7). Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing indenture, plus accrued and unpaid interest and additional interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. On July 1, 2013, ARP filed a registration statement relating to the exchange offer for the 7.75% ARP Senior Notes and the exchange offer was completed on January 2, 2014.

The 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes are full and unconditional and joint and several, and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.

150

The indentures governing the 9.25% ARP Senior Notes and 7.75% ARP Senior Notes contain 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. ARP was in compliance with these covenants as of December 31, 2013.

APL Credit Facility

At December 31, 2013, APL had a $600.0 million senior secured revolving credit facility with a syndicate of banks, which matures in May 2017, of which $152.0 million was outstanding. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at December 31, 2013 was 4.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at December 31, 2013. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet at December 31, 2013. At December 31, 2013, APL had $447.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. The Partnership has not guaranteed any of the obligations under APL’s senior secured revolving credit facility.

Borrowings under APL’s credit facility are secured by (i) a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the West OK and West TX entities in which APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies.

The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on its ability to (i) incur additional indebtedness, (ii) make certain acquisitions, loans or investments, (iii) make distribution payments to its unitholders if an event of default exists, or (iv) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

The events which constitute an event of default under the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount and a change of control of APL’s general partner.

On April 19, 2013, APL entered into an amendment to the credit agreement which, among other changes:

• allowed the TEAK Acquisition to be a Permitted Investment, as defined in the credit agreement;

• did not require the joint venture interests acquired in the TEAK Acquisition to be guarantors;

• permitted the payment of cash distributions, if any, on APL’s Class D Preferred Units so long as APL has a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million; and

• modified the definition of Consolidated Funded Debt Ratio, Interest Coverage Ratio and Consolidated EBITDA to allow for an Acquisition Period whereby the terms for calculating each of these ratios have been adjusted.

APL was in compliance with these covenants as of December 31, 2013.

APL Senior Notes

At December 31, 2013, APL had $500.0 million principal outstanding of 6.625% APL Senior Notes due 2020, $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”) and $400.0 million of 4.75% Senior Notes due 2021 (with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”).

151

On May 10, 2013, APL issued $400.0 million of the 4.75% APL Senior Notes in a private placement transaction. The 4.75% APL Senior Notes were issued at par. APL received net proceeds of $391.2 million after underwriting commissions and other transactions costs and utilized the proceeds to repay a portion of the outstanding indebtedness under the revolving credit agreement as part of the TEAK Acquisition (see Note 4). Interest on the 4.75% APL Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% APL Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offer for the 4.75% APL Senior Notes on December 10, 2013 and the exchange offer was completed January 9, 2014.

On February 11, 2013, APL issued $650.0 million of 5.875% Senior Notes in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million and utilized the proceeds to redeem the 8.75% APL Senior Notes and repay a portion of its outstanding indebtedness under its revolving credit facility. Interest on the 5.875% APL Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% APL Senior Notes are redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offer for the 5.875% APL Senior Notes on December 10, 2013 and the exchange offer was completed on January 9, 2014.

On September 28, 2012 and December 20, 2012, APL issued an aggregate of $500.0 million of its 6.625% APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes were presented combined with a net $4.6 million unamortized premium as of December 31, 2013. APL received net proceeds in aggregate of $495.0 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on its revolving credit facility and to partially finance the Cardinal Acquisition (see Note 4). Interest on the 6.625% APL Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% APL Senior Notes are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. APL commenced an exchange offering for the 6.625% APL Senior Notes on September 18, 2013 and the exchange offer was completed on October 16, 2013. Pursuant to the terms of the registration rights agreement related to the 6.625% APL Senior Notes, because the exchange offer was not consummated within the required timeframe, APL incurred a 0.25% interest penalty of $0.1 million for the period from September 23, 2013 through consummation of the exchange offer on October 16, 2013.

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

Indentures governing the APL Senior Notes contain covenants, including limitations on APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all its assets. APL was in compliance with these covenants as of December 31, 2013.

APL Senior Notes Redemptions

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, excluding unamortized premium, 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% APL Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% APL Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, APL accepted for purchase all 8.75% APL Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million premium, $3.7 million accrued interest and $8.0 million consent payment. APL entered into a supplemental indenture amending and supplementing the 8.75% APL Senior Notes Indenture.

On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million outstanding 8.75% APL Senior Notes due 2018 plus a $6.3 million premium and $2.0 million in accrued interest. APL funded the redemption with a portion of the net proceeds from the issuance of the 5.875% APL Senior Notes due 2023. During the year ended December 31, 2013, APL recognized a loss of $26.6 million within loss on early extinguishment of debt on the Partnership’s consolidated statements of operations, related to the redemption of the 8.75% APL Senior Notes. The loss includes $17.5 million premiums paid, $8.0 million consent payment and a $5.3 million write-off of deferred financing costs (see Note 7), partially offset by $4.2 million of unamortized premium recognized.

152

On April 7, 2011, APL redeemed $7.2 million of the 8.75% APL Senior Notes, which were tendered upon its offer to purchase the 8.75% APL Senior Notes, at par. The sale of APL’s 49% non-controlling interest in Laurel Mountain on February 17, 2011 constituted an “asset sale” pursuant to the terms of the indenture of the 8.75% APL Senior Notes. As a result of the asset sale, APL offered to purchase any and all of the 8.75% APL Senior Notes. Subsequent to the redemption of the 8.75% APL Senior Notes, APL redeemed all of the 8.125% APL Senior Notes. The redemption price was determined in accordance with the indenture for the 8.125% APL Senior Notes, plus accrued and unpaid interest thereon to the redemption date. APL paid $293.7 million to redeem the $275.5 million principal plus $11.2 million premium and $7.0 million accrued interest. In addition, APL recorded $5.2 million related to accelerated amortization of deferred financing costs associated with the retirement of the 8.125% APL Senior Notes and a partial redemption of the 8.75% APL Senior Notes.

APL Capital Leases

During the year ended December 31, 2013, APL accelerated payment on certain leases and purchased the leased property by paying approximately $7.5 million in accordance with the lease agreements. These leases were to mature in August 2013.

During the year ended December 31, 2012, APL recorded $2.8 million related to capital lease agreements, including $0.9 million as part of the Cardinal Acquisition (see Note 4), within property, plant and equipment, net and recorded an offsetting liability within long-term debt on the Partnership’s consolidated balance sheet. This amount was based upon the minimum payments required under the leases and the Partnership’s incremental borrowing rate.

The following is a summary of the leased property under capital leases as of December 31, 2013 and 2012, which are included within property, plant and equipment, net (see Note 6) (in thousands):

	December 31,
	2013			2012
Pipelines, processing and compression facilities	$	2,281		$	15,457
Less – accumulated depreciation		(330	)		(1,066	)
	$	1,951		$	14,391

Depreciation expense for leased properties was $0.3 million, $0.7 million and $0.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. Depreciation expense for leased properties is included within depreciation, depletion and amortization expense on the Partnership’s consolidated statements of operations.

As of December 31, 2013, future minimum lease payments related to APL’s capital leases are as follows (in thousands):

	Capital Lease Minimum Payments
2014	$	524
2015		225
2016		5
2017		—
2018		—
Thereafter		—
Total minimum lease payments		754

153

	Capital Lease Minimum Payments
Less amounts representing interest		(26	)
Present value of minimum lease payments		728
Less current portion of capital lease obligations		(503	)
Long-term capital lease obligations	$	225

154

The aggregate amount of the Partnership’s, ARP’s and APL’s debt maturities is as follows (in thousands):

Years Ended December 31:
2014	$	2,924
2015		225
2016		5
2017		152,000
2018		419,000
Thereafter		2,312,000
Total principle maturities		2,886,154
Unamortized premiums		4,556
Unamortized discounts		(1,666	)
Total debt	$	2,889,044

Cash payments for interest by the Partnership and its subsidiaries were $96.6 million, $38.8 million and $33.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.

NOTE 10 — DERIVATIVE INSTRUMENTS

The Partnership and its subsidiaries use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. The Partnership and its subsidiaries enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, the Partnership and its subsidiaries receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

155

The Partnership and its subsidiaries formally document all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity and interest derivative contracts to the forecasted transactions. The Partnership and its subsidiaries assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership and its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations. For derivatives qualifying as hedges, the Partnership and its subsidiaries recognize the effective portion of changes in fair value of derivative instruments in partners’ capital as accumulated other comprehensive income (loss) and reclassify the portion relating to the Partnership and ARP’s commodity derivatives to gas and oil production revenues and gathering and processing revenues for APL’s commodity derivatives and the portion relating to interest rate derivatives to interest expense within the Partnership’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized within gain (loss) on mark-to-market derivatives in the Partnership’s consolidated statements of operations as they occur.

The Partnership and its subsidiaries enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s consolidated balance sheets as the initial value of the options.

The Partnership and its subsidiaries enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.

Derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value. The Partnership reflected net derivative assets on its consolidated balance sheets of $14.9 million and $51.3 million at December 31, 2013 and 2012, respectively. Of the $10.3 million of net gain in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at December 31, 2013, if the fair values of the instruments remain at current market values, the Partnership will reclassify $1.6 million of losses to gas and oil production revenue on its consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $11.9 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes. Approximately $3.9 million of derivative gains were reclassified from other comprehensive income related to derivative instruments entered into during the year ended December 31, 2013, respectively.

The following table summarizes the Partnership’s, ARP’s and APL’s gains or losses recognized in the Partnership’s consolidated statements of operations for effective derivative instruments, excluding the effect of non-controlling interest, for the periods indicated (in thousands):

	Years Ended December 31,
	2013			2012			2011
(Gain) loss reclassified from accumulated other comprehensive income:
Gas and oil production revenue	$	(10,216	)	$	(19,281	)	$	(10,542	)
Gathering and processing revenue		—			4,390			6,834
Total	$	(10,216	)	$	(14,891	)	$	(3,708	)

156

The Partnership

The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of December 31, 2013
Current portion of derivative assets	$	24	$	(23	)	$	1
Long-term portion of derivative assets		1,547		(33	)		1,514
Current portion of derivative liabilities		63		(63	)		—
Total derivative assets	$	1,634	$	(119	)	$	1,515
As of December 31, 2012
Current portion of derivative assets	$	—	$	—		$	—
Long-term portion of derivative assets		—		—			—
Current portion of derivative liabilities		—		—			—
Long-term portion of derivative liabilities		—		—			—
Total derivative assets	$	—	$	—		$	—

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of December 31, 2013
Current portion of derivative assets	$	(23	)	$	23	$	—
Long-term portion of derivative assets		(33	)		33		—
Current portion of derivative liabilities		(96	)		63		(33	)
Total derivative liabilities	$	(152	)	$	119	$	(33	)
As of December 31, 2012
Current portion of derivative assets	$	—		$	—	$	—
Long-term portion of derivative assets		—			—		—
Current portion of derivative liabilities		—			—		—
Long-term portion of derivative liabilities		—			—		—
Total derivative liabilities	$	—		$	—	$	—

During the year ended December 31, 2013, the Partnership recorded gains of $0.5 million on settled derivative contracts within its consolidated statements of operations. These gains were included within gas and oil production revenue in the Partnership’s consolidated statement of operations. No gains or losses were recorded on settled derivative contracts within the Partnership’s consolidated statements of operations for the years ended December 31, 2012 and 2011 as the Partnership had no derivative contracts in those years. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the year ended December 31, 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

157

In connection with the Arkoma Acquisition, the Partnership entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through September 30, 2013 for production volumes related to the Arkoma assets acquired from EP Energy (see Note 4). In connection with the swaption contacts, the Partnership paid premiums of $2.3 million which represented their fair value on the date the transactions were initiated, were initially recorded as a derivative asset on the Partnership’s consolidated balance sheet and were fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through termination date. For the year ended December 31, 2013, the Partnership recognized approximately $2.3 million, respectively, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts.

At December 31, 2013, the Partnership had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2014		2,760,000	$	4.177	$	(32	)
2015		2,280,000	$	4.302		355
2016		1,440,000	$	4.433		430
2017		1,200,000	$	4.590		504
2018		420,000	$	4.797		225
		The Partnership’s net asset			$	1,482

⁽¹⁾  “MMBtu” represents million British Thermal Units.

⁽²⁾  Fair value based on forward NYMEX natural gas prices, as applicable.

Atlas Resource Partners

The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of December 31, 2013
Current portion of derivative assets	$	2,664	$	(773	)	$	1,891
Long-term portion of derivative assets		31,146		(4,062	)		27,084
Current portion of derivative liabilities		4,341		(4,341	)		—
Long-term portion of derivative liabilities		122		(122	)		—
Total derivative assets	$	38,273	$	(9,298	)	$	28,975
As of December 31, 2012
Current portion of derivative assets	$	14,248	$	(1,974	)	$	12,274
Long-term portion of derivative assets		14,724		(5,826	)		8,898
Long-term portion of derivative liabilities		800		(800	)		—
Total derivative assets	$	29,772	$	(8,600	)	$	21,172

158

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of December 31, 2013
Current portion of derivative assets	$	(773	)	$	773	$	—
Long-term portion of derivative assets		(4,062	)		4,062		—
Current portion of derivative liabilities		(10,694	)		4,341		(6,353	)
Long-term portion of derivative liabilities		(189	)		122		(67	)
Total derivative liabilities	$	(15,718	)	$	9,298	$	(6,420	)
As of December 31, 2012
Current portion of derivative assets	$	(1,974	)	$	1,974	$	—
Long-term portion of derivative assets		(5,826	)		5,826		—
Long-term portion of derivative liabilities		(1,688	)		800		(888	)
Total derivative liabilities	$	(9,488	)	$	8,600	$	(888	)

In June 2012, ARP received approximately $3.9 million in net proceeds from the early termination of natural gas and oil derivative positions for production periods from 2015 through 2016. In conjunction with the early termination of these derivatives, ARP entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ARP’s credit facility (see Note 9). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income (loss) and will be reclassified into the Partnership’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

In connection with the EP Energy Acquisition, ARP entered into swaption contracts up through September 30, 2013 for production volumes related to assets ARP acquired from EP Energy (see Note 4). In connection with the swaption contracts, ARP paid premiums of $14.5 million which represented their fair value on the date the transactions were initiated, were initially recorded as derivative assets on the Partnership’s consolidated balance sheet and were fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through termination date. For the year ended December 31, 2013, ARP recognized $14.5 million, respectively, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts.

In connection with the Carrizo Acquisition, ARP entered into swaption contracts up through May 31, 2012 for production volumes related to wells acquired from Carrizo (see Note 4). In connection with the swaption contracts, ARP paid premiums of $4.6 million, which represented their fair value on the date the transactions were initiated, were initially recorded as derivative assets on the Partnership’s consolidated balance sheet and were fully amortized as of September 30, 2012. For the year ended December 31, 2012, ARP recorded $4.6 million of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts.

ARP recognized gains of $9.7 million, $19.3 million and $10.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. As the underlying prices and terms in ARP’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2013, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At December 31, 2013, ARP had the following commodity derivatives:

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2014		60,153,000	$	4.152	$	(2,238	)
2015		51,474,500	$	4.236		4,639

159

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2016		45,746,300	$	4.311		8,183
2017		24,840,000	$	4.532		9,053
2018		3,960,000	$	4.716		1,819
					$	21,456

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/(Liability)
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2014	Puts purchased		3,840,000	$	4.221	$	1,322
2014	Calls sold		3,840,000	$	5.120		(363	)
2015	Puts purchased		3,480,000	$	4.234		1,747
2015	Calls sold		3,480,000	$	5.129		(639	)
						$	2,067

Natural Gas Put Options – Drilling Partnerships

Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Fair Value Asset
		(MMBtu)(1)		(per MMBtu)(1)		(in thousands)(2)
2014	Puts purchased		1,800,000	$	3.800	$	222
2015	Puts purchased		1,440,000	$	4.000		486
2016	Puts purchased		1,440,000	$	4.150		667
						$	1,375

Natural Gas Liquids Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2014		105,000	$	91.571	$	(417	)
2015		96,000	$	88.550		44
2016		84,000	$	85.651		183
2017		60,000	$	83.780		186
					$	(4	)

Natural Gas Liquids Ethane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset
	(Gal)(1)		(per Gal)(1)		(in thousands)(4)
2014		2,520,000	$	0.303	$	67
					$	67

160

Natural Gas Liquids Propane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Liability
	(Gal)(1)		(per Gal)(1)		(in thousands)(5)
2014		12,348,000	$	0.996	$	(1,409	)
2015		8,064,000	$	1.016		(144	)
					$	(1,553	)

Natural Gas Liquids Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Liability
	(Gal)(1)		(per Gal)(1)		(in thousands)(6)
2014		1,512,000	$	1.308	$	(27	)
2015		1,512,000	$	1.248		(70	)
					$	(97	)

Natural Gas Liquids Iso Butane Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Liability
	(Gal)(1)		(per Gal)(1)		(in thousands)(7)
2014		1,512,000	$	1.323	$	(7	)
2015		1,512,000	$	1.263		(99	)
					$	(106	)

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes		Average Fixed Price		Fair Value Asset/(Liability)
	(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2014		552,000	$	92.668	$	(1,657	)
2015		567,000	$	88.144		51
2016		225,000	$	85.523		463
2017		132,000	$	83.305		348
					$	(795	)

161

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes		Average Floor and Cap		Fair Value Asset/ (Liability)
		(Bbl)(1)		(per Bbl)(1)		(in thousands)(3)
2014	Puts purchased		41,160	$	84.169	$	79
2014	Calls sold		41,160	$	113.308		(36	)
2015	Puts purchased		29,250	$	83.846		158
2015	Calls sold		29,250	$	110.654		(56	)
						$	145
					ARP’s net asset	$	22,555

⁽¹⁾  “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

⁽²⁾  Fair value based on forward NYMEX natural gas prices, as applicable.

⁽³⁾  Fair value based on forward WTI crude oil prices, as applicable.

⁽⁴⁾  Fair value based on forward Mt. Belvieu ethane prices, as applicable.

⁽⁵⁾  Fair value based on forward Mt. Belvieu propane prices, as applicable.

⁽⁶⁾  Fair value based on forward Mt. Belvieu butane prices, as applicable.

⁽⁷⁾  Fair value based on forward Mt. Belvieu iso butane prices, as applicable.

At December 31, 2013, ARP had net cash proceeds of $3.5 million related to ARP’s hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s consolidated balance sheet. ARP will allocate the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts. The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated balance sheets as of December 31, 2013 and 2012.

In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At December 31, 2013, net unrealized derivative assets of $1.4 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

At December 31, 2013, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 9), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility 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 its assets.

162

Atlas Pipeline Partners

APL has elected not to apply hedge accounting for derivative contracts entered into in July 2008 and after. Changes in the fair value of derivatives are recognized immediately within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated statements of operations. The change in fair value of commodity-based derivative instruments entered into prior to the discontinuation of hedge accounting was reclassified from within accumulated other comprehensive income on the Partnership’s consolidated balance sheets to gathering and processing revenue on the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. During the years ended December 31, 2012 and 2011, APL reclassified losses of $4.4 million and $6.8 million, respectively, out of accumulated other comprehensive income related to derivative contracts entered into prior to July 2008. No amounts were reclassified out of accumulated other comprehensive income related to derivative contracts entered into prior to July 2008 nor during the year ended December 31, 2013. As of December 31, 2012, all amounts had been reclassified out of accumulated other comprehensive income, and APL had no amounts outstanding within accumulated other comprehensive income.

The following table summarizes APL’s gross fair values of its derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets as of the dates indicated (in thousands):

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets
As of December 31, 2013
Current portion of derivative assets	$	1,310	$	(1,136	)	$	174
Long-term portion of derivative assets		5,082		(2,812	)		2,270
Current portion of derivative liabilities		1,612		(1,612	)		—
Long-term portion of derivative liabilities		949		(949	)		—
Total derivative assets	$	8,953	$	(6,509	)	$	2,444
As of December 31, 2012
Current portion of derivative assets	$	23,534	$	(457	)	$	23,077
Long-term portion of derivative assets		9,637		(1,695	)		7,942
Total derivative assets	$	33,171	$	(2,152	)	$	31,019

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets
Offsetting Derivative Liabilities
As of December 31, 2013
Current portion of derivative assets	$	(1,136	)	$	1,136	$	—
Long-term portion of derivative assets		(2,812	)		2,812		—
Current portion of derivative liabilities		(12,856	)		1,612		(11,244	)
Current portion of derivative liabilities		(1,269	)		949		(320	)
Total derivative liabilities	$	(18,073	)	$	6,509	$	(11,564	)

163

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets
As of December 31, 2012
Current portion of derivative liabilities	$	(457	)	$	457	$	—
Long-term portion of derivative liabilities		(1,695	)		1,695		—
Total derivative liabilities	$	(2,152	)	$	2,152	$	—

As of December 31, 2013, APL had the following commodity derivatives:

Fixed Price Swaps

Production Period	Purchased/ Sold	Commodity	Volumes(2)		Average Fixed Price		Fair Value Asset/ (Liability) (in thousands)(1)
Natural Gas
2014	Sold	Natural Gas		12,900,000	$	3.984	$	(2,588	)
2015	Sold	Natural Gas		16,960,000	$	4.225		1,368
2016	Sold	Natural Gas		6,150,000	$	4.302		950
Natural Gas Liquids
2014	Sold	Natural Gas Liquids		82,404,000	$	1.180		(9,791	)
2015	Sold	Natural Gas Liquids		41,454,000	$	1.078		(2,083	)
2016	Sold	Natural Gas Liquids		6,300,000	$	1.034		(92	)
Crude Oil
2014	Sold	Crude Oil		312,000	$	92.368		(1,245	)
2015	Sold	Crude Oil		60,000	$	85.130		(186	)
Total Fixed Price Swaps							$	(13,667	)

Options

Production Period	Purchased/ Sold	Type	Commodity	Volumes(2)		Average Strike Price		Fair Value Asset (in thousands) (1)
Natural Gas
2014	Purchased	Put	Natural Gas		600,000	$	4.125	$	168
Natural Gas Liquids
2014	Purchased	Put	Natural Gas Liquids		4,410,000	$	1.001		100

164

Production Period	Purchased/ Sold	Type	Commodity	Volumes(2)		Average Strike Price		Fair Value Asset (in thousands) (1)
2015	Purchased	Put	Natural Gas Liquids		1,890,000	$	0.901		110
Crude Oil
2014	Purchased	Put	Crude Oil		448,500	$	94.685		2,019
2015	Purchased	Put	Crude Oil		270,000	$	89.175		2,150
Total Options								$	4,547
							APL’s net liability	$	(9,120	)

⁽¹⁾  See Note 11 for discussion on fair value methodology.

⁽²⁾  Volumes for natural gas are stated in MMBtu’s. Volumes for NGLs are stated in gallons. Volumes for crude oil are stated in barrels.

The following tables summarize APL’s derivatives not designated as hedges, which are included within gain on mark-to market derivatives on the Partnerships consolidated statements of operations:

	Years Ended December 31,
	2013			2012		2011
Gain (loss) recognized in gain (loss) on mark-to-market derivatives:
Commodity contract—realized(1)	$	(324	)	$	10,993	$	(13,124	)
Commodity contract – unrealized(2)		(28,440	)		20,947		(7,329	)
Gain (loss) on mark-to-market derivatives	$	(28,764	)	$	31,940	$	(20,453	)

⁽¹⁾  Realized gain (loss) represents the gain (loss) incurred when the derivative contract expires and/or is cash settled.

⁽²⁾  Unrealized gain (loss) represents the mark-to-market gain (loss) recognized on open derivative contracts, which have not yet settled.

The fair value of the derivatives included in the Partnership’s consolidated balance sheets for the periods indicated was as follows (in thousands):

	December 31,
	2013			2012
Current portion of derivative asset	$	2,066		$	35,351
Long-term derivative asset		30,868			16,840
Current portion of derivative liability		(17,630	)		—
Long-term derivative liability		(387	)		(888	)
Total Partnership net asset	$	14,917		$	51,303

165

NOTE 11 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership and its subsidiaries own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership and its subsidiaries use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 10). The Partnership and its subsidiaries manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. The Partnership and its subsidiaries’ commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and NGL options, are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Valuations for APL’s NGL fixed price swaps are based on forward price curves provided by a third party, which are considered to be Level 3 inputs. The prices for propane, iso butane, normal butane and natural gasoline are adjusted based upon the relationship between the prices for the product/locations quoted by the third party and the underlying product/locations utilized for the swap contracts, as determined by a regression model of the historical settlement prices for the different product/locations. The regression model is recalculated on a quarterly basis. This adjustment is an unobservable Level 3 input. The NGL fixed price swaps are over the counter instruments which are not actively traded in an open market. However, the prices for the underlying products and locations do have a direct correlation to the prices for the products and locations provided by the third party, which are based upon trading activity for the products and locations quoted. A change in the relationship between these prices would have a direct impact upon the unobservable adjustment utilized to calculate the fair value of the NGL fixed price swaps. Valuations for APL’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3. The NGL options are over the counter instruments that are not actively traded in an open market, thus APL utilizes the valuations provided by the financial institutions that provide the NGL options for trade. These valuations are tested for reasonableness through the use of an internal valuation model.

Information for the Partnership’s and its subsidiaries’ assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows (in thousands):

	Level 1		Level 2			Level 3		Total
As of December 31, 2013
Derivative assets, gross
Commodity swaps	$	—	$	1,634		$	—	$	1,634
ARP Commodity swaps		—		33,594			—		33,594
ARP Commodity puts		—		1,374			—		1,374
ARP Commodity options		—		3,305			—		3,305
APL Commodity swaps		—		2,994			1,412		4,406
APL Commodity options		—		4,337			210		4,547
Total derivative assets, gross		—		47,238			1,622		48,860
Derivative liabilities, gross
Commodity swaps		—		(152	)		—		(152	)

166

	Level 1		Level 2			Level 3			Total
ARP Commodity swaps		—		(14,624	)		—			(14,624	)
ARP Commodity options		—		(1,094	)		—			(1,094	)
APL Commodity swaps		—		(4,695	)		(13,378	)		(18,073	)
Total derivative liabilities, gross		—		(20,565	)		(13,378	)		(33,943	)
Total derivatives, fair value, net	$	—	$	26,673		$	(11,756	)	$	14,917
As of December 31, 2012
Derivative assets, gross
ARP Commodity swaps	$	—	$	15,859		$	—		$	15,859
ARP Commodity puts		—		2,991			—			2,991
ARP Commodity options		—		10,923			—			10,923
APL Commodity swaps		—		2,007			17,573			19,580
APL Commodity options		—		7,322			6,269			13,591
Total derivative assets, gross		—		39,102			23,842			62,944
Derivative liabilities, gross
ARP Commodity swaps		—		(6,813	)		—			(6,813	)
ARP Commodity puts		—		—			—			—
ARP Commodity options		—		(2,676	)		—			(2,676	)
APL Commodity swaps		—		(1,393	)		(759	)		(2,152	)
Total derivative liabilities, gross		—		(10,882	)		(759	)		(11,641	)
Total derivatives, fair value, net	$	—	$	28,220		$	23,083		$	51,303

APL’s Level 3 fair value amounts relate to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments for the periods indicated (in thousands):

	NGL Fixed Price Swaps						NGL Put Options						Total
	Gallons			Amount			Gallons			Amount			Amount
Balance – January 1, 2012		49,644		$	(1,733	)		92,610		$	18,279		$	16,546
New contracts(1)		84,294			—			—			—			—
Cash settlements from unrealized gain (loss)(2)(3)		(46,872	)		(7,863	)		(54,054	)		(142	)		(8,005	)
Net change in unrealized loss(2)		—			26,410			—			923			27,333
Option premium recognition(3)		—			—			—			(12,791	)		(12,791	)

167

	NGL Fixed Price Swaps						NGL Put Options						Total
	Gallons			Amount			Gallons			Amount			Amount
Balance – December 31, 2012		87,066		$	16,814			38,556		$	6,269		$	23,083
New contracts(1)		104,328			—			7,560			816			816
Cash settlements from unrealized gain (loss)(2)(3)		(61,236	)		(11,496	)		(39,816	)		8,545			(2,951	)
Net change in unrealized loss(2)		—			(17,284	)		—			(2,367	)		(19,651	)
Option premium recognition(3)		—			—			—			(13,053	)		(13,053	)
Balance – December 31, 2013		130,158		$	(11,966	)		6,300		$	210		$	(11,756	)

⁽¹⁾  Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade.

