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. ¨

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

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

The aggregate market value of the voting and non-voting common units held by non-affiliates of the registrant, based on the closing price of such units on the last business day of the registrant’s most recently completed second quarter, June 30, 2014, was approximately $2.2 billion.

The number of outstanding common units of the registrant on February 24, 2015 was 52,021,532.

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

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

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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:

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.

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:

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

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:

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, 2014, ARP’s estimated proved reserves were 1,429 Bcfe, including reserves net to ARP’s equity interest in its tax-advantaged investment partnerships (“Drilling Partnerships”). Of ARP’s estimated proved reserves, approximately 77% were proved developed and approximately 71% were natural gas. For the year ended December 31, 2014, ARP’s average daily net production was approximately 270.0 MMcfe. Through December 31, 2014, ARP owns production positions in the following areas:

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. Since it began operations in March 2012, ARP has acquired significant net proved reserves and production through the following transactions:

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.

On November 5, 2014, the Development Subsidiary and ARP completed the acquisition of interests in oil and natural gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas, including 4,000 operated gross acres and net reserves of 12 Mmboe as of July 1, 2014 (the “Eagle Ford Acquisition”). The purchase price was $339.2 million, of which $179.5 million was paid at closing by ARP and $19.7 million was paid by the Development Subsidiary, and approximately $140.0 million will be paid over the four quarters following closing. ARP will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. The Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing.

At December 31, 2014, our Development Subsidiary had completed 2 wells in the Eagle Ford and 15 wells in the Marble Falls and Mississippi Lime. At December 31, 2014, we owned an 1.7% limited partner interest in our Development Subsidiary and 80.0% 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.

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:

APL is a leading provider of natural gas gathering, processing and treating services primarily in the Anadarko, Ardmore, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in southern Texas.

APL’s operations are all located in or near areas of abundant and long-lived natural gas production, including, within Oklahoma, the Golden Trend, Mississippian Limestone and Hugoton Field in the Anadarko Basin; the South Central Oklahoma Oil Province (“SCOOP”) play in the Ardmore Basin; the Woodford Shale play in the Arkoma Basin; and within Texas, the Spraberry and Wolfberry Trends, which are oil plays 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 our 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 conducts its business in the midstream segment of the natural gas industry through two reportable segments: Oklahoma Gathering and Processing (“Oklahoma”) and Texas Gathering and Processing (“Texas”).

As a result of the May 2014 sale of two former subsidiaries that owned an interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations - Recent Developments”), APL realigned the management of its business from our previously reportable segments of “Gathering and Processing” and “Transportation and Treating” into the two new reportable segments.

The Oklahoma segment consists of APL’s SouthOK and WestOK operations, which are comprised of natural gas gathering, processing and treating assets servicing drilling activity in the Anadarko, Ardmore and Arkoma Basins. These operations were formerly included within the previous Gathering and Processing segment. Revenues are primarily derived from the sale of residue gas and NGLs and the gathering, processing and treating of natural gas within the state of Oklahoma.

The Texas segment consists of (1) APL’s SouthTX and WestTX operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Permian Basin and the Eagle Ford Shale play in southern Texas; and (2) APL’s natural gas gathering assets located in the Barnett Shale play in Texas. These assets were formerly included within the previous Gathering and Processing segment. Revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas within the state of Texas.

The previous Transportation and Treating segment, which consisted of (1) APL’s gas treating operations, which own contract gas treating facilities located in various shale plays; and (2) the former APL subsidiaries’ interest in WTLPG, which was sold in May 2014. This has been eliminated and the financial information is now included within Corporate and Other. The natural gas gathering assets located in the Appalachian Basin in Tennessee, which were formerly included in the previous Gathering and Processing Segment, are also now included within Corporate and Other.

At December 31, 2014, we owned an approximate 12.0% interest in Lightfoot LP and an approximate 15.9% 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.

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, 2014.

On October 13, 2014, we entered into a definitive merger agreement with Targa Resources Corp. (“TRC”; NYSE: TRGP) (the “Merger Agreement”), pursuant to which TRC agreed to acquire us through the merger of a newly formed, wholly-owned subsidiary of TRC with and into us (the “Merger”). Upon completion of the Merger, holders of our common units will have the right to receive, for each of our common units, (i) 0.1809 TRC shares and, (ii) $9.12 in cash.

Concurrently with the execution of the Merger Agreement, APL entered into a definitive merger agreement (the “APL Merger Agreement”) with us, TRC, Targa Resources Partners LP (“TRP”; NYSE: NGLS), pursuant to which TRP agreed to acquire APL through the merger of a newly formed, wholly-owned subsidiary of TRP with and into us (the “APL Merger”). Upon completion of the APL Merger, holders of APL’s common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each APL common unit.

Concurrent with the execution of the Merger Agreement and the APL Merger Agreement, we agreed to (i) transfer our assets and liabilities, other than those related to APL, to Atlas Energy Group, which is currently our wholly-owned subsidiary and (ii) immediately prior to the Merger, effect a pro rata distribution to our unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”). Atlas Energy Group’s assets, assuming the Spin-Off had been completed as of December 31, 2014, consist of:

The closing of the Merger is subject to approval by holders of a majority of our common units, approval by a majority of the holders of TRC common stock voting at a special meeting held to approve the issuance of TRC shares in the Merger and other closing conditions, including the closing of the APL Merger and the Spin-Off. On February 20, 2015, we and TRC each held special meetings, where holders of a majority of our common units approved the Merger and a majority of the holders of TRC common stock voting at the TRC special meeting approved the issuance of TRC shares in the Merger. In addition, holders of a majority of APL’s common units approved the APL Merger at a special meeting held on the same day. Completion of each of the APL Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger.

Following the announcement on October 13, 2014 of the Merger, we, our general partner, TRC, Trident GP Merger Sub LLC (“GP Merger Sub”) and the members of our general partner’s board of directors have been named as defendants in two putative unitholder class action lawsuits challenging the Merger, one of which has subsequently been voluntarily dismissed. In addition, we, APL, Atlas Pipeline Partners GP LLC (“APL GP”), TRC, TRP, Targa Resources GP LLC (“TRP GP”), Trident MLP Merger Sub LLC (“MLP Merger Sub”) and the members of the managing board of APL GP have been named as defendants in five putative unitholder class action lawsuits challenging the APL Merger, one of which has subsequently been voluntarily dismissed. The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for our unitholders in the Merger and APL Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs.

We have also been named as a defendant in a putative class action and derivative lawsuit brought on January 28, 2015 and amended on February 23, 2015, by a shareholder of TRC against TRC and its directors challenging the disclosures made in connection with the Merger. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the Merger and failing to disclose purportedly material information concerning the Merger. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest, and costs.

All of the above referenced lawsuits, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015, which are conditioned upon, among other things, the execution of an appropriate stipulations of settlement. The stipulations of settlement will be subject to customary conditions, including, among other things, judicial approval of the proposed settlements contemplated by the memoranda of understanding. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements.

At this time, we cannot reasonably estimate the range of possible loss as a result of the lawsuits. See “Item 3: Legal Proceedings” for more information regarding these lawsuits.

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.

Acquisitions. APL has encountered competition in acquiring midstream assets owned by third parties. In several instances, APL submitted bids in auction situations and in direct negotiations for the acquisition of such assets and it was either outbid by others or it was unwilling to meet the sellers’ expectations. In the future, APL expects to encounter equal, if not greater, competition for the acquisition of midstream assets.

Oklahoma. In APL’s Oklahoma segment, it competes for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by: Caballo Energy, LLC; DCP Midstream Partners, LLC; Enable Midstream Partners, L.P.; Energy Transfer Partners, L.P.; Kinder Morgan Energy Partners, L.P.; Lumen Midstream Partners, LLC; Mustang Fuel Corporation; ONEOK Field Services Company, LLC; SemGas, L.P.; and Superior Pipeline Company, LLC.

Texas. In APL’s Texas segment, it competes for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by: DCP Midstream Partners, LP; Energy Transfer Partners, L.P.; Enlink Midstream Partners, LP; Enterprise Products Partners, L.P.; Kinder Morgan Energy Partners, L.P.; Southcross Energy Partners, L.P.; Southern Union Company; Targa Resources Partners LP; and West Texas Gas, Inc.

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

APL believes 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 corporate and other segment, it competes for gas treating services provided on gas gathering lines, including gas treating services provided by Kinder Morgan Energy Partners, L.P.; Spartan Energy Partners LLC; and TransTex Hunter, LLC.

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

Our, ARP’s and our Development Subsidiary’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 our Development Subsidiary must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:

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, ARP’s and our Development Subsidiary’s operating costs.

We believe that our, ARP’s and our Development Subsidiary’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 or their 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’s and our Development Subsidiary’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, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly affect 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 , ARP’s and our Development Subsidiary’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 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 USEPA, 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 USEPA 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’s and our Development Subsidiary’s operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that they are required under such laws and regulations. Although we 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.

CERCLA. 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.

Our, ARP’s and our Development Subsidiary’s operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we, ARP and our Development Subsidiary 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 us 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. However, none of these spills or releases appears to be material to our, ARP’s and our Development Subsidiary’s 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 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, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations 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 USEPA 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 our , ARP’s and our Development Subsidiary’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.

On April 21, 2014, the U.S. Army Corps of Engineers and USEPA proposed a rule that would define ‘Waters of the United States,’ i.e., the scope of waters protected under the Clean Water Act, in light of several U.S. Supreme Court opinions (U.S. v. Riverside Bayview, Rapanos v. United States, and Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers). The U.S. Army Corps of Engineers and USEPA have stated that the proposed rule would enhance protection for nationwide public health and aquatic resources, and increase Clean Water Act program predictability and consistency. The public comment period concluded on November 14, 2014. USEPA is in the process of reviewing the more than 800,000 comments received on the proposed rule, and has indicated that a final rule may be issued in 2015. As drafted, this proposed rule may increase the costs of compliance and result in additional permitting requirements for some of our, ARP’s or our Development Subsidiary’s existing or future facilities. Additionally, USEPA’s Science Advisory Board released its review of USEPA’s Office of Research and Development’s draft “Connectivity of Streams and Wetlands to Downstream Waters: A Review and Synthesis of the Scientific Evidence” report issued October 17, 2014. USEPA released its final report publicly on January 15, 2015.

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’s and our Development Subsidiary’s operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. Our , ARP’s and our Development Subsidiary’s operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean Air Act, 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. 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. 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. Various air quality regulations are periodically reviewed by USEPA and are amended as deemed necessary. USEPA may also issue new regulations based on changing environmental concerns.

Recent revisions to federal NSPS and NESHAP rules impose additional emissions control requirements and practices on our, ARP’s or our Development Subsidiary’s operations. Some of our 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 or revised requirements. These regulations may increase the costs of compliance for some facilities. Our, ARP’s and our Development Subsidiary’s failure to comply with these requirements could subject each of us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that our, ARP’s and our Development Subsidiary’s operations are in substantial compliance with the requirements of the Clean Air Act and comparable state laws and regulations.

While we, ARP and our Development Subsidiary will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to obtain and maintain operating permits and approvals for air emissions, we believe that our, ARP’s and our Development Subsidiary’s 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.

OSHA and Other Regulations. We, ARP and our Development Subsidiary are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes. The OSHA hazard communication standard,

USEPA 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’s and our Development Subsidiary’s operations. We believe that we are all 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’s and our Development Subsidiary’s businesses. However, Congress has been actively considering climate change legislation. More directly, USEPA 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), USEPA 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, USEPA has promulgated two rules that will affect our, ARP’s and our Development Subsidiary’s businesses.

First, USEPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31,514 (June 3, 2010). Both the federal preconstruction review program, known as “PSD,” and the operating permit program 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 the requisite operating permits.

On June 23, 2014, the United States Supreme Court ruled on challenges to the Tailoring Rule in the case of Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2014). The Court limited the applicability of the PSD program and Tailoring Rule to only new sources or modifications that would trigger PSD for another criteria pollutant such that projects cannot trigger PSD based solely on greenhouse gas emissions. However, if PSD is triggered for another pollutant, greenhouse gases could be subject to a control technology review process. The Court’s decision also means that sources cannot trigger a federal operating permit requirement based solely on greenhouse gas emissions. Overall, the impact of the Tailoring Rule after the Court’s decision is that it is unlikely to have much, if any, impact on our, ARP’s and our Development Subsidiary’s operations.

Second, USEPA 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. This subpart was most recently revised in November 2014, when USEPA finalized changes to calculation methods, monitoring and data reporting requirements, and other provisions. Shortly thereafter, in December 2014, USEPA proposed additional revisions to this subpart for public comment. In general, the Greenhouse Gas Reporting Rule requires certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to USEPA 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 our Development Subsidiary to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

In addition to these existing rules, the Obama Administration announced in January 2015 that it is developing additional rules to curb greenhouse gas emissions from the oil and gas sector, as part of a new national strategy for reducing methane emissions from the sector by 40 – 45% from 2012 levels by the year 2025. Among other steps being taken as part of this national methane strategy, USEPA is expected to build on the 2012 NSPS in a rulemaking action aimed at reducing both methane and VOC emissions from the oil and gas sector.