⁽²⁾  Included within gain (loss) on mark-to-market derivatives on the Partnership’s consolidated statements of operations.

⁽³⁾  Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration.

The following table provides a summary of the unobservable inputs used in the fair value measurement of APL’s NGL fixed price swaps at December 31, 2013 and 2012 (in thousands):

	Gallons		Third Party Quotes(1)			Adjustments(2)			Total Amount
As of December 31, 2013
Propane swaps		100,296	$	(10,260	)	$	—		$	(10,260	)
Iso butane swaps		6,300		(2,342	)		955			(1,387	)
Normal butane swaps		7,560		40			322			362
Natural gasoline swaps		16,002		132			(813	)		(681	)
Total NGL swaps — December 31, 2013		130,158	$	(12,430	)	$	464		$	(11,966	)
As of December 31, 2012
Propane swaps		69,678	$	16,302		$	(552	)	$	15,750
Iso butane swaps		1,134		(219	)		187			(32	)
Normal butane swaps		6,174		(909	)		242			(667	)
Natural gasoline swaps		10,080		3,247			(1,484	)		1,763
Total NGL swaps – December 31, 2012		87,066	$	18,421		$	(1,607	)	$	16,814

⁽¹⁾  Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap.

⁽²⁾  Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three year historical period.

168

The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for APL’s NGL fixed price swaps for the periods indicated (in thousands):

				Adjustment Based upon Regression Coefficient
	Level 3 Fair Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of December 31, 2013
Iso butane swaps	$	955			1.1184		1.1284		1.1234
Normal butane swaps		322			1.0341		1.0386		1.0364
Natural gasoline swaps		(813	)		0.9727		0.9751		0.9739
Total NGL swaps – December 31, 2013	$	464

				Adjustment Based upon Regression Coefficient
	Level 3 Fair Value Adjustments			Lower 95%		Upper 95%		Average Coefficient
As of December 31, 2012
Propane swaps	$	(552	)		0.9019		0.9122		0.9071
Iso butane swaps		187			1.1285		1.1376		1.1331
Normal butane swaps		242			1.0370		1.0416		1.0393
Natural gasoline swaps		(1,484	)		0.8988		0.9169		0.9078
Total NGL swaps – December 31, 2012	$	(1,607	)

APL had $14.5 million and $7.8 million of NGL linefill at December 31, 2013 and 2012, respectively, which were included within prepaid expenses and other on the Partnership’s consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties for which the counterparty will pay at a designated later period at a price determined by the then market price. APL’s NGL linefill held by one counterparty will be settled at various periods in the future and is defined as a Level 3 asset, which is valued using the same forward price curve utilized to value APL’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was a reduction of $0.4 million and $0.4 million as of December 31, 2013 and 2012, respectively. APL’s NGL linefill held by other counterparties is adjusted on a monthly basis according to the volumes delivered to the counterparties each period and is valued on a first in first out (“FIFO”) basis.

The following table provides a summary of changes in fair value of APL’s NGL linefill for the years ended December 31, 2013 and 2012 (in thousands):

	Linefill Valued at Market						Linefill Valued on FIFO						Total NGL Linefill
	Gallons			Amount			Gallons			Amount			Gallons			Amount
Balance – January 1, 2012		10,408		$	11,529			—		$	—		$	10,408		$	11,529
Cash Settlements(1)		(2,520	)		(2,698	)		—			—			(2,520	)		(2,698	)
Net change in NGL linefill valuation(1)		—			(2,111	)		—			—			—			(2,111	)
Acquired NGL linefill(2)		1,260			1,063			—			—			1,260			1,063
Balance – December 31, 2012		9,148		$	7,783			—		$	—			9,148		$	7,783
Deliveries into NGL linefill		—			—			80,758			60,565			80,758			60,565
NGL linefill sales		(3,360	)		(2,795	)		(71,433	)		(52,155	)		(74,793	)		(54,950	)
Net change in NGL linefill valuation(1)		—			(249	)		—			—			—			(249	)
Acquired NGL linefill(2)		—			—			2,213			1,368			2,213			1,368
Balance – December 31, 2013		5,788		$	4,739			11,538		$	9,778			17,326		$	14,517

⁽¹⁾  Included within gathering and processing revenues on the Partnership’s consolidated statements of operations.

⁽²⁾  NGL linefill acquired as part of the Cardinal and TEAK acquisitions (see Note 4).

169

Other Financial Instruments

The estimated fair value of the Partnership and its subsidiaries’ other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership and its subsidiaries could realize upon the sale or refinancing of such financial instruments.

The Partnership and its subsidiaries’ other current assets and liabilities on its consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of the Partnership and its subsidiaries’ debt at December 31, 2013 and 2012, which consist principally of ARP’s and APL’s senior notes and borrowings under the Partnership’s, ARP’s and APL’s revolving and term loan credit facilities, were $2,841.7 million and $1,576.9 million, respectively, compared with the carrying amounts of $2,889.0 million and $1,540.3 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP and APL senior notes were based upon the market approach and calculated using the yields of the ARP and APL senior notes as provided by financial institutions and thus were categorized as a Level 3 value.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership and ARP estimate the fair value of their respective asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and ARP and estimated inflation rates (see Note 8).

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2013 and 2012 was as follows (in thousands):

	Years Ended December 31,
	2013				2012
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	23,129	$	23,129	$	16,568	$	16,568
Total	$	23,129	$	23,129	$	16,568	$	16,568

Management estimates the fair value of the Partnership’s and ARP’s long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. For the years ended December 31, 2013, 2012, and 2011, ARP recognized $38.0 million, $9.5 million and $7.0 million, respectively, of impairment of long-lived assets which were defined as a Level 3 fair value measurements (see Note 2 – Impairment of Long-Lived Assets).

170

During the year ended December 31, 2013, the Partnership completed the Arkoma Acquisition and ARP completed the EP Energy Acquisition. During the year ended December 31, 2013, APL completed the TEAK Acquisition. During the year ended December 31, 2012, ARP completed the acquisitions of certain oil and gas assets from Carrizo, certain proved reserves and associated assets from Titan, Equal and DTE, while APL completed the Cardinal Acquisition (see Note 4). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimates of fair value of the EP Energy and TEAK acquisitions as of their respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of December 31, 2013, are subject to change as the final valuation has not yet been completed, and such changes may be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Partnership’s and ARP’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 8). These inputs require significant judgments and estimates by the Partnership’s and ARP’s management at the time of the valuation and are subject to change.

In February 2012, APL acquired a gas gathering system and related assets 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, if certain volumes are achieved on the acquired gathering system within a specified time period (“Trigger Payments”). Sufficient volumes were achieved in December 2012, and APL paid the first Trigger Payment of $6.0 million in January 2013. As of December 31, 2013, the fair value of the remaining Trigger Payment resulted in a $6.0 million long-term liability, which was recorded within other long-term liabilities on the Partnership’s consolidated balance sheets. The range of the undiscounted amounts APL could pay related to the remaining Trigger Payment is up to $6.0 million.

NOTE 12 – INCOME TAXES

In connection with the Cardinal Acquisition (see Note 4), APL acquired a taxable subsidiary in December 2012. The components of the federal and state income tax expense (benefit) for APL’s taxable subsidiary for the years ended December 31, 2013 and 2012 are as follows (in thousands):

	Years Ended December 31,
	2013			2012
Deferred expense (benefit):
Federal	$	(2,024	)	$	158
State		(236	)		18
Total income tax expense (benefit)	$	(2,260	)	$	176

As of December 31, 2013 and 2012, APL had non-current net deferred income tax liabilities of $33.3 million and $30.3 million, respectively. The components of net deferred tax liabilities as of December 31, 2013 and 2012 consist of the following (in thousands):

	Years Ended December 31,
	2013			2012
Deferred tax assets:
Net operating loss tax carryforwards and alternative minimum tax credits	$	14,900		$	10,277
Deferred tax liabilities:
Excess of asset carrying value over tax basis		(48,190	)		(40,535	)
Net deferred tax liabilities	$	(33,290	)	$	(30,258	)

As of December 31, 2013, APL had net operating loss carry forwards for federal income tax purposes of approximately $38.5 million, which expire at various dates from 2029 to 2033. APL believes it more likely than not that the deferred tax asset will be fully utilized. APL expects all goodwill recorded to be deductible for tax purposes.

171

NOTE 13 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with Drilling Partnerships. ARP conducts certain activities through, and a portion of its revenues are attributable to, the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

Relationship between ARP and APL. In the Chattanooga Shale, a portion of the natural gas produced by ARP is gathered and processed by APL. For the years ended December 31, 2013, 2012 and 2011, $0.3 million, $0.4 million and $0.3 million, respectively, of gathering fees paid by ARP to APL were eliminated in consolidation.

In addition, in Lycoming County, Pennsylvania, APL agreed to provide assistance in the design and construction management services for ARP with respect to a pipeline. ARP reimbursed approximately $1.8 million to APL as of December 31, 2013.

Relationship with Resource America, Inc. In connection with the issuance of the Term Facility, CVC Credit Partners, LLC (“CVC”), which is a joint-venture between Resource America, Inc. and an unrelated third party private equity firm, was allocated an aggregate of $12.5 million of the Term Facility. The Partnership’s Chief Executive Officer and President is Chairman of the board of directors of Resource America, Inc., and the Partnership’s Executive Chairman of the General Partner’s board of directors is Chief Executive Officer and President and Resource America, Inc.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

General Commitments

The Partnership leases office space and equipment under leases with varying expiration dates. Rental expense was $24.4 million, $9.6 million and $7.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):

Years Ended December 31,
2014	$	8,532
2015		7,106
2016		6,259
2017		3,312
2018		2,337
Thereafter		6,105
	$	33,651

ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by ARP, as managing general partner. ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, as of December 31, 2013, the management of ARP believes that any such liability incurred would not be material. Also, ARP has agreed to subordinate a portion of its share of net partnership revenues from certain of the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% per year determined on a cumulative basis, over a specific period, typically the first five to eight years, in accordance with the terms of the partnership agreements. For the years ended December 31, 2013, 2012 and 2011, $9.6 million, $6.3 million and $4.0 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.

172

The Partnership and its subsidiaries are party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

In connection with ARP’s EP Energy Acquisition (see Note 4), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of December 31, 2013 were as follows: 2014—$8.8 million; 2015—$8.6 million; 2016—$2.1 million; and 2017 to 2018—none.

APL has certain long-term unconditional purchase obligations and commitments, primarily transportation contracts. These agreements provide for transportation services to be used in the ordinary course of APL’s operations. Transportation fees paid related to these contracts, including minimum shipment payments, were $34.8 million, $10.5 million and $10.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. The future fixed and determinable portions of APL’s obligations as of December 31, 2013 were as follows: 2014—$9.5 million; 2015 to 2017—$3.5 million per year; and 2018—$2.7 million.

As of December 31, 2013, the Partnership and its subsidiaries are committed to expend approximately $116.4 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

Legal Proceedings

The Partnership and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership and its subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 15 — ISSUANCES OF UNITS

The Partnership

The Partnership recognizes gains on ARP’s and APL’s equity transactions as credits to partners’ capital on its consolidated balance sheets rather than as income on its consolidated statements of operations. These gains represent the Partnership’s portion of the excess net offering price per unit of each of ARP’s and APL’s common units over the book carrying amount per unit.

Purchase of ARP Preferred Units.

In July 2013, in connection with ARP’s EP Energy Acquisition (see Note 4), the Partnership purchased 3,746,986 of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ended September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, the Partnership, as purchaser of the Class C preferred units, also received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of ARP common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

Equity Offerings

In February 2011, the Partnership paid $30.0 million in cash and issued approximately 23.4 million newly issued common limited partner units for the Transferred Business acquired from AEI. Based on the Partnership’s common limited partner unit’s February 17, 2011 closing price on the NYSE, the common units issued to AEI were valued approximately at $372.2 million (see Note 3).

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Atlas Resource Partners

Equity Offerings

In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 4), ARP issued 3,749,986 newly created Class C convertible preferred units to the Partnership at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were issued with 562,497 warrants to purchase ARP common units at an exercise price of $23.10 at the Partnership’s option beginning on October 29, 2013. The warrants will expire on July 31, 2016. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act (see “Purchase of ARP Preferred Units”).

Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

In June 2013, in connection with the EP Energy Acquisition (see Note 4), ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 9).

In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. Sales of common limited partner units, if any, could be made in negotiated transactions or transactions that were deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the NYSE, the existing trading market for the common limited partner units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP paid each of the agents a commission, which in each case was not more than 2.0% of the gross sales price of common limited partner units sold through such agent. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated its equity distribution agreement effective December 27, 2013.

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 of 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 then-existing term loan credit facility.

In July 2012, ARP completed the acquisition of certain proved reserves and associated assets in the Barnett Shale from Titan in exchange for 3.8 million ARP common units and 3.8 million newly-created convertible ARP Class B preferred units (which have an estimated collective value of $193.2 million, based upon the closing price of ARP’s publicly traded common units as of the acquisition closing date), as well as $15.4 million in cash for closing adjustments (see Note 4). The Class B preferred units are voluntarily convertible to common units on a one-for-one basis within three years of the acquisition closing date at a strike price of $26.03 plus all unpaid preferred distributions per unit, and will be mandatorily converted to common units on the third anniversary of the issuance. While outstanding, the preferred units will receive regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution.

ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC by January 25, 2013 to register the resale of the ARP common units issued on the acquisition closing date and those issuable upon conversion of the Class B preferred units. ARP agreed to use its commercially reasonable efforts to have the registration statement declared effective by March 31, 2013, and to cause the registration statement to be continuously effective until the earlier of (i) the date as of which all such common units registered thereunder are sold by the holders and (ii) one year after the date of effectiveness. On September 19, 2012, ARP filed a registration statement with the SEC in satisfaction of the registration requirements of the registration rights agreement, and the registration statement was declared effective by the SEC on October 2, 2012.

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In April 2012, ARP completed the acquisition of certain oil and gas assets from Carrizo (see Note 4). To partially fund the acquisition, ARP sold 6.0 million of its common units in a private placement at a negotiated purchase price per unit of $20.00, for net proceeds of $119.5 million, of which $5.0 million was purchased by certain executives of the Partnership. The common units issued by ARP are subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that ARP would (a) file a registration statement with the SEC by October 30, 2012 and (b) cause the registration statement to be declared effective by the SEC by December 31, 2012. On July 11, 2012, ARP filed a registration statement with the SEC for the common units subject to the registration rights agreement in satisfaction of one of the requirements of the registration rights agreement noted previously. On August 28, 2012, the registration statement was declared effective by the SEC.

In connection with the issuance of ARP’s common and preferred units during the years ended December 31, 2013 and 2012, the Partnership recorded gains of $27.3 million and $66.6 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheets and consolidated statement of partners’ capital.

ARP Common Unit Distribution

In February 2012, the board of directors of the Partnership’s general partner approved the distribution of approximately 5.24 million of ARP’s common limited partner units which were distributed on March 13, 2012 to the Partnership’s unitholders using a ratio of 0.1021 ARP common limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012.

Atlas Pipeline Partners

Equity Offerings

In April 2013, APL sold 11,845,000 of its common units in a public offering at a price of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. APL also received a capital contribution from the Partnership of $8.3 million to maintain its 2.0% general partnership interest in APL. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see Note 4).

In May 2013, APL issued $400.0 million of its Class D Preferred Units in a private placement transaction, at a negotiated price per unit of $29.75, resulting in net proceeds of $397.7 million pursuant to the Class D preferred unit purchase agreement dated April 16, 2013 (the “Commitment Date”). The Partnership, as general partner, contributed $8.2 million to maintain its 2.0% general partnership interest in APL, upon the issuance of the Class D Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see Note 4).

The Class D Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. APL has the right to convert the Class D Preferred Units, in whole but not in part, beginning one year following their issuance, into an equal number of common units, subject to customary anti-dilution adjustments. Unless previously converted, all Class D Preferred Units will convert into common units on May 7, 2015. In the event of any liquidation, dissolution or winding up of APL or the sale or other disposition of all or substantially all of the assets of APL, the holders of the Class D Preferred Units are entitled to receive, out of the assets of APL available for distribution to unitholders, prior and in preference to any distribution of any assets of APL to the holders of any other existing or subsequently issued units, an amount equal to $29.75 per Class D Preferred Unit plus any unpaid preferred distributions.

The fair value of APL’s common units on April 16, 2013 was $36.52 per unit, resulting in an embedded beneficial conversion discount on the Class D Preferred Units of $91.0 million. The Partnership recognized the fair value of the Class D Preferred Units with the offsetting intrinsic discount within non-controlling interests on the Partnership’s consolidated balance sheet as of December 31, 2013. The discount will be accreted and recognized by APL as imputed dividends over the term of the Class D Preferred Units as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. For the year ended December 31, 2013, APL recorded $29.5 million within income (loss) attributable to non-controlling interests for the preferred unit imputed dividend effect on the Partnership’s consolidated statements of operations to recognize the accretion of the beneficial conversion discount. APL’s Class D Preferred Units are presented combined with a net $61.5 million unaccreted beneficial conversion discount within non-controlling interests on the Partnership’s consolidated balance sheet at December 31, 2013.

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The Class D Preferred Units will receive distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of the Partnership, as general partner. Cash distributions will be paid to the Class D Preferred Unitholders prior to any other distributions of available cash. Distributions will be determined based upon the cash distribution declared each quarter on APL’s common limited partner units plus a preferred yield premium. Class D Preferred Unit distributions, whether in kind units or in cash, will be accounted for as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. For the year ended December 31, 2013, APL recorded costs related to preferred unit distributions in kind of $23.6 million within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations. During the year ended December 31, 2013, APL distributed 378,486 Class D Preferred Units to the holders of the Class D Preferred Units as a distribution in kind. APL’s Class D Preferred Unit distributions paid in kind represented non-cash transactions during the year ended December 31, 2013.

Upon the issuance of the Class D Preferred Units, APL entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class D Preferred Units. APL agreed to use its commercially reasonable efforts to have the registration statement declared effective within 180 days of the date of conversion.

APL had an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL offered and sold through Citigroup, as its sales agent, common units for $150.0 million. Sales were at market prices prevailing at the time of the sale. During the years ended December 31, 2013 and 2012, APL issued 3,895,679 and 275,429 common units, respectively, under the equity distribution program for net proceeds of $137.8 million and $8.7 million, net of $2.8 million and $0.2 million, respectively, in sales commissions incurred and other offering costs. APL also received capital contributions from the Partnership of $2.9 million and $0.2 million during the years ended December 31, 2013 and 2012, respectively, to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from the common unit offering for general partnership purposes. As of December 31, 2013, APL had used the full capacity under the equity distribution program.

In December 2012, 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 the Partnership to maintain its 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%, or $4.0 million.

In connection with the issuance of APL’s common units during the years ended December 31, 2013 and 2012, the Partnership recorded an $11.9 million and $7.9 million gain, respectively, within partner’s capital and a corresponding decrease in non-controlling interests on its consolidated statement of partners’ capital during the years ended December 31, 2013 and 2012.

On May 27, 2011, APL redeemed the 8,000 12% Cumulative Class C Limited Partner Preferred Units (the “APL Class C Preferred Units”) newly-created in June 2010 for cash, at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividends on the 8,000 APL Class C Preferred Units prior to APL’s redemption. Subsequent to the redemption, APL had no APL Class C Preferred Units outstanding.

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NOTE 16 — CASH DISTRIBUTIONS

The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2011 through December 31, 2013 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distributions Paid to Common Limited Partners
May 20, 2011	March 31, 2011	$	0.11	$	5,635
August 19, 2011	June 30, 2011	$	0.22	$	11,276
November 18, 2011	September 30, 2011	$	0.24	$	12,303
February 17, 2012	December 31, 2011	$	0.24	$	12,307
May 18, 2012	March 31, 2012	$	0.25	$	12,830
August 17, 2012	June 30, 2012	$	0.25	$	12,831
November 19, 2012	September 30, 2012	$	0.27	$	13,866
February 19, 2013	December 31, 2012	$	0.30	$	15,410
May 20, 2013	March 31, 2013	$	0.31	$	15,928
August 19, 2013	June 30, 2013	$	0.44	$	22,611
November 19, 2013	September 30, 2013	$	0.46	$	23,649

On January 29, 2014, the Partnership declared a cash distribution of $0.46 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2013. The $23.7 million distribution was paid on February 19, 2014 to unitholders of record at the close of business on February 10, 2014.

ARP Cash Distributions. ARP has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. If ARP’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels.

Distributions declared by ARP from its formation through December 31, 2013 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit			Total Cash Distribution to Common Limited Partners		Total Cash Distribution To Preferred Limited Partners		Total Cash Distribution to the General Partner
May 15, 2012	March 31, 2012	$	0.12	(1)	$	3,144	$	—	$	64
August 14, 2012	June 30, 2012	$	0.40		$	12,891	$	—	$	263
November 14, 2012	September 30, 2012	$	0.43		$	15,510	$	1,652	$	350
February 14, 2013	December 31, 2012	$	0.48		$	21,107	$	1,841	$	618
May 15, 2013	March 31, 2013	$	0.51		$	22,428	$	1,957	$	946
August 14, 2013	June 30, 2013	$	0.54		$	32,097	$	2,072	$	1,884
November 14, 2013	September 30, 2013	$	0.56		$	33,291	$	4,248	$	2,443

⁽¹⁾  Represents a pro-rated cash distribution of $0.40 per common limited partner unit for the period from March 5, 2012, the date the Partnership’s exploration and production assets were transferred to ARP, to March 31, 2012.

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On January 29, 2014, ARP 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, 2013. The $41.8 million distribution, including $2.9 million and $4.4 million to the Partnership, as general partner, and preferred limited partners, respectively, was paid on February 14, 2014 to unitholders of record at the close of business on February 10, 2014.

APL Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 13% and 48% of such distributions in excess of the specified target levels.

Common unit and general partner distributions declared by APL for the period from January 1, 2011 through December 31, 2013 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution to Common Limited Partners		Total APL Cash Distribution to the General Partner
May 13, 2011	March 31, 2011	$	0.40	$	21,400	$	439
August 12, 2011	June 30, 2011	$	0.47	$	25,184	$	967
November 14, 2011	September 30, 2011	$	0.54	$	28,953	$	1,844
February 14, 2012	December 31, 2011	$	0.55	$	29,489	$	2,031
May 15, 2012	March 31, 2012	$	0.56	$	30,030	$	2,217
August 14, 2012	June 30, 2012	$	0.56	$	30,085	$	2,221
November 14, 2012	September 30, 2012	$	0.57	$	30,641	$	2,409
February 14, 2013	December 31, 2012	$	0.58	$	37,442	$	3,117
May 15, 2013	March 31, 2013	$	0.59	$	45,382	$	3,980
August 14, 2013	June 30, 2013	$	0.62	$	48,165	$	5,875
November 14, 2013	September 30, 2013	$	0.62	$	49,298	$	6,013

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On January 28, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2013. The $56.1 million distribution, including $6.1 million to the Partnership as general partner, was paid on February 14, 2014 to unitholders of record at the close of business on February 7, 2014. Based on this declaration, APL issued approximately 274,785 Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended December 31, 2013 (see Note 19).

NOTE 17 — BENEFIT PLANS

2010 Long-Term Incentive Plan

The Board of Directors of the General Partner approved and adopted the Partnership’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,763,781 common limited partner units. At December 31, 2013, the Partnership had 4,506,946 phantom units and unit options outstanding under the 2010 LTIP, with 1,202,774 phantom units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the 2010 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership’s general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

• cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

• accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to the Partnership’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

• provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

• terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

• make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate.

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2010 Phantom Units. A phantom unit entitles a Participant to receive a Partnership common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units granted to employees under the 2010 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2010 LTIP at December 31, 2013, there are 482,943 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at December 31, 2013 include DERs. During the years ended December 31, 2013, 2012 and 2011, the Partnership paid $3.1 million, $2.0 million and $1.0 million, respectively, with respect to the 2010 LTIP DERs.

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The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2013					2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		2,044,227		$	20.90		1,838,164		$	22.11		—		$	—
Granted		112,000			50.26		133,080			29.95		1,891,539			22.11
Vested(1)		(25,684	)		19.87		(19,677	)		20.11		—			—
Forfeited		(76,009	)		20.67		(72,808	)		20.65		(53,375	)		21.21
ARP anti-dilution adjustment(3)		—			—		165,468			—		—			—
Outstanding, end of year(2)		2,054,534		$	22.58		2,044,227		$	20.90		1,838,164		$	22.11
Non-cash compensation expense recognized (in thousands)				$	11,848				$	11,612				$	8,060

⁽¹⁾  The aggregate intrinsic values of phantom unit awards vested were $1.3 million and $0.7 million, respectively, for the years ended December 31, 2013 and 2012. No phantom unit awards vested during the year ended December 31, 2011.

⁽²⁾  The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2013 was $96.3 million.

⁽³⁾  The number of 2010 phantom units was adjusted concurrently with the distribution of ARP common units.

At December 31, 2013, the Partnership had approximately $16.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.

2010 Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the Partnership’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2010 LTIP generally will vest over a three or four year period from the date of grant. There are 595,119 unit options outstanding under the 2010 LTIP at December 31, 2013 that will vest within the following twelve months. For the years ended December 31, 2013 and 2012, the Partnership received cash of $0.1 million and $0.1 million, respectively, from the exercise of options. No cash was received from the exercise of options for the year ended December 31, 2011.

The following table sets forth the 2010 LTIP unit option activity for the periods indicated:

	Years Ended December 31,
	2013					2012					2011
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		2,504,703		$	20.51		2,304,300		$	22.12		—		$	—
Granted		—			—		77,167			27.55		2,384,300			22.12
Exercised(1)		(3,262	)		20.44		(5,438	)		18.44		—			—
Forfeited		(49,029	)		20.38		(79,119	)		20.33		(80,000	)		22.23

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	Years Ended December 31,
	2013				2012				2011
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
ARP anti-dilution adjustment(2)		—		—		207,793		—		—		—
Outstanding, end of year(3)(4)		2,452,412	$	20.52		2,504,703	$	20.51		2,304,300	$	22.12
Options exercisable, end of year(5)		13,865	$	20.03		3,398	$	20.85		—	$	—
Non-cash compensation expense recognized (in thousands)			$	5,768			$	5,966			$	4,591

⁽¹⁾  The intrinsic value of options exercised during the years ended December 31, 2013 and 2012 was $0.1 million and $0.1 million, respectively. No options were exercised during the year ended December 31, 2011.

⁽²⁾  The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

⁽³⁾  The weighted average remaining contractual life for outstanding options at December 31, 2013 was 7.3 years.

⁽⁴⁾  The options outstanding at December 31, 2013 had an aggregate intrinsic value of $64.6 million.

⁽⁵⁾  The weighted average remaining contractual life for exercisable options at December 31, 2013 was 7.6 years. The intrinsic values of exercisable options at December 31, 2013 and 2012 were $0.4 million and approximately $47,000, respectively. No options were exercisable at December 31, 2011.

At December 31, 2013, the Partnership had approximately $5.7 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards. The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

	Years Ended December 31,
	2013			2012			2011
Expected dividend yield		—	%		3.7	%		1.6	%
Expected unit price volatility		—	%		45.0	%		48.0	%
Risk-free interest rate		—	%		1.4	%		2.7	%
Expected term (in years)		—			6.84			6.87
Fair value of unit options granted	$	—		$	8.08		$	9.79

2006 Long-Term Incentive Plan

The Board of Directors approved and adopted the Partnership’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for the Partnership. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,261,516 common limited partner units. At December 31, 2013, the Partnership had 1,174,879 phantom units and unit options outstanding under the 2006 LTIP, with 763,476 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

182

In the case of awards held by eligible employees, following a “change in control”, as defined in the 2006 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2006 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

2006 Phantom Units. Generally, phantom units granted to employees under the 2006 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2006 LTIP at December 31, 2013, 85,809 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at December 31, 2013 include DERs. During the years ended December 31, 2013, 2012 and 2011, respectively, the Partnership paid approximately $0.4 million, $42,000 and $20,000 with respect to 2006 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheets.

The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2013					2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		50,759		$	21.02		32,641		$	15.99		27,294		$	13.81
Granted		207,363			38.05		25,248			29.70		17,685			17.71
Vested (1) (2)		(20,182	)		21.34		(10,107	)		20.26		(12,338	)		13.65
Forfeited		(3,000	)		36.45		—			—		—			—
ARP anti-dilution adjustment(3)		—			—		2,977			—		—			—
Outstanding, end of year(4)(5)		234,940		$	35.82		50,759		$	21.02		32,641		$	15.99
Non-cash compensation expense recognized (in thousands)				$	5,317				$	660				$	422

(1) The intrinsic value for phantom unit awards vested during the years ended December 31, 2013, 2012 and 2011 were $1.0 million, $0.3 million and $0.2 million, respectively.

(2) There were 1,146 vested units during the year ended December 31, 2013 that were settled for approximately $52,000 cash. No units were settled in cash during the years ended December 31, 2012 and 2011.

(3) The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units.

(4) The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2013 was $11.0 million.

(5) There was $1.1 million and $0.7 million recognized as liabilities on the Partnership’s consolidated balance sheets at December 31, 2013 and 2012, respectively, representing 41,525 and 44,234 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units are $29.67 and $23.25 as of December 31, 2013 and 2012, respectively.

At December 31, 2013, the Partnership had approximately $4.0 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards.

2006 Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2006 LTIP will vest over a three or four year period from the date of grant. There are 2,500 unit options outstanding under the 2006 LTIP at December 31, 2013 that will vest within the following twelve months. For the years ended December 31, 2012 and 2011, the Partnership received cash of $0.2 million and $0.2 million, respectively, from the exercise of options. No cash was received from the exercise of options for the year ended December 31, 2013.

183

The following table sets forth the 2006 LTIP unit option activity for the periods indicated:

	Years Ended December 31,
	2013				2012					2011
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		929,939	$	20.75		903,614		$	21.52		955,000		$	20.54
Granted		10,000		38.51		—			—		—			—
Exercised(1)		—		—		(51,998	)		3.03		(51,386	)		3.24
Forfeited		—		—		—			—		—			—
ARP anti-dilution adjustment(2)		—		—		78,323			—		—			—
Outstanding, end of year(3)(4)		939,939	$	20.94		929,939		$	20.75		903,614		$	21.52
Options exercisable, end of year(5)		929,939	$	20.75		929,939		$	20.75		903,614		$	21.52
Non-cash compensation expense recognized (in thousands)			$	36				$	—				$	28

(1) The intrinsic values of options exercised during the years ended December 31, 2012 and 2011 were $1.5 million and $1.0 million, respectively. No options were exercised during the year ended December 31, 2013.

(2) The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

(3) The weighted average remaining contractual life for outstanding options at December 31, 2013 was 2.9 years.

(4) The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $24.4 million.

(5) The weighted average remaining contractual lives for exercisable options at December 31, 2013 and 2012 were 2.9 years and 3.9 years, respectively. The aggregate intrinsic values of options exercisable at December 31, 2013 and 2012 were $24.3 million and $13.0 million, respectively.

At December 31, 2013, the Partnership had approximately $39,000 of unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. The Partnership uses the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

	Years Ended December 31,
	2013			2012			2011
Expected dividend yield		3.2	%		—	%		—	%
Expected unit price volatility		30.0	%		—	%		—	%
Risk-free interest rate		0.7	%		—	%		—	%
Expected term (in years)		6.25			—			—
Fair value of unit options granted	$	7.54		$	—		$	—

The transfer of assets to ARP on March 5, 2012 and the subsequent distribution of ARP common units on March 13, 2012 resulted in an adjustment to the Partnership’s 2010 and 2006 long-term incentive plans. Concurrent with the distribution of ARP common units, the number of phantom units, restricted units and options in the plans were increased in an amount equivalent to the percentage change in the Partnership’s publicly traded unit price from the closing price on March 13, 2012 to the opening price on March 14, 2012. In addition, the strike price of unit option awards was decreased by the same percentage change.

184

ARP Long-Term Incentive Plan

ARP has a 2012 Long-Term Incentive Plan effective March 2012 (the “ARP LTIP”). Awards of options to purchase units, restricted units and phantom units may be granted to officers, employees and directors of ARP’s general partner under the ARP LTIP, and such awards may be subject to vesting terms and conditions in the discretion of the administrator of the ARP LTIP. Up to 2,900,0000 common units of ARP, subject to adjustment as provided for under the ARP LTIP, may be issued pursuant to awards granted under the ARP LTIP. The ARP LTIP is administered by the Compensation Committee of the board (the “ARP LTIP Committee”). At December 31, 2013, ARP had 2,322,483 phantom units, restricted units and unit options outstanding under the ARP LTIP, with 352,586 phantom units, restricted units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Partnership, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

• cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

• accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

• provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

• terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

• make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate.

ARP Phantom Units. Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at December 31, 2013, 278,795 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at December 31, 2013 include DERs. During the years ended December 31, 2013 and 2012, ARP paid $1.9 million and $0.7 million, respectively, with respect to the 2012 ARP LTIP’s DERs. No amounts were paid during the year ended December 31, 2011. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheets.

185

The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2013					2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding, beginning of year		948,476		$	24.76		—		$	—		—	$	—
Granted		145,813			21.87		949,476			24.76		—		—
Vested (1)		(215,981	)		24.73		—			—		—		—
Forfeited		(38,500	)		23.96		(1,000	)		24.67		—		—
Outstanding, end of year(2)(3)		839,808		$	24.31		948,476		$	24.76		—	$	—
Non-cash compensation expense recognized (in thousands)				$	9,166				$	7,630			$	—

(1) The intrinsic value of phantom unit awards vested during the year ended December 31, 2013 was $6.1 million. No phantom unit awards vested during the years ended December 31, 2012 and 2011.

(2) The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2013 was $17.2 million.

(3) There was approximately $81,000 and $31,000 recognized as liabilities on the Partnership’s consolidated balance sheets at December 31, 2013 and December 31, 2012, respectively, representing 16,084 and 3,476 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $22.15 and $28.75 at December 31, 2013 and 2012, respectively.

At December 31, 2013, ARP had approximately $8.9 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards.

ARP Unit Options. The exercise price of the unit option may be equal to or more than the fair market value of ARP’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 370,750 unit options outstanding under the ARP LTIP at December 31, 2013 that will vest within the following twelve months. No cash was received from the exercise of options for the years ended December 31, 2013, 2012 and 2011.

The following table sets forth the ARP LTIP unit option activity for the periods indicated:

	Years Ended December 31,
	2013					2012					2011
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of year		1,515,500		$	24.68		—		$	—		—	$	—
Granted		5,000			21.56		1,517,500			24.68		—		—
Exercised(1)		—			—		—			—		—		—
Forfeited		(37,825	)		24.80		(2,000	)		24.67		—		—
Outstanding, end of year(2)(3)		1,482,675		$	24.66		1,515,500		$	24.68		—	$	—
Options exercisable, end of year(4)		370,700		$	24.67		—		$	—		—	$	—
Non-cash compensation expense recognized (in thousands)				$	3,514				$	3,198			$	—

186

⁽¹⁾  No options were exercised during the years ended December 31, 2013, 2012 and 2011.

⁽²⁾  The weighted average remaining contractual life for outstanding options at December 31, 2013 was 8.4 years.

⁽³⁾  The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000.

⁽⁴⁾  The weighted average remaining contractual life for exercisable options at December 31, 2013 was 8.4 years. There were no aggregate intrinsic values of options exercisable at December 31, 2013, 2012 and 2011.

At December 31, 2013, ARP had approximately $2.8 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

187

The following weighted average assumptions were used for the periods indicated:

	Years Ended December 31,
	2013			2012			2011
Expected dividend yield		8.0	%		5.9	%		—	%
Expected unit price volatility		35.5	%		47.0	%		—	%
Risk-free interest rate		1.4	%		1.0	%		—	%
Expected term (in years)		6.31			6.25			—
Fair value of unit options granted	$	2.95		$	6.10		$	—

APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“APL 2004 LTIP”), and a 2010 Long-Term Incentive Plan, which was modified on April 26, 2011 (“APL 2010 LTIP” and collectively with the APL 2004 LTIP, the “APL LTIPs”), in which officers, employees and non-employee managing board members of APL’s general partner and employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by APL’s compensation committee (the “APL LTIP Committee”). Under the APL LTIPs, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At December 31, 2013, APL had 1,446,553 phantom units outstanding under the APL LTIPs, with 840,870 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options, which have vested and have been exercised. Share based payments to non-employees that have a cash settlement option are recognized within liabilities in the consolidated financial statements based upon their current fair market value.

APL Phantom Units. Through December 31, 2013, phantom units granted under the APL LTIPs generally had vesting periods of four years. In conjunction with the approval of the APL 2010 LTIP, the holders of 300,000 equity indexed bonus units (“Bonus Units”), under APL’s plan discussed below, agreed to exchange their Bonus Units for an equivalent number of phantom units. These phantom units vested over a three year period. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of APL’s board automatically vest upon a change of control, as defined in the APL LTIPs. Of the units outstanding under the APL LTIPs at December 31, 2013, 464,452 units will vest within the following twelve months. APL is authorized to purchase common units from employees to cover employee-related taxes when certain phantom units have vested. During the years ended December 31, 2012 and 2011, APL purchased and retired 24,052 common units and 28,878 common units, respectively, to cover employee-related taxes, for a cost of $0.7 million and $1.0 million, respectively. The purchased and retired units were recorded as a reduction of non-controlling interests on the Partnership’s consolidated balance sheets. There were no phantom units purchased and retired during the year ended December 31, 2013. On February 17, 2011, the employment agreement with the Chief Executive Officer (“CEO”) of the Partnership, as general partner, was terminated in connection with the Chevron Merger (see Note 3) and 75,250 outstanding phantom units, which represents all outstanding phantom units held by the CEO, automatically vested and were issued.

All phantom units outstanding under the APL LTIPs at December 31, 2013 include DERs. The amounts paid with respect to APL LTIP DERs were $3.1 million, $2.0 million and $0.8 million, respectively, for the years ended December 31, 2013, 2012 and 2011. These amounts were recorded as reductions of non-controlling interest on the Partnership’s consolidated balance sheet.

188

The following table sets forth the APL LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2013					2012					2011
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		1,053,242		$	33.21		394,489		$	21.63		490,886		$	11.75
Granted		744,997			38.96		907,637			34.94		178,318			33.47
Vested and issued(1)(2)		(290,136	)		31.88		(181,209	)		17.88		(233,465	)		11.34
Forfeited		(61,550	)		36.11		(67,675	)		29.83		(41,250	)		13.49
Outstanding, end of year(3)(4)		1,446,553		$	36.32		1,053,242		$	33.21		394,489		$	21.63
Non-cash compensation expense recognized (in thousands)(5)				$	19,344				$	11,635				$	3,271

⁽¹⁾  The intrinsic values for phantom unit awards vested and issued were $10.7 million, $5.5 million and $7.4 million, respectively, during the years ended December 31, 2013, 2012 and 2011.

⁽²⁾  There were 1,677, 792 and 414 vested phantom units, which were settled for $58,000, $26,000 and $14,000 cash during the years ended December 31, 2013, 2012 and 2011, respectively.

⁽³⁾  There were 22,539 and 17,926 outstanding phantom unit awards at December 31, 2013 and December 31, 2012, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards.

⁽⁴⁾  The aggregate intrinsic values for phantom unit awards outstanding at December 2013 and 2012 were $50.7 million and $33.3 million, respectively.

⁽⁵⁾  Non-cash compensation expense includes incremental compensation expense of $0.5 million, related to the accelerated vesting of phantom units held by the CEO of APL’s General Partner during the year ended December 31, 2011.

At December 31, 2013, APL had approximately $30.8 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.1 years.

APL Unit Options. At December 31, 2013, there were no unit options outstanding. On February 17, 2011, the employment agreement with the CEO of APL’s General Partner was terminated in connection with the Chevron Merger (see Note 3) and 50,000 outstanding unit options held by the CEO automatically vested. As of December 31, 2013, all unit options had been exercised.

The following table sets forth the APL LTIPs’ unit option activity for the periods indicated:

	Years Ended December 31,
	2013				2012				2011
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		—	$	—		—	$	—		75,000		$	6.24
Exercised(1)		—		—		—		—		(75,000	)		6.24
Outstanding, end of year(2)		—	$	—		—	$	—		—		$	—
Non-cash compensation expense recognized (in thousands)(3)			$	—			$	—				$	3

(1) The intrinsic value for the options exercised during the year ended December 31, 2011 was $1.7 million. Approximately $0.5 million was received from the exercise of unit option awards during the year ended December 31, 2011.

(2) No options are outstanding or exercisable at December 31, 2013 and 2012.

(3) Incremental expense of approximately $2,000, related to the accelerated vesting of options held by APL’s CEO, was recognized during the year ended December 31, 2011.

189

At December 31, 2013, APL had no unrecognized compensation expense related to unvested unit options outstanding under APL’s LTIPs based upon the fair value of the awards.

APL uses the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. No options were granted during the years ended December 31, 2013, 2012 and 2011 under the APL LTIPs.

APL Employee Incentive Compensation Plan and Agreement

A wholly-owned subsidiary of APL has an incentive plan (the “Cash Plan”), which allowed for equity-indexed cash incentive awards to employees of APL (the “Participants”). The Cash Plan was administered by a committee appointed by the CEO of APL’s General Partner. Under the Cash Plan, cash bonus units were awarded to Participants at the discretion of the committee. An APL Bonus Unit entitled the employee to receive the cash equivalent of the then-fair market value of a common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vested ratably over a three year period from the date of grant and automatically vested upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause.

At December 31, 2013 and 2012, APL had no outstanding APL Bonus Units under the Cash Plan and does not anticipate any further grants under the Cash Plan. APL recognized compensation expense related to these awards based upon the fair value, which is re-measured each reporting period based upon the current fair value of the underlying common units. During the years ended December 31, 2012 and 2011, 25,500 and 24,750 APL Bonus Units, respectively, vested and cash payments were made for $0.7 million and $0.9 million, respectively. All outstanding bonus units became fully vested at the end of December 31, 2012. APL recognized income of $0.1 million during the year ended December 31, 2012 and expense of $0.9 million during the year ended December 31, 2011, which was recorded within general and administrative expense on the Partnership’s consolidated statements of operations. No expense was recognized during the year ended December 31, 2013.

NOTE 18 — OPERATING SEGMENT INFORMATION

The Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands):

	Years Ended December 31,
	2013			2012			2011
Atlas Resource:
Revenues	$	467,655		$	267,629		$	247,522
Operating costs and expenses		(348,812	)		(246,267	)		(189,846	)
Depreciation, depletion and amortization expense		(136,763	)		(52,582	)		(31,938	)
Asset impairment		(38,014	)		(9,507	)		(6,995	)
Gain (loss) on asset sales and disposal		(987	)		(6,980	)		87
Interest expense		(34,324	)		(4,195	)		—
Segment income (loss)	$	(91,245	)	$	(51,902	)	$	18,830
Atlas Pipeline:
Revenues	$	2,102,113		$	1,252,674		$	1,306,785
Operating costs and expenses		(1,863,510	)		(1,052,826	)		(1,138,898	)
Depreciation, depletion and amortization expense		(168,617	)		(90,029	)		(77,435	)
Asset impairment		(43,866	)		—			—
Gain (loss) on asset sales and disposal		(1,519	)		—			256,202
Interest expense		(89,637	)		(41,760	)		(31,603	)
Loss on early extinguishment of debt		(26,601	)		—			(19,574	)
Segment income (loss)	$	(91,637	)	$	68,059		$	295,477
Corporate and other:
Revenues	$	7,747		$	1,140		$	16,267
Operating costs and expenses		(41,690	)		(33,613	)		(16,359	)

190

	Years Ended December 31,
	2013			2012			2011
Depreciation, depletion and amortization expense		(3,153	)		—			—
Gain on asset sales and disposal		—			—			3
Interest expense		(8,620	)		(565	)		(6,791	)
Segment loss	$	(45,716	)	$	(33,038	)	$	(6,880	)
Reconciliation of segment income (loss) to net income (loss):
Segment income (loss):
Atlas Resource	$	(91,245	)	$	(51,902	)	$	18,830
Atlas Pipeline		(91,637	)		68,059			295,477
Corporate and other		(45,716	)		(33,038	)		(6,880	)
Net income (loss)	$	(228,598	)	$	(16,881	)	$	307,427
Capital expenditures:
Atlas Resource	$	263,537		$	127,226		$	47,324
Atlas Pipeline		450,560			373,533			245,426
Corporate and other		3,943			—			—
Total capital expenditures	$	718,040		$	500,759		$	292,750

	December 31,
	2013		2012
Balance sheet:
Goodwill:
Atlas Resource	$	31,784	$	31,784
Atlas Pipeline		368,572		319,285
Corporate and other		—		—
	$	400,356	$	351,069
Total assets:
Atlas Resource	$	2,343,800	$	1,498,952
Atlas Pipeline		4,327,845		3,065,638
Corporate and other		120,996		32,604
	$	6,792,641	$	4,597,194

NOTE 19 — SUBSEQUENT EVENTS

Distribution. On January 29, 2014, the Partnership declared a cash distribution of $0.46 per unit on its outstanding common units, representing the cash distribution for the quarter ended December 31, 2013. The $23.7 million distribution was paid on February 19, 2014 to unitholders of record at the close of business on February 10, 2014.

Atlas Resource

Distribution. On February 24, 2014, ARP declared its initial monthly distribution of $0.1933 per common unit for the month of January 2014, which is payable on March 17, 2014 to holders of record as of March 7, 2014. In January 2014, ARP’s board of directors had approved the modification of its distribution payment practice to a monthly distribution program.

GeoMet Acquisition. On February 13, 2014, ARP entered into a definitive asset purchase and sale agreement to acquire certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014, subject to certain purchase price adjustments. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. The closing of the acquisition is subject to certain closing conditions, including a vote by GeoMet’s stockholders to approve the transaction.

Distribution. On January 29, 2014, ARP 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, 2013. The $41.8 million distribution, including $2.9 million and $4.4 million to the Partnership, as general partner, and preferred limited partners, respectively, was paid on February 14, 2014 to unitholders of record at the close of business on February 10, 2014.

191

Atlas Pipeline

Distribution. On January 28, 2014, APL declared a cash distribution of $0.62 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2013. The $56.1 million distribution, including $6.1 million to the Partnership as general partner, was paid on February 14, 2014 to unitholders of record at the close of business on February 7, 2014. Based on this declaration, APL also issued approximately 274,785 Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended December 31, 2013. The in kind distribution was issued on February 14, 2014 to the preferred unitholders of record at the close of business on February 7, 2014 (see Note 15).

NOTE 20 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil, Gas and NGL Reserve Information. The preparation of the Partnership’s and ARP’s natural gas, oil and NGL reserve estimates were completed in accordance with the Partnership’s and ARP’s prescribed internal control procedures by the Partnership’s and ARP’s reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared for the Partnership’s and ARP’s annual reports on Form 10-K for the year ended December 31, 2013. For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves. The reserve information includes natural gas, oil and NGL reserves which are all located throughout the United States. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The Partnership’s and 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 the Partnership’s and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the Partnership’s and ARP’s senior engineering staff and management, with final approval by the Chief Operating Officer and President.

The reserve disclosures that follow reflect the Partnership’s and ARP’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, 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 developed reserves are those reserves of any category 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 undeveloped reserves are reserves of any category 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. The proved reserves quantities and future net cash flows as of December 31, 2013, 2012 and 2011 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2013, 2012 and 2011, including adjustments related to regional price differentials and energy content.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within the Partnership and ARP or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.

192

The Partnership

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

	Gas (Mcf)			Oil (Bbls)		NGLs (Bbls)
Balance, January 1, 2013(1)		—			—		—
Purchase of reserves in-place		40,797,400			366		—
Production		(1,855,955	)		—		—
Balance, December 31, 2013		38,941,445			366		—
Proved developed reserves at(1):
January 1, 2013		—			—		—
December 31, 2013		38,941,445			366		—

(1) Prior to the Arkoma Acquisition on July 31, 2013, the Partnership had no oil and gas reserves. At December 31, 2013, there were no proved undeveloped reserves related to the Partnership’s oil and gas assets.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows (in thousands):

	Years Ended December 31,
	2013			2012
Natural gas and oil properties:
Proved properties	$	64,480		$	—
Unproved properties		—			—
Support equipment		253			—
		64,733			—
Accumulated depreciation, depletion and amortization		(2,955	)		—
Net capitalized costs	$	61,778		$	—

Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows (in thousands):

	Years Ended December 31,
	2013			2012		2011
Revenues	$	6,821		$	—	$	—
Production costs		(2,861	)		—		—
Depreciation, depletion and amortization		(3,020	)		—		—
	$	940		$	—	$	—

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Partnership in its oil and gas activities during the periods indicated are as follows (in thousands):

	Years Ended December 31,
	2013		2012		2011
Property acquisition costs:
Proved properties	$	64,480	$	—	$	—
Unproved properties		—		—		—
Exploration costs(1)		—		—		—
Development costs		—		—		—
Total costs incurred in oil & gas producing activities	$	64,480	$	—	$	—

(1) There were no exploratory wells drilled during the years ended December 31, 2013, 2012 and 2011.

193

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013, 2012 and 2011, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):

	Years Ended December 31,
	2013			2012		2011
Future cash inflows	$	122,313		$	—	$	—
Future production costs		(50,405	)		—		—
Future development costs		(5,644	)		—		—
Future net cash flows		66,264			—		—
Less 10% annual discount for estimated timing of cash flows		(26,165	)		—		—
Standardized measure of discounted future net cash flows	$	40,099		$	—	$	—

Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since the Partnership allocates taxable income to its owner, no recognition has been given to income taxes:

	Years Ended December 31,
	2013			2012		2011
Balance, beginning of year	$	—		$	—	$	—
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(3,828	)		—		—
Purchases of reserves in-place		43,927			—		—
Outstanding, end of year	$	40,099		$	—	$	—

Atlas Resource

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within ARP are as follows (unaudited):

	Gas (Mcf)			Oil (Bbls)(1)			NGLs (Bbls) (1)
Balance, January 1, 2011		176,065,003			1,832,535			—
Extensions, discoveries and other additions(2)		9,966,952			8,217			—
Sales of reserves in-place		(990	)		—			—
Purchase of reserves in-place		586,662			2,216			—
Transfers to limited partnerships		(6,042,432	)		—			—
Revisions(3)		(11,436,615	)		77,661			—
Production		(11,462,149	)		(274,330	)		—
Balance, December 31, 2011		157,676,431			1,646,299			—
Extensions, discoveries and other additions(2)		6,756,817			10,688			—
Sales of reserves in-place		—			—			—
Purchase of reserves in-place		462,504,519			7,485,998			16,212,356
Transfers to limited partnerships		—			—			—
Revisions(4)		(27,760,192	)		(153,413	)		206,091
Production		(25,403,318	)		(120,736	)		(356,550	)
Balance, December 31, 2012		573,774,257			8,868,836			16,061,897
Extensions, discoveries and other additions(2)		90,098,219			8,255,531			8,197,272
Sales of reserves in-place		(2,755,155	)		—			(4,625	)

194

	Gas (Mcf)			Oil (Bbls)(1)			NGLs (Bbls) (1)
Purchase of reserves in-place		452,683,902			1,598			55,187
Transfers to limited partnerships		(2,485,210	)		(239,910	)		(258,381	)
Revisions(5)		(88,488,497	)		(1,412,359	)		(3,826,744	)
Production		(57,993,487	)		(485,226	)		(1,267,590	)
Balance, December 31, 2013		964,834,029			14,988,470			18,957,016
Proved developed reserves at:
January 1, 2011		137,393,017			1,832,535			—
December 31, 2011		138,403,225			1,638,083			—
December 31, 2012		338,655,324			3,400,447			7,884,778
December 31, 2013		727,926,951			3,458,907			7,676,389
Proved undeveloped reserves at:
January 1, 2011		38,671,986			—			—
December 31, 2011		19,273,206			8,216			—
December 31, 2012		235,118,932			5,468,389			8,177,120
December 31, 2013		236,907,078			11,529,563			11,280,627

(1) Oil includes NGL information for the year ended December 31, 2011, which was less than 500 MBbls.