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, ARP’s and our Development Subsidiary’s businesses 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 discussions 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’s and our Development Subsidiary’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’s and our Development Subsidiary’s businesses, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

Energy Policy Act. Much of our, ARP’s and our Development Subsidiary’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, or “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, USEPA published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” on May 10, 2012. . In February 2014, USEPA released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on USEPA’s previous draft guidance, a factsheet and a memorandum to USEPA’s regional offices regarding implementation of the guidance. The process for implementing USEPA’s final guidance document may vary across states depending on the regulatory authority responsible for implementing the SDWA UIC program in each state.

The U.S. Senate and House of Representatives considered legislative bills in the 111^th, 112^th, and 113^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,” or “Frac Act,” the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. If re-introduced in the current 114^th Session of Congress and 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, ARP and our Development Subsidiary.

We believe our, ARP’s and our Development Subsidiary’s 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.

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. ARP and our Development Subsidiary conduct its natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. ARP and our Development Subsidiary employ numerous safety precautions at their operations to ensure the safety of their employees. There are various federal and state environmental and safety requirements for handling sour gas, and ARP and our Development Subsidiary are in substantial compliance with all such requirements.

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, ARP’s or our Development Subsidiary’s 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, ARP or our Development Subsidiary can produce from our wells or limit the number of wells or the locations at which we 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 NGLs 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 2014, the impact fee for qualifying unconventional horizontal wells spudded during 2014 was $50,300 per well, while the impact fee for unconventional vertical wells was $10,100 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 , ARP’s and our Development Subsidiary’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 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 oil produced and an oil field clean up regulatory fee of $0.000667 per Mcf of gas produced and $.00625 per barrel of crude. New Mexico imposes, among other taxes, a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax of up to 0.24% 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% on oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, up to 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 on our, ARP’s and our Development Subsidiary’s businesses.

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 believe we, ARP and our Development Subsidiary have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

A number of federal agencies, including USEPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, USEPA is conducting a study that evaluates any potential effects of hydraulic fracturing on drinking water and ground water. USEPA released a progress report on this study on December 21, 2012 that did not provide any results or conclusions. On December 9, 2013, USEPA’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. Individual research projects associated with USEPA’s study were published in July 2014. Research results are expected to be released in draft form for review by the public and USEPA Science Advisory Board. USEPA has not provided a specific date for completion of the draft report after peer review, which may occur in 2015. 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. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A revised rule was reportedly sent to the White House Office of Management and Budget review in August 2014, and a final rule is expected to be issued in 2015.

In addition, state and 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 the following:

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:

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by 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, ARP’s or our Development Subsidiary’s 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’s and our Development Subsidiary’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.

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

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. 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, federal and state agencies frequently enact new, or revise existing, environmental laws and regulations that may result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry, which could have a significant impact on APL’s operating costs.

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

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

Endangered Species Act. The federal Endangered Species Act ("ESA") restricts activities that may affect endangered or threatened species or their habitats. Endangered species, including, without limitation, the American Burying Beetle and Lesser Prairie Chicken, are located in various states in which APL operates. 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 APL’s construction and mitigation costs or further restricts APL’s 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 APL 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 APL’s midstream operations.

Risk Management Planning. The Environmental Protection Agency (“EPA”), in conjunction with the Occupational Safety and Health Administration (“OSHA”) and the U.S. Department of Homeland Security (“DHS”), in response to numerous recent industrial facility explosions, has initiated a nation-wide Request for Information (“RFI”), with the intent of strengthening the existing Chemical Accident Prevention Provisions (40 CFR 68). The EPA has indicated that rule changes will be forthcoming based upon results of the RFI. If implemented, such changes have the potential to impact APL’s gas plants by defining more rigorous design standards, regulating siting of new processes, requiring installation of automated detection devices and implementing mandatory third-party audits.

Hazardous Waste. 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 EPA, individual states administer some or all of the provisions of the 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.

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

Site Remediation. 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.

APL currently owns or leases, and has in the past owned or leased, numerous properties that for many years were used for the measurement, gathering, field compression and processing of natural gas. Although APL believes it 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 APL or on or under other locations, including off-site locations, where such substances have been taken for disposal. There may be evidence that petroleum spills or releases have occurred at some of the properties owned or leased by APL. However, none of these spills or releases appear to be material to its financial condition and APL believes 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 were not under 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, APL 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 operations to prevent future contamination.

Air Emissions. APL’s operations are subject to the federal Clean Air Act, as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including APL’s processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require APL to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. 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 regulations impose additional emissions control requirements and practices on APL’s operations. Some of its facilities may incur additional capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities. APL’s failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. APL believes its operations are in substantial compliance with the requirements of the Clean Air Act.

In 2014, the EPA proposed to lower the current ozone National Ambient Air Quality Standards (“NAAQS”) to a more stringent NAAQS. The EPA is required to promulgate the ozone NAAQS by court order no later than October 1, 2015. If lowered, the more stringent ozone NAAQS could impose additional permitting and regulatory requirements on major new facilities and facility expansions as well as existing facilities. These requirements could increase the cost of compliance at APL’s facilities and other industrial sources in future years.

While 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, APL believes its operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to it than other similarly situated companies.

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. 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 a permit or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. APL believes its operations are in substantial compliance with the requirements of the Clean Water Act.

OSHA and other regulations. APL is subject to the requirements of 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 APL organizes and/or discloses information about hazardous materials used or produced in its operations. APL believes it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

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. A portion of the gas processed at APL’s Velma gas plant contains high levels of hydrogen sulfide, and APL employs numerous safety precautions at the system to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and APL believes it is in substantial compliance with such requirements.

Chemicals of Interest. APL operates several facilities registered with 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 believes it is currently in substantial compliance with the Department’s requirements. None of APL’s affected facilities are considered high security risks by DHS at this time and no specific security plans for such per DHS regulations are required.

Greenhouse gas regulation and climate change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on APL’s business. However, Congress has been actively considering climate change legislation. More recently, the EPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts V. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will impact APL’s business.

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. Likewise, existing facilities could be required to obtain a PSD permit if modification projects are significant. 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. This rule imposes additional obligations on APL to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions. This rule also imposes monitoring and sampling requirements upon APL’s gas processing plants via the use of expensive instruments. In 2014, EPA proposed regulations that could expand such requirements to compressor stations, which have previously been exempt from these types of monitoring requirements. If finalized, these requirements could increase cost of operation at APL’s compressor stations in future years.

On January 14, 2015, the EPA announced its intent to set new standards for the regulation of Methane and Volatile Organic Compounds emissions in the oil and gas sector. It is anticipated that these standards will be built upon the 2012 New Source Performance Standards for the oil and gas sector and the EPA is aiming to finalize the rulemaking in 2016. The EPA has indicated the rule could address emissions from new and modified oil and gas production sources, and natural gas processing and transmission sources.

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 APL’s business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

agreements that could have an impact on APL’s business. Currently, some scientific and international organizations believe that methane, a greenhouse gas inadvertently emitted from APL’s operations, has a higher global warming potential than previously recognized. The EPA may amend regulations to reflect this change. If so, the change would make it more likely that some of APL’s operations would be subject to PSD and Title V permitting requirements.

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. APL does not believe these conditions are having any material current adverse impact on its business, and APL is unable to predict at this time, what, if any, long-term impact such climate effects would have.

Pipeline Safety. Some of APL’s natural gas pipelines are subject to regulation by the U.S. Department of Transportation, or 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 Materials Safety Administration, or PHMSA. Acting primarily through the Office of Pipeline Safety, or OPS, PHMSA administers a national regulatory program to ensure the safety of transportation-related gas and hazardous liquid pipeline facilities.

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

PHMSA also oversees a program that allows the states to submit an annual certification to regulate intrastate pipeline facilities. States that participate in the program can apply additional or more stringent safety standards to the pipeline facilities under their certifications, so long as those standards are compatible with the minimum federal requirements. States can also enter into agreements with PHMSA to participate in the oversight of intrastate or interstate pipelines, primarily by performing inspections for compliance with preemptive federal safety standards. The Kansas Corporation Commission, the Oklahoma Corporation Commission, and the Texas Railroad Commission all participate in the federal gas pipeline safety program and have certification to regulate intrastate gas pipeline facilities. The Oklahoma Corporation Commission and the Texas Railroad Commission also have 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 “Job Act”) was signed into law. The Job 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. The PHMSA is considering these and other provisions in the Job Act and has sought public comment on changes to a number of regulations related to pipeline safety. On September 25, 2013, the PHMSA issued a final rule implementing changes in its administrative procedures required by the Job Act, but the rulemaking process is continuing with respect to aspects of the Job 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 APL, as part of the midstream natural gas industry, could be required as a result of any new PHMSA regulations to incur additional capital expenditures and increased operating costs.

The state of Texas adopted House Bill 2982, effective on September 1, 2013. This bill amended the Texas laws delegating to the Texas Railroad Commission the authority to regulate pipeline safety for intrastate pipelines to include transportation and gathering facilities for gas in Class 1 locations and for hazardous liquids and CO² in rural locations. Before September 1, 2015, the Texas Railroad Commission must implement rules governing the commission investigations of 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 any such issues and to file reports with respect to any such issues, or to require operators to provide information requested by the Texas Railroad Commission.

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 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 gathering facility not subject to FERC jurisdiction. However, the distinction between FERC-regulated natural gas transportation facilities and federally unregulated natural gas gathering facilities is the subject of regular litigation, so the classification and regulation of some of APL’s 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 production without discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In particular, Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Kansas Corporation Commission, the Oklahoma Corporation Commission or the Texas Railroad Commission become more active, APL’s revenues could decrease. Collectively, any of these laws may restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or gather natural gas.

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

Transmission Pipeline Regulation. APL operates natural gas pipelines that extend from some of its processing plants to interconnections with both intrastate and interstate natural gas pipelines. Those facilities, known in the industry as “plant tailgate” pipelines, typically operate at transmission pressure levels and may transport “pipeline quality” natural gas. Because APL’s plant tailgate pipelines are relatively short, it treats them as “stub” lines, which are exempt from FERC’s jurisdiction under the Natural Gas Act. FERC’s treatment of the “stub” line exemption has varied over time, but, absent other factors, FERC generally limits the length of the lines that qualify for the “stub” line exemption.

APL owns (in conjunction with Pioneer) and operates the Driver Residue Pipeline, a gas transmission pipeline extending from its Driver processing plant in WestTX just over ten miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. APL has obtained a limited jurisdiction certificate of public convenience and necessity under the Natural Gas Act for the Driver Residue Pipeline. In the certificate order, among other things, FERC waived requirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specified accounting and reporting requirements. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirements FERC imposes on “open access” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certain business practices and to file certain reports. If, however, APL were to receive a bona fide request for firm service on the Driver Residue Pipeline from a third party, FERC would reexamine the waivers it has granted APL and would require it to file for authorization to offer “open access” transportation under its regulations, which would impose additional costs upon APL.

To the extent its plant tailgate pipelines do not qualify for the “stub” line exemption, APL will consider whether it needs to obtain FERC authorization to operate its tailgate pipelines or whether they can be reconfigured or otherwise modified to eliminate the possibility that they could be subject to FERC jurisdiction. If APL concludes that FERC authorization is necessary, it would expect to seek regulatory treatment similar to the treatment FERC has accorded to the

Driver Residue Pipeline. APL cannot, however, assure you that FERC would agree to assert only limited jurisdiction. If FERC were to find that it must assert comprehensive jurisdiction, APL’s operating costs would increase and it could be subject to enforcement actions under the Energy Policy Act of 2005.

APL has an ownership interest of 50% of the capacity in a 50-mile long intrastate natural gas transmission pipeline, which extends from the tailgate of three natural gas processing plants located near Pettus, Texas to interconnections with existing intrastate and interstate natural gas pipelines near Refugio, Texas. The capacity is held by its subsidiary, APL SouthTex Transmission Company LP (“APL SouthTex Transmission”), which is entitled to transport natural gas through its capacity on behalf of third parties to both intrastate and interstate markets. Because the jointly owned pipeline system was initially interconnected only with intrastate markets, each of the capacity holders qualified as an “intrastate pipeline” within the meaning of the Natural Gas Policy Act of 1978, or the NGPA and therefore are able to provide transportation of natural gas to interstate markets under Section 311 of the NGPA. Under Sections 311 and 601 of the NGPA, an intrastate pipeline may transport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gas company” under the Natural Gas Act. Transportation of natural gas under authority of Section 311 must be filed with FERC and must be shown to be “fair and equitable.” APL SouthTex Transmission has a Statement of Operating Conditions on file with FERC, and FERC has accepted the rates, which APL SouthTex Transmission’s predecessor filed, as being in accordance with the “fair and equitable” standard. APL SouthTex Transmission is required to file, on or before November 6, 2017, a petition for approval of its then-existing rates, or to propose a new rate, applicable to NGPA Section 311 service.

NGL Pipeline Regulation. The transportation of crude oil, petroleum products and NGLs is subject in certain circumstances to regulation under the Interstate Commerce Act. Responsibility for the regulation of so-called oil pipelines now resides with the FERC. Rates charged for the interstate movement of crude oil, petroleum products and NGLs must be filed with FERC and are subject to FERC review and, under the Interstate Commerce Act, FERC has exclusive jurisdiction to determine whether oil pipelines’ interstate rates and terms of service are just, reasonable, and not unduly discriminatory. Pursuant to the Interstate Commerce Act, interstate oil pipeline rates can be challenged before FERC either by protest when they are initially filed or increased or by complaint for as long as they remain on file with FERC. FERC does not, however, regulate oil pipelines’ decisions to commence or terminate service or the construction of oil pipeline facilities. Individual states may regulate oil pipelines as utilities or as common carriers. As a general rule, neither FERC nor the states regulate oil pipelines that are purely proprietary and provide transportation service only for the pipeline’s owner.

The Oklahoma Corporation Commission and Texas Railroad Commission both have authority to regulate rates charged by common carrier pipelines in their respective jurisdictions.

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 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.

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate natural gas pipelines in particular. Overall, the legislation attempts to increase supply sources by calling for various studies of the overall resource base and attempting to advantage deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the provisions of primary interest to APL as an operator of natural gas gathering lines and sellers of natural gas focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructure development, the Energy Policy Act shortens the depreciable life for gathering facilities; statutorily designates FERC as the lead agency for environmental reviews required in connection with federal authorizations and permits relating to interstate natural gas pipelines; 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 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 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.

APL’s Driver Residue Pipeline is subject to only limited regulation by FERC under the Natural Gas Act. The APL SouthTex Transmission pipeline is subject to limited regulation of the interstate transportation services it provides under Section 311 of the NGPA. Accordingly, 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 thus it is subject to (1) civil penalties for violations of the Natural Gas Act; (2) the NGPA or FERC regulations or orders issued under those laws; and (3) for conduct determined to constitute market manipulation. The penalties associated with any violations of the Energy Policy Act could be substantial.

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 that operators must bear. 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 APL’s cost of doing business and, consequently, affects its profitability, these burdens generally do not affect APL any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. APL’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.

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.

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.

Targa and we may have difficulty attracting, motivating and retaining employees in light of the Atlas Mergers.

The success of the combined entities after the Atlas Mergers will depend in part upon the ability of Targa and us to retain our respective key employees. Key employees may depart after the Atlas Mergers because of issues relating to the uncertainty and difficulty of integration or a desire not to remain following the Atlas Mergers. Accordingly, no assurance can be given that the combined entities will be able to retain key employees to the same extent as in the past.

Targa and we will incur substantial transaction-related costs in connection with the Atlas Mergers.

Targa and we expect to incur substantial expenses in connection with completing the Atlas Mergers and integrating our businesses, operations, networks, systems, technologies, policies and procedures. There are a large number of systems that must be integrated, including billing, management information, purchasing, accounting and finance, sales, payroll and benefits, fixed assets, lease administration and regulatory compliance, and there are a number of factors beyond Targa’s and our control that could affect the total amount or the timing of integration expenses. Many of the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time. Due to these factors, the transaction and integration expenses associated with the Atlas Mergers could, particularly in the near term, exceed any savings that the combined entities might otherwise realize from the elimination of duplicative expenses and the realization of economies of scale related to the integration of the businesses following the completion of the Atlas Mergers.

Failure to successfully combine Targa’s business with our business in the expected time frame may adversely affect the future results of the combined entities.

The success of the Atlas Mergers will depend, in part, on Targa’s ability to realize the anticipated benefits and synergies from combining Targa’s business with our business. To realize these anticipated benefits, the businesses must be successfully integrated. If the combined entities are not able to achieve these objectives, or are not able to achieve these objectives on a timely basis, the anticipated benefits of the Atlas Mergers may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the Atlas Mergers.

Certain of our executive officers and directors have interests in the Atlas Mergers that are different from, or in addition to, the interests of our unitholders generally, which could have influenced their decision to support or approve the Atlas Mergers.

Certain of our executive officers and directors are parties to agreements or participants in other arrangements that give them interests in the Atlas Mergers that may be different from, or be in addition to, your interests as an ATLS unitholder including, among others:

TRC shares to be received by our unitholders as a result of the ATLS Merger have different rights from our common units.

Following completion of the ATLS Merger, our unitholders will no longer hold our common units, but will instead be stockholders of TRC. There are important differences between the rights of our unitholders and the rights of TRC stockholders. Ownership interests in a limited partnership are fundamentally different from ownership interests in a corporation. Our unitholders will own TRC common stock following the completion of the ATLS Merger, and their rights associated with the TRC common stock will be governed by TRC’s organizational documents and Delaware corporation law, which differ in a number of respects from the our partnership agreement and the Delaware LP Act.

Targa and we have been subject to litigation related to the Atlas Mergers. Between October and December 2014, five public unitholders of APL filed putative class action lawsuits, one of which has subsequently been voluntarily dismissed, against us, APL, APL GP, its managers, TRC, TRP, TRP GP and MLP Merger Sub. In October and November 2014, two of our public unitholders filed putative class action lawsuits, one of which has subsequently been voluntarily dismissed, against us, our general partner, its managers, TRC and GP Merger Sub. In January 2015, a public shareholder of TRC filed a putative class action and derivative suit against TRC, its directors and various other parties. The plaintiffs alleged a variety of causes of action challenging the Atlas Mergers. These matters, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements. It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs, members of the putative classes they purport to represent or by others in an effort to enjoin the Atlas Mergers or seek monetary relief. We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits. An unfavorable resolution of any such litigation surrounding the Atlas Mergers could delay or prevent their consummation. In addition, the costs of defending the litigation, even if resolved in Targa’s or our favor, could be substantial and such litigation could distract Targa and us from pursuing the consummation of the Atlas Mergers and other potentially beneficial business opportunities. For additional information regarding this litigation, see the section entitled “Legal Proceedings.”

The receipt of the ATLS Merger Consideration will be taxable for U.S. federal income tax purposes, and our unitholders could recognize tax gain in excess of the ATLS Merger Consideration received.

A U.S. holder who receives TRC shares and cash in exchange for our common units pursuant to the ATLS Merger will recognize gain or loss in an amount equal to the difference between (i) the “amount realized,” which is the sum of (A) the amount of cash received, (B) the fair market value of TRC shares received, and (C) such U.S. holder’s share of our nonrecourse liabilities immediately prior to the ATLS Merger; and (ii) such U.S. holder’s adjusted tax basis in the common units exchanged therefor (which includes any remaining basis attributable to such U.S. holder’s share of our nonrecourse liabilities immediately prior to the ATLS Merger).

Because the amount realized includes the amount of our liabilities allocated to each unitholder immediately prior to the ATLS Merger, it is possible that the amount of gain our unitholders recognize could exceed the fair market value of the shares of TRC common stock and cash received. The application of other complicated tax rules also may give rise to adverse tax consequences to our unitholders. Because the tax consequences of the ATLS Merger to a unitholder will depend on the unitholder’s particular factual circumstances and are uncertain in some material respects, unitholders should consult their tax advisors regarding the potential tax consequences of exchanging our common units for TRC shares and cash in the ATLS Merger.

The U.S. federal income tax treatment to our unitholders with respect to owning and disposing of any TRC shares received in the ATLS Merger will be different than their U.S. federal income tax treatment with respect to owning and disposing of their ATLS common units.

For U.S. federal income tax purposes, we are classified as a partnership. Thus, we are generally not a taxable entity and incur no U.S. federal income tax liability. Instead, each unitholder is required to take into account such unitholder’s share of items of our income, gain, loss and deduction in computing its U.S. federal income tax liability, regardless of whether cash distributions are made to such unitholder by us. A distribution of cash by us to a unitholder who is a U.S. holder (as defined in Internal Revenue Code) is generally not taxable for U.S. federal income tax purposes unless the amount of cash distributed is in excess of the unitholder’s adjusted tax basis in its common units. In contrast, TRC is classified as a corporation for U.S. federal income tax purposes, and thus, TRC (and not its stockholders) is subject to U.S. federal income tax on its taxable income. A distribution of cash by TRC to a stockholder who is a U.S. holder will generally be included in such U.S. holder’s income as ordinary dividend income to the extent of TRC’s current or accumulated “earnings and profits,” as determined under U.S. federal income tax principles. A portion of the cash distributed to TRC shareholders by TRC after the ATLS Merger may exceed TRC’s current and accumulated earnings and profits. Cash distributions in excess of TRC’s current or accumulated earnings and profits will be treated as a non-taxable return of capital, reducing a U.S. holder’s adjusted tax basis in such stockholder’s TRC shares and, to the extent the cash distribution exceeds such stockholder’s adjusted tax basis, as gain from the sale or exchange of such TRC shares.

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:

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.

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:

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

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.

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.

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 hedges and physical hedges for our production. Physical hedges are not deeded hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We and our subsidiaries general limit these arrangements to smaller quantities than those we project 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 natural gas 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 our and our subsidiaries cash flow from operations for the periods covered by these arrangements. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

In addition, it is not always possible for us and our subsidiaries to engage in a derivative transaction that completely mitigates our and our subsidiaries exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we and our subsidiaries are unable to enter into a completely effective hedge transaction.

The failure by counterparties to our and our subsidiaries derivative risk management activities to perform their obligations could have a material adverse effect on our results of operations.

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under our and our subsidiaries derivative arrangements, such a default could have a material adverse effect on our results of operations, and could result in a larger percentage of our and our subsidiaries future production being subject to commodity price changes.

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.

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 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 are implemented through regulation, primarily through rules adopted by the Commodity Futures Trading Commission. Many market participants are 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 are subject to new reporting and recordkeeping requirements. The new regulations may require us to comply 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, but we could nevertheless be exposed to greater liquidity and credit risk with respect to our hedging transactions if we do not use cleared and exchange-traded swaps.

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 or 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. The legislation was also 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.

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

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:

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:

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.

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.

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 laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, while potential physical effects of climate change could disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits because of their potential criteria pollutant emissions will be required to comply with “best available control technology” standards for GHGs. These regulations could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the Obama Administration announced its Climate Action Plan in 2013, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas industry. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies in the coming years. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil, which have declined substantially. Lower commodity prices may reduce the amount of natural gas and oil that we and ARP can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge. Because our reserves are predominantly natural gas, changes in natural gas prices have a more significant impact on our financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2014, the NYMEX Henry Hub natural gas index price ranged from a high of $6.15 per MMBtu to a low of $2.89 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $53.27 per Bbl. Between January 1, 2015 and February 24, 2015, the NYMEX Henry Hub natural gas index price ranged from a high of $3.23 per MMBtu to a low of $2.58 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $53.53 per Bbl to a low of $44.45 per Bbl. If natural gas and oil prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

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.

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 and oil 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.

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

As of December 31, 2014, leases covering approximately 40,103 of ARP’s 794,030 net undeveloped acres, or 5.1%, are scheduled to expire on or before December 31, 2015. An additional 0.7% of ARP’s net undeveloped acres are scheduled to expire in 2016 and 1.6% in 2017. If ARP is unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, ARP will lose the right to develop the acreage that is covered by an expired lease.

Drilling for and producing natural gas and oil 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 and oil 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:

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.

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.

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 and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our and ARP’s natural gas and oil 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 commodity 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 commodities 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.

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.

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.

Any production associated with the assets ARP acquired in the Rangely acquisition will decline if the operator’s access to sufficient amounts of carbon dioxide is limited.

Production associated with the assets ARP acquired in the Rangely acquisition is dependent on CO₂ tertiary recovery operations in the Rangely Field. The crude oil and NGL production from these tertiary recovery operations depends, in large part, on having access to sufficient amounts of CO₂. The ability to produce oil and NGLs from these assets would be hindered if the supply of CO₂ was limited due to, among other things, problems with the Rangely Field’s current CO₂ producing wells and facilities, including compression equipment, or catastrophic pipeline failure. Any such supply limitation could have a material adverse effect on the results of operations and cash flows associated with these tertiary recovery operations. ARP’s anticipated future crude oil and NGL production from tertiary operations is also dependent on the timing, volumes and location of CO₂ injections and, in particular, on the operator’s ability to increase its combined purchased and produced volumes of CO₂ and inject adequate amounts of CO₂ into the proper formation and area within the Rangely Field.