(2) Principally includes increases of proved reserves due to the addition of Marcellus wells.

(3) Represents a downward revision of proved undeveloped reserves in the New Albany Shale due to the reduction of certain drilling plans related to ARP’s shallow natural gas wells, as well as a downward revision and related impairment charge related to the Partnership’s shallow natural gas wells in Colorado.

(4) Represents a downward revision and related impairment charge related to ARP’s shallow natural gas wells in Michigan and Colorado due to declines in the average 1^st day of the month price for the year ended December 31, 2012 as compared with the year ended December 31, 2011.

(5) Represents a downward revision primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of ARP during the periods indicated were as follows (in thousands):

	Years Ended December 31,
	2013			2012
Natural gas and oil properties:
Proved properties	$	2,489,587		$	1,468,886
Unproved properties		211,536			292,053
Support equipment		23,004			13,110
		2,724,127			1,774,049
Accumulated depreciation, depletion and amortization		(646,680	)		(504,625	)
Net capitalized costs	$	2,077,447		$	1,269,424

Results of Operations from Oil and Gas Producing Activities. The results of operations related to ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands):

	Years Ended December 31,
	2013			2012			2011
Revenues	$	266,783		$	92,901		$	66,979
Production costs		(97,237	)		(26,624	)		(17,100	)
Depreciation, depletion and amortization		(129,729	)		(47,000	)		(27,430	)
Asset impairment(1)		(38,014	)		(9,507	)		(6,995	)
	$	1,803		$	9,770		$	15,454

(1) During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany shale and unproved acreage in the Chattanooga and New Albany shales. During the year ended December 31, 2012, ARP recognized $9.5 million of impairment related to its shallow natural gas wells in the Antrim and Niobrara shales. During the year ended December 31, 2011, ARP recognized $7.0 million of impairment related to its shallow natural gas wells in the Niobrara Shale.

195

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by ARP in its oil and gas activities during the periods indicated are as follows (in thousands):

	Years Ended December 31,
	2013		2012		2011
Property acquisition costs:
Proved properties	$	798,941	$	528,684	$	9,199
Unproved properties		895		213,638		323
Exploration costs(1)		1,053		1,026		1,156
Development costs		214,383		83,538		29,809
Total costs incurred in oil & gas producing activities	$	1,015,272	$	826,886	$	40,487

(1) There were no exploratory wells drilled during the years ended December 31, 2013, 2012 and 2011.

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013, 2012 and 2011, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):

	Years Ended December 31,
	2013			2012			2011
Future cash inflows	$	5,145,835		$	2,930,514		$	949,286
Future production costs		(2,347,592	)		(1,185,084	)		(425,493	)
Future development costs		(746,725	)		(441,423	)		(27,266	)
Future net cash flows		2,051,518			1,304,007			496,527
Less 10% annual discount for estimated timing of cash flows		(1,012,326	)		(680,331	)		(276,668	)
Standardized measure of discounted future net cash flows	$	1,039,192		$	623,676		$	219,859

Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since ARP allocates taxable income to its owner, no recognition has been given to income taxes:

	Years Ended December 31,
	2013			2012			2011
Balance, beginning of year	$	623,676		$	219,859		$	236,630
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		167,581			(54,969	)		(46,304	)
Net changes in prices and production costs		85,191			(87	)		(34	)
Revisions of previous quantity estimates		(1,881	)		(6,378	)		757
Development costs incurred		27,245			575			1,842
Changes in future development costs		(21,579	)		—			(3,591	)
Transfers to limited partnerships		(53,392	)		—			(8,022	)
Extensions, discoveries, and improved recovery less related costs		143,338			64			14,923
Purchases of reserves in-place		473,058			510,467			736
Sales of reserves in-place		(2,053	)		—			(1	)
Accretion of discount		62,368			21,986			23,663
Estimated settlement of asset retirement obligations		(18,858	)		(2,823	)		(3,105	)
Estimated proceeds on disposals of well equipment		17,052			3,806			3,363
Changes in production rates (timing) and other		(127,392	)		(68,824	)		(998	)
Outstanding, end of year	$	1,039,192		$	623,676		$	219,859

196

NOTE 21 — QUARTERLY RESULTS (Unaudited)

	Fourth Quarter(1)			Third Quarter(1)			Second Quarter(1)			First Quarter(1)
	(in thousands, except unit data)
Year ended December 31, 2013:
Revenues	$	761,629		$	649,989		$	643,795		$	522,102
Net loss		(102,169	)		(79,546	)		(5,189	)		(41,694	)
(Income) loss attributable to non-controlling interests		75,169			52,022			(3,058	)		29,098
Net loss attributable to common limited partners	$	(27,000	)	$	(27,524	)	$	(8,247	)	$	(12,596	)
Net loss attributable to common limited partners per unit:
Basic	$	(0.53	)	$	(0.54	)	$	(0.16	)	$	(0.25	)
Diluted	$	(0.53	)	$	(0.54	)	$	(0.16	)	$	(0.25	)

⁽¹⁾  For the first, second, third and fourth quarters of the year ended December 31, 2013, approximately 3,594,000, 4,092,000, 4,196,000 and 4,091,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive.

	Fourth Quarter(1)			Third Quarter(1)			Second Quarter(1)			First Quarter(1)
	(in thousands, except unit data)
Year ended December 31, 2012:
Revenues	$	439,004		$	354,773		$	363,039		$	364,627
Net income (loss)		(31,917	)		(21,392	)		51,570			(15,142	)
(Income) loss attributable to non-controlling interests		17,042			9,982			(59,191	)		(3,365	)
Net loss attributable to common limited partners	$	(14,875	)	$	(11,410	)	$	(7,621	)	$	(18,507	)
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.29	)	$	(0.22	)	$	(0.15	)	$	(0.36	)
Diluted	$	(0.29	)	$	(0.22	)	$	(0.15	)	$	(0.36	)

⁽¹⁾  For the first, second, third and fourth quarters of the year ended December 31, 2012, approximately 2,260,000, 3,084,000, 3,011,000 and 3,111,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit because the inclusion of such units would have been anti-dilutive.

197

ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A: CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, excluding assets acquired from EP Energy. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2013, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 1992 Internal Control – Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

In conducting management’s evaluation of the effectiveness of its internal control over financial reporting, management has excluded, due to the timing, size, and complexity, the operations of our and ARP’s newly acquired assets from EP Energy, which were acquired in July 2013, from its December 31, 2013 Sarbanes-Oxley 404 review (see “Item 8. Financial Statements and Supplemental Data – Note 4”). In connection with these acquisitions, we and ARP have entered into transition services agreements with the previous owner. As a result, we and ARP did not begin to perform substantially all accounting control functions related to our Arkoma Acquisition and ARP’s EP Energy Acquisition until January 31, 2014. Our Arkoma and ARP’s EP Energy acquisitions constituted 0.9% and 10.5%, respectively, of our total assets as of December 31, 2013 and 0.3% and 2.6%, respectively, of our total revenues for the year ended December 31, 2013. We are continuing to integrate these systems’ historical internal controls over financial reporting with our existing internal controls over financial reporting. This integration may lead to changes in our or the acquired systems’ historical internal controls over financial reporting in future fiscal reporting periods. During the years ended December 31, 2013 and 2012, ARP acquired certain assets from Titan and DTE, and APL acquired certain assets from TEAK and Cardinal which have been fully integrated into our existing internal control environment in 2013. Other than the previously mentioned items, there have been no changes in our internal control over financial reporting during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

198

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2013. Grant Thornton LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2013, which is included herein.

199

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Energy, L.P.

We have audited the internal control over financial reporting of Atlas Energy, L.P. (a Delaware limited partnership) and subsidiaries (collectively the “Partnership”) as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of Arkoma and EP Energy, which are consolidated subsidiaries of the Partnership, whose financial statements reflect aggregate total assets and revenues constituting 11.4% and 2.9%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2013. As indicated in Management’s Report, Arkoma and EP Energy were acquired during 2013. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Arkoma and EP Energy.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2013, and our report dated February 28, 2014, expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 28, 2014

ITEM 9B: OTHER INFORMATION

None.

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PART III

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us. Our general partner will be liable, as general partner, for all of our debts to the extent not paid, except to the extent that indebtedness or other obligations incurred by us are specifically with recourse only to our assets. Whenever possible, our general partner intends to limit recourse on our indebtedness or other obligations only to our assets.

As set forth in our Partnership Governance Guidelines and in accordance with New York Stock Exchange (“NYSE”) listing standards, the non-management members of our general partner’s board of directors meet in executive session regularly without management. The managing board member who presides at these meetings rotates each meeting. The purpose of these executive sessions is to promote open and candid discussion among the non-management board members. Interested parties wishing to communicate directly with the non-management members may contact the chairman of the audit committee, Mark Biderman. Correspondence to Mr. Biderman should be marked “Confidential” and sent to Mr. Biderman’s attention, c/o Atlas Energy, L.P., 1845 Walnut Street, 10^th Floor, Philadelphia, PA 19103.

The independent board members comprise all of the members of the audit committee, the nominating and governance committee, the compensation committee and the investment committee.

Until the consummation of the merger with Chevron Corporation, a Delaware corporation (“Chevron”), in which Atlas Energy, Inc. (“AEI”) became a wholly-owned subsidiary of Chevron on February 17, 2011 (the “Chevron Merger”), we did not directly employ any of the persons responsible for our management or operation. Rather, AEI personnel managed and operated our business. With the completion of the Chevron Merger, we are no longer affiliated with AEI. We employ certain former AEI employees, including the members of our senior management. In addition, as a result of the sale of assets from AEI to us on February 17, 2011 (the “AHD Transactions”), we own our general partner, and our unitholders elect our general partner’s board of directors rather than AEI.

Board of Directors and Executive Officers of Our General Partner

The following table sets forth information with respect to the executive officers and directors of our general partner:

Name	Age		Position with the general partner	Year in which service began		Term expires
Edward E. Cohen		75	Chief Executive Officer, President and Director		2006		2014
Sean P. McGrath		42	Chief Financial Officer		2011		—
Jonathan Z. Cohen		43	Executive Chairman of the Board		2006		2016
Matthew A. Jones		52	Senior Vice President and President and of E&P Division		2011		—
Eugene N. Dubay		65	Senior Vice President of Midstream		2011		—
Daniel C. Herz		37	Senior Vice President of Corporate Development & Strategy		2011		—
Freddie M. Kotek		58	Senior Vice President of Investment Partnership Division		2011
Lisa Washington		46	Vice President, Chief Legal Officer and Secretary		2011		—
Jeffrey M. Slotterback		31	Chief Accounting Officer		2011		—
Carlton M. Arrendell		52	Director		2011		2016
Mark C. Biderman		68	Director		2011		2016
Dennis A. Holtz		73	Director		2011		2015
Walter C. Jones		51	Director		2013		2015
Ellen F. Warren		57	Director		2011		2014

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Edward E. Cohen has served as our Chief Executive Officer and President since February 2011. Mr. Cohen was the Chair of the Board of our general partner from its formation in January 2006 until February 2011. Mr. Cohen served as the Chief Executive Officer of our general partner from its formation in January 2006 until February 2009. Mr. Cohen has served on the executive committee of our general partner since 2006. Mr. Cohen also was the Chair of the Board and Chief Executive Officer of Atlas Energy, Inc. (formerly known as Atlas America, Inc.) from its organization in 2000 until the consummation of the Chevron Merger in February 2011 (the “Chevron Merger”) and also served as its President from September 2000 to October 2009. Mr. Cohen has been the Executive Chair of the managing board of Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), since its formation in 1999. Mr. Cohen was the Chief Executive Officer of Atlas Pipeline GP from 1999 to January 2009. Mr. Cohen has served as Chair of the board and Chief Executive Officer of Atlas Resource Partners GP, LLC (“Atlas Resource GP”) since February 2012. Mr. Cohen was the Chair of the Board and Chief Executive Officer of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc. from their formation in June 2006 until the consummation of the Chevron Merger in February 2011. In addition, Mr. Cohen has been Chair of the Board of Directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990 and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chair of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005 until November 2009 and currently serves on its board; and Chair of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen. Mr. Cohen has been active in the energy business for over 30 years. Mr. Cohen’s strong financial and energy industry experience, along with his deep knowledge of the company resulting from his long tenure with the company and its predecessors, enables Mr. Cohen to provide valuable perspectives on many issues facing the company. Mr. Cohen’s service on the Board of our general partner creates an important link between management and the Board and provides the company with decisive and effective leadership. Mr. Cohen’s extensive experience in founding, operating and managing public and private companies of varying size and complexity enables him to provide valuable expertise to the company. Additionally, among the reasons for his appointment as a director, Mr. Cohen brings to the Board the vast experience that he has accumulated through his activities as a financier, investor and operator in various parts of the country. These diverse experiences have enabled Mr. Cohen to bring unique perspectives to the Board, particularly with respect to business management, financial markets and financing transactions and corporate governance issues.

Sean P. McGrath has been our Chief Financial Officer since February 2011. Before that he was the Chief Accounting Officer of AEI and the Chief Accounting Officer of Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath has served as the Chief Financial Officer of Atlas Resource GP since February 2012, and served as the Chief Accounting Officer of our general partner from January 2006 until November 2009 and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. Mr. McGrath is a Certified Public Accountant.

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Jonathan Z. Cohen has served as the Executive Chair of the Board of our general partner since January 2012. Before that, he served as Chair of the Board of our general partner from February 2011 until January 2012 and as Vice Chair of the Board of our general partner from its formation in January 2006 until February 2011. Mr. Cohen has served as chair of the executive committee of our general partner since 2006. Mr. Cohen was the Vice Chair of the Board of Atlas Energy, Inc. from its incorporation in September 2000 until the consummation of the Chevron Merger in February 2011. Mr. Cohen has been the Executive Vice Chair of the managing board of Atlas Pipeline GP since its formation in 1999 and Vice Chair of the Board of Atlas Resource GP since February 2012. Mr. Cohen was the Vice Chair of the Board of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc. from their formation in June 2006 until the consummation of the Chevron Merger in February 2011. Mr. Cohen has been a senior officer of Resource America, Inc. (a publicly-traded specialized asset management company) since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005. Mr. Cohen is a son of Edward E. Cohen. Mr. Cohen’s extensive knowledge of the company resulting from his long length of service with the company and its predecessors, as well as his strong financial and industry experience, allow him to contribute valuable perspectives on many issues facing the company. Mr. Cohen’s service on the Board of our general partner creates an important link between management and the Board and provides the company with decisive and effective leadership. Mr. Cohen’s involvement with public and private entities of varying size, complexity and focus and raising debt and equity for such entities provides him with extensive experience and contacts that are valuable to the company. Additionally, among the reasons for his appointment as a director, Mr. Cohen’s financial, business, operational and energy experience as well as the experience that he has accumulated through his activities as a financier and investor, add strategic vision to our general partner’s Board to assist with our growth, operations and development. Mr. Cohen is able to draw upon these diverse experiences to provide guidance and leadership with respect to exploration and production operations, capital markets and corporate finance transactions and corporate governance issues.

Matthew A. Jones has been Senior Vice President of our general partner and President of our exploration and production division since February 2011 and served as Chief Operating Officer of our exploration and production division from February 2011 until October 2013. Before that, he was the Chief Financial Officer of AEI from March 2005 and an Executive Vice President from October 2009 until February 2011. Mr. Jones has been the President and a director of Atlas Resource Partners GP since March 2012 and its Chief Operating Officer from March 2012 until October 2013, and was the Chief Financial Officer of Atlas Energy Resources, LLC and Atlas Energy Management, Inc. from their formation in June 2006 until the consummation of the Chevron Merger in February 2011. Mr. Jones served as the Chief Financial Officer of our general partner from January 2006 until September 2009 and as a member of the Board from February 2006 until February 2011. Mr. Jones was the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005. Mr. Jones served as a director of our general partner from February 2006 to February 2011. Mr. Jones is a Chartered Financial Analyst.

Eugene N. Dubay has been our Senior Vice President of Midstream since February 2011. Before that, he was the Chief Executive Officer and President and a director of our general partner from February 2009 until February 2011. Mr. Dubay has been Chief Executive Officer of Atlas Pipeline GP since January 2009 and its President from January 2009 until October 2013. Mr. Dubay has served as a member of the managing board of Atlas Pipeline GP since October 2008, where he served as an independent member until his appointment as President and Chief Executive Officer. Mr. Dubay has been the President of Atlas Pipeline Mid-Continent, LLC since January 2009. Mr. Dubay was the Chief Operating Officer of Continental Energy Systems LLC, the parent of SEMCO Energy, from 2002 to January 2009. Mr. Dubay has also held positions with ONEOK, Inc. and Southern Union Company and has over 20 years’ experience in midstream assets and utilities operations, strategic acquisitions, regulatory affairs and finance.

Daniel C. Herz has served as Senior Vice President of Corporate Development and Strategy of our general partner since February 2011. Before that, he was Senior Vice President of Corporate Development of AEI and Atlas Energy Resources, LLC from August 2007 until February 2011. Mr. Herz has served as Senior Vice President of Corporate Development and Strategy of Atlas Resource Partners GP since March 2012. Mr. Herz has been Senior Vice President of Corporate Development of Atlas Pipeline Partners GP, LLC since August 2007. Before that, Mr. Herz was Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC from December 2004 and of Atlas Energy’s general partner from January 2006. Prior to joining Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC, Mr. Herz was an investment banker with Banc of America Securities from 1999 to 2003.

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Freddie M. Kotek has been our Senior Vice President of the Investment Partnership Division of our general partner since February 2011. Before that, he was the Executive Vice President of AEI from February 2004 until February 2011 and served as a director from September 2001 until February 2004. Mr. Kotek has been Senior Vice President of Atlas Resource GP since March 2012, and Chairman of Atlas Resources, LLC since September 2001. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek served as AEI’s Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004.

Lisa Washington has been our Vice President, Chief Legal Officer and Secretary of our general partner since February 2011. Ms. Washington has been the Chief Legal Officer and Secretary of Atlas Resource GP since February 2012 and a Senior Vice President since October 2013. Ms. Washington served as Chief Legal Officer and Secretary of our general partner from January 2006 to October 2009 and as a Senior Vice President of our general partner from October 2008 to October 2009. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Pipeline GP from November 2005 to October 2009, a Senior Vice President from October 2008 to October 2009 and a Vice President from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of AEI, from November 2005 until February 2011, a Senior Vice President from October 2008 until February 2011 and. a Vice President from November 2005 until October 2008. Ms. Washington served as Chief Legal Officer and Secretary of Atlas Energy Resources, LLC from 2006 until February 2011, a Senior Vice President from July 2008 until February 2011 and a Vice President from 2006 until July 2008. From 1999 to 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

Jeffrey M. Slotterback has been our Chief Accounting Officer since March 2011. Mr. Slotterback has also been the Chief Accounting Officer of Atlas Resource GP since March 2012. Mr. Slotterback served as the Manager of Financial Reporting for AEI from July 2009 until February 2011 and then served as the Manager of Financial Reporting for our general partner from February 2011 until March 2011. Mr. Slotterback served as Manager of Financial Reporting for both our general partner and Atlas Pipeline GP from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.

Carlton M. Arrendell has served as a director since February 2011. Mr. Arrendell has been the Chief Investment Officer and a Vice President of Full Spectrum of NY LLC since May 2007. Prior to joining Full Spectrum, Mr. Arrendell served as a special consultant to the AFL-CIO Investment Trust Corporation following six years of service as Investment Trust Corporation’s Chief Investment Officer. Mr. Arrendell is a seasoned energy company director having previously served as a director of Atlas Energy, Inc. from February 2004 until February 2011 as well as the chair of its audit committee from 2004 to 2009. He is also an attorney admitted to practice law in Maryland and the District of Columbia. As a member of the National Association of Corporate Directors and a result of his legal background, Mr. Arrendell offers expertise in corporate governance matters. Mr. Arrendell brings over 25 years of business experience to the Board and his investment expertise is valuable to our company and our subsidiaries in evaluating acquisitions being pursued. In addition, the Board benefits from his strong background in finance.

Mark C. Biderman has served as a director since February 2011. Before that, he was a director of Atlas Energy, Inc. from July 2009 until February 2011. Mr. Biderman was Vice Chair of National Financial Partners Corp. (a publicly-traded financial services company) from September 2008 to December 2008. Before that, from November 1999 to September 2008, he was National Financial’s Executive Vice President and Chief Financial Officer. From May 1987 to October 1999, he served as Managing Director and Head of the Financial Institutions Group at CIBC World Markets Group (an investment banking firm) and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman serves as a director and chair of the audit committee of Full Circle Capital Corporation (a publicly-traded investment company), as well as a member of its corporate governance and nominating committee, since August 2010. Mr. Biderman serves as a director, and chair of the compensation committee of Apollo Commercial Real Estate Finance, Inc. (a publicly-traded commercial real estate finance company) as well as a member of its audit committee, since November 2010. He also serves as a director and chair of the audit committee and as a member of the nominating and corporate governance committee of Apollo Residential Mortgage, Inc. (a publicly-traded residential real estate finance company) since July 2011. Mr. Biderman is a Chartered Financial Analyst. Mr. Biderman brings extensive financial expertise to the board as well as to the audit committee, on which he serves as chair and as a “financial expert”. Mr. Biderman brings over 40 years of business and financial experience to the Board, including his service as a chief financial officer for over eight years. Mr. Biderman also brings more than eight years of collective service on various boards of directors as well as his service on the audit committees of three other companies. In addition, the Board benefits from his business acumen and valuable financial experience.

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Dennis A. Holtz has served as a director since February 2011. Before that, he was a director of Atlas Energy, Inc. from February 2004 to February 2011. Mr. Holtz maintained a corporate and real estate law practice in Philadelphia and New Jersey from 1988 until his retirement in January 2008. During that period, Mr. Holtz was counsel for or corporate secretary of numerous private and public business entities and this extensive experience with corporate governance issues was the reason he was chosen as chair of the nominating and governance committee. Mr. Holtz offers a unique and invaluable perspective into corporate governance matters, as a licensed attorney with 48 years of business experience. Additionally, Mr. Holtz has extensive knowledge of the energy industry having served as a director of former affiliated companies for nine years.

Walter C. Jones has served as a director since October 2013. From April 2010 to October 2013, Mr. Jones served as the United States Executive Director and Chief-of-Mission to the African Development Bank in Tunis, Tunisia, having been nominated for the position by President Barack Obama in 2009 and confirmed by the United States Senate in 2010, whereby he represented the United States on the African Development Bank’s board of directors, and served as chair of the bank’s audit committee, and vice-chair of both the bank’s ethics and development effectiveness committees. From June 2005 until May 2007, Mr. Jones served as the Head of Private Equity and General Counsel at GRAVITAS Capital Advisors, LLC (an independent advisory firm). From May 1994 to May 2005, and then again from September 2007 until April 2010, Mr. Jones was at the Overseas Private Investment Corporation, where he served as Manager for Asia, Africa, the Middle East, Latin America and the Caribbean, as well as a Senior Investment Officer in the Finance Department. Prior to that, Mr. Jones was an International Consultant at the Washington, D.C. firm of Neill & Co. Mr. Jones began his career at the law firm of Sidley & Austin where he was a transactions associates specializing in leverage buyouts. Mr. Jones is a seasoned energy company director having previously served as a director and chair of the audit committee of Atlas Energy Resources, LLC from December 2006 until September 2009 and a director of Atlas Energy, Inc. from September 2009 until March 2010. Mr. Jones’ combination of private and public sector experience, as well as his international work, has afforded Mr. Jones with a unique combination of management and leadership experience. In addition, the Board benefits from his investment and transaction expertise as well as his valuable financial experience.

Ellen F. Warren has served as a director since February 2011. Before that, she was a director of Atlas Energy, Inc. from September 2009 until February 2011. She is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. She was previously Vice President of Marketing/Communications for Jefferson Bank (a Philadelphia-based financial institution) from September 1992 to February 1998 and President of Diversified Advertising, Inc. (an advertising and marketing firm) from December 1984 to September 1992, where she provided marketing services to various industries, including the energy industry. Ms. Warren is a seasoned energy company director having served as an independent member of the board of Atlas Energy Resources, LLC from December 2006 until September 2009, where she chaired a special committee, and later on the board of Atlas Energy, Inc. Ms. Warren serves as chair of the general partner’s compensation committee. As a member of the National Association of Corporate Directors, Ms. Warren offers expertise in corporate governance matters. Ms. Warren has extensive public relations, corporate communications and marketing experience, having founded and led various marketing communications firms and is uniquely positioned to provide leadership to the Board in public relations and communications matters. Ms. Warren brings valuable management, communication, community involvement and leadership skills to our general partner’s board.

We have assembled a board of directors of our general partner comprised of individuals who bring diverse but complementary skills and experience to oversee our business. Our directors collectively have a strong background in energy, finance, law, marketing, accounting and management. Based upon the experience and attributes of the directors discussed herein, our board of our general partner determined that each of the directors should, as of the date hereof, serve on the board of our general partner.

Jonathan Z. Cohen serves as the executive chairman of the board of directors of our general partner and Edward E. Cohen serves as the chief executive officer and president of our general partner. The board of directors of our general partner believes that the most effective leadership structure at the present time is for separation of the executive chairman of the board of directors from the chief executive officer position. The chief executive officer and the executive chairman are in constant contact and serve together as the executive committee of the Company.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires executive officers and managing board members of our general partner and persons who beneficially own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies of all such reports.

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Based solely upon our review of reports received by us, or representations from certain reporting persons that no filings were required for those persons, we believe that during fiscal year 2013 our executive officers, directors of our general partner and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements.

Nominations to Our General Partner’s Board of Directors

Pursuant to our limited partnership agreement, our unitholders may nominate candidates for election to our general partner’s board by providing timely prior notice to our general partner as follows:

• The notice must be delivered to our general partner not earlier than the close of business on the 120th day nor later than the close of business on the 90th day prior to the first anniversary of the preceding year’s annual meeting; provided, however, that in the event that the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date, a limited partner’s notice to be timely must be so delivered not earlier than the close of business on the 120th day prior to the date of such annual meeting and not later than the close of business on the later of the 90th day prior to the date of such annual meeting or, if the first public announcement of the date of such annual meeting is less than 100 days prior to the date of such annual meeting, the 10th day following the day on which public announcement of the date of the annual meeting is first made. In no event shall an adjournment or postponement of an annual meeting, or the public announcement thereof, commence a new time period for the giving of a limited partner’s notice as described above.

• The notice must be updated and supplemented, if necessary, so that the information provided or required to be provided in such notice shall be true and correct as of the record date for the meeting and as of the date that is ten business days prior to the meeting or any adjournment or postponement thereof, and such updates and supplements must be delivered to our general partner not later than five business days after the record date for the meeting in the case of the update and supplement required to be made as of the record date, and not later than eight business days prior to the date for the meeting, any adjournment or postponement thereof in the case of the update and supplement required to be made as of ten business days prior to the meeting or any adjournment or postponement thereof.

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• The notice must set forth: (A) the name and address of the unitholder, as they appear on our books, of the beneficial owner, if any, and of their respective affiliates or associates or others acting in concert therewith, (B) (I) the class or series and number of our securities which are, directly or indirectly, owned beneficially and of record by such unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, (II) any option, warrant, convertible security, stock appreciation right, or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any of our securities or with a value derived in whole or in part from the value of any of our securities, or any derivative or synthetic arrangement having the characteristics of a long position in any of our securities, or any contract, derivative, swap or other transaction or series of transactions designed to produce economic benefits and risks that correspond substantially to the ownership of any of our securities, including due to the fact that the value of such contract, derivative, swap or other transaction or series of transactions is determined by reference to the price, value or volatility of any of our securities, whether or not such instrument, contract or right shall be subject to settlement in the underlying security, through the delivery of cash or other property, or otherwise, and without regard to whether the unitholder of record, the beneficial owner, if any, or any affiliates or associates or others acting in concert therewith, may have entered into transactions that hedge or mitigate the economic effect of such instrument, contract or right, or any other direct or indirect opportunity to profit or share in any profit derived from any increase or decrease in the value of common units or any of our securities (any of the foregoing, a “Derivative Instrument”) directly or indirectly owned beneficially by such unitholder, the beneficial owner, if any, or any affiliates or associates or others acting in concert therewith, (III) any proxy, contract, arrangement, understanding, or relationship pursuant to which such unitholder has a right to vote any of our securities, (IV) any agreement, arrangement, understanding, relationship or otherwise, including any repurchase or similar so-called “stock borrowing” agreement or arrangement, involving such unitholder, directly or indirectly, the purpose or effect of which is to mitigate loss to, reduce the economic risk (of ownership or otherwise) of any of our securities by, manage the risk of share price changes for, or increase or decrease the voting power of, such unitholder with respect to any of our securities, or which provides, directly or indirectly, the opportunity to profit or share in any profit derived from any decrease in the price or value of any Partnership Security (any of the foregoing, a “Short Interest”), (V) any rights to dividends on any of our securities owned beneficially by such unitholder that are separated or separable from the underlying security, (VI) any proportionate interest in any of our securities or Derivative Instruments held, directly or indirectly, by a general or limited partnership in which such unitholder is a general partner or, directly or indirectly, beneficially owns an interest in a general partner of such general or limited partnership, (VII) any performance-related fees (other than an asset-based fee) that such unitholder is entitled to based on any increase or decrease in the value of any of our securities or Derivative Instruments, if any, including without limitation any such interests held by members of such unitholder’s immediate family sharing the same household, (VIII) any significant equity interests or any Derivative Instruments or Short Interests in any of our principal competitors held by such unitholder, and (IX) any direct or indirect interest of such unitholder in any contract with us, any of our affiliates or any of our principal competitors (including, in any such case, any employment agreement, collective bargaining agreement or consulting agreement), and (C) any other information relating to such unitholder and beneficial owner, if any, that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for, as applicable, the proposal and/or for the election of directors in a contested election pursuant to Section 14 of the Securities Exchange Act and the rules and regulations promulgated thereunder.

• If the notice relates to any business other than a nomination of a director that the unitholder proposes to bring before the meeting, the notice must, in addition to the matters set forth in paragraph above, also set forth: (A) a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest of the unitholder and beneficial owner, if any, in such business, (B) the text of the proposal or business (including the text of any resolutions proposed for consideration), and (C) a description of all agreements, arrangements and understandings between the unitholder and beneficial owner, if any, and any other person or persons (including their names) in connection with the proposal of such business by the unitholder.

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• As to each person whom the unitholder proposes to nominate for election or reelection to the board, the notice must also: (A) set forth all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Securities Exchange Act and the rules and regulations promulgated thereunder (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if elected); (B) set forth a description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, between or among such unitholder and beneficial owner, if any, and their respective affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective affiliates and associates, or others acting in concert therewith, on the other hand, including, without limitation all information that would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the unitholder making the nomination and any beneficial owner on whose behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in concert therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant; and (C) include a completed and signed questionnaire with respect to the background and qualification of the person nominated and the background of any other person or entity on whose behalf the nomination is being made, and a completed and signed representation and agreement that the person nominated (a) is not and will not become a party to (i) any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how the person, if elected as a director, will act or vote on any issue or question (a “Voting Commitment”) that has not been disclosed to us or (ii) any Voting Commitment that could limit or interfere with the person’s ability to comply, if elected as a director, with the person’s fiduciary duties under applicable law, (b) is not and will not become a party to any agreement, arrangement or understanding with any person or entity other than us with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a director that has not been disclosed therein, and (c) in the person’s individual capacity and on behalf of any person or entity on whose behalf the nomination is being made, would be in compliance, if elected as a director, and will comply, with all of our applicable publicly disclosed corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines. In addition, we may require any proposed nominee to furnish such other information as we may reasonably require to determine the eligibility of such proposed nominee to serve as an independent director or that could be material to a reasonable unitholder’s understanding of the independence, or lack thereof, of such nominee.

Information Concerning the Audit Committee

The board of directors of our general partner has a standing audit committee. All of the members of the audit committee are independent directors as defined by NYSE rules. The members of the audit committee are Mr. Biderman, Mr. Arrendell and Mr. Jones, with Mr. Biderman acting as the chairman. Our general partner’s board has determined that Mr. Biderman is an “audit committee financial expert,” as defined by SEC rules. Prior to Mr. Magarick’s resignation from our general partner’s board, he served as chair of the audit committee as well as the “audit committee financial expert”. Mr. Biderman serves on the audit committee of more than three public companies. The board of directors of our general partner has determined that Mr. Biderman’s simultaneous service on the audit committees of more than three public companies will not impair his ability to serve effectively on our general partner’s audit committee. The audit committee reviews the scope and effectiveness of audits by the independent accountants, is responsible for the engagement of independent accountants and reviews the adequacy of our internal controls.

Compensation Committee Interlocks and Insider Participation

The compensation committee of our general partner’s board of directors consists of Ms. Warren and Messrs. Arrendell and Holtz.

None of the independent directors of our general partner is an employee or former employee of ours or of our general partner. No executive officer of our general partner is a director or executive officer of any entity in which an independent director is a director or executive officer.

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Code of Business Conduct and Ethics, Partnership Governance Guidelines and Committee Charters

We have adopted a code of business conduct and ethics that applies to the principal executive officer, principal financial officer and principal accounting officer of our general partner, as well as to persons performing services for us generally. We have also adopted Partnership Governance Guidelines and charters for our audit committee, compensation committee, nominating and governance committee, and investment committee. We will make a printed copy of our code of ethics, our Partnership Governance Guidelines and our committee charters available to any unitholder who so requests. Requests for print copies may be directed to us as follows: Atlas Energy, L.P., Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, PA 15275, Attention: Secretary. Each of the code of business conduct and ethics, the Partnership Governance Guidelines and the charters for the audit committee, compensation committee and nominating and governance committee are posted, and any waivers we grant to our code of business conduct and ethics will be posted, on our website at www.atlasenergy.com.

Role in Risk Oversight

General

The Board’s role in risk oversight recognizes the multifaceted nature of risk management. The Board has empowered several Board committees with aspects of risk oversight. We administer our risk oversight function through our audit committee and Atlas Resource Partners and Atlas Pipeline Partners’ environmental, health and safety committees. The audit committee monitors material enterprise risks and, in order to assist in its oversight function, it oversaw the creation of the enterprise risk management committee consisting of senior officers from our various divisions that are responsible for day-to-day risk oversight. It meets with the members of the enterprise risk management committee as needed to discuss our risk management framework and related areas. The audit committee also reviews any major transactions or decisions affecting our risk profile or exposure, and reviews with counsel legal compliance and legal matters that could have a significant impact on our financial statements. Our audit committee also oversees our internal audit function, and is responsible for monitoring the integrity and ensuring the transparency of our financial reporting processes and systems of internal controls regarding finance, accounting and regulatory compliance. Our audit committee incorporates its risk oversight function into its regular reports to the Board. The environmental, health and safety committees of Atlas Resource Partners and Atlas Pipeline Partners assist in determining whether appropriate policies and management systems are in place with respect to environment, health and safety and related matters and monitor and review compliance with applicable environmental, health and safety laws, rules and regulations. Our subsidiaries’ environmental, health and safety committees review actions taken by management with respect to deficiencies identified or improvements recommended.

In addition to our audit committee and subsidiaries’ environmental, health and safety committees’ role in overseeing risk management, our full Board regularly engages in discussions of the most significant risks that we face and how these risks are being managed. Our general partner’s senior executives provide the Board and its committees with regular updates about our strategies and objectives and the risks inherent within them at board and committee meetings and in regular reports. Board and committee meetings also provide a venue for directors to discuss issues of concern with management. The Board and committees call special meetings when necessary to address specific issues or matters that should be addressed before the next regularly scheduled meeting. In addition, our directors have access to our management at all levels to discuss any matters of interest, including those related to risk. Those members of management most knowledgeable of the issues attend Board meetings to provide additional insight into items being discussed, including risk exposures.

Compensation Programs

Our compensation policies and programs are intended to encourage our employees to remain focused on both our short-term and long-term goals. For example, our equity awards often vest over a three or four year period. We believe this practice encourages our employees to focus on sustained unit price appreciation, thus limiting the potential of our executives to engage in excessive risk-taking. Annual incentives are intended to tie a significant portion of each of the named executive officer’s compensation to our annual performance and/or that of the subsidiaries or divisions for which the officer is responsible. We believe that our focus on revenue growth and distributable cash flow in making incentive bonus awards and unit price performance in granting equity awards provides a check on excessive risk taking. In addition, our Clawback Policy allows us to recoup any excess incentive compensation paid to our NEOs if the financial results on which the awards were based are materially restated due to fraud, illegal or intentional misconduct or gross negligence of the executive officer. Our Code of Business Conduct and Ethics, which applies to all officers and directors, further seeks to mitigate the potential for inappropriate risk taking. We also prohibit hedging transactions involving our units so our officers and directors cannot insulate themselves from the effects of our unit price performance.

Our Compensation Committee, together with senior management, also reviews compensation programs and benefits plans affecting employees generally (in addition to those applicable to our executive officers), and we have concluded that

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our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on the company. We also believe that our incentive compensation arrangements provide incentives that do not encourage risk-taking beyond our ability to effectively identify and manage significant risks; are compatible with effective internal controls and our risk management practices; and are supported by the oversight and administration of the Compensation Committee with regard to executive compensation programs.

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ITEM 11: EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

The purpose of this Compensation Discussion and Analysis is to explain the Compensation Committee’s philosophy for determining the compensation program for the Chief Executive Officer, Chief Financial Officer and three other most highly compensated executive officers of our General Partner for 2013 (the “Named Executive Officers” or “NEOs”) and to discuss why and how the 2013 compensation package for these executives was implemented. Following this discussion are tables that include compensation information for the NEOs. The NEOs for 2013 are as follows:

• Edward E. Cohen, Chief Executive Officer and President

• Sean P. McGrath, Chief Financial Officer

• Jonathan Z. Cohen, Executive Chairman of the Board

• Eugene N. Dubay, Senior Vice President of Midstream

• Matthew A. Jones, Senior Vice President and President of E&P Division

Executive Summary

2013 PERFORMANCE OVERVIEW

The following charts depict our total unitholder returns as compared to our oil and gas industry peer group (see “—Governance of Executive Compensation—Independent Compensation Consultant” below for a description of the peer group):

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2013 was another successful year for our company. We achieved high returns in our common unit price and distributions to our unitholders. Our three-year total unitholder return is 274% and our 2013 total unitholder return is 39%.

Other highlights of company performance in 2013 include:

• In an industry that strives to maintain constant levels of reserves of hydrocarbons, a declining asset, our proved reserves increased by approximately 52%.

• We acquired over 600,000 net undeveloped acres of energy rights (an increase of almost 200%) and over 340,000 net developed acres (an increase of 95%). In addition, we added approximately 1,500 potential drilling locations, more than doubling the 1,200 sites held at the beginning of the year.

• Our natural gas production increased by 97%, and our processed volumes at APL increased by approximately 80%.

OBJECTIVES OF OUR COMPENSATION PROGRAM

An understanding of our executive compensation program begins with our program objectives.

• Aligning the interests of our executives and unitholders. We seek to align the interests of our executives with those of our unitholders through equity-based compensation and executive unit ownership requirements.

• Linking rewards to performance. We seek to implement a pay-for-performance philosophy by tying a significant portion of our executives’ compensation to their achievement of financial goals that are linked to our business strategy and each executive’s contributions towards the achievement of those goals.

• Offering competitive compensation. We seek to offer an executive compensation program that is competitive and that helps us attract, motivate and retain top performing executives.

We continue to believe that a significant portion of executive compensation should be variable and based on defined performance goals and/or unit price change (i.e., “at risk”). Our program meets this goal by delivering compensation in the form of equity and other performance-based awards. The chart below shows the 2012 mix of target compensation opportunity for Mr. E. Cohen and for the other NEOs as a group against the peer group median. See “—Governance of Executive Compensation—Independent Compensation Consultant” below for a description of the peer group and survey group.

	Atlas	Peer Group Median	Survey Median

	Atlas	Peer Group Median	Survey Median

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The Compensation Committee believes our executive compensation program includes key features that align the interests of our NEOs with our long-term strategic direction.

What we do	What we don’t do
p Tie Pay to Performance. A significant portion of each executive officer’s target annual compensation is tied to corporate and individual performance, requiring the achievement of predetermined performance objectives during the year.	q Tax Gross Ups. We don’t pay tax gross ups for excise taxes that may be imposed as a result of severance or other payments deemed made in connection with a change of control.
p Make Annual Incentive Awards Substantially in the Form of Equity Rather Than Cash. For 2013, no cash component of the bonuses awarded to our NEOs exceeded 32%.	q Excessive Perquisites. We generally do not provide perquisites to our executives, other than automobile allowances and Excess 401(k) match contributions for some of our NEOs.
pCap Annual Incentive Awards. Annual incentive awards are limited to 18.3% of distributable cash flow. The total amount of the awards (cash and equity) for 2013 was 4.7% of the distributable cash flow.	q Allow Hedging and Pledging. Our insider trading policy prohibits margining, derivative or speculative transactions, such as hedges, pledges and margin accounts for executive officers.
p Utilize Stock Ownership Guidelines. We have significant unit ownership guidelines, which require our executive officers and directors to hold a percentage of their annual base salary (for directors, their retainer) in equity.
p Employ a Clawback Policy. Our Clawback Policy allows us to recoup any excess incentive compensation paid to our NEOs if the financial results on which the awards were based are materially restated due to fraud, illegal or intentional misconduct or gross negligence of the executive officer.
p Retain an Independent Compensation Consultant. The Compensation Committee engages an independent compensation consultant, who does not provide services to management.
p Have Double-Trigger Severance Arrangements. Our employment and equity award agreements require a qualifying termination of employment in addition to a change of control before change of control benefits or accelerated equity vesting are triggered.
pConduct an Annual Say on Pay Vote. Our unitholders voted in favor of an annual Say on Pay advisory vote at our 2012 annual meeting, and we determined that an annual vote would be appropriate and consistent with our unitholders’ interests. At our 2013 annual meeting, more than 88% of the votes cast on the Say on Pay proposal were in favor of the fiscal year 2012 compensation of our NEOs.
p Employment Agreements. We have written employment agreements with a majority of our NEOs.

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ELEMENTS OF OUR EXECUTIVE COMPENSATION PROGRAM

The 2013 compensation program for our NEOs consisted of the following components:

Component	Type of pay	Purpose	Key characteristics
Base salary	Fixed	Provide fixed compensation for performance of core duties that contribute to our success. Not intended to compensate for extraordinary or for above average performance.	Fixed compensation that is reviewed annually and adjusted if and when appropriate.
Annual incentives	Performance-based	Motivate NEOs to achieve annual performance targets.	Variable performance-based cash and equity awards tied to pre-established performance goals.
Long-term incentives	Performance-based	Align compensation with changes in unit prices and unitholder return experience.	Time-vested phantom stock and option awards, including ARP and APL equity-based awards.

2013 COMPENSATION DETERMINATIONS

In line with the performance we achieved as summarized above and in accordance with the Compensation Committee’s compensation philosophy, the Committee approved compensation for 2013 and salaries for 2014 for the NEOs as follows:

• Base salary;

• Annual incentives; and

• Long-term incentives.

REPORTED COMPENSATION VS. REALIZED PAY

The accompanying chart illustrates the difference between reported compensation in the 2013 Summary Compensation Table and the pay actually realized by our Chief Executive Officer and President in 2013. We believe this supplemental information is important because a substantial portion of reported compensation is an incentive for future performance and will actually be received by Mr. E. Cohen over a period of three years.

Reported compensation vs. realized pay for our CEO

Reported compensation(1)		Realized compensation(2)		Realized pay as a % of reported pay
$	7,586,669	$	5,115,557		67.43	%

(1) Reported compensation is total compensation as reported in the 2013 Summary Compensation Table.

(2) Realized pay is compensation actually received by the CEO during the year, including salary, non-equity bonus (amount reported for 2013 through actually paid in 2014), payouts on DERs, net spread on option exercises, market value at vesting of previously granted phantom units and All Other Compensation amounts realized during the year. Excludes the value of unvested equity awards, change in pension value and other amounts that will not actually be received until a future date.

Compensation Objectives

We believe that our compensation program must support our business strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. We also believe that a significant portion of the NEOs’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishments.

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Governance of Executive Compensation

COMPENSATION COMMITTEE

The Compensation Committee is responsible for designing our compensation objectives and methodology, and evaluating the compensation to be paid to our NEOs. The Compensation Committee is also responsible for administering our clawback policy, stock ownership guidelines and employee benefit plans, including incentive plans.

Our NEOs and other employees who perform services for ARP and APL may receive bonus and equity awards from ARP and/or APL. ARP has delegated compensation decisions to the Compensation Committee, since ARP does not have its own compensation committee and does not directly employ its officers. Therefore, our Compensation Committee determines awards to be made by ARP to our NEOs, as well as determining the compensation to be paid to NEOs of ARP. Since April 2012, APL has had its own compensation committee which determines compensation for its NEOs. APL’s compensation committee provides its determinations to our Compensation Committee, and our Committee retains the right to accept, reject, or modify the determinations with respect to the NEOs who serve both companies.

The Compensation Committee is comprised solely of independent directors, consisting of Ms. Warren and Messrs. Arrendell and Holtz, with Ms. Warren acting as the chair.

CHIEF EXECUTIVE OFFICER

Our Chief Executive Officer makes recommendations to the Compensation Committee regarding the salary, bonus, and incentive compensation component of each of the other NEO’s total compensation. Our Chief Executive Officer provides the Compensation Committee with key elements of our company’s and the other NEOs’ performance during the year. Our Chief Executive Officer, at the Compensation Committee’s request, may attend committee meetings solely to provide insight into our company’s and the other NEOs’ performance, as well as the performance of other comparable companies in the same industry.

INDEPENDENT COMPENSATION CONSULTANT

For 2013, the Compensation Committee engaged Mercer (US) Inc., an independent compensation consulting firm, to provide information and objective advice regarding executive compensation. All of the decisions with respect to our NEOs’ compensation, however, are made by the Compensation Committee or, in the case of awards from APL, the APL compensation committee, which communicates the APL award information to the Compensation Committee.

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Mercer worked with our senior management to develop a peer group in 2012 that reflected as close as possible, our business mix, structure and size. The peer group is comprised of 14 oil and gas companies with the majority having revenues ranging from  ¹⁄₂ to 2 times our company’s revenues, which are near the median. The peer group is the same as the peer group used in 2012, except that Copano Energy LLC was excluded because it was acquired by Kinder Morgan Energy Partners LP in May 2013 and no longer deemed a peer. The members of the peer group are:

Ticker	Company Name	2012 Revenue ($ millions)
NGLS	TARGA RESOURCES CORP	$	5,886
PXD	PIONEER NATURAL RESOURCES CO	$	2,812
SD	SANDRIDGE ENERGY INC	$	2,731
SWN	SOUTHWESTERN ENERGY CO	$	2,715
WLL	WHITING PETROLEUM CORP	$	2,170
MMP	MAGELLAN MIDSTREAM PRTNRS LP	$	1,772
LINE	LINN ENERGY LLC	$	1,753
EQT	EQT CORP	$	1,642
MWE	MARKWEST ENERGY PARTNERS LP	$	1,452
RRC	RANGE RESOURCES CORP	$	1,408
COG	CABOT OIL & GAS CORP	$	1,205
EROC	EAGLE ROCK ENERGY PARTNRS LP	$	984
CRZO	CARRIZO OIL & GAS INC	$	368
EVEP	EV ENERGY PARTNERS LP	$	285

Summary Statistics (n= 14)
	75th Percentile:	$	2,579
	Median	$	1,697
	25th Percentile:	$	1,255
ATLAS ENERGY LP		$	1,476

Source: Standards & Poor’s Compustat Database

Mercer’s analysis also included its compensation survey data for the oil and gas industry. Mercer’s analysis included:

• A market competitive assessment against the peer group and survey data evaluating base salaries, total cash compensation, and total direct compensation (representing the annualized long-term incentive award value plus total cash compensation), as well as pay mix. Mercer found that:

• base salaries were competitive (defined as within 15% of a market benchmark) with the 90^th percentile of the peer group and the survey, except for Mr. Jones’, which was competitive with the median of both groups, Mr. McGrath’s, which was competitive with the 25^th percentile of the peer group and below the competitive range of the 25^th percentile of the survey, and Mr. Dubay’s which was below the competitive range of the 25^th percentile of the survey;

• total cash compensation was competitive with or above the 90^th percentile of the peer group and the survey, except for Mr. Dubay’s, which was competitive with the 75^th percentile of the survey, and Mr. McGrath’s, which was competitive with the 75^th percentile of the peer group and between the 75^th and 90^th percentile of the survey;

• total direct compensation was above the 90^th percentile of the peer group, except for Mr. McGrath’s, which was between the 25th and 50^th percentiles, and above the competitive range of the survey 90^th percentile, except for Mr. Dubay’s and Mr. McGrath’s, which were competitive with the median; and

• in the aggregate, we place more emphasis on variable pay than the peer group or the survey.

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• A pay for performance assessment that tests the alignment between the actual compensation awarded and total shareholder return for the 3-year and 1-year periods ending December 2012 against the peer group. Mercer found that:

• Our total shareholder return was the highest among our peers for both periods;

• On a 3-year basis, our total direct compensation was aligned with total shareholder return;

• On a 1-year basis, our total cash compensation was aligned with total shareholder return.

• A run rate and dilution assessment which reviewed potential dilution, share-based run rate and economic run rate against the peer group. Mercer found that, largely as a result of the multi-year long-term incentive grants of our equity made in 2011, our 2012 equity usage was the highest relative to the peer group.

• An executive benefits assessment. Mercer found that:

• We provide 401(k) match contributions to all employees, as do all of our peers; and

• We have a deferred compensation plan pursuant to which certain senior executives may defer an additional portion of their compensation which we match up to 50% of base salary.

The Compensation Committee and management plan to continue to monitor the peer group to ensure that it remains aligned with our size and business mix.

A critical criterion in our Compensation Committee’s selection of Mercer to provide executive and director compensation consulting services was the fact that Mercer does not provide any other services to us or our affiliated companies. In addition to reaffirming this on an annual basis, we also conduct a search of our accounts payable system to confirm that no Mercer affiliates are providing services outside of the compensation consulting services. As discussed in “Code of Business Conduct and Ethics” and “Certain Relationships and Related Transactions” we have a code of business conduct and ethics as well as a related party transaction policy which governs potential conflicts of interest. Our directors and officers are also required to complete questionnaires on an annual basis which allows us to review whether there are any potential conflicts as a result of personal or business relationships. There are no business or personal relationships between the consultants from Mercer who work with us and our directors and executive officers other than the compensation consulting described herein.

TIMING OF COMPENSATION DECISION PROCESS

The Compensation Committee makes its determination on compensation amounts shortly after the close of our fiscal year. In the case of base salaries, the Committee recommends the amounts to be paid for the new fiscal year. In the case of annual bonus and long-term incentive compensation, the committee determines the amount of awards based on the most recently concluded fiscal year.

We typically pay cash awards and issue equity awards in February of each year, although the Compensation Committee has the discretion to recommend salary adjustments and the issuance of equity awards at other times during the fiscal year. In addition, our NEOs and other employees who perform services for APL may receive annual bonus and long-term incentive compensation awarded by APL’s compensation committee.

Elements of our Compensation Program

BASE SALARY

Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contributed to our success. Base salaries are not intended to compensate individuals for their extraordinary performance or for above average company performance.

ANNUAL INCENTIVES

Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to our annual performance and/or that of our subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within our company, the greater is the incentive component of that executive’s target total cash compensation. The Compensation Committee may recommend awards of performance-based bonuses and discretionary bonuses.

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PERFORMANCE-BASED BONUSES

We have an Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, to award bonuses for achievement of predetermined performance objectives during a 12-month performance period, generally our fiscal year. Awards under the Senior Executive Plan may be paid in cash or in a combination of cash and time-vesting equity. Making all equity awards vest over time adds an additional performance-based component to the bonuses.

Summary of performance factors that determine bonus

• No awards are made unless at least one of the performance goals is met, except in exceptionally rare circumstances

• Equity awards vest over time—a delayed payout feature that further aligns interests of NEOs with sustainable long-term growth in unitholder value

During 2013, the Compensation Committee approved 2013 bonus awards to be paid from a bonus pool. The bonus pool is equal to a maximum of 18.3% of the distributable cash flow of our entire enterprise. One of two goals for 2013 had to be met before any bonuses would be paid:

• at least 80% of the average distributable cash flow allocable to us for the past three years; and

• at least 80% of the average production volumes (which for ARP means production volumes and for APL means gathered volumes) for the past three years.

The goals are set early in the year, but actual awards are ultimately determined by the Committee’s year-end evaluation that also evaluates other factors as set forth below. While the Compensation Committee has the discretion to make awards even if one of the goals is not met, it does not anticipate doing so absent exceptionally rare circumstances justifying the payment of a bonus.

In the event that distributable cash flow includes any capital transaction gains in excess of $50 million, then only 10% of that excess is included in the bonus pool. Distributable cash flow means the sum of (i) cash available for distribution by us, including the distributable cash flow of any of our subsidiaries (regardless of whether such cash is actually distributed), plus (ii) to the extent not otherwise included in distributable cash flow, any realized gain on the sale of securities, including securities of a subsidiary, less (iii) to the extent not otherwise included in distributable cash flow, any loss on the sale of securities, including securities of a subsidiary. A return of our capital investment in a subsidiary was not intended to be included and, accordingly, if distributable cash flow included proceeds from the sale of all or substantially all of the assets of a subsidiary, the amount of such proceeds to be included in distributable cash flow would be reduced by our basis in the subsidiary.