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 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:

In addition to state law, local land use restrictions, such as municipal ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Recent changes regarding local land use restrictions in Pennsylvania occurred because of decisions of the Pennsylvania Supreme and Commonwealth Courts. On December 19, 2013, when the Pennsylvania Supreme Court issued its Robinson Township v. Commonwealth of Pennsylvania ruling, which invalidated key sections of the 2012 Oil and Gas Act that placed limits on the regulatory authority of local governments. Additionally, the Pennsylvania Supreme Court remanded a number of issues to the Commonwealth Court for further decision. On July 17, 2014, the Commonwealth Court ruled on the remanded issues. The cumulative effect of the Supreme and Commonwealth Court rulings is that all of the challenged provisions relating to local ordinances contained in the 2012 Oil and Gas Act are invalid, except for the definitions section and most of the updated preemption language in the 2012 Oil and Gas Act that was included from the 1984 Oil and Gas Act. While the total impact of these rulings are not clear and will occur over an extended period of time, an immediate impact of the rulings has been increased regulatory impediments and disputes at the local government level, as well as validity challenges initiated by private landowners alleging that local ordinances do not adequately protect health, safety, and welfare. On June 30, 2014, the New York Court of Appeals issued its opinion in Wallach v. Town of Dryden affirming local zoning laws adopted by two upstate municipalities that prohibited oil and gas-related activities within their borders. Specifically, the Court of Appeals ruled that there was nothing within the plain language, statutory scheme and legislative history of the New York Oil, Gas and Solution Mining Law that manifested an intent by the legislature to preempt a municipality’s home rule authority to regulate land use. On October 16, 2014, the New York Court of Appeals denied a request by the petitioner – the bankruptcy trustee for Norse

Energy – to re-hear arguments in the case. 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. 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, EPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. In February 2014, EPA released its revised final guidance document on Safe Drinking Water Act underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on EPA’s previous draft guidance, a fact sheet and a memorandum to EPA’s regional offices regarding implementation of the guidance. The process for implementing EPA’s final guidance document may vary across the states depending on the regulatory authority responsible for implementing the Safe Drinking Water Act underground injection control program in each state. 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, EPA is currently studying the potential environmental effects of hydraulic fracturing on drinking water and groundwater. 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. Individual research projects associated with EPA’s study were published in July 2014. Research results are expected to be released in draft form for review by the public and EPA’s Science Advisory Board. EPA has not provided a specific date for completion of the draft report after peer review, which may occur in 2015. In 2013, EPA indicated that it intended to propose a draft water quality criteria document that would update the aquatic life water quality criteria for chloride by the summer of 2014. However, EPA has yet to propose the draft water quality criteria document and it has not provided an updated timeframe for the proposal. EPA announced in its September 2014 “Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans” document that it intends to continue a rulemaking effort to potentially revise the effluent limitation guidelines for the Oil and Gas Extraction Point Source Category to address pretreatment standards for shale gas extraction. EPA proposed in that same document a detailed study of centralized waste treatment facilities that accept oil and gas extraction wastewater. The public comment period on the Preliminary 2014 Effluent Guidelines Program Plan closed on November 17, 2014. EPA is evaluating the comments submitted and will next prepare and issue the Final 2014 Effluent Guidelines Program Plan. 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 revised rule was reportedly sent to the White House Office of Management and Budget review in August 2014, and a final rule is expected to be issued in 2015.

Certain members of the 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 released on May 7, 2014. The next Annual Energy Outlook is reported to be in March 2015 by U.S. Energy Information Administration. These ongoing 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 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 the following:

Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our 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 are unable to dispose of the flowback and produced water from the strata at a reasonable cost and within applicable environmental rules, our 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, the 2012 Oil and Gas Act requires the development, submission and approval of a water management plan before withdrawing or using water from water sources in Pennsylvania to drill or hydraulically fracture an unconventional well. The requirements of these plans continue to be modified by proposed amendments to state regulations and agency policies and guidance. For Pennsylvania operations located in the Susquehanna River Basin, the Susquehanna River Basin Commission regulates consumptive water uses, water withdrawals, and the diversions of water into and out of the Susquehanna River Basin, and specific 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, we will be required to develop a Water Conservation Plan and obtain a withdrawal permit for that project. West Virginia also requires that if a certain amount of water is withdrawn water management plans are required and/or registration and reporting requirements are triggered.

Our 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 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, EPA published final rules that established new and revised requirements for emissions from oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants to address emissions of hazardous air pollutants frequently associated with oil and natural gas production, processing, transmission and storage activities. The New Source Performance Standards require operators, beginning January 1, 2015, to reduce volatile organic compounds emissions from oil and natural gas production facilities by conducting “green completions” for hydraulic fracturing, that is, recovering rather than venting or flaring the gas and NGLs that come to the surface during completion of the fracturing process. The New Source Performance Standards also established new notification and reporting requirements, more stringent leak detection standards for natural gas processing plants, and specific requirements regarding emissions from compressors, storage tanks, and other sources. In 2013, EPA made significant changes to the New Source Performance Standards applicable to storage vessels, and in December 2014, EPA finalized additional revisions to the New Source Performance Standards, including revisions to the green completion requirements. Compliance with recently revised New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

States are also proposing more stringent requirements for emissions from well sites and compressor stations. For example, in August 2013, Pennsylvania revised its list of sources exempt from air permitting requirements such that previously exempted types of sources associated with unconventional oil and gas exploration and production now are required to demonstrate compliance with specific criteria(e.g., emission limits, monitoring and recordkeeping) in order to claim the permit exemption. PADEP has since released implementation instructions that expand the list of information which operators must submit in a compliance demonstration in order to rely on the exemption. Additionally, PADEP issued a revised General Permit for Natural Gas Compression and/or Processing Facilities in January 2015, that requires the permittee to annually certify its compliance with the terms and conditions of the general permit. In April 2014, Ohio revised its current General Permit for Natural Gas Production Operations to cover emissions from completion activities. In 2013, West Virginia issued General Permit 70-A for natural gas production facilities at the well site. In February 2015, West Virginia issued a draft General Permit 80-A to replace General Permit 70-A and other exiting general permits for natural gas compressor and dehydration facilities.

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. Pennsylvania’s Oil and Gas Act of 2012, passed in February 2012, 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. Based upon natural gas prices for 2014, the impact fee for qualifying unconventional horizontal wells spudded during 2014 was $50,300 per well and the impact fee for unconventional vertical wells was $10,100 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 approximately $1.0 million for the year ended December 31, 2014.

President Obama’s budget proposals for fiscal year 2016 includes proposed provisions with significant tax consequences. The proposed budget, if enacted, would repeal over $4 billion per year in U.S. tax subsidies to oil, gas and other fossil fuel producers.

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:

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, particularly for activities occurring in West Virginia. We also understand that the EPA has taken an increased interest in assessing operator compliance with the Spill Prevention, Control and Countermeasures regulations, set forth at 40 CFR Part 112.

Certain environmental statutes, including RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where certain substances have been disposed of or otherwise released, whether caused by 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 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 activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas and oil 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. The natural gas and oil regulatory environment could also 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, the 2012 Oil and Gas Act imposes significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for unconventional gas wells, based on the price of natural gas and the age of the unconventional gas well. Proposed regulations associated with this legislation were published for public comment by the PADEP and, if finalized, will affect how natural gas operations are conducted in Pennsylvania. West Virginia has promulgated regulations associated with its existing Horizontal Well Control Act and has developed new aboveground storage tank laws that are being applied broadly and impose stringent requirements that affect the natural gas industry. We 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.

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:

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.

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 $166.8 million in 2014, $150.0 million in 2013 and $127.1 million in 2012. 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.

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 2016 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 year ended December 31, 2014, $5.3 million of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced ARP’s cash distributions received from the Drilling

Partnerships. For the years ended December 31, 2013 and 2012, the subordinated amounts were $9.6 million and $6.3 million, respectively, net of corresponding production costs.

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:

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

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

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

APL derives a majority of its gross margin from POP and Keep-Whole contracts. As a result, its income depends to a significant extent upon the prices at which it buys and sells natural gas and at which it sells NGLs and condensate. Average estimated unhedged 2015 market prices for NGLs, natural gas and crude oil, based upon NYMEX forward price curves as of December 16, 2014, were $0.53 per gallon, $3.58 per MMBTU and $58.19 per barrel, respectively. Additionally, changes in natural gas prices may indirectly impact APL’s profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to its pipeline system or that it expects will be connected to its system to shut in their production until prices improve, thereby affecting the volume of gas APL gathers and processes. Historically, the prices of natural gas, NGLs and crude oil have been subject to significant volatility in response to relatively minor changes in the supply and demand for these products, market uncertainty and a variety of additional factors beyond APL’s control. West Texas Intermediate crude oil prices traded in a range of $53.27 per barrel to $107.26 per barrel in 2014, while Henry Hub natural gas prices have traded in a range of $2.89 per MMBTU to $6.15 per MMBTU, during the same time period. We expect this volatility to continue. This volatility may cause APL’s gross margin and cash flows to vary widely from period to period. Its commodity price risk management strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all the throughput volumes. Moreover, derivative instruments are subject to inherent risks, which we describe in “--Risks Related to Our Business‒Hedging transactions may limit our potential gains or cause us to lose money.”

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.

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 2014, Atoka Midstream, LLC; Chesapeake Energy Corporation; COG Operating, LLC; DCP; Endeavor Energy Resources L.P.; Laredo Petroleum Inc.; Marathon Oil Company; MarkWest; Merit Management Partners; Parsley Energy, L.P.; Pioneer; SandRidge; Statoil; Talisman; Vanguard Natural Resources, LLC; and XTO 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.

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 Transmission 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.

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.

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:

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:

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

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

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

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

APL’s revolving credit facility and the indentures governing its senior notes contain covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. APL’s revolving credit facility also contains covenants requiring it to maintain certain financial ratios 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, FERC may limit the extent to which it regulates those activities. The way APL operates, the implementation of new laws or policies (including changed interpretations of existing laws) or a change in facts relating to APL’s plant tailgate pipeline operations could subject its operations to more extensive regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. APL expects that any such regulation could increase its costs, decrease its gross margin and cash flow, or both.

Even if APL’s gathering and processing of natural gas is not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect its business and the market for APL’s products. FERC’s policies and practices affect a range of natural gas pipeline activities, including, for example, its policies on interstate natural gas pipeline open access transportation, ratemaking, capacity release, environmental protection and market center promotion, which indirectly affect intrastate markets. FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. There can be no assurance that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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:

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.

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.

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:

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.

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:

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.

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.

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.

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

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

We are currently treated as a partnership for federal income tax purposes, which requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise be subject to federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

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

Current law or our business may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced.

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

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

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

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

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

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

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

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

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

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

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

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in our capital and profits within a 12-month period. Likewise, ARP and APL will be considered to have terminated their partnerships for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in ARP’s or APL’s capital and profits within a 12-month period. The termination would, among other things, result in the closing of our, ARP or APL’s taxable year for all unitholders and could result in a deferral of depreciation

deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholder with respect to that period.

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

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

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

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we, ARP or APL do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We, ARP and APL presently anticipate that substantially all of our income will be generated in Alabama, Colorado, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, and West Virginia. 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.

The following tables summarize information regarding our and ARP’s estimated proved natural gas and oil reserves as of December 31, 2014. 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 independent third-party engineers. 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 reports related to our and ARP’s estimated proved reserves at December 31, 2014 is included as Exhibits 99.8 through 99.10 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, 2014 and 2013, and are listed below as of the dates indicated:

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. Other than for ARP’s Rangely assets, 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 38 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. For ARP’s Rangely assets, Cawley, Gillespie, and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 32 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 16 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.

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 our independent

third-party engineers 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.

We and ARP evaluate natural gas and oil reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas and oil 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 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 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.

PUD Locations. As of December 31, 2014, there were no PUD locations related to our natural gas and oil reserves and ARP had 426 PUD locations totaling approximately 331.9 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 acquisitions in the Arkoma Basin and ARP’s acquisitions in the Barnett Shale and Marble Falls play, the Mississippi Lime play, 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, Marble Falls play, the Mississippi Lime play, 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, 2014 were due to ARP’s:

Development Costs. Costs incurred related to the development of our and our subsidiary’s PUDs were approximately $177.7 million, $103.3 million, and $79.4 million for the years ended December 31, 2014, 2013, and 2012, respectively. During the years ended December 31, 2014, 2013, and 2012, approximately 41.2 Bcfe, 58.4 Bcfe, and 30.6 Bcfe of our and our subsidiary’s reserves, respectively, were converted from PUDs to proved developed reserves. Of the 30.6 Bcfe of reserves converted from PUDs to proved developed reserves during the year ended December 31, 2012, 29.8 Bcfe is related to PUDs acquired and developed during the year. See “Item 1. Business – Overview” for further information. As of December 31, 2014, there were no PUDs that had remained undeveloped for five years or more.

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, 2014. 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:

The following tables set forth information about our and ARP’s developed and undeveloped natural gas and oil acreage as of December 31, 2014. The information in ARP’s table includes ARP’s proportionate interest in acreage owned by Drilling Partnerships.