The maximum award, expressed as a percentage of our estimated 2013 distributable cash flow, for each participant was as follows: Mr. E. Cohen, 6.22% ($21,500,000); Mr. J. Cohen, 5.49% ($19,000,000); Mr. Jones, 2.93% ($10,100,000); Mr. Dubay, 2.20% ($7,600,000); and Mr. McGrath, 1.46% ($5,100,000). Mr. Dubay’s maximum award amount will be reduced by any incentive compensation paid to him by APL, and the deducted amount may be available for allocation among the other participants in the Senior Executive Plan.

Pursuant to the terms of the Senior Executive Plan, the Compensation Committee has discretion to recommend reductions, but not increases, in maximum awards under the Senior Executive Plan. In making its decisions, the Compensation Committee considers factors including, growth of reserves, growth in production, processing and intake of natural gas, total market and distribution return to unitholders, and health and safety performance.

DISCRETIONARY BONUSES

In exceptional circumstances, discretionary bonuses may be awarded to recognize individual and group performance without regard to limitations otherwise in effect.

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LONG-TERM INCENTIVES

We believe that our long-term success depends upon aligning our executives’ and unitholders’ interests. To support this objective, we provide our executives with various means to become significant equity holders, including awards under our 2006 Long-Term Incentive Plan (the “2006 Plan”) and our 2010 Long-Term Incentive Plan (the “2010 Plan”), which we refer to as our Plans. Under our Plans, the Compensation Committee may recommend grants of equity awards in the form of options and/or phantom units. Generally, the unit options and phantom units vest over a three or four year period.

Our NEOs are eligible to receive awards under the Atlas Resource Partners, L.P.’s 2012 Long-Term Incentive Plan, which we refer to as the ARP Plan. Our NEOs are also eligible to receive awards under the Atlas Pipeline Partners, L.P.’s 2004 Long-Term Incentive Plan and its 2010 Long-Term Incentive Plan, which we refer to as the APL Plans; however, awards under the APL Plans are determined by the APL compensation committee and the amount of the APL awards are communicated to our Compensation Committee.

Additional Information Concerning Executive Compensation

DEFERRED COMPENSATION

All of our employees may participate in our 401(k) plan, which is a qualified defined contribution plan designed to help participating employees accumulate funds for retirement. In July 2011, we established the Atlas Energy Executive Excess 401(k) Plan (the “Excess 401(k) Plan”), a non-qualified deferred compensation plan that is designed to permit individuals who exceed certain income thresholds and who may be subject to compensation and/or contribution limitations under our 401(k) plan to defer an additional portion of their compensation. The purpose of the Excess 401(k) Plan is to provide participants with an incentive for a long-term career with us by providing them with an appropriate level of replacement income upon retirement. Under the Excess 401(k) Plan, a participant may contribute to an account an amount up to 10% of annual cash compensation (which means a participant’s salary and non-performance-based bonus) and up to 100% of all performance-based bonuses. We are obligated to make matching contributions on a dollar-for-dollar basis of the amount deferred by the participant subject to a maximum matching contribution equal to 50% of the participant’s base salary for any calendar year. We do not pay above-market or preferential earnings on deferred compensation. Participation in the Excess 401(k) Plan is available pursuant to the terms of an individual’s employment agreement or at the designation of the Compensation Committee. Currently, Messrs. E. Cohen and J. Cohen are the only participants in the Excess 401(k) Plan. For further details, please see the 2013 Non-Qualified Deferred Compensation table.

POST-TERMINATION COMPENSATION

Our NEOs received substantial cash amounts from Chevron in connection with the Chevron Merger, both as a result of the termination payments due under their employment agreements and their equity holdings. The Compensation Committee believed that the amounts thus realized left our NEOs without adequate financial incentives to continue employment with us, which the Committee did not believe was in our interest as we moved forward with significant new operations. In order to encourage these executives to remain with us on a long-term basis, we entered into employment agreements with Messrs. E. Cohen, J. Cohen, Jones and Dubay that, among other things, provide compensation upon termination of their employment by reason of death or disability, by us without cause or by each of them for good reason. See “—Employment Agreements and Potential Payments Upon Termination or Change of Control.”

The Compensation Committee considered the following in entering into these agreements:

• “Double trigger” severance payments—Change in control severance benefits (base salary and bonus payments) to each NEO are paid pursuant to a “double-trigger,” which means that to receive such benefits employment must terminate both: (1) as a result of a qualifying termination of employment, where his position with us changes substantially and is essentially an involuntary termination, and (2) after a change in control.

• Benefit multiple—The Compensation Committee determined the benefit multiple, that is, the cash severance amount based on each executive’s salary and bonus, after consideration of comparable market practices provided to the committee by Mercer.

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CLAWBACK POLICY

In February 2014, the Compensation Committee established a Clawback Policy pursuant to which NEOs and other key executive officers will be required to return incentive compensation paid to them if the financial results upon which the awards were based are restated due to the fraud or intentional illegal conduct of the executive officer.

The Clawback Policy does not authorize the Compensation Committee to seek recovery to the extent it determines that to do so would be unreasonable or that it would be better for our company not to do so. The Compensation Committee will determine in its discretion if it will seek to recover applicable compensation, taking into account the following considerations as it deems appropriate:

• Whether the amount of any bonus or equity compensation paid or awarded during the covered time period, based on the achievement of specific performance targets, would have been reduced based on the restated financial results;

• The likelihood of success of recouping the compensation under governing law relative to the cost and effort involved;

• Whether the assertion of the claim may prejudice our interests, including in any related proceeding or investigation;

• The passage of time since the occurrence of the misconduct; and

• Any pending legal action related to the misconduct.

We believe our Clawback Policy is sufficiently broad to reduce the potential risk that an executive officer would intentionally misstate results in order to benefit under an incentive program and provides a right of recovery in the event that an executive officer takes actions that, in hindsight, should not have been rewarded.

This Clawback Policy applies in addition to the clawback provisions of awards under our Plans, which provide that the Compensation Committee has the express right to cancel an option or phantom unit grant, and to demand the return of any vested units, if the recipient has disclosed confidential information or trade secret or engaged in any activity in competition with our business or the business of any of our subsidiaries or, in the case of the 2006 Plan awards, is convicted of a felony or a crime of moral turpitude with respect to our company or engages in fraud or embezzlement with respect to our company.

STOCK OWNERSHIP GUIDELINES FOR NEOS

In February 2014, the Compensation Committee established unit ownership guidelines for our NEOs pursuant to which these executives are expected to hold a minimum number of our common units equal to a specified multiple of their annual base salaries, as follows:

Position	Required ownership multiple
Chief Executive Officer	Five (5) times annual base salary
Executive Chair and Executive Vice Chair	Four (4) times annual base salary
Chief Financial Officer	Three (3) times annual base salary
Executive Vice Presidents	Three (3) times annual base salary
Senior Vice Presidents	Two (2) times annual base salary

Equity interests that count toward the satisfaction of the ownership guidelines include common units held directly or indirectly by the executive, including common units purchased on the open market or acquired upon the exercise of a stock option and common units remaining or received upon the settlement of restricted stock, restricted stock units, and phantom units, and vested units allocated to the executive’s account under any qualified plan. Common units of APL and ARP will also satisfy the ownership guidelines so long as at least 50% of an executive’s holdings are our common units. Executives have five years from the date of the commencement of the guidelines or the date the executive is designated a covered

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executive by the Compensation Committee, whichever is later, to attain these ownership levels. If an executive officer does not meet the applicable guideline by the end of the five-year period, the executive officer is required to hold any net shares resulting from any future vesting of restricted or phantom units or exercise of stock options until the guideline is met. These guidelines reinforce the importance of aligning the interests of our executive officers with the interests of our unitholders and encourage our executive officers to consider the long-term perspective when managing our company.

Additionally, we have instituted stock ownership guidelines for our non-employee directors. For information regarding these guidelines, see the section entitled “Director Compensation.”

NO HEDGING OF COMPANY STOCK

All of our employees are prohibited from hedging their company stock.

NO TAX GROSS UPS

We do not provide tax reimbursements to our NEOs.

PERQUISITES

At the discretion of the Compensation Committee, we provide perquisites to our NEOs. In 2013, these benefits were limited to providing automobile allowances or automobile related expenses to Messrs. E. Cohen and Jones.

CONSULTING AGREEMENT WITH MR. J. COHEN

In connection with the formation of the Lightfoot entities in 2007, Atlas Energy, Inc. entered into an agreement with Mr. J. Cohen to provide compensation to him in recognition of his role in negotiating and structuring its investment and his continued service as chairman of Lightfoot GP. We acquired Atlas Energy, Inc.’s direct and indirect ownership interests in the Lightfoot entities as part of the assets and liabilities we acquired from Atlas Energy, Inc. in February 2011. Under the agreement, Mr. J. Cohen receives an amount equal to 10% of the distributions that we receive from the Lightfoot entities, excluding amounts that constitute a return of our capital.

Determination of 2013 Compensation Amounts

Following its review of Mercer’s analyses, in the fall of 2013, the Compensation Committee began to prepare for the executive compensation process by discussing the schedule for upcoming meetings and reviewing a proposed calendar. The Compensation Committee held meetings in October to review and discuss the compensation philosophy. In February 2014, the Compensation Committee met with Mercer, with our Chief Executive Officer in attendance, to evaluate our company’s performance and to approve annual payouts to NEOs as well as long-term incentive grants to senior employees.

SAY ON PAY

At our 2013 annual meeting, our unitholders were asked to vote on a non-binding resolution approving the compensation of our NEOs as disclosed in the proxy statement. Our unitholders approved compensation of our NEOs with approximately 88% of the votes cast in favor of our “say on pay” proposal. Additionally, consistent with the vote of the unitholders at the 2012 annual meeting, the Board of Directors of our general partner decided to conduct an advisory vote on the compensation of our NEOs every year until the next required vote on the frequency of the unitholder vote on executive compensation. While these unitholder votes are advisory and non-binding, the Compensation Committee has interpreted the results as strongly supportive of the compensation paid to our NEOs and therefore has decided to maintain similar compensation practices for 2013. In addition, the annual review by the unitholders will provide the Committee with a current perspective on the compensation awarded to the NEOs.

BASE SALARY

As described above, Mercer’s market competitive assessment found that that base salaries of these NEOs were competitive with the 90th percentile of the peer group and the survey, except for Mr. Jones’, which was competitive with the median of both groups, and Mr. McGrath’s, which was competitive with the 25th percentile of both the peer groups and below the competitive range of the 25th percentile of the survey, and Mr. Dubay’s, which was below the competitive range of the 25th percentile of the survey. Taking that analysis into consideration, our Compensation Committee determined that the

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current base salaries for Messrs. E. Cohen, J. Cohen and Jones were appropriate for 2014. The APL compensation committee likewise determined that Mr. Dubay’s base salary was appropriate for 2014. Our Compensation Committee increased Mr. McGrath’s 2014 base salary to $400,000 in order to bring it to the median of the peer group and survey data.

ANNUAL INCENTIVES

After the end of our 2013 fiscal year, our Compensation Committee considered incentive awards pursuant to the Senior Executive Plan based on the year’s performance. In determining the actual amounts to be paid to the NEOs, the Compensation Committee considered both individual and company performance. Our Chief Executive Officer made recommendations of incentive award amounts based upon our performance as well as the performance of our subsidiaries; however, the Compensation Committee had the discretion to approve, reject, or modify the recommendations. The Compensation Committee noted that our total unitholder return, including cash distributions, was 39% during 2013, which was approximately the median of our peer group. The Committee took into consideration that the 2013 return followed annual returns of 67% and 61% during the prior two years, thus representing a greater achievement than similar increases in share prices at other peer companies whose stock price increases had been far inferior to our return over the prior two years. Our distributable cash flow was more than double the performance goal set under our Senior Executive Plan. Our reserve levels of hydrocarbons increased by approximately 52% during 2013 from 911 Bcfe to 1.4 Tcfe, and we added over 600,000 net undeveloped acres of energy rights (almost a 200% increase) and over 340,000 developed acres (a 95% increase); our natural gas production grew by approximately 97% from approximately130 Mmcf/ed to approximately 260 Mmcfed; and in both the pipeline and E&P operations, significant safety incidents were at low levels.

The Committee confirmed that our company had achieved not one, but both, of the threshold performance standards permitting bonus payments under the Senior Executive Plan. The Committee determined that the average three years of distributable cash flow allocable to us was $98 million, which was double the pre-determined minimum threshold of 80% of three year average distributable cash flow of $43 million. The Committee also determined that the production volume for 2013 was 1,665 mmcfed, far surpassing 80% of the average production volume for the past three years of 608 mmcfed. The Compensation Committee reviewed the calculations of our maximum 2013 bonus pool which was 18.3% of our adjusted distributable cash flow of $345 million (although actual awards are far less than planned maximums). The Committee, however, recognized NEOs’ continued strong performance and decided to make awards that were generally commensurate with overall awards that had been granted in 2011 and 2012, and therefore, did not grant awards at the maximum level for any of the NEOs.

At this time, in view of evolving corporate governance standards, the Committee decided to continue to move annual incentive compensation from a largely cash-based system to a substantially equity-based bonus system and to institute clawback provisions. To that end, the Committee determined to grant awards that were substantially in the form of equity, such that no cash component of the bonuses awarded to the NEOs for 2013 exceeded 32% as compared to 2012 when the cash component averaged 63%. Because the committee deemed these equity awards to be annual incentive awards made in lieu of cash, they determined that these phantom units vest ratably over the next two years. Because the equity awards were made in 2014, they do not appear in the Summary Compensation table or the Grants of Plan-Based Awards table that follow, but will be reflected in those tables next year. The following table shows the maximum amounts that could be awarded under the Senior Executive Plan and the breakdown of the awards actually granted:

Named Executive Officer	Maximum percentage of bonus pool (18.3%)			Maximum potential awards		Total compensation value		Cash amount awarded		Number of ATLS phantom units awarded
Edward E. Cohen		6.22	%	$	21,500,000	$	6,000,000	$	1,200,000		109,589
Jonathan Z. Cohen		5.49	%	$	19,000,000	$	5,500,000	$	1,200,000		98,174
Matthew A. Jones		2.93	%	$	7,600,000	$	3,000,000	$	750,000		51,370
Sean P. McGrath		1.46	%	$	5,100,000	$	1,900,000	$	600,000		34,247

In February 2014, the APL compensation committee awarded Mr. Dubay 50,000 phantom units (with DERs), which will vest ratably over three years. In light of this APL award, Mr. Dubay did not receive a separate award under the Senior Executive Plan.

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For 2013, our Compensation Committee did not award any discretionary bonuses.

The APL compensation committee (consisting solely of APL independent directors unaffiliated with us) has authorized APL’s executive committee to make cash awards of $100,000 each to its NEOs (including Messrs. E. Cohen, J. Cohen and Dubay) if (i) APL’s gathered volumes on operating assets initially included in its approved 2014 budget reach at least 1.8 billion cubic feet per day (Bcf/day), as averaged over a fiscal quarter, and (ii) the executive committee determines such awards are appropriate.

LONG-TERM INCENTIVES

In July 2013, the APL compensation committee provided retention bonuses for a number of executives including several of our NEOs as follows: Mr. E. Cohen – 50,000 phantom units; Mr. J. Cohen – 50,000 phantom units; and Mr. Dubay – 50,000 phantom units. The awards will vest 25% on each anniversary of the grant. The APL compensation committee determined that competition for experienced personnel, particularly from private equity firms, had substantially increased and that the awards were necessary to assure the continued services of APL personnel.

In February 2014, the APL compensation committee made awards of our phantom units (with DERs), for similar reasons, as follows: 50,000 phantom units to each of Messrs. E. Cohen, J. Cohen and Dubay. The units will vest ratably over three years.

Because these awards were made after 2013 year-end, they do not appear in the Summary Compensation table or the Grants of Plan-Based Awards table that follow, but will be reflected in the tables appearing in our 2014 annual report.

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SUMMARY COMPENSATION TABLE

Name and principal position	Year		Salary ($)		Bonus ($)		Unit awards ($)(1)		Option awards ($)(2)		Non-equity incentive plan compensation ($)		All other compensation ($)			Total ($)
Edward E. Cohen, Chief Executive Officer and President		2013		1,000,000		—		3,775,488		—		1,200,000		1,611,182	(3)		7,586,670
		2012		896,154		—		7,198,500		2,135,000		2,750,000		2,066,013			15,045,667
		2011		746,154		—		6,669,000		6,951,000		3,500,000		3,066,906			20,933,060
Sean P. McGrath, Chief Financial Officer		2013		350,000		—		499,973		—		600,000		159,851	(4)		1,609,824
		2012		250,000		—		1,233,500		305,000		550,000		173,962			2,512,462
		2011		250,000		1,275,000		666,900		347,550		—		17,638			2,557,088
Jonathan Z. Cohen, Executive Chairman of the Board		2013		700,000		—		3,575,468		—		1,200,000		1,481,840	(5)		6,957,308
		2012		630,769		—		7,198,500		2,135,000		2,700,000		1,981,760			14,646,029
		2011		530,769		—		5,557,500		4,965,000		3,000,000		2,892,500			16,945,769
Eugene N. Dubay, Senior Vice President of Midstream		2013		500,000		—		1,975,500		—		—		338,638	(6)		2,814,138
		2012		500,000		1,500,000		1,778,400		993,000		—		440,683			5,938,683
		2011		500,000		—		1,334,009		1,008,700		1,000,000		5,136,128			9,407,528
Matthew A. Jones, Senior Vice President and President of E&P Division		2013		400,000		—		1,099,995		—		750,000		480,892	(7)		2,730,887
		2012		358,462		—		2,467,000		1,372,500		1,650,000		254,033			6,101,995
		2011		298,024		—		3,334,500		1,986,000		1,250,000		1,344,910			8,213,434

(1) For fiscal year 2013, the amounts reflect the grant date fair value of the phantom units under the ATLS Plans and the APL Plans. The grant date fair value was determined in accordance with FASB ASC Topic 718, and is based on the market value on the grant date of ATLS units and APL units. See Item 8: Financial Statements and Supplementary Data—Note 17 for further discussion regarding assumptions made in fair value valuation. For fiscal year 2012, the amounts reflect the grant date fair value of the phantom units under the APL Plans and ARP Plan. For fiscal year 2011, the amounts reflect the grant date fair value of the phantom units under the ATLS Plans.

(2) The amounts in this column reflect the grant date fair value of options awarded under the ATLS Plans and the APL Plans calculated in accordance with FASB ASC Topic 718. See Item 8: Financial Statements and Supplementary Data—Note 17 for further discussion regarding assumptions made in fair value valuation.

(3) Comprised of (i) payments on DERs of $564,100 with respect to the phantom units awarded under our Plans, (ii) payments on DERs of $272,250 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $272,000 with respect to the phantom units awarded under the APL Plans, (iv) a matching contribution of $500,000 under the Excess 401(k) Plan; and (v) tax, title and insurance premiums for Mr. E. Cohen’s automobile.

(4) Comprised of (i) payments on DERs of $69,101 with respect to the phantom units awarded under our Plans and (ii) payments on DERs of $90,750 with respect to the phantom units awarded under the ARP Plan.

(5) Comprised of (i) payments on DERs of $474,048 with respect to the phantom units awarded under our Plans, (ii) payments on DERs of $272,250 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $272,000 with respect to the phantom units awarded under the APL Plans, (iv) a matching contribution of $350,000 under the Excess 401(k) Plan; and (v) $113,542 paid under the agreement relating to Lightfoot.

(6) Comprised of (i) payments on DERs of $131,388 with respect to the phantom units awarded under our Plans and (ii) payments on DERs of $257,250 with respect to the phantom units awarded under the APL Plans.

(7) Comprised of (i) payments on DERs of $289,982 with respect to the phantom units awarded under our Plans, (ii) payments on DERs of $181,500 with respect to the phantom units awarded under the ARP Plan; and (iii) an automobile allowance.

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2013 GRANTS OF PLAN-BASED AWARDS

	Estimated possible payments under non-equity incentive plan awards(1)
Name	Threshold ($)		Target ($)		Maximum ($)		Grant date		All other stock awards: Number of units			All other option awards: Number of securities underlying options		Exercise or base price of option awards ($/Unit)		Grant date fair value of unit and option awards ($)(4)
Edward E. Cohen		N/A		N/A		21,500,000		2/4/13		47,281	(2)		—		—		1,799,988
								7/10/13		50,000	(3)		—		—		1,975,500
Sean P. McGrath		N/A		N/A		5,100,000		2/4/13		13,133	(2)		—		—		499,973
Jonathan Z. Cohen		N/A		N/A		19,000,000		2/4/13		42,027	(2)		—		—		1,599,968
								7/10/13		50,000	(3)		—		—		1,975,500
Eugene N. Dubay		N/A		N/A		7,600,000		7/10/13		50,000	(3)		—		—		1,975,500
Matthew A. Jones		N/A		N/A		10,100,000		2/4/13		28,894	(2)		—		—		1,099,995

(1) Represents performance-based bonuses under our Senior Executive Plan which may be paid in cash and/or equity. As discussed under “Compensation Discussion and Analysis—Elements of our Compensation Program—Annual Incentives—Performance-Based Bonuses,” the Compensation Committee set performance goals based on our distributable cash flow and established maximum awards, but not minimum or target amounts, for each eligible NEO.

(2) Represents phantom units granted under the 2006 ATLS Long-Term Incentive Plan.

(3) Represents phantom units granted under the APL 2010 Long-Term Incentive Plan.

(4) The grant date fair value was calculated in accordance with FASB ASC Topic 718.

EMPLOYMENT AGREEMENTS AND POTENTIAL PAYMENTS UPON TERMINATION

OR CHANGE OF CONTROL

We have employment agreements with our NEOs that provide for severance compensation to be paid if their employment is terminated under certain conditions.

Terms Used

“Good reason” is defined in the following employment agreements as:

• a material reduction in base salary;

• a demotion from his position;

• a material reduction in duties, it being deemed such a material reduction if we cease to be a public company unless we become a subsidiary of a public company and,

• in the case of Mr. E. Cohen, becomes the chief executive officer of the public parent immediately following the applicable transaction;

• in the case of Mr. J. Cohen, becomes an executive officer of the public parent with responsibilities substantially equivalent to his previous position immediately following the applicable transaction;

• in the case of Messrs. Jones and Dubay, the CEO or the Chairman of our general partner’s board is not our CEO or the CEO of the acquiring entity;

• the executive is required to relocate to a location more than 35 miles from the executive’s previous location;

• in the case of Mr. E. Cohen and Mr. J. Cohen, ceasing to be elected to our board; or

• any material breach of the agreement.

“Cause” is defined in Mr. E. Cohen and Mr. J. Cohen’s employment agreements as:

• the executive is convicted of a felony, or any crime involving fraud or embezzlement;

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• the executive intentionally and continually fails to perform his reasonably assigned duties (other than as a result of disability), which failure is materially and demonstrably detrimental to our company and has continued for 30 days after written notice signed by a majority of the independent directors of our general partner; or

• executive is determined, through arbitration, to have materially breached the restrictive covenants in the agreement.

“Cause” is defined in Messrs. Jones and Dubay’s employment agreements as:

• the executive has committed any demonstrable and material fraud;

• illegal or gross misconduct that is willful and results in damage to our business or reputation;

• in the case of Mr. Jones, he is convicted of a felony, or any crime involving fraud or embezzlement and in the case of Mr. Dubay, he is charged with a felony;

• failure to substantially perform his duties (other than as a result of disability) after written demand and a reasonable opportunity to cure; or

• failure to follow reasonable written instructions which are consistent with his duties.

Edward E. Cohen

Effective May 16, 2011, we entered into an employment agreement with Mr. Cohen to secure his service as President and Chief Executive Officer. The agreement has a term of three years, which automatically renews daily unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $700,000, which may be increased at the discretion of the board of directors of our general partner. Mr. Cohen is entitled to participate in any short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by us for our senior level executives generally. Mr. Cohen participates in the Excess 401(k) Plan, under which he may elect to defer up to 10% of his total annual cash compensation, which we must match on a dollar-for-dollar basis up to 50% of his annual base salary. See “2013 Non-Qualified Deferred Compensation.” During the term of the agreement, we must maintain a term life insurance policy on Mr. Cohen’s life which provides a death benefit of $3 million, which can be assumed by Mr. Cohen upon a termination of employment.

The agreement provides the following benefits in the event of a termination of employment:

• Upon termination of employment due to death, all equity awards held by Mr. Cohen accelerate and vest in full upon the later of the termination of employment or six months after the date of grant of the awards (“Acceleration of Equity Vesting”), and Mr. Cohen’s estate is entitled to receive, in addition to payment of all accrued and unpaid amounts of base salary, vacation, business expenses and other benefits (“Accrued Obligations”), a pro-rata bonus for the year of termination, based on the actual bonus that would have been earned had the termination of employment not occurred, determined and paid consistent with past practice (the “Pro-Rata Bonus”).

• We may terminate Mr. Cohen’s employment if he has been unable to perform the material duties of his employment for 180 days in any 12-month period because of physical or mental injury or illness, but we are required to pay his base salary until we act to terminate his employment. Upon termination of employment due to disability, Mr. Cohen will receive the Accrued Obligations, all amounts payable under our long-term disability plans, three years’ continuation of group term life and health insurance benefits (or, alternatively, we may elect to pay executive cash in lieu of such coverage in an amount equal to three years’ healthcare coverage at COBRA rates and the premiums we would have paid during the three-year period for such life insurance) (such coverage, the “Continued Benefits”), Acceleration of Equity Vesting, and the Pro-Rata Bonus.

• Upon termination of employment by us without cause or by Mr. Cohen for good reason, Mr. Cohen will be entitled to either (i) if he does not execute and not revoke a release of claims against us, payment of the Accrued Obligations, or (ii), in addition to payment of the Accrued Obligations, if he executes and does not revoke a release of claims against us, (A) a lump-sum cash payment in an amount equal to three times his average compensation (which, assuming a termination date of December 31, 2013 is defined as the sum of (1) his annualized base salary in effect immediately before the termination of employment plus (2) the average of the bonuses earned for 2012 and 2011, (B) Continued Benefits for three years, (C) the Pro-Rata Bonus, and (D) Acceleration of Equity Vesting.

• Upon a termination by us for cause or by Mr. Cohen without good reason, he is entitled to receive payment of the Accrued Obligations.