	Developed acreage ⁽¹⁾				Undeveloped acreage⁽²⁾
Atlas Resource Partners	Gross ⁽³⁾		Net ⁽⁴⁾		Gross ⁽³⁾		Net ⁽⁴⁾
West Virginia		387,478		157,699		3,946		2,047
Pennsylvania		154,445		74,819		2,358		2,327
New Mexico		126,246		126,246		447,713		447,713
Ohio⁽⁵⁾		109,736		101,345		100,431		98,154
Texas		83,384		72,085		65,572		53,224
Alabama		56,200		55,218		40,488		37,104
Colorado		39,778		31,663		20,924		20,924
Indiana		32,388		24,781		61,949		54,648
Wyoming		29,737		5,677		830		156
Oklahoma		22,253		18,266		13,170		11,060
Tennessee		20,119		8,409		45,108		44,908
New York		13,254		12,122		20,957		18,936
Virginia		6,489		6,040		—		—
Other		1,290		207		3,014		2,829
Total		1,082,797		694,577		826,460		794,030

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, 2014. As of December 31, 2014, none of the leases covering our approximately 29,492 net undeveloped acres, or 0.0%, are scheduled to expire on or before December 31, 2015. Leases covering approximately 40,103 of ARP’s 794,030 net undeveloped acres, or 5.1%, are scheduled to expire on or before December 31, 2015. An additional 0.7% and 1.6% are scheduled to expire in each of the years 2016 and 2017, respectively.

We believe that we and ARP hold good and indefeasible title related to producing properties, in accordance with standards generally accepted in the 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 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. These 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 our or ARP’s use of our or its properties.

APL’s principal facilities consist of 17 natural gas processing plants; 18 gas treating facilities; approximately 12,300 miles of active 2 inch to 30 inch diameter natural gas gathering lines. 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:

Facility	Location	Year Constructed	Design Throughput Capacity (MMCFD)	2014 Average Utilization Rate
Atoka plant (idle)	Atoka County, OK	2006	20
Coalgate plant	Coal County, OK	2007	80
Stonewall plant	Coal County, OK	2014	160
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			540	76%⁽¹⁾

Waynoka I plant	Woods County, OK	2006	200
Waynoka II plant	Woods County, OK	2012	200
Chaney Dell plant	Major County, OK	2012	30
Chester plant	Woodward County, OK	1981	28
Total WestOK			458	100%⁽¹⁾

Total Oklahoma			998	95%⁽¹⁾

Consolidator plant	Reagan County, TX	2009	150
Driver plant	Midland County, TX	2013	200
Midkiff plant	Reagan County, TX	1990	60
Benedum plant (idle)	Upton County, TX	Updated 1981	45
Edward plant	Upton County, TX	2014	200
Total WestTX			655	70%

Silver Oak I	Bee County, TX	2012	200
Silver Oak II	Bee County, TX	2014	200
Total SouthTX			400	30%

Total Texas			1,055	55%

Total			2,053	75%⁽¹⁾

Of the 18 gas treating facilities APL owns, 17 are held for use 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 SouthOK system and is included in APL’s Oklahoma segment. APL’s 17 contract gas treating facilities are included in its Corporate and Other segment.

APL’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not materially interfered, and APL does not expect they will materially interfere, with the conduct of its business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the rights-of-way grants. In a few instances, APL’s rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the rights-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

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

We and our subsidiaries are party to various routine legal proceedings arising in the ordinary course of our business. We do not believe that any 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”.

Since the announcement on October 13, 2014 of the Merger and the APL Merger, we, APL and the other parties to the Atlas Mergers have been named as defendants in putative stockholder class action complaints challenging the transactions. Although New Atlas has not been named as a defendant in these complaints, certain of our expected officers have been named as defendants, and the litigation could delay or impede the consummation of the separation and distribution.

As of February 24, 2015, we are aware that we, our general partner, TRC, GP Merger Sub (a subsidiary of TRC created in connection with the Merger), and the members of our board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in two putative stockholder class action complaint challenging the Merger filed in the Court of Common Pleas for Allegheny County, Pennsylvania. These cases are captioned: Rick Kane v. Atlas Energy, L.P., et al., Case No. GD-14-019658 (Pa. Ct. Comm. Pls. Oct. 22, 2013) and Jeffrey Ayers v. Atlas Energy, L.P., et al., Case No. GD-14-020255 (Pa. Ct. Comm. Pls. Nov. 3, 2014) (the “ATLS Lawsuits”). The ATLS Lawsuits were consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit”), although the Kane litigation has since been voluntarily dismissed. We are also aware that APL, APL’s general partner, us, Targa Resources, Targa Resources Partners, Targa Resource Partners’ general partner, MLP Merger Sub (a subsidiary of TRP created in connection with the APL Merger), and the members of the APL board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in five putative stockholder class action complaints challenging the APL Merger, four filed in the Court of Common Pleas for

Allegheny County, Pennsylvania and one filed in the District Court of Tulsa County, Oklahoma. These cases are captioned: Michael Envin v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-019245 (Pa. Ct. Comm. Pls. Oct. 17, 2013), Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020108 (Pa. Ct. Comm. Pls. Oct. 31, 2014), Mike Welborn v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020729 (Pa. Ct. Comm. Pls. Nov. 10, 2014), Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-22208 (Pa. Ct. Comm. Pls. Dec. 5, 2014) and William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., Case No. CJ-2014-04087 (Okla. D. Ct. Oct. 28, 2014) (the “APL Lawsuits” and, together with the ATLS Lawsuits, the “Lawsuits”). The Evnin, Greenthal, Welborn and Feldbaum APL Lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). The Federman lawsuit has subsequently been voluntarily dismissed.

The Lawsuits generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for the ATLS and APL unitholders in, respectively, each of the Merger and the APL Merger, agreeing to certain terms in each of the merger agreements that allegedly restrict the defendants’ ability to obtain a more favorable offer, favoring their self-interests over the interests of ATLS and APL unitholders, and omitting material information from the Proxy Statements. The Lawsuits further allege that those breaches were aided and abetted by some combination of us, APL, TRC, TRP, or various affiliates of those entities named above. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses, and costs.

Additionally, a putative stockholder class action and derivative lawsuit, captioned Inspired Investors v. Perkins et. al., Case No. 2015-04961, was filed purportedly on behalf of TRC shareholders in the District Court of Harris County, Texas on January 28, 2015 and amended on February 23, 2015. The lawsuit names us and the individual members of the board of directors of TRC as defendants and TRC as a nominal defendant. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the Merger and omitting purportedly material information from the registration statement on Form S-4 that TRC initially filed with the SEC on November 20, 2014 and most recently amended on January 22, 2015. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest and costs.

Our common units trade on the New York Stock Exchange under the symbol “ATLS.” At the close of business on February 24, 2015, the closing price of our common limited partner units was $31.27, and there were 169 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, 2014 and 2013:

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”.

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2014, 2013 and 2012, 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 year ended December 31, 2011 and 2010 as well as consolidated balance sheet data for the year ended December 31, 2012, 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, 2014, 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:

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

The 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,
	2014			2013			2012			2011			2010
Statement of operations data:	(in thousands, except per unit data)
Revenues:
Gas and oil production	$	475,758		$	273,906		$	92,901		$	66,979		$	93,050
Well construction and completion		173,564			167,883			131,496			135,283			206,802
Gathering and processing		2,836,322			2,139,694			1,219,815			1,329,418			944,609
Administration and oversight		15,564			12,277			11,810			7,741			9,716
Well services		24,959			19,492			20,041			19,803			20,994
Gain (loss) on mark-to-market derivatives		133,883			(28,764	)		31,940			(20,453	)		(5,944	)
Other, net		8,653			(6,973	)		13,440			31,803			17,437
Total revenues		3,668,703			2,577,515			1,521,443			1,570,574			1,286,664

Costs and expenses:
Gas and oil production		184,296			100,178			26,624			17,100			23,323
Well construction and completion		150,925			145,985			114,079			115,630			175,247
Gathering and processing		2,420,759			1,802,618			1,009,100			1,123,051			789,548
Well services		10,007			9,515			9,280			8,738			10,822
General and administrative		217,371			197,976			165,777			80,584			37,561
Chevron transaction expense		—			—			7,670			—			—
Depreciation, depletion and amortization		444,622			308,533			142,611			109,373			115,655
Asset impairment		580,654			81,880			9,507			6,995			50,669
Total costs and expenses		4,008,634			2,646,685			1,484,648			1,461,471			1,202,825
Operating income (loss)		(339,931	)		(69,170	)		36,795			109,103			83,839
Gain (loss) on asset sales and disposal		45,522			(2,506	)		(6,980	)		256,292			(13,676	)
Interest expense		(173,357	)		(132,581	)		(46,520	)		(38,394	)		(90,448	)
Loss on early extinguishment of debt		—			(26,601	)		—			(19,574	)		(4,359	)
Income (loss) from continuing operations before tax		(467,766	)		(230,858	)		(16,705	)		307,427			(24,644	)
Income tax (benefit) expense		(2,376	)		(2,260	)		176			—			—
Income (loss) from continuing operations		(465,390	)		(228,598	)		(16,881	)		307,427			(24,644	)
Income (loss) from discontinued operations		—			—			—			(81	)		321,155
Net income (loss)		(465,390	)		(228,598	)		(16,881	)		307,346			296,511
(Income) loss attributable to non-controlling interests		273,132			153,231			(35,532	)		(257,643	)		(245,764	)
Net income (loss) after non-controlling interests.		(192,258	)		(75,367	)		(52,413	)		49,703			50,747
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).		—			—			—			(4,711	)		(22,813	)
Net income (loss) attributable to common limited partners.	$	(192,258	)	$	(75,367	)	$	(52,413	)	$	44,992		$	27,934
Allocation of net income (loss) attributable to common limited partners:
Continuing operations	$	(192,258	)	$	(75,367	)	$	(52,413	)	$	45,002		$	(11,994	)
Discontinued operations		—			—			—			(10	)		39,928
	$	(192,258	)	$	(75,367	)	$	(52,413	)	$	44,992		$	27,934
Net income (loss) attributable to common limited partners per unit:
Basic:
Income (loss) from continuing operations attributable to common limited partners	$	(3.71	)	$	(1.47	)	$	(1.02	)	$	0.91		$	(0.43	)
Income from discontinued operations attributable to common limited partners		—			—			—			—			1.44
Net income (loss) attributable to common limited partners	$	(3.71	)	$	(1.47	)	$	(1.02	)	$	0.91		$	1.01
Diluted⁽¹⁾:
Income (loss) from continuing operations attributable to common limited partners	$	(3.71	)	$	(1.47	)	$	(1.02	)	$	0.88		$	(0.43	)
Income from discontinued operations attributable to common limited partners		—			—			—			—			1.44
Net income (loss) attributable to common limited partners	$	(3.71	)	$	(1.47	)	$	(1.02	)	$	0.88		$	1.01
Balance sheet data (at period end):
Property, plant and equipment, net	$	5,669,262		$	4,910,875		$	3,502,609		$	2,093,283		$	1,849,486
Total assets		7,866,636			6,792,641			4,597,194			2,684,771			2,435,262
Total debt, including current portion		3,570,570			2,889,044			1,540,343			524,140			601,389
Total partners’ capital		3,360,745			3,222,876			2,479,848			1,744,081			1,406,123
Cash flow data:
Net cash provided by operating activities	$	154,802		$	37,608		$	70,276		$	88,195		$	157,253
Net cash provided by (used in) investing activities		(1,488,893	)		(2,496,607	)		(1,650,505	)		14,159			502,330
Net cash provided by (used in) financing activities		1,393,800			2,445,720			1,539,633			(25,225	)		(660,439	)
Capital expenditures		(873,383	)		(718,040	)		(500,759	)		(292,750	)		(139,360	)

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.

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, 2014, our operations primarily consisted of our ownership interests in the following:

Our consolidated financial statements contain our accounts and those of our consolidated subsidiaries, all of which are wholly-owned at December 31, 2014, except for ARP, APL and our Development Subsidiary, which we control. 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, 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.

dismissed. In addition, we, APL, Atlas Pipeline Partners GP LLC (“APL GP”), TRC, TRP, Targa Resources GP LLC (“TRP GP”), Trident MLP Merger Sub LLC (“MLP Merger Sub”) and the members of the managing board of APL GP have been named as defendants in five putative unitholder class action lawsuits challenging the APL Merger, one of which has subsequently been voluntarily dismissed. The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for our unitholders in the Merger and APL Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs.

At this time, we cannot reasonably estimate the range of possible loss as a result of the lawsuits. See “Item 3: Legal Proceedings” for more information regarding these lawsuits.

Cash Distribution. On January 28, 2015, we declared a cash distribution of $0.52 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $27.1 million distribution was paid on February 19, 2015 to unitholders of record at the close of business on February 9, 2015.

Credit Facility Amendment. On February 23, 2015, ARP entered into a Sixth Amendment to the Second Amended and Restated Credit Agreement (the “Sixth Amendment”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which amendment amends the Second Amended and Restated Credit Agreement (the “ARP Credit Agreement”), dated July 31, 2013. Among other things, the Sixth Amendment:

The Amendment was approved by the lenders and was effective on February 23, 2015.

Second Lien Term Loan Facility. On February 23, 2015, ARP entered into a Second Lien Credit Agreement (the “Second Lien Credit Agreement”) with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “Term Loan Facility”). The Term Loan Facility matures on February 23, 2020.

ARP has the option to prepay the Term Loan Facility at any time, and is required to offer to prepay the Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest:

ARP’s obligations under the Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans.

The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving credit facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables.

Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the Term Loan Facility so long as the aggregate outstanding principal amount of the Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020.

Cash Distributions. On January 28, 2015, ARP declared a cash distribution of $0.1966 per common unit for the month of December 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to us as the general partner and preferred limited partners, respectively, was paid on February 13, 2015 to holders of record as of February 9, 2015.

On February 23, 2015, ARP declared a cash distribution of $0.1083 per common unit for the month of January 2015. The $9.9 million distribution, including $0.2 million and $0.4 million to us as the general partner and preferred limited partners, respectively, will be paid on March 17, 2015 to holders of record as of March 10, 2015.

Notice of Preferred Unit Redemption. On January 27, 2015, APL delivered notice of its intention to redeem all outstanding shares of its Class E cumulative redeemable perpetual preferred units (“Class E APL Preferred Units”). The redemption of the Class E APL Preferred Units will occur immediately prior to the close of the APL Merger. APL expects the APL Merger to close on February 27, 2015 and, accordingly, the redemption would also be on February 27, 2015. The Class E Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E APL Preferred Units as of the redemption date. TRP has agreed to deposit the funds for such redemption with APL’s paying agent (see “Issuance of Units”).

Conversion of Preferred Units. On January 22, 2015, APL exercised its right under the certificate of designation of the Class D APL Preferred Units (“Class D APL Certificate of Designation”) to convert all outstanding Class D APL Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D APL Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued (see “Issuance of Units”).

Redemption of APL Senior Notes. On January 15, 2015, TRP announced cash tender offers to redeem any and all of APL’s outstanding $500.0 million aggregate principal amount of its 6.625% unsecured senior notes due October 1, 2020 (“6.625% APL Senior Notes”); $400.0 million aggregate principal amount of its 4.75% unsecured senior notes due November 2021 (“4.75% APL Senior Notes”); and $650.0 million aggregate principal amount of its 5.875% unsecured notes due August 2023 (“5.875% APL Senior Notes”). TRP made the cash tender offers in connection with, and conditioned upon, the consummation of the APL Merger. The APL Merger, however, is not conditioned on the consummation of the tender offers. On February 2, 2015, TRP announced as of January 29, 2015, it had received tenders pursuant to its previously announced cash tender offers on January 15, 2015 from holders representing:

Also on February 2, 2015, TRP announced a change of control cash tender offer for any and all of the outstanding $500.0 million of the 6.625% APL Senior Notes. TRP made the change of control cash tender offer in connection with, and conditioned upon, the consummation of the APL Merger. The APL Merger, however, is not conditioned on the consummation of the change in control cash tender offer. The change in control cash tender offer was made independently of TRP’s January 15, 2015 cash tender offers (see “Senior Notes”).

Cash Distributions. On January 15, 2015, APL paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on its Class E APL Preferred Units, representing the cash distribution for the period October 15, 2014 through January 14, 2015 (see “Issuance of Units”).

On January 9, 2015, APL declared a cash distribution of $0.64 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $62.2 million distribution, including $8.1 million to us as general partner, was paid on February 13, 2015 to unitholders of record at the close of business on January 21, 2015.

Eagle Ford Shale Asset Acquisition. On November 5, 2014, ARP and our Development Subsidiary completed an acquisition of oil and natural gas liquid assets in the Eagle Ford Shale in Atascosa County, Texas. The purchase price was $339.2 million, of which $179.5 million was paid at closing by ARP and $19.7 million was paid by our Development Subsidiary, and approximately $140.0 million will be paid over the four quarters following closing. ARP will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. Our Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing. ARP may pay up to $20.0 million of our deferred portion of the purchase price with the issuance of its Class D Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”). The acquisition has an effective date of July 1, 2014.

Issuance of Senior Notes. In connection with the Eagle Ford Acquisition, on October 14, 2014, ARP issued an additional $75.0 million of its 9.25% Senior Notes due 2021 (“9.25% ARP Senior Notes”) in a private transaction under Rule 144A and Regulation S of the Securities Act of 1933, as amended (the “Securities Act”) at an offering price of 100.5%. In connection with the issuance, ARP also entered into a registration rights agreement. Under the registration rights agreement, ARP agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated no later than 270 days after the issuance of the ARP 9.25% Senior Notes. Under certain circumstances, in lieu of, or in addition to, a registered exchange offer, we agreed to file a shelf registration statement with respect to the issuance. If ARP fails to comply with its obligations to register the notes within the specified time periods, ARP will be subject to additional interest, up to 1% per annum, until such time that the exchange offer is consummated or the shelf registration is declared effective, as applicable (see “Senior Notes”).

Issuance of Preferred Units. Also in connection with the Eagle Ford Acquisition, in October 2014 ARP issued 3,200,000 8.625% Class D ARP Preferred Units at a public offering price of $25.00 per Class D Unit. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

Equity Distribution Program. On August 29, 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may 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 New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent (see “Issuances of Units”). As of December 31, 2014, no units have been sold under this program.

Rangely Acquisition. On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado for approximately $409.4 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of its 7.75% Senior Notes due 2021 (“7.75 ARP Senior Notes”) (see “Senior Notes”) and the issuance of 15,525,000 of ARP’s common limited partner units (see “Issuance of Units”). The Rangely Acquisition had an effective date of April 1, 2014. Our consolidated financial statements reflect the operating results of the acquired business commencing June 30, 2014.

GeoMet Acquisition. On May 12, 2014, ARP completed the acquisition of assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

Issuance of Common Units. In May 2014, in connection with the closing of the Rangely Acquisition, ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million. The units were registered under the Securities Act pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014 (see “Issuance of Units”).

In March 2014, ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014 (see “Issuance of Units”).

Cash Distribution Practice. On January 29, 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program, whereby a monthly cash distribution is paid within 45 days from the month end.

Completion of Connection within SouthOK system. In December 2014, APL completed the connection between the Velma and Arkoma systems within the SouthOK system. The connection accommodates the increased demand for processing capacity behind the Velma system, where the emerging South Central Oklahoma Oil Province (“SCOOP”) play has attracted significant producer interest. The connection between Velma and Arkoma offers APL more operational flexibility and helps it better utilize its processing capacity across the SouthOK system.

Cryogenic Processing Plant. On September 15, 2014, APL placed in service a new 200 MMCFD cryogenic processing plant, known as the Edward plant, in its WestTX system in the Permian Basin of West Texas, increasing the WestTX system capacity to 655 MMCFD. On June 25, 2014, APL placed in service a new 200 MMCFD cryogenic processing plant, known as the Silver Oak II plant, in its SouthTX system in the Eagle Ford Shale play of South Texas, increasing the SouthTX system capacity to 400 MMCFD. On May 1, 2014, APL placed in service a new 120 MMCFD cryogenic processing plant, known as the Stonewall plant, in its SouthOK system in the Arkoma Basin of Oklahoma, increasing the SouthOK system capacity to 500 MMCFD. A planned expansion of the Stonewall plant to raise the processing capacity to 200 MMcfd is anticipated to be completed in the first quarter of 2015.

Amendment to Credit Agreement. On August 28, 2014, APL entered into a Second Amended and Restated Credit Agreement (the “Revised APL Credit Agreement”) which, among other changes:

Sale of WTLPG. On May 14, 2014, APL completed the sale of its 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) to a subsidiary of Martin Midstream Partners L.P. (NYSE: MMLP). APL received $131.0 million in proceeds, net of selling costs and working capital adjustments, which were used to pay down its revolving credit facility. As a result of the sale, APL recognized a $47.8 million gain on asset sales and disposal on our consolidated statements of operations for the year ended December 31, 2014.

Equity Distribution Agreement. On May 12, 2014, APL entered into an equity distribution agreement with Citigroup Global Markets Inc., Wells Fargo Securities, LLC and MLV & Co. LLC, through which APL may offer and sell from time to time common units having an aggregate value up to $250.0 million. Sales are at market prices prevailing at the time of the sale. However, APL is currently restricted from selling common units by the APL Merger Agreement. During the year ended December 31, 2014, APL issued 3,558,005 common units under the 2014 equity distribution agreement for proceeds of $121.6 million, net of $1.2 million in commissions paid to the sales agents (see “Issuance of Units”).

Issuance of Preferred Units. On March 17, 2014, APL issued 5,060,000 of its Class E APL Preferred Units to the public at an offering price of $25.00 per Class E APL Preferred Unit. APL received $122.3 million in net proceeds. The proceeds were used to pay down APL’s revolving credit facility (see “Issuance of Units”).

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 pricing indices for the majority of our and ARP’s production areas are as follows:

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 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 2016. ARP also holds firm transportation obligations on East Tennessee Natural Gas, Columbia Gas Transmission and Equitrans for the benefit of production from the central Appalachian Basin. The total of firm transportation held is approximately 25,000 dth/d, 15,500 dth/d and 2,300 dth/d, respectively, under contracts expiring between the years 2015 and 2022.

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/pipeline charges. The oil and natural gas liquids production of ARP’s Rangely assets flows into a common carrier pipeline and is sold at prevailing market prices, less applicable transportation and oil quality differentials. 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 indicated 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, 2014, Tenaska Marketing Ventures, Chevron, Enterprise, and Interconn Resources LLC accounted for approximately 25%, 15%, 14% and 13% 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.

Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As it deploys Drilling Partnership investor capital, ARP recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, ARP will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on our consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%.

As managing general partner of our Drilling Partnerships, we recognize our Drilling Partnership management fees in the following manner:

Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for its 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 it remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby it 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 Drilling Partnerships by approximately 3%.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized.

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

For the year ended December 31, 2014, ONEOK Hydrocarbon, L.P. (“ONEOK”); DCP NGL Services, LLC, a subsidiary of DCP Midstream, LLC (“DCP”); and BP Energy Company accounted for approximately 21%, 13% and 11%, respectively, of APL’s third-party revenues within its Oklahoma segment and DCP and Tenaska Marketing Ventures, Inc. accounted for approximately 47% and 16%, respectively, of APL’s third-party revenues within the Texas segment, with no other single customer accounting for more than 10% for this period.

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.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the latter half of 2014 and early 2015, particularly in December 2014 and January 2015. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. 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 and oil 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.

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.

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.

Production Profile. At December 31, 2014, our consolidated gas and oil production revenues and expenses consist 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 plays throughout the United States. ARP previously 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, 2014, we and ARP have established production positions in the following operating areas:

The following table presents the number of wells we and ARP drilled and the number of wells we and ARP turned in line, both gross and for our and ARP’s interest, during the years ended December 31, 2014, 2013 and 2012:

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, 2014, 2013 and 2012:

		Years Ended December 31,
	2014		2013		2012
Production:⁽¹⁾⁽²⁾
Atlas Energy:
Natural gas (MMcf)		4,460		1,864	—
Oil (000’s Bbls)		43		3	—
Natural gas liquids (000’s Bbls)		32		1	—
Total (MMcfe)		4,908		1,885	—
Atlas Resource:
Natural gas (MMcf)		82,682		57,993	25,403
Oil (000’s Bbls)		1,254		485	121
Natural gas liquids (000’s Bbls)		1,388		1,268	357
Total (MMcfe)		98,535		68,511	28,267
Total production:
Natural gas (MMcf)		87,142		59,857	25,403
Oil (000’s Bbls)		1,297		488	121
Natural gas liquids (000’s Bbls)		1,420		1,269	357
Total (MMcfe)		103,443		70,396	28,267
Production per day:⁽¹⁾⁽²⁾
Atlas Energy:
Natural gas (Mcfd)		12,219		5,106	—
Oil (Bpd)		117		7	—
Natural gas liquids (Bpd)		88		3	—
Total (Mcfed)		13,448		5,164	—
Atlas Resource:
Natural gas (Mcfd)		226,526		158,886	69,408
Oil (Bpd)		3,436		1,329	330
Natural gas liquids (Bpd)		3,802		3,473	974
Total (Mcfed)		269,958		187,701	77,232
Total production per day:
Natural gas (Mcfd)		238,745		163,992	69,408
Oil (Bpd)		3,553		1,336	330
Natural gas liquids (Bpd)		3,891		3,476	974
Total (Mcfed)		283,406		192,866	77,232