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In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Cohen will be reduced such that the total payments to the executive which are subject to Internal Revenue Code Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

The following table provides an estimate of the value of the benefits to Mr. Cohen if a termination event had occurred as of December 31, 2013:

Reason for termination	Lump sum severance payment			Benefits(1)		Accelerated vesting of unit awards and option awards(2)
Death	$	9,000,000	(3)	$	—	$	44,294,671
Disability		6,000,000			57,626		44,294,671
Termination by us without cause or by Mr. Cohen for good reason		30,785,232	(4)		57,626		44,294,671

(1) Dental and medical benefits were calculated using 2013 COBRA rates.

(2) Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End” table. The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2013. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2013.

(3) Represents Mr. Cohen’s bonus for 2013 plus life insurance policy proceeds.

(4) Represents (i) three times ((a) Mr. Cohen’s base salary plus (b) the average of his bonuses for 2012 and 2011) plus (ii) his bonus for 2013. The value of unit awards is based on the fair market value of the underlying stock at the grant date. The value of options is based on Black-Scholes option pricing at grant date.

Jonathan Z. Cohen

Effective May 16, 2011, we entered into an employment agreement with Mr. Cohen to secure his service as Chairman of the Board. The agreement has a term of three years, which automatically renews daily unless terminated before the expiration of the term pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $500,000, which may be increased at the discretion of the board of directors of our general partner. Mr. Cohen is entitled to participate in any short-term and long-term incentive programs and health and welfare plans of the company and receive perquisites and reimbursement of business expenses, in each case as provided by us for our senior level executives generally. Mr. Cohen participates in the Excess 401(k) Plan, under which he may elect to defer up to 10% of his total annual cash compensation, which we must match on a dollar-for-dollar basis up to 50% of his annual base salary. See “2013 Non-Qualified Deferred Compensation.” During the term of the agreement, we must maintain a term life insurance policy on Mr. Cohen’s life which provides a death benefit of $2 million, which can be assumed by Mr. Cohen upon a termination of employment.

The agreement provides the same benefits in the event of a termination of employment as described above in Mr. E. Cohen’s employment agreement summary.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Cohen will be reduced such that the total payments to the executive which are subject to Internal Revenue Code Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

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The following table provides an estimate of the value of the benefits to Mr. Cohen if a termination event had occurred as of December 31, 2013:

Reason for termination	Lump sum severance payment			Benefits(1)		Accelerated vesting of unit awards and option awards(2)
Death	$	7,500,000	(3)	$	—	$	35,755,710
Disability		5,500,000			83,652		35,755,710
Termination by us without cause or by Mr. Cohen for good reason		28,260,202	(4)		83,652		35,755,710

(1) Dental and medical benefits were calculated using 2013 COBRA rates.

(2) Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End” table. The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2013. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2013.

(3) Includes the $2 million death benefit from the life insurance policy and payment of the 2013 bonus.

(4) Represents (i) three times ((a) Mr. Cohen’s base salary plus (b) the average of his bonuses for 2012 and 2011) plus (ii) his bonus for 2013. The value of unit awards is based on the fair market value of the underlying stock at the grant date. The value of options is based on Black-Scholes option pricing at grant date.

Matthew A. Jones

In November 2011, we entered into an employment agreement with Matthew A. Jones. Mr. Jones has the title of Senior Vice President and President of the Exploration and Production Division of the Company. The agreement has an effective date of November 4, 2011 and has an initial term of two years, which automatically renews daily after the first anniversary of the agreement for one year terms.

The agreement provides for an initial annual base salary of $280,000. Mr. Jones is entitled to participate in any of our short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by us for our senior executives generally.

The agreement provides the following benefits in the event of a termination of employment:

• Upon a termination by us for cause or by Mr. Jones without good reason, he is entitled to receive payment of accrued but unpaid base salary and (to the extent required to be paid under company policy) amounts of accrued but unpaid vacation, in each case through the date of termination (together, the “Accrued Obligations”).

• Upon a termination of employment due to death or disability (defined as Mr. Jones being physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and the determination by our general partner’s board of directors, in good faith based upon medical evidence, that he is unable to perform his duties), all equity awards held by Mr. Jones accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Jones or his estate is entitled to receive in one cash payment, in addition to payment of all Accrued Obligations and any accrued but unpaid bonus earned for any year before the date of termination, a pro-rata amount in respect of the bonus granted to the executive for the fiscal year in which the termination occurs in an amount equal to the bonus earned by Mr. Jones for the prior fiscal year multiplied by a fraction, the numerator of which is the number of days in the fiscal year in which the termination occurs through the date of termination, and the denominator of which is the total number of days in such fiscal year (the “Pro-Rata Bonus”). In addition, his family is entitled to company-paid health insurance for the one-year period after his death.

• Upon a termination of employment by us without cause (which, for purposes of the “Acceleration of Equity Vesting” includes a non-renewal of the agreement) or by the executive for good reason, Mr. Jones will be entitled to either:

• if Mr. Jones does not timely execute (or revokes) a release of claims against us, payment in one cash payment of the Accrued Obligations, any accrued but unpaid bonus and the Pro-Rata Bonus; or

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• in addition to payment in one cash payment of the Accrued Obligations, any accrued but unpaid bonus and the Pro-Rata Bonus, if Mr. Jones timely executes and does not revoke a release of claims against us:

• a lump-sum cash severance payment in an amount equal to two times his average compensation (which is the sum of his then-current base salary and the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurs);

• healthcare continuation at active employee rates for two years (or, where such coverage would have a negative tax effect to our healthcare plan or Mr. Jones, we may elect to pay Mr. Jones cash in lieu of such coverage at COBRA rates); and

• Acceleration of Equity Vesting.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Jones will be reduced such that the total payments to the executive which are subject to Section 280G are no greater than the Section 280G “safe harbor amount” if Mr. Jones would be in a better after-tax position as a result of such reduction.

The following table provides an estimate of the value of the benefits to Mr. Jones if a termination event had occurred as of December 31, 2013:

Reason for termination	Lump sum severance payment			Benefits(1)		Accelerated vesting of unit awards and option awards(2)
Death	$	1,650,000		$	18,732	$	16,296,820
Disability		1,650,000			18,732		16,296,820
Termination by us without cause or by Mr. Jones for good reason		3,233,333	(3)		37,464		16,296,820

(1) Dental and medical benefits were calculated using 2013 active employee rates.

(2) Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End” table. The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2013. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2013.

(3) Calculated based on Mr. Jones’s 2013 base salary and the applicable bonus.

Eugene N. Dubay

On November 4, 2011, we entered into an employment agreement with Mr. Dubay. Under the agreement, Mr. Dubay has the title of Senior Vice-President of our Midstream Operations division. The agreement has an effective date of November 4, 2011 and has an initial term of two years, which automatically renews for successive one-year terms unless earlier terminated pursuant to the termination provisions of the agreement.

The agreement provides for an initial annual base salary of $500,000, and Mr. Dubay is entitled to participate in any short-term and long-term incentive programs and health and welfare plans and receive perquisites and reimbursement of business expenses, in each case as provided by us for our senior executives generally.

The agreement provides the following benefits in the event of a termination of Mr. Dubay’s employment:

• Upon a termination by us for cause or by Mr. Dubay without good reason, he is entitled to receive payment of accrued but unpaid base salary and (to the extent required to be paid under company policy) amounts of accrued but unpaid vacation, in each case through the date of termination (together, the “Accrued Obligations”).

• Upon a termination of employment due to death or disability (defined as Mr. Dubay being physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and the determination by our general partner’s board of directors, in good faith based upon medical evidence, that he is unable to perform his duties), all equity awards held by Mr. Dubay accelerate and vest in full upon such termination (“Acceleration of Equity Vesting”), and Mr. Dubay or his estate is entitled to receive, in addition to payment of all Accrued Obligations, an amount equal to the bonus earned by him for the prior fiscal year multiplied by a

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fraction, the numerator of which is the number of days in the fiscal year in which his termination occurs through the date of termination, and the denominator of which is the total number of days in such fiscal year (the “Pro-Rata Bonus”).

• Upon a termination of employment by us without cause (which, for purposes of the “Acceleration of Equity Vesting” includes a non-renewal of the agreement) or by Mr. Dubay for good reason, he is entitled to either:

• if he does not timely execute (or revokes) a release of claims against us, payment of the Accrued Obligations; or

• in addition to payment of the Accrued Obligations, if he timely executes and does not revoke a release of claims against us:

• monthly cash severance installments each in an amount equal to one-twelfth of the sum of his then-current (i) annual base salary and (ii) the annual cash incentive bonus earned by him in respect of the fiscal year preceding the fiscal year in which his termination of employment occurs for the portion of the employment term remaining after the date of termination, payable for the then-remaining portion of the employment term (taking into account any applicable renewal term) assuming his termination had not occurred,

• healthcare continuation at active employee rates for the then-remaining portion of the employment term (taking into account any applicable renewal term) assuming his termination had not occurred,

• a prorated amount in respect of the bonus granted to him in respect of the fiscal year in which his termination of employment occurs based on actual performance for such year, calculated as the product of (x) the amount which would have been earned in respect of the award based on actual performance measured at the end of such fiscal year and (y) a fraction, the numerator of which is the number of days in such fiscal year through the date of termination, and the denominator of which is the total number of days in such fiscal year, paid in a lump sum in cash on the date payment would otherwise be made had he remained employed by the Company, and

• Acceleration of Equity Vesting.

In connection with a change of control, any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code) otherwise payable to Mr. Dubay will be reduced such that the total payments to him which are subject to Section 280G are no greater than the Section 280G “safe harbor amount” if he would be in a better after-tax position as a result of such reduction.

The following table provides an estimate of the value of the benefits to Mr. Dubay if a termination event had occurred as of December 31, 2013:

Reason for termination	Lump sum severance payment			Benefits(1)		Accelerated vesting of unit awards and option awards(2)
Death	$	1,500,000		$	—	$	11,330,246
Disability		1,500,000			—		11,330,246
Termination by us without cause or by Mr. Dubay for good reason		1,166,667	(3)		20,520		11,350,766

(1) Dental and medical benefits were calculated using 2013 active employee rates.

(2) Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End” table. The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2013. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2013.

(3) Calculated based on Mr. Dubay’s 2013 base salary plus applicable bonus. Payment would be made in monthly installments for the remaining term of Mr. Dubay’s employment agreement.

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LONG-TERM INCENTIVE PLANS

Our 2006 Plan

Our 2006 Plan provides equity incentive awards to officers, employees and board members of our general partner and its affiliates, consultants and joint-venture partners who perform services for us. Our 2006 Plan is administered by our Compensation Committee. The committee may grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units, which was adjusted to an aggregate of 2,261,516 common limited partner units in connection with the ARP Distribution described below.

Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. Non-employee directors may receive an annual grant of phantom units having a fair market value of $125,000, which upon vesting entitles the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. The phantom units granted to employees under our 2006 Plan generally vest over a three or four year period and phantom grants to non-employee directors generally vest over a four year period, 25% per year. In tandem with phantom unit grants, the committee may grant a DER. The committee determines the vesting period for phantom units.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the committee on the date of grant of the option. The committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under our 2006 Plan will vest over a three or four year period from the date of grant.

Change of Control.

Individual:	Triggering event:	Acceleration:
Eligible employees	Change of Control (as defined in the 2006 Plan), and Termination of employment without “cause” as defined in grant agreement or upon any other type of termination specified in the applicable award agreement(s), following a change of control	Unvested awards immediately vest in full and in the case of options, become exercisable for the one-year period following the date of termination (but not later than the end of the original term of the option)
Independent directors	Change of Control (as defined in the 2006 Plan)	Unvested awards immediately vest in full

Our 2010 Plan

Our 2010 Plan provides equity incentive awards to officers, employees and board members of our general partner and its affiliates, consultants and joint-venture partners who perform services for us. Our 2010 Plan is administered by our Compensation Committee which may grant awards of either phantom units, unit options or restricted units for an aggregate of 5,300,000 common limited partner units, which was adjusted to an aggregate of 5,763,781 common limited partner units in connection with the ARP Distribution described below.

Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. Non-employee directors may receive an annual grant of phantom units having a market value of $125,000, which, upon vesting, entitle the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. The phantom units granted to employees under our 2010 Plan generally vest over a three or four year period and phantom grants to non-employee directors generally vest over a four year period, 25% per year. In tandem with phantom unit grants, the committee may grant a DER. The committee determines the vesting period for phantom units.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the committee on the date of grant of the option. The committee determines the vesting and exercise period for unit options and generally, the unit options granted under our 2010 Plan will vest over a three or four year period from the date of grant.

Partnership Restricted Units. A restricted unit is a common unit issued that entitles a participant to receive it upon vesting of the restricted unit. Prior to or upon grant of an award of restricted units, the committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both.

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Change of Control.

Individual:	Triggering event:	Acceleration:
Eligible employees	Change of Control (as defined in the 2010 Plan), and Termination of employment without “cause” as defined in the 2010 Plan or upon any other type of termination specified in the applicable award agreement(s), following a change of control	Unvested awards immediately vest in full and in the case of options, become exercisable for the one-year period following the date of termination (but not later than the end of the original term of the option)
Independent directors	Change of Control (as defined in the 2010 Plan)	Unvested awards immediately vest in full

Adjustments to Awards under Our Plans

On March 13, 2012, we distributed approximately 5.24 million ARP common units to our unitholders, which common units represented an approximately 19.6% limited partner interest in ARP (the “Distribution”). Our Compensation Committee determined that the Distribution qualified as the type of event necessitating an adjustment to the outstanding options and phantom units issued pursuant to our Plans. Accordingly, on March 13, 2012, the exercise price and the number of options outstanding were adjusted in order to maintain the aggregate pre-adjustment difference between the market value of the units subject to the option and the option exercise price. The number of phantom units outstanding was also adjusted to maintain the awards’ pre-adjustment values. All other terms of the awards remained unchanged.

APL Plans

The APL 2004 Long-Term Incentive Plan (the “2004 APL Plan”) and the 2010 Long-Term Incentive Plan, which was modified in April 2011 (the “2010 APL Plan” and collectively with the 2004 APL Plan the “APL Plans”) provide incentive awards to officers, employees and non-employee managers of Atlas Pipeline GP and officers and employees of its affiliates, consultants and joint venture partners who perform services for APL or in furtherance of its business. The APL Plans are administered by APL’s compensation committee (the “APL Committee”). Under the APL Plans, the APL Committee may make awards of either phantom units or options covering an aggregate of 435,000 common units under the 2004 APL Plan and 3,000,000 common units under the 2010 APL Plan.

APL Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. In addition, the APL Committee may grant a participant the right, which is referred to as a DER, to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions are made on an APL common unit during the period the phantom unit is outstanding.

APL Unit Options. An option entitles the grantee to purchase APL common units at an exercise price determined by the APL Committee, which may be less than, equal to or more than the fair market value of APL common units on the date of grant. The compensation committee will also have discretion to determine how the exercise price may be paid.

Except for phantom units awarded to non-employee managers of Atlas Pipeline GP, the APL Committee will determine the vesting period for phantom units and the exercise period for options. Phantom units awarded to non-employee managers will generally vest over a 4-year period at the rate of 25% per year. Both types of awards will automatically vest upon a change of control, as defined in the APL Plans.

ARP Plan

The ARP 2012 Long-Term Incentive Plan (the “ARP Plan”) provides equity incentive awards to officers, employees and managing board members of Atlas Resource Partners GP and employees of its affiliates, consultants and joint venture partners who perform services for ARP. The ARP Plan is administered by our Compensation Committee which may grant awards of either phantom units, unit options or restricted units for an aggregate of 2,900,000 common limited partner units.

ARP Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. The phantom units vest over four years. In tandem with phantom unit grants, the committee may grant a DER. The committee determines the vesting period for phantom units.

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ARP Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the committee on the date of grant of the option. The committee determines the vesting and exercise period for unit options.

ARP Restricted Units. A restricted unit is a common unit issued that entitles a participant to receive it upon vesting of the restricted unit. Prior to or upon grant of an award of restricted units, the committee can condition the vesting or transferability of the restricted units upon conditions that it may determine such as the attainment of performance goals.

Change of Control.

Individual	Triggering event	Acceleration
Eligible employees	Change of Control (as defined in the ARP Plan), and Termination of employment without “cause” as defined in the ARP Plan or upon any other type of termination specified in the applicable award agreement(s), following a change of control	Unvested awards immediately vest in full and in the case of options, become exercisable for the one-year period following the date of termination (but not later than the end of the original term of the option)
Independent directors	Change of Control (as defined in the ARP Plan)	Unvested awards immediately vest in full

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2013 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE

	Option awards										Unit awards
Name	Exercisable			Unexercisable			Option exercise price ($)		Option expiration date		Number of units that have not vested (#)			Market value of units that have not vested ($)
Edward E. Cohen		543,825	(1)		—			20.75		11/10/2016		—			—
		—			761,355	(2)		20.44		3/25/2021		326,295	(3)		15,286,921
		—			—			N/A		N/A		75,000	(4)		2,628,750
		87,500	(5)		262,500	(6)	$	24.67		5/15/2022		112,500	(7)		2,304,000
		—			—			N/A		N/A		47,281	(8)		2,215,115
		—			—			N/A		N/A		50,000	(9)		1,752,500
Sean P. McGrath		16,314	(1)		—			20.75		11/10/2016		—			—
		—			38,067	(12)		20.44		3/25/2021		32,629	(13)		1,528,669
		12,500	(5)		37,500	(14)		24.67		5/15/2022		37,500	(15)		768,000
		—			—			N/A		N/A		13,133	(16)		615,281
Jonathan Z. Cohen		217,530	(1)		—			20.75		11/10/2016		—			—
		—			543,825	(17)		20.44		3/25/2021		271,912	(18)		12,739,077
		—			—			N/A		N/A		75,000	(4)		2,628,750
Eugene N. Dubay		87,500	(5)		262,500	(6)		24.67		5/15/2022		112,500	(7)		2,304,000
		—			—			N/A		N/A		42,027	(19)		1,968,965
		—			—			N/A		N/A		50,000	(9)		1,752,500
		—			108,765	(10)		20.44		3/25/2021		87,012	(11)		4,076,512
		—			—			N/A		N/A		75,000	(4)		2,628,750
		—			—			N/A		N/A		50,000	(9)		1,752,500
Matthew A. Jones		108,765	(1)		—			20.75		11/10/2016		—			—
		—			217,530	(20)		20.44		3/25/2021		163,147	(21)		7,643,437
		56,250	(5)		168,750	(22)		24.67		5/15/2022		75,000	(23)		1,536,000
		—			—			N/A		N/A		28,894	(24)		1,353,684

(1) Represents options to purchase our units.

(2) Represents options to purchase our units, which vest as follows: 3/25/2014 -190,338 and 3/25/2015 - 571,017.

(3) Represents our phantom units, which vest as follows: 3/25/2014 - 81,573 and 3/25/2015 - 244,722.

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(4) Represents APL phantom units, which vest as follows: 4/26/2014 - 25,000, and 4/26/2015 - 25,000 and 4/26/2016 - 25,000.

(5) Represents options to purchase ARP units.

(6) Represents options to purchase ARP’s units, which vest as follows: 5/15/2014 - 87,500, 5/15/2015 - 87,500 and 5/15/2016 - 87,500.

(7) Represents ARP’s phantom units, which vest as follows: 5/15/2014 - 37,500, 5/15/2015 - 37,500 and 5/15/2016 - 37,500.

(8) Represents our phantom units, which vest as follows: 2/4/2014 - 15,760, 2/4/2015 - 15,760 and 2/4/2016 - 15,761.

(9) Represents APL’s phantom units, which vest as follows: 7/10/2014 - 12,500, 7/10/2015 - 12,500, 7/10/2016 - 12,500 and 7/10/2017 - 12,500.

(10) Represents options to purchase our units, which vest as follows: 3/25/2014 - 27,191 and 3/25/2015 - 81,574.

(11) Represents our phantom units, which vest as follows: 3/25/2014 - 21,753 and 3/25/2015 - 65,259.

(12) Represents options to purchase our units, which vest as follows: 3/25/2014 - 9,516 and 3/25/2015 - 28,551.

(13) Represents our phantom units, which vest as follows: 3/25/2014 - 8,157 and 3/25/2015 - 24,472.

(14) Represents options to purchase ARP units, which vest as follows: 5/15/2014 - 12,500, 5/15/2015 - 12,500 and 5/15/2016 - 12,500.

(15) Represents ARP phantom units, which vest as follows: 5/15/2014 - 12,500, 5/15/2015 - 12,500 and 5/15/2016 - 12,500.

(16) Represents our phantom units, which vest as follows: 2/4/2014 - 4,377, 2/4/2015 - 4,377 and 2/4/2016 - 4,379.

(17) Represents options to purchase our units, which vest as follows: 3/25/2014 - 135,956 and 3/25/2015 - 407,869.

(18) Represents our phantom units, which vest as follows: 3/25/2014 - 67,978 and 3/25/2015 - 203,934.

(19) Represents our phantom units, which vest as follows: 2/4/2014 - 14,009, 2/4/2015 - 14,009 and 2/4/2016 - 14,009.

(20) Represents options to purchase our units, which vest as follows: 3/25/2014 - 54,382 and 3/25/2015 - 163,148.

(21) Represents our phantom units, which vest as follows: 3/25/2014 - 40,786 and 3/25/2015 - 122,361.

(22) Represents options to purchase ARP units, which vest as follows: 5/15/2014 - 56,250, 5/15/2015 - 56,250 and 5/15/2016 - 56,250.

(23) Represents ARP phantom units, which vest as follows: 5/15/2014 - 25,000, 5/15/2015 - 25,000 and 5/15/2016 - 25,000.

(24) Represents our phantom units, which vest as follows: 2/4/2014 - 9,631, 2/4/2015 - 9,631 and 2/4/2016 - 9,632.

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2013 OPTION EXERCISES AND UNITS VESTED TABLE

	Option awards				Unit awards
Name	Number of units acquired on exercise		Value realized on exercise ($)		Number of units acquired on vesting		Value realized on vesting ($)
Edward E. Cohen		—		—		62,500		1,804,375
Sean P. McGrath		—		—		12,500		303,125
Jonathan Z. Cohen		—		—		62,500		1,804,375
Eugene N. Dubay		—		—		25,000		895,000
Matthew A. Jones		—		—		25,000		606,250

2013 NON-QUALIFIED DEFERRED COMPENSATION

Name	Executive contributions in the last FY ($)			Registrant contributions in the last FY ($)			Aggregate earnings in the last FY ($)		Aggregate balance at last FYE ($)
Edward E. Cohen		500,000	(1)		500,000	(3)		53,316		1,053,316
Jonathan Z. Cohen		350,000	(2)		350,000	(4)		37,565		737,565

(1) This amount is included within the Summary Compensation Table for 2013 reflecting $100,000 in the salary column and $400,000 in the non-equity incentive compensation column.

(2) This amount is included within the Summary Compensation Table for 2013 reflecting $70,000 in the salary column and $280,000 in the non-equity incentive compensation column.

(3) This amount is included within the Summary Compensation Table for 2013 reflecting our $500,000 matching contribution in the all other compensation column.

(4) This amount is included within the Summary Compensation Table for 2013 reflecting our $350,000 matching contribution in the all other compensation column.

Effective July 1, 2011, we established the Excess 401(k) Plan, an unfunded nonqualified deferred compensation plan for certain highly compensated employees. The Excess 401(k) Plan provides Messrs. E. and J. Cohen, the plan’s current participants, with the opportunity to defer, annually, the receipt of a portion of their compensation, and to permit them to designate investment indices for the purpose of crediting earnings and losses on any amounts deferred under the Excess 401(k) Plan. Messrs. E. and J. Cohen may defer up to 10% of their total annual cash compensation (which means base salary and non-performance-based bonus) and up to 100% of all performance-based bonuses, and we are obligated to match such deferrals on a dollar-for-dollar basis (i.e., 100% of the deferral) up to a total of 50% of their base salary for any calendar year. The account is invested in a mutual fund and cash balances are invested daily in a money market account. We established a “rabbi” trust to serve as the funding vehicle for the Excess 401(k) Plan and we will, not later than the last day of the first month of each calendar quarter, make contributions to the trust in the amount of the compensation deferred, along with the corresponding match, during the preceding calendar quarter. Notwithstanding the establishment of the rabbi trust, our obligation to pay the amounts due under the Excess 401(k) Plan constitutes a general, unsecured obligation, payable out of our general assets, and Messrs. E. and J. Cohen do not have any rights to any specific asset of the company.

The Excess 401(k) Plan has the following additional provisions:

• At the time the participant makes his deferral election with respect to any year, he must specify the date or dates (but not more than two) on which distributions will start, which date may be upon termination of employment or

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a date that is at least three years after the year in which the amount deferred would otherwise have been earned. A participant may subsequently defer a specified payment date for a minimum of an additional five years from the previously elected payment date. If the participant fails to make an election, all amounts will be distributable upon the termination of employment.

• Distributions will be made earlier in the event of death, disability or a termination of employment due to a change of control.

• If the participant elects to receive all or a portion of his distribution upon the termination of employment, it will be paid in a lump sum. Otherwise, the participant may elect to receive a lump sum payment or equal installments over not more than 10 years.

• A participant may request a distribution of all or part of his account in the event of an unforeseen financial emergency. An unforeseen financial emergency is a severe financial hardship due to an unforeseeable emergency resulting from a sudden and unexpected illness or accident of the participant, or, a sudden and unexpected illness or accident of a dependent, or loss of the participant’s property due to casualty, or other similar and extraordinary unforeseeable circumstances arising as a result of events beyond the control of the participant. An unforeseen financial emergency is not deemed to exist to the extent it is or may be relieved through reimbursement or compensation by insurance or otherwise; by borrowing from commercial sources on reasonable commercial terms to the extent that this borrowing would not itself cause a severe financial hardship; by cessation of deferrals under the plan; or by liquidation of the participant’s other assets (including assets of the participant’s spouse and minor children that are reasonably available to the participant) to the extent that this liquidation would not itself cause severe financial hardship.

The table above reflects salary and matching contribution costs allocated to us.

2013 DIRECTOR COMPENSATION TABLE

Name	Fees earned or paid in cash ($)		Stock swards ($)			All other Compensation  ($)(1)			Total ($)
Carlton M. Arrendell		75,000		124,971	(2)		12,581			212,552
Mark C. Biderman		84,817		124,971	(2)		12,581			222,369
Dennis A. Holtz		82,500		124,971	(2)		12,581			220,052
Walter C. Jones		14,063		124,981	(3)		1,190			140,233
William Karis		26,291		—			44,012	(4)		70,303
Harvey Magarick		65,788		—			126,387	(4)		192,175
Ellen F. Warren		85,000		124,971	(2)		12,581			222,552

(1) Represents DERs for phantom units.

(2) For Messrs. Arrendell, Biderman, Holtz and Ms. Warren, represents 3,314 phantom units granted under our 2006 Plan, having a grant date fair value of $37.71. The phantom units vest 25% on the anniversary of the date of grant as follows: 2/17/14—828, 2/17/15—828, 2/17/16—828 and 2/17/17—830.