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents production revenues and average sales prices for our and ARP’s natural gas, oil, and natural gas liquids production for the years ended December 31, 2014, 2013 and 2012, 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,
	2014		2013			2012
Production revenues (in thousands):
Atlas Energy:
Natural gas revenue	$	17,103	$	6,849	$	—
Oil revenue		3,770		241		—
Natural gas liquids revenue		928		33		—
Total revenues	$	21,801	$	7,123	$	—
Atlas Resource:
Natural gas revenue	$	302,826	$	186,229	$	70,151
Oil revenue		110,070		44,160		11,351
Natural gas liquids revenue		41,061		36,394		11,399
Total revenues	$	453,957	$	266,783	$	92,901
Total production revenues:
Natural gas revenue	$	319,929	$	193,078	$	70,151
Oil revenue		113,840		44,401		11,351
Natural gas liquids revenue		41,989		36,427		11,399
Total revenues	$	475,758	$	273,906	$	92,901
Average sales price:
Atlas Energy:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge	$	3.83	$	3.48	$	3.29
Total realized price, before hedge	$	3.98	$	3.25	$	2.60
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	88.61	$	91.02	$	94.02
Total realized price, before hedge	$	88.61	$	95.86	$	91.32
Natural gas liquids (per Bbl):⁽¹⁾
Total realized price, after hedge	$	28.80	$	34.88	$	—
Total realized price, before hedge	$	28.80	$	34.88	$	—
Atlas Resource:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge⁽²⁾	$	3.76	$	3.47	$	3.29
Total realized price, before hedge⁽²⁾	$	3.93	$	3.25	$	2.60
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	87.76	$	91.01	$	94.02
Total realized price, before hedge	$	82.22	$	95.88	$	91.32
Natural gas liquids (per Bbl):⁽¹⁾
Total realized price, after hedge	$	29.59	$	28.71	$	31.97
Total realized price, before hedge	$	29.39	$	29.43	$	31.97
Total:
Natural gas (per Mcf):⁽¹⁾
Total realized price, after hedge⁽²⁾	$	3.76	$	3.48	$	3.29
Total realized price, before hedge⁽²⁾	$	3.93	$	3.25	$	2.60
Oil (per Bbl):⁽¹⁾
Total realized price, after hedge	$	87.79	$	91.02	$	94.02
Total realized price, before hedge	$	82.42	$	95.86	$	91.32
Natural gas liquids (per Bbl):⁽¹⁾
Total realized price, after hedge	$	29.57	$	28.71	$	31.97
Total realized price, before hedge	$	29.37	$	29.43	$	31.97

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total production revenues were $475.8 million for the year ended December 31, 2014, an increase of $201.9 million from $273.9 million for the year ended December 31, 2013. This increase principally consisted of a $125.0 million increase attributable to our and ARP’s newly acquired coal-bed methane assets, a $41.5 million increase attributable to ARP’s newly acquired Rangely assets, a $13.3 million increase attributable to our and ARP’s Mississippi Lime/Hunton assets, a $9.6 million increase attributable to our and ARP’s newly acquired Eagle Ford assets, a $9.0 million increase attributable to our and ARP’s Barnett Shale/Marble Falls operations, and a $5.3 million increase attributable to ARP’s Appalachia assets due primarily to the Marcellus and Utica Shale wells drilled.

Total production costs were $184.3 million for the year ended December 31, 2014, an increase of $84.1 million from $100.2 million for the year ended December 31, 2013. This increase primarily consisted of a $53.7 million increase attributable to production costs associated with our and ARP’s newly acquired coal-bed methane assets, a $15.1 million increase attributable to ARP’s newly acquired Rangely assets, an $11.1 million increase primarily attributable to new well connections, consisting of $6.3 million attributable to our and AGP’s Barnett Shale/Marble Falls assets, $3.5 million attributable to our and ARP’s Mississippi Lime/Hunton assets, and $1.3 million attributable to ARP’s Appalachia operations, a $3.1 million decrease in the credit received against ARP’s lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships, and a $1.2 million increase attributable to our and ARP’s newly acquired Eagle Ford assets. Total production costs per Mcfe increased to $1.81 per Mcfe for the year ended December 31, 2014 from $1.50 per Mcfe for the comparable prior year period primarily as a result of the increases in our oil and natural gas liquids production.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total production revenues were $273.9 million for the year ended December 31, 2013, an increase of $181.0 million from $92.9 million for the year ended December 31, 2012. This increase principally consisted of a $92.6 million increase attributable to our and ARP’s Barnett Shale/Marble Falls operations, a $72.9 million increase attributable to our and ARP’s newly acquired coal-bed methane assets, a $15.4 million increase attributable to ARP’s Mississippi Lime/Hunton assets, and a $2.1 million increase attributable to ARP’s Appalachia assets due primarily to the Marcellus and Utica Shale wells drilled.

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 2013 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 and natural gas liquids volumes during the year ended December 31, 2013.

Drilling Program Results. At December 31, 2014, 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 the years ended December 31, 2014, 2013 and 2012. There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012:

	Years Ended December 31,
	2014		2013			2012
Drilling partnership investor capital:
Raised	$	166,798	$	149,967	$	127,071
Deployed	$	173,564	$	167,883	$	131,496
Gross partnership wells drilled:
Appalachia
Marcellus Shale		—		—		10
Utica		4		3		5
Ohio		—		—		7
Barnett/Marble Falls		77		51		4
Mississippi Lime/Hunton		17		21		11
Eagle Ford		2		—		—
Niobrara		—		—		51
Total		100		75		88
Net partnership wells drilled:
Appalachia
Marcellus Shale		—		—		10
Utica		4		3		5
Ohio		—		—		7
Barnett/Marble Falls		64		25		2
Mississippi Lime/Hunton		16		21		9
Eagle Ford		1		—		—
Niobrara		—		—		51
Total		85		49		84

Well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for Drilling Partnerships which 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):

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Well construction and completion segment margin was $22.6 million for year ended December 31, 2014, an increase of $0.7 million from $21.9 million for the year ended December 31, 2013. This increase consisted of a $7.7 million increase related to a greater number of wells recognized for revenue within ARP’s Drilling Partnerships, partially offset by a $7.0 million decrease associated with ARP’s lower gross profit margin per well. Average revenue and cost per well decreased between periods due primarily to capital deployed for lower cost Marble Falls wells within ARP’s Drilling Partnerships during the year ended December 31, 2014 compared with capital deployed for higher cost Marcellus and Utica Shale wells during the prior year period. As ARP’s drilling contracts with its Drilling Partnerships are on a “cost-plus” basis, an increase or decrease in its 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, 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.

At December 31, 2014, 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 play and Niobrara Shale, as compared to deep, horizontal wells, such as those drilled in the Marcellus and Utica Shales.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Administration and oversight fee revenues were $15.6 million for the year ended December 31, 2014, an increase of $3.3 million from $12.3 million for the year ended December 31, 2013. This increase was due to increases in the number of wells spud within the current year period compared with the prior year period, particularly within the Marble Falls play.

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 and Marble Falls plays, partially offset by a decrease in the number of Marcellus Shale wells drilled during the year ended December 31, 2013.

At December 31, 2014, 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, 2014 Compared with the Year Ended December 31, 2013. Well services revenues were $25.0 million for the year ended December 31, 2014, an increase of $5.5 million from $19.5 million for the year ended December 31, 2013. Well services expenses were $10.0 million for the year ended December 31, 2014, an increase of $0.5 million from $9.5 million for the year ended December 31, 2013. The increase in well services revenue is primarily related to the increased utilization of ARP’s salt water gathering and disposal systems within the Mississippi Lime and Marble Falls plays by ARP’s Drilling Partnership wells. The increase in well services expense is primarily related to higher labor costs.

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.

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:

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, 2014 Compared with the Year Ended December 31, 2013. ARP’s net gathering and processing expense for the year ended December 31, 2014 was $1.1 million, a decrease of $0.9 million compared with net gathering and processing expense of $2.0 million for the year ended December 31, 2013. This favorable decrease was principally due to a full year of gathering fees from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline.

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 gathering and processing 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 Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline.

APL’s Gathering and Processing Profile. At December 31, 2014, APL’s gathering and processing volumes are primarily generated through its operations in the following areas:

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 year ended December 31, 2014, 2013 and 2012:

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Gathering and processing margin for APL was $416.7 million for the year ended December 31, 2014 compared with $339.1 million for the year ended December 31, 2013. This increase was due principally to higher production volumes.

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.

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 gain of $74.9 million, a loss of $19.7 million and a gain of $27.3 million for the years ended December 31, 2014, 2013 and 2012, respectively, for APL’s mark-to-market gain (loss) on derivatives valued upon unobservable inputs.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Gain on mark-to-market derivatives was $133.9 million for the year ended December 31, 2014 as compared with a loss of $28.8 million for the year ended December 31, 2013. The favorable movement of $162.7 million was primarily due to a $141.0 million mark-to-market gain in the current year as a result of a decrease in forward prices, related to falling oil prices, combined with an increase in forward prices during the prior year, which resulted in $28.4 million mark-to-market losses on derivatives, partially offset by a $9.6 million unfavorable movement in cash settlements in the current year compared to the prior year mainly due to favorable propane swap settlements in the prior year. In addition, ARP recorded $2.8 million of gains within mark-to-market derivatives on our consolidated statement of operations for the year ended December 31, 2014 in connection with it entering into derivative instruments upon signing the Eagle Ford Acquisition (see “Recent Developments”).

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, 2014 Compared with the Year Ended December 31, 2013. Other, net for the year ended December 31, 2014 was income of $8.7 million as compared with expense of $7.0 million for the comparable prior year period. This favorable movement was primarily due to the $14.5 million of premium amortization associated with swaption derivative contracts for production volumes related to our wells and ARP’s wells acquired from EP Energy in the prior year period, and an arrangement with respect to APL’s SouthTX system in the current year period, partially offset by a $5.0 million decrease in revenues from WTLPG due its sale in May 2014 (see “Recent Developments”), a $4.3 million increase in the loss on the T2 Eagle Ford joint venture and a $1.1 million decrease in income from the equity investment in Lightfoot. APL’s T2 LaSalle and T2 Eagle Ford joint ventures are structured to earn revenues equal to their operating costs, exclusive of depreciation expense. APL’s loss on equity method investments primarily represents the depreciation expense of these assets.

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.

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

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total general and administrative expenses increased to $217.4 million for the year ended December 31, 2014 compared with $198.0 million for the year ended December 31, 2013. Our $65.0 million of general and administrative expenses for the year ended December 31, 2014 represented a $26.0 million increase from the comparable prior year period, primarily due to a $21.0 million increase in non-cash compensation expense and a $8.0 million increase related to our Development Subsidiary, partially offset by $3.0 million decrease in salaries, wages and other corporate activities. ARP’s $72.3 million of general and administrative expenses for the year ended December 31, 2014 represents a $5.7 million decrease from the comparable prior year period primarily due to a $12.1 million decrease in non-recurring transaction costs related to the acquisitions of assets in the current and prior year periods and a $4.6 million decrease in non-cash compensation expense, partially offset by a $7.0 million increase in salaries, wages and benefits, and a $3.9 million increase in other corporate activities due to the growth of ARP’s business. APL’s $80.0 million of general and administrative expense for the year ended December 31, 2014 represents a decrease of $0.9 million from the comparable prior year period, which was principally due to a decrease in salaries, wages, and other corporate activities.

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.

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”).

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):

Total depreciation, depletion and amortization increased to $444.6 million for the year ended December 31, 2014 compared with $308.5 million for the comparable prior year period, which was primarily due to an $98.8 million increase in our and ARP’s depletion expense resulting from the acquisitions consummated during 2014 and 2013 and a $33.9 million increase in APL’s depreciation expenses, primarily due to additional expense related to assets acquired in the TEAK Acquisition and APL’s expansion capital expenditures incurred subsequent to December 31, 2013. 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

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):

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Depletion expense was $231.6 million for the year ended December 31, 2014, an increase of $98.8 million compared with $132.9 million for the year ended December 31, 2013. Depletion expense of gas and oil properties as a percentage of gas and oil revenues remained consistent at 49% for the years ended December 31, 2014 and 2013. Depletion expense per Mcfe was $2.24 for the year ended December 31, 2014, an increase of $0.35 per Mcfe from $1.89 per Mcfe for the year ended December 31, 2013, which was primarily due to an increase in ARP’s depletion expense associated with its oil and natural gas liquids wells drilled between the periods. Depletion expense increased between periods principally due to an overall increase in production volume.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. 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, 2014 Compared with the Year Ended December 31, 2013. Asset impairment for the year ended December 31, 2014 was $580.7 million as compared with $38.0 million for the comparable prior year period. The $580.7 million of asset impairment primarily consisted of $562.6 million of oil and gas impairment primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. In addition, $18.1 million of asset impairment is due to ARP’s goodwill impairment. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. During the year ended December 31, 2013, we recognized $38.0 million of asset impairment related to impairments of gas and oil properties within property, plant and equipment, net on our consolidated balance sheet primarily for our shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. These impairments related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair values at December 31, 2014 and 2013 and our 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 commodity prices in comparison to their carrying values at December 31, 2014 and 2013.

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 amounts of these gas and oil properties being in excess of ARP’s estimates of their fair values at December 31, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimates 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, 2014 Compared with the Year Ended December 31, 2013. During the year ended December 31, 2014 and 2013, gains on asset sales and disposal were $45.5 million and losses on asset sales and disposal were $2.5 million, respectively. ARP recognized losses on asset sales and disposal of $1.9 million and $1.0 million during year ended December 31, 2014 and 2013, respectively. The $1.9 million loss on asset sales and disposal for year ended December 31, 2014 was primarily related to the sale of producing wells in ARP’s Niobrara Shale in connection with the settlement of a third party farmout agreement and a $0.3 million loss on the involuntary conversion of the Mossy Oak compressor station. APL recognized gains of $47.4 million and losses of $1.5 million on asset sales and disposal for year ended December 31, 2014 and 2013, respectively. The $47.4 million gain on asset sales and disposal for year ended December 31, 2014 primarily related to its sale of WTLPG (see Recent Developments). APL’s $1.5 million loss on asset sales and disposal for year ended December 31, 2013 primarily related to its decision to not pursue a project to construct pipelines in an area where acquired rights of way had expired.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. During the year ended December 31, 2013 and 2012, loss on asset sales and disposals were $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.

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

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total interest expense increased to $173.4 million for the year ended December 31, 2014 as compared with $132.6 million for the year ended December 31, 2013. This $40.8 million increase was due to our $9.5 million increase, a $27.8 million increase related to ARP and a $3.5 million increase related to APL. The $9.5 million increase in our interest expense consisted of a $10.0 million increase associated with our term loan facility, including a $0.9 million increase in the amortization of deferred financing costs, partially offset by a $0.5 million decrease associated with our credit facility. The $27.8 million increase in ARP’s interest expense consisted of a $20.7 million increase associated with interest expense on ARP’s senior notes, a $6.4 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility, a $0.2 million increase in the amortization of ARP’s 7.75% and 9.25% Senior Notes’ discounts, and interest that was capitalized on ARP’s ongoing capital projects, partially offset by a $0.4 million decrease associated with amortization of ARP’s deferred financing costs and a $0.3 million decrease in ARP’s commitment fees. The increase in interest expense related to ARP’s Senior Notes is primarily due to the issuance of an additional $100.0 million of ARP’s 7.75% Senior notes due 2021 in June 2014 and an additional $75.0 million of ARP’s 9.25% Senior Notes due 2021 in October 2014, as well as a full year of interest expense related to the $275.0 million ARP 7.75% Senior Notes issued in January 2013 and $250.0 million of ARP’s 9.25% Senior Notes issued in July 2013. The $3.5 million increase in interest expense for APL was primarily due to $6.9 million in additional interest related to its 4.75% APL Senior Notes, $4.2 million of additional interest related to its 5.875% APL Senior Notes and $2.0 million increased interest on APL’s revolving credit facility; partially offset by $4.2 million in reduced interest expense on the 8.75% APL Senior Notes and a $5.1 million increase in capitalized interest expense. The increase in the interest on the 4.75% APL Senior Notes and the 5.875% APL Senior Notes is due to their issuance during 2013. The decrease in the interest for the 8.75% APL Senior Notes is due to their redemption in February 2013. The increase in the interest on APL’s revolving credit facility is due to increased borrowings compared to the prior year. The increase in capitalized interest is due to increased capital expenditures over the same period last year.

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, 2014 Compared With the Year Ended December 31, 2013. There was no loss on early extinguishment of debt for the year ended December 31, 2014. 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”).

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, 2014 Compared with the Year Ended December 31, 2013. Loss attributable to non-controlling interests was $273.1 million for the year ended December 31, 2014 as compared with a loss of $153.2 million for the comparable prior year period. Loss (income) attributable to non-controlling interests includes an allocation of APL’s, ARP’s and Development Subsidiary’s net income (loss) to non-controlling interest holders. The increase in loss attributable to non-controlling interests between the year ended December 31, 2014 and the prior year comparable period was primarily due to the increase in ARP’s net loss during the year ended December 31, 2014, partially offset by an increase in APL’s net earnings between periods and a decrease in our ownership interests in ARP and APL between the periods.

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.

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP and APL, and 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 revolving 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:

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:

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, 2014 Compared with the Year Ended December 31, 2013

Net cash provided by operating activities of $154.8 million for the year ended December 31, 2014 represented a favorable movement of 117.2 million from net cash used in operating activities of $37.6 million for the comparable prior year period. The $117.2 million favorable movement was derived principally from a $355.6 million favorable movement in net loss excluding non-cash items, partially offset by a $132.3 million unfavorable movement in working capital and a $106.1 million increase in distributions paid to non-controlling interests. The non-cash charges which impacted net loss primarily included a $498.8 million increase in asset impairment, an increase of $136.1 million of depreciation, depletion and amortization, an increase of $22.3 million in compensation expense, a favorable movement of $9.3 million in equity and distributions related to unconsolidated subsidiaries and an $0.6 million increase in amortization of deferred financing costs, partially offset by an increase of $236.8 million in net loss, an unfavorable movement $48.0 million in (gain) loss on asset sales and disposal, a decrease of $26.6 million in loss on early extinguishment of debt and an increase of $0.1 million in deferred income tax benefit. 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 $156.2 million unfavorable movement in accounts receivable, prepaid expenses and other, partially offset by a $23.9 million favorable movement in accounts payable and accrued liabilities. The $156.2 million unfavorable movement in accounts receivable, prepaid expenses and other was primarily due to an increase in net derivative assets during 2014. The $23.9 million favorable movement in accounts payable and accrued liabilities was primarily due to the timing of ARP’s and APL’s respective capital programs and the growth of ARP’s business during the year ended December 31, 2014.

Net cash used in investing activities of $1,488.9 million for the year ended December 31, 2014 represented a favorable movement of $1,007.7 million from net cash used in investing activities of $2,496.6 million for the comparable prior year period. This favorable movement was principally due to a $1,015.2 million decrease in net cash paid for acquisitions, an increase of $132.7 million in net proceeds from asset sales pertaining to APL’s sale of its 20% interest in WTLPG (see “Recent Developments”), a $9.8 million favorable movement in other assets, and a favorable movement of $5.3 million in APL’s investment in joint ventures, partially offset by a $155.3 million increase in capital expenditures. See further discussion of capital expenditures under “Capital Requirements”.

Net cash provided by financing activities of $1,393.8 million for the year ended December 31, 2014 represented an unfavorable movement of $1,051.9 million from net cash provided by financing activities of $2,445.7 million for the comparable prior year period. This unfavorable movement was principally due to a $1,367.9 million decrease in net proceeds from the issuance of ARP’s and APL’s long-term debt, a $423.2 million decrease in net proceeds from ARP’s and APL’s equity offerings, an increase of $22.4 million in distributions paid to our limited partners and a decrease of $5.3 million in contributions from APL’s non-controlling interest, partially offset by a decrease of $365.8 million in repayments of APL’s long-term debt, an increase of $190.0 million in our and our subsidiaries’ borrowings under the respective revolving credit facilities, a decrease of $160.6 million in repayments of our and our subsidiaries’ revolving credit facilities, a decrease of $25.6 million in payments of premium on the retirement of APL’s long-term debt and a favorable movement of $24.9 million in deferred financing costs, distribution equivalent rights and other. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities, 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.

The deferred portion of the purchase price related to the Eagle Ford Acquisition (see “Recent Developments”) represented a non-cash transaction during the year ended December 31, 2014. APL’s Class D Preferred Unit distributions paid in kind represented non-cash transactions during the year ended December 31, 2014.

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, partially offset by an $82.2 million favorable movement in net income (loss) excluding non-cash items and an $8.0 million favorable movement in working capital. 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 $27.3 million favorable movement in accounts receivable, prepaid expenses and other, partially offset by 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 $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.

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

ARP’s July 2012 acquisition of Titan in exchange for 3.8 million common units and 3.8 million convertible Class B preferred units (which had an estimated collective value of $193.2 million, based upon the closing price of our publicly traded units as of the acquisition date) represented a non-cash transaction during the year ended December 31, 2012.

At December 31, 2014, 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:

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:

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

Atlas Energy. During the years ended December 31, 2014 and 2013, our total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs of our Development Subsidiary.

Atlas Resource Partners. During the year ended December 31, 2014, ARP’s $212.6 million of total capital expenditures consisted primarily of $82.2 million for wells drilled exclusively for ARP’s own account compared with $110.8 million for the comparable prior year period, $72.4 million of investments in our Drilling Partnerships compared with $92.3 million for the prior year comparable period, $25.5 million of leasehold acquisition costs compared with $20.9 million for the prior year comparable period and $32.5 million of corporate and other costs compared with $39.5 million for the prior year comparable period, which primarily related to a decrease in gathering and processing costs.

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.

Atlas Pipeline Partners. APL’s capital expenditures increased to $647.7 million for the year ended December 31, 2014 compared with $450.6 million for the comparable prior year period. The increase was primarily due to construction costs for the Stonewall plant within SouthOK, which was placed in service in May 2014 (see “Recent Developments”); the Silver Oak II plant within SouthTX placed in service in June 2014 (see “Recent Developments”); the Edward plant within WestTX placed in service in September 2014 (see “Recent Developments”); and the construction of the Velma to Arkoma connection within SouthOK, which was completed in December 2014.

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.

We, ARP and APL continuously evaluate acquisitions of gas and oil assets. In order to make any acquisitions in the future, we, ARP and APL believe we 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, ARP or APL will be successful in our and its efforts to obtain outside capital.

As of December 31, 2014, we and our subsidiaries are committed to expending approximately $198.0 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

As of December 31, 2014, our off-balance sheet arrangements were limited to ARP’s letters of credit outstanding of $4.4 million, APL’s letters of credit outstanding of $4.2 million, commitments to spend $198.0 million related to capital expenditures and APL’s surety bonds which its maximum liability is $10.7 million. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where APL operates, (ii) surety, and (iii) counterparty support.

ARP and APL have certain long-term unconditional purchase obligations and commitments, primarily throughput contracts (see “Contractual Obligations and Commercial Commitments”).

ARP is the managing general partner of the Drilling Partnerships and have agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and it may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that ARP does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of December 31, 2014, ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

In connection with the Eagle Ford Acquisition (see “Recent Developments”), ARP guaranteed the Development Subsidiary’s deferred purchase obligation, whereby ARP provided a guaranty of timely payment of the deferred portion of the purchase price that is to be paid by the Development Subsidiary. Pursuant to the agreement between ARP and the Development Subsidiary, ARP will have the right to receive some or all of the assets acquired by the Development Subsidiary in the event of its failure to contribute its portion of any deferred payments.

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:

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 cash distribution payment practice to a monthly cash distribution program. Monthly cash distributions are 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 and D 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 per quarter and the distribution payable to common unitholders and with respect to ARP’s Class D Preferred Unit, an amount equal to its fixed quarterly distribution; 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 per quarter 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 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.

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.

The Class D APL Preferred Units received distributions of additional Class D APL Preferred Units in each of the full quarterly periods following their issuance in May 2013. On January 22, 2015, APL exercised its right to convert all outstanding Class D APL Preferred Units into common limited partner units.

APL makes cumulative cash distributions on the Class E APL Preferred Units. The cash distributions are payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, when, and if, declared by APL’s board of directors. The initial distribution on the Class E APL Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million, representing the distribution for the period March 17, 2014 through July 14, 2014. Thereafter, APL pays cumulative distributions in cash on the Class E APL Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year.

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”). At December 31, 2014, $237.0 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 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 us. We are 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.

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 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. At December 31, 2014, 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 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. 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.

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, 2014, 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.

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 the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility).

The credit facility is subject to an intercreditor agreement as described above under the “Term Loan Facility”.

At December 31, 2014, we have not guaranteed any of ARP’s or APL’s debt obligations.

On February 23, 2015, ARP entered into a Sixth Amendment to the Second Amended and Restated Credit Agreement and a Second Lien Credit Agreement (see “Subsequent Events”). On November 24, 2014, ARP entered into a Fifth Amendment to the Second Amended and Restated Credit Agreement with Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto, among ARP as borrower, the 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 with a current borrowing base of $900.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018.

The Fifth Amendment was entered into in connection with the previously announced restructuring of ARP’s general partner and the sale of the general partner’s parent, ATLS and its midstream assets (collectively, the “Transaction”) (see

“Merger with Targa Resources Corp.”). Among other things, the Fifth Amendment amended several definitions for the purpose of ensuring that the Transaction did not result in a Change of Control or Event of Default determination under the ARP Credit Agreement (each as defined in the ARP Credit Agreement).

ARP’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At December 31, 2014, $696.0 million was outstanding under ARP’s credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.4 million was outstanding at December 31, 2014. ARP’s obligations under the facility are secured by mortgages on our oil and gas properties and first priority security interests in substantially all of our assets. Additionally, obligations under ARP’s facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP’s are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% 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 0.50% 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 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more 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 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, 2014. The ARP Credit Agreement also requires ARP to maintain a ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the 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 on June 30, 2014, September 30, 2014 and December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ending March 31, 2015, 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.

At December 31, 2014, APL had an $800.0 million senior secured revolving credit facility with a syndicate of banks, which matures in August 2019, of which $385.0 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) the LIBOR rate plus 1.0%, or (ii) the LIBOR rate for the applicable period, in each case plus the applicable margin. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $4.2 million was outstanding at December 31, 2014. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet at December 31, 2014. We have not guaranteed any of the obligations under APL’s senior secured revolving credit facility.

On August 28, 2014, APL entered into a Second Amended and Restated Credit Agreement which, among other changes, extended the maturity date, increased the revolving credit commitment and incremental revolving credit amount, and reduced the applicable margin used to determine interest rates by 0.25% (see “Recent Developments”).

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, West TX and Centrahoma joint ventures and their respective subsidiaries; and (ii) the guarantee of each of APL’s consolidated subsidiaries other than the joint