(3) For Mr. Jones, who joined our general partner’s board of directors effective October 24, 2013, represents 2,586 phantom units granted under our 2006 Plan, having a grant date fair value of $48.33. The phantom units vest 25% on the anniversary of the date of grant as follows: 10/24/14—646, 10/24/15—646, 10/24/16—646 and 10/24/17—648.

(4) Messrs. Karis and Magarick, resigned from our general partner’s board of directors effective April 25, 2013 and September 24, 2013, respectively, and each received a pro-rated cash equivalent of their annual equity grant amount for 2013.

Director Compensation

Our general partner does not pay additional remuneration to officers or employees who also serve as board members. In 2013, the annual retainer for non-employee directors was comprised of $75,000 in cash and an annual grant of phantom units with DERs issued under our Plans having a fair market value of $125,000. Chairs of the nominating and governance

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committee and the investment committee receive an additional retainer of $7,500, the chair of the Compensation Committee receives an additional retainer of $10,000 and the chair of the audit committee receives an additional retainer of $25,000, which was increased from $15,000 in October 2013.

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COMPENSATION COMMITTEE REPORT

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management and, based upon its review and discussions, the Compensation Committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this annual report on Form 10-K for the year ended December 31, 2013.

This report has been provided by the Compensation Committee of the Board of Directors of Atlas Energy GP, LLC.

Ellen F. Warren, Chair

Carlton M. Arrendell

Dennis A. Holtz

ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of common units owned, as of February 25, 2014, by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding common units, (b) each of our present directors and nominees, (c) each of our executive officers serving during the 2013 fiscal year, and (d) all of our directors, nominees and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Common units issuable pursuant to options or warrants are deemed to be outstanding for purposes of computing the percentage of the person or group holding such options or warrants but are not deemed to be outstanding for purposes of computing the percentage of any other person. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person.

	Common unit amount and nature of beneficial ownership			Percent of class
Beneficial owner
Directors (1)
Carlton M. Arrendell		5,617				*
Mark C. Biderman		19,111				*
Edward E. Cohen		2,231,153	(2)(4)		4.26	%
Jonathan Z. Cohen		1,758,846	(3)(4)		3.39	%
Dennis A. Holtz		13,898				*
Walter C. Jones		0				*
Ellen F. Warren		4,687				*
Non-director principal officers(1)
Eugene N. Dubay		13,898	(5)			*
Freddie M. Kotek		116,465	(6)			*
Matthew A. Jones		245,616	(4)			*
Daniel C. Herz		146,783				*
Sean P. McGrath		48,888	(4)			*

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	Common unit amount and nature of beneficial ownership			Percent of class
Jeffrey M. Slotterback		5,738				*
Lisa Washington		23,617	(4)			*
All executive officers, directors and nominees as a group (14 persons)		2,957,991	(7)		5.56	%
Other owners of more than 5% of outstanding common units
Leon G. Cooperman		4,446,947	(8)		8.64	%
ING Groep N.V./ING Capital Markets LLC		3,489,681	(9)		6.78	%

* Less than 1%

⁽¹⁾  The business address for each director, director nominee and executive officer is Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, PA 15275-1011.

⁽²⁾  Includes (i) 26,251 common units held in an individual retirement account of Mr. E. Cohen’s spouse, (ii) 1,161,702 common units held by a charitable foundation of which Mr. E. Cohen, his spouse and their children serve as co-trustees; and (iii) 67,273 common units held in trust for the benefit of Mr. E. Cohen’s spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of the above referenced common units. 1,228,975 of these common units are also included in the common units referred to in footnote 3 below.

⁽³⁾  Includes (i) 67,273 common units held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 1,161,702 common units held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve as co-trustees. These common units are also included in the common units referred to in footnote 2 above. Mr. J. Cohen disclaims beneficial ownership of the above referenced common units.

⁽⁴⁾  Includes common units issuable on exercise of options granted under our Plans in the following amounts: Mr. E. Cohen — 734,163 common units; Mr. J. Cohen — 353,486 common units; Mr. Jones — 163,147 common units; Mr. McGrath—25,875; and Ms. Washington—10,876.

⁽⁵⁾  Includes 620 common units held in trust for the benefit of Mr. Dubay’s spouse.

⁽⁶⁾  Includes (i) 2,731 common units held by spouse, (ii) 1 common unit held by GRAT, (iii) 1 common unit held by his spouse’s GRAT, (iv) 57,126 common units held by his children’s trust, (v) 1,930 common units held by his children and (vi) 6,458 common units held by his mother-in-law.

⁽⁷⁾  This number has been adjusted to exclude 67,273 common units and 1,161,702 common units which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.

⁽⁸⁾  This information is based on a Schedule 13G/A filed with the SEC on February 3, 2014. The principal business office of Mr. Cooperman is 11431 W. Palmetto Park Road, Boca Raton, FL 33428.

⁽⁹⁾  This information is based on a Schedule 13G/A filed with the SEC on February 14, 2014. The address for ING Groep N.V. is Bijlmerplein 888, 1102 MG, Amsterdam-Zuidoost, Postbus 1800, 1000 BV Amsterdam, The Netherlands and the address for ING Capital Markets LLC is 1013 Centre Road, Wilmington, New Castle, DE 19805.

Equity Compensation Plan Information

The following table contains information about our 2006 Plan as of December 31, 2013:

Plan category	Number of securities to be issued upon exercise of equity instruments		Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders – phantom units		234,940		n/a
Equity compensation plans approved by security holders – unit options		939,939	$	20.94
Equity compensation plans approved by security holders – Total		1,174,879				763,476

240

The following table contains information about our 2010 Plan as of December 31, 2013:

Plan category	Number of securities to be issued upon exercise of equity instruments		Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders – phantom units		2,054,534		n/a
Equity compensation plans approved by security holders – unit options		2,452,412	$	20.52
Equity compensation plans approved by security holders – Total		4,506,946				1,202,774

The following table contains information about ARP’s 2012 Plan as of December 31, 2013:

Plan category	Number of securities to be issued upon exercise of equity instruments		Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders – phantom units		839,808		n/a
Equity compensation plans approved by security holders – unit options		1,482,675	$	24.66
Equity compensation plans approved by security holders – Total		2,322,483				352,586

The following table contains information about the APL’s 2004 Plan as of December 31, 2013:

Plan category	Number of securities to be issued upon exercise of equity instruments		Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders – phantom units		45,732		n/a
Equity compensation plans approved by security holders – unit options		0		n/a
Equity compensation plans approved by security holders – Total		45,732				6,409

241

The following table contains information about the APL’s 2010 Plan as of December 31, 2013:

Plan category	Number of securities to be issued upon exercise of equity instruments		Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders – phantom units		1,400,821		n/a
Equity compensation plans approved by security holders – unit options		0		n/a
Equity compensation plans approved by security holders – Total		1,400,821				834,461

242

ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The board of directors of our general partner has determined that Ms. Warren and Messrs. Arrendell, Biderman, Holtz and Jones each satisfy the requirement for independence set out in Section 303A.02 of the rules of the New York Stock Exchange including those set forth in Rule 10A-3(b)(1) of the Securities Exchange Act, and meet the definition of an independent member set forth in our Partnership Governance Guidelines. In making these determinations, the board of directors reviewed information from each of these non-management board members concerning all their respective relationships with us and analyzed the materiality of those relationships.

Effective as of April 30, 2009, our general partner adopted a written policy governing related party transactions. For purposes of this policy, a related party includes: (i) any executive officer, director or director nominee; (ii) any person known to be a beneficial owner of 5% or more of our common units; (iii) an immediate family member of any person included in clauses (i) and (ii) (which, by definition, includes, a person’s spouse, parents, and parents in law, step parents, children, children in law and step children, siblings and brothers and sisters in law and anyone residing in that person’s home); and (iv) any firm, corporation or other entity in which any person included in clauses (i) through (iii) above is employed as an executive officer, is a director, partner, principal or occupies a similar position or in which that person owns a 5% or more beneficial interest. With certain exceptions outlined below, any transaction between us and a related party that is anticipated to exceed $120,000 in any calendar year must be approved, in advance, by the Conflicts Committee of our general partner. If approval in advance is not feasible, the related party transaction must be ratified by the Conflicts Committee. In approving a related party transaction the Conflicts Committee will take into account, in addition to such other factors as the Conflicts Committee deems appropriate, the extent of the related party’s interest in the transaction and whether the transaction is no less favorable to us than terms generally available to an unaffiliated third party under similar circumstances.

The following related party transactions are pre-approved under the policy: (i) employment of an executive officer to perform services on our behalf (or on behalf of one of our subsidiaries) if (a) the compensation is required to be reported in our annual proxy or (b) the executive officer is not an immediate family member and such compensation was approved, or recommended to the board of directors for approval, by the compensation committee; (ii) compensation paid to directors for serving on the board of our general partner or any committee thereof or reimbursement of expenses in connection with such services, if the compensation is required to be reported in our annual proxy; (iii) transactions where the related party’s interest arises solely as a holder of our common units and all holders of our common units received the same benefit on a pro rata basis (e.g. dividends), or transactions available to all employees generally; (iv) a transaction at another company where the related party is only an employee (and not an executive officer), director or beneficial owner of less than 10% of such company’s shares and the aggregate amount involved does not exceed the greater of $1,000,000 or 2% of that company’s total annual revenues; and (v) any charitable contribution, grant or endowment by us or our general partner to a charitable organization, foundation or university at which the related party’s only relationship is an employee (other than an executive officer) or director or similar capacity, if the aggregate amount involved does not exceed the lesser of $200,000 or 2% of the charitable organization’s total annual receipts, expenditures or assets.

Neither APL nor ARP employ any persons to manage or operate their businesses. Instead, as owner of the general partners, we provide employees and incur expenses related to managing operations. We get reimbursed for expenses we incur in managing such operations, and we are also reimbursed for compensation and benefits related to our employees who perform services for each of APL and ARP, which is based upon an estimate of the time spent by such persons on activities for these subsidiaries. For the year ended December 31, 2013, we were reimbursed $5.0 million, and $5.0 million for expenses, compensation and benefits related to APL and ARP, respectively.

Relationship with Resource America. Edward E. Cohen, our general partner’s Chief Executive Officer and President, serves as Chairman of Resource America, Inc., the former parent of AEI (“Resource America”) and is a greater than 10% shareholder, and Jonathan Z. Cohen, our Executive Chairman, serves as Chief Executive Officer and President of Resource America and is a greater than 10% shareholder. We sublease office space from Resource America and reimburse it for certain shared services.

On July 31, 2013, we entered into a $240.0 million term secured term loan facility with a group of outside investors, which included CVC Credit Partners, LLC (“CVC”). CVC , which is a joint venture between Resource America, Inc. and an unrelated third party private equity firm, manages funds which are allocated an aggregate of $12.5 million of our term loan facility.

243

Investment in ARP’s of Class C Preferred Units

In July 2013, in connection with the EP Energy Acquisition, we purchased $86.6 million of ARP’s newly created Class C convertible preferred units, at a negotiated price per unit of $23.10, which was the face value of the units. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The initial Class C preferred distribution was paid for the quarter ending September 30, 2013. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, we received 562,497 warrants to purchase ARP’s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of our common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

Upon issuance of the Class C preferred units and warrants on July 31, 2013, we and ARP entered into a registration rights agreement pursuant to which ARP agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants.

244

ITEM 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2013 and 2012, the accounting fees and services (in thousands) charged by Grant Thornton, LLP, our independent auditors, were as follows:

	Years Ended December 31,
	2013		2012
Audit fees(1)	$	3,159	$	2,822
Audit-related fees(2)		242		174
Tax fees(3)		300		183
All other fees		—		—
Total accounting fees and services	$	3,701	$	3,179

⁽¹⁾  Represents the aggregate fees recognized in each of the last two years for professional services rendered by Grant Thornton LLP principally for the audits of our and our subsidiaries’ annual financial statements and the quarterly reviews of our and our subsidiaries’ financial statements included in Form 10-Qs and also for services related to our and our subsidiaries’ registration statements, Form 8-Ks and comfort letters.

⁽²⁾  Represents the aggregate fees recognized during the years ended December 31, 2013 and 2012 for professional services rendered by Grant Thornton LLP substantially related to the historical audit of recently acquired EP Energy in 2013 and DTE in 2012, certain necessary audit related services in connection with the registration and/or private placement of ARP’s Drilling Partnerships and audits of our benefit plans.

⁽³⁾  The fees for tax services rendered related to tax compliance.

Audit Committee Pre-Approval Policies and Procedures

The audit committee of our general partner, on at least an annual basis, reviews audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2013 and 2012.

PART IV

ITEM 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:

(1) Financial Statements

The financial statements required by this Item 15(a)(1) are set forth in Item 8: Financial Statements and Supplementary Data.

(2) Financial Statement Schedules

None

(3) Exhibits:

Exhibit No.	Description
2.1	Purchase and Sale Agreement, dated as of June 9, 2013, by and among EP Energy E&P Company, L.P., EPE Nominee Corp. and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request. (47)

245

Exhibit No.	Description
2.2	Assignment & Assumption Agreement, dated as of June 9, 2013, between Atlas Resource Partners, L.P. and Atlas Energy, L.P. (50)
3.1(a)	Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.(1)
3.1(b)	Certificate of Amendment of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.1(c)	Amendment to Certificate of Limited Partnership of Atlas Energy, L.P. (5)
3.2(a)	Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(13)
3.2(b)	Amendment No. 1 to Second Amended and Restated Limited Partnership Agreement of Atlas Pipeline Holdings, L.P.(13)
3.2(c)	Amendment No. 2 to Second Amended and Restated Limited Partnership Agreement of Atlas Energy, L.P. (5)
4.1	Specimen Certificate Representing Common Units(1)
10.1	Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC. (13)
10.2	Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(22)
10.3(a)	Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1)
10.3(b)	Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(4)
10.3(c)	Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(d)	Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(e)	Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(6)
10.3(f)	Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(7)
10.3(g)	Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(8)
10.3(h)	Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(9)
10.3(i)	Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(14)

246

Exhibit No.	Description
10.3(j)	Amendment No. 10 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P. (39)
10.4	Atlas Pipeline Partners, L.P.’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class D Convertible Preferred Units, dated as of May 7, 2013(39)
10.5	Second Amended and Restated Limited Liability Company Agreement of Atlas Resource Partners GP, LLC (53)
10.6(a)	Amended and Restated Limited Partnership Agreement of Atlas Resource Partners, L.P.(28)
10.6(b)	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P. dated as of July 25, 2012(17)
10.6(c)	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Atlas Resource Partners, L.P. dated as of July 31, 2013(44)
10.7	Atlas Resource Partners, L.P’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class B Preferred Units, dated as of July 25, 2012(17)
10.8	Atlas Resource Partners, L.P’s Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional and Other Special Rights and Qualifications, Limitations and Restrictions thereof of Class C Convertible Preferred Units, dated as of July 31, 2013(44)
10.9(a)	Long-Term Incentive Plan(6)
10.9(b)	Amendment No. 1 to Long-Term Incentive Plan(15)
10.10	Form of Phantom Grant under 2006 Long-Term Incentive Plan(54)
10.11	Form of Phantom Grant under 2006 Long-Term Incentive Plan (2013)
10.12	2010 Long-Term Incentive Plan(16)
10.13	Form of Phantom Unit Grant under 2010 Long-Term Incentive Plan(32)
10.14	Form of Stock Option Grant under 2010 Long-Term Incentive Plan(32)
10.15	Amended and Restated Credit Agreement, dated July 31, 2013 among Atlas Energy, L.P., the lenders party thereto and Wells Fargo Bank, NA as administrative agent(45)
10.16	Secured Term Loan Credit Agreement, dated July 31, 2013 among Atlas Energy, L.P., the lenders party thereto and Deutsche Bank AG New York Branch, as administrative agent(45)

247

Exhibit No.	Description
10.17	Intercreditor Agreement, dated July 31, 2013 among Atlas Energy, L.P., the grantors party thereo, Wells Fargo Bank, NA as revolving facility administrative agent and Deutsche Bank AG, New York Branch, as term facility administrative agent(45)
10.18(a)	Amended and Restated Credit Agreement, dated July 27, 2007, amended and restated as of December 22, 2010, among Atlas Pipeline Partners, L.P., the guarantors therein, Wells Fargo Bank, National Association, and other banks party thereto(23)
10.18(b)	Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of April 19, 2011 (25)
10.18(c)	Incremental Joinder Agreement to the Amended and Restated Credit Agreement, dated as of July 8, 2011 (26)
10.18(d)	Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of May 31, 2012(18)
10.18(e)	Amendment No. 3 to the Amended and Restated Credit Agreement(34)
10.18(f)	Amendment No. 4 to the Amended and Restated Credit Agreement(11)
10.19	Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.20(a)	Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.20(b)	Amendment No. 1 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of January 6, 2011. (12)
10.20(c)	Amendment No. 2 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of February 2, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)
10.21	Transaction Confirmation, Supply Contract No. 0001, under Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated February 17, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission. (12)

248

Exhibit No.	Description
10.22	Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.23	Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble, LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.(12)
10.24	Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011(12)
10.25	Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011(12)
10.26	Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011(21)
10.27	Employment Agreement between Atlas Energy, L.P. and Matthew A. Jones dated as of November 4, 2011(32)
10.28	Employment Agreement between Atlas Energy, L.P. and Daniel Herz dated as of November 4, 2011(55)
10.29	Employment Agreement between Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Patrick J. McDonie dated as of July 3, 2012 (35)
10.30	Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010(21)
10.31(a)	Second Amended and Restated Credit Agreement dated July 31, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(44)
10.31(b)	First Amendment to Second Amended and Restated Credit Agreement dated December 6, 2013 among Atlas Resource Partners, L.P., the lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the lenders(56)
10.32(a)	Credit Agreement, dated as of March 5, 2012, among Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (30)
10.32(b)	First Amendment to Credit Agreement, dated as of April 30, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (31)
10.32(c)	Second Amendment to Amended and Restated Credit Agreement, dated as of July 26, 2012, between Atlas Resource Partners, L.P. and Wells Fargo Bank, N.A., as administrative agent for the Lenders (17)
10.32(d)	Third Amendment to Amended and Restated Credit Agreement dated as of December 20, 2012(36)
10.32(e)	Fourth Amendment to Amended and Restated Credit Agreement dated as of January 11, 2013(37)

249

Exhibit No.	Description
10.32(f)	Fifth Amendment to Amended and Restated Credit Agreement dated as of May 30, 2013(51)
10.33	Secured Hedge Facility Agreement dated as of March 5, 2012 among Atlas Resources, LLC, the participating partnerships from time to time party thereto, the hedge providers from time to time party thereto and Wells Fargo Bank, N.A., as collateral agent for the hedge providers(30)
10.34	Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan(28)
10.35	Atlas Pipeline Partners, L.P. Long-Term Incentive Plan (27)
10.36	Atlas Pipeline Partners, L.P. Amended and Restated 2010 Long-Term Incentive Plan(20)
10.37	Registration Rights Agreement, dated as of April 30, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein(31)
10.38	Registration Rights Agreement, dated as of July 25, 2012, among Atlas Resource Partners, L.P. and the various parties listed therein(17)
10.39	Registration Rights Agreement, dated as of January 23, 2013 among Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation and the initial purchasers named therein(10)
10.40	Registration Rights Agreement, dated May 16, 2012, between Atlas Pipeline Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Credit Agreement dated May 16, 2012 by and among Atlas Energy, L.P. and the lenders named therein(35)
10.41	Equity Distribution Agreement dated November 5, 2012, by and between Atlas Pipeline Partners, L.P. and Citigroup Global Markets Inc.(43)
10.42	Purchase and Sale Agreement, dated as of April 16, 2013, among TEAK Midstream Holdings, LLC, TEAK Midstream, L.L.C. and Atlas Pipeline Mid-Continent Holdings, LLC. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Registration S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request(29)
10.43	Registration Rights Agreement, dated February 11, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein(38)
10.44	Class D Preferred Unit Purchase Agreement, dated as of April 16, 2013, among Atlas Pipeline Partners, L.P. and the various purchasers party thereto(29)
10.45	Registration Rights Agreement, dated May 7, 2013, by and among Atlas Pipeline Partners, L.P. and the purchasers named therein(39)
10.46	Purchase and Sale Agreement, dated as of June 9, 2013, by and among EP Energy E&P Company, L.P., EPE Nominee Corp. and Atlas Resource Partners, L.P. The schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.(47)
10.47	Warrant to Purchase Common Units(44)
10.48	Distribution Agreement dated as of May 10, 2013, between Atlas Resource Partners, L.P. and Deutsche Bank Securities Inc., as representative of the several agents(48)

250

Exhibit No.	Description
10.49	Class C Preferred Unit Purchase Agreement, dated as of June 9, 2013, between Atlas Resource Partners, L.P. and Atlas Energy, L.P. (50)
10.50	Indenture dated as of July 30, 2013, by and between Atlas Resource Escrow Corporation and Wells Fargo Bank, National Association(49)
10.51	Supplemental Indenture dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association(49)
10.52	Registration Rights Agreement dated as of July 31, 2013, by and among Atlas Resource Partners, L.P., Atlas Energy Holdings Operating Company, LLC, Atlas Resource Finance Corporation, the guarantors named therein and Deutsche Bank Securities, Inc., for itself and on behalf of the Initial Purchasers(49)
10.53	Registration Rights Agreement dated as of July 31, 2013 by and among Atlas Energy, L.P. and Atlas Resource Partners, L.P. (44)
10.54	Registration Rights Agreement dated May 7, 2013, among Atlas Pipeline Partners, L.P. and the purchasers named therein(52)
10.55	Indenture dated as of May 10, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein and U.S. Bank National Association(46)
10.56	Registration Rights Agreement, dated May 10, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the guarantors named therein and Citigroup Global Markets, Inc. for itself and on behalf of the initial purchasers(46)
10.57	Asset Purchase Agreement, dated as of February 13, 2014, by and among GeoMet, Inc., GeoMet Operating Company, Inc., GeoMet Gathering Company, LLC and ARP Mountaineer Production, LLC. The exhibits and schedules to the Asset Purchase Agreement have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted exhibits and schedules will be furnished to the U.S. Securities and Exchange Commission upon request(33)
21.1	Subsidiaries of Atlas Energy, L.P.
23.1	Consent of Grant Thornton LLP
23.2	Consent of Wright and Company, Inc.
31.1	Rule 13(a)-14(a)/15(d)-14(a) Certification
31.2	Rule 13(a)-14(a)/14(d)-14(a) Certification
32.1	Section 1350 Certification
32.2	Section 1350 Certification
99.1	Atlas Energy, L.P. Summary Reserve Report of Wright & Company, Inc.
99.2	Atlas Resource Partners, L.P. Summary Reserve Report of Wright & Company, Inc. (56)
99.3	Voting Agreement, dated as of February 13, 2014, by and among ARP Mountaineer Production, LLC, Atlas Resource Partners, L.P. and each of the persons listed on Annex I thereto(33)
101.INS	XBRL Instance Document(57)

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Exhibit No.	Description
101.SCH	XBRL Schema Document(57)
101.CAL	XBRL Calculation Linkbase Document(57)
101.LAB	XBRL Label Linkbase Document(57)
101.PRE	XBRL Presentation Linkbase Document(57)
101.DEF	XBRL Definition Linkbase Document(57)

(1) Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999).

(2) Previously filed as an exhibit to current report on Form 8-K filed May 21, 2012.

(3) Previously filed as an exhibit to current report on Form 8-K filed on March 4, 2013.

(4) Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007.

(5) Previously filed as an exhibit to current report on Form 8-K filed December 13, 2011.

(6) Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008.

(7) Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009.

(8) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 2, 2010.

(9) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 7, 2010.

(10) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 25, 2013.

(11) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 23, 2013.

(12) Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(13) Previously filed as an exhibit to current report on Form 8-K filed on February 24, 2011.

(14) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 13, 2011.

(15) Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2010.

(16) Previously filed as an exhibit to current report on Form 8-K filed on November 12, 2010.

(17) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on July 26, 2012.

(18) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 31, 2012.

(19) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on September 1, 2010.

(20) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q filed on March 31, 2011.

(21) Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2011.

(22) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on October 29, 2013.

(23) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 23, 2010.

(24) Previously filed as an exhibit to current report on Form 8-K filed on March 25, 2011.

(25) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(26) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on July 11, 2011.

(27) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s annual report on Form 10-K for the year ended December 31, 2009.

(28) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 14, 2012.

(29) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on April 17, 2013.

(30) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on March 7, 2012.

(31) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 1, 2012.

(32) Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2011.

(33) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on February 18, 2014

(34) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on December 13, 2012.

(35) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2012.

(36) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on December 26, 2012.

(37) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on January 11, 2013.

(38) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on February 12, 2013.

252

(39) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 8, 2013.

(40) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2012.

(41) Intentionally omitted.

(42) Intentionally omitted.

(43) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on November 6, 2012.

(44) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 6, 2013.

(45) Previously filed as an exhibit to current report on Form 8-K filed on August 6, 2013.

(46) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 13, 2013.

(47) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on June 10, 2013.

(48) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 10, 2013.

(49) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on August 2, 2013.

(50) Previously filed as an exhibit to current report on Form 8-K filed on June 13, 2013.

(51) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s current report on Form 8-K filed on May 31, 2013.

(52) Previously filed as an exhibit to Atlas Pipeline Partners, L.P.’s current report on Form 8-K filed on May 8, 2013.

(53) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2013.

(54) Previously filed as an exhibit to Atlas Energy, L.P.’s quarterly report on Form 10-Q for the quarter ended September 30, 2010.

(55) Previously filed as an exhibit to Atlas Energy, L.P.’s quarterly report on Form 10-Q for the quarter ended June 30, 2013.

(56) Previously filed as an exhibit to Atlas Resource Partners, L.P.’s annual report on Form 10-K for the year ended December 31, 2013.

(57) Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

253

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS ENERGY, L.P.
	By: Atlas Energy GP, LLC, its General Partner
Date: February 28, 2014	By:	/s/ EDWARD E. COHEN
		Edward E. Cohen Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated as of February 28, 2014.

/s/ EDWARD E. COHEN	Chief Executive Officer, President and Director of the General Partner
Edward E. Cohen
/s/ JONATHAN Z. COHEN	Executive Chairman of the Board of the General Partner
Jonathan Z. Cohen
/s/ SEAN P. MCGRATH	Chief Financial Officer of the General Partner
Sean P. McGrath
/s/ JEFFREY M. SLOTTERBACK	Chief Accounting Officer
Jeffrey M. Slotterback
/s/ CARLTON M. ARRENDELL	Director of the General Partner
Carlton M. Arrendell
/s/ MARK C. BIDERMAN	Director of the General Partner
Mark C. Biderman
/s/ DENNIS A. HOLTZ	Director of the General Partner
Dennis A. Holtz
/s/ WALTER C. JONES	Director of the General Partner
Walter C. Jones
/s/ ELLEN F. WARREN	Director of the General Partner
Ellen F. Warren

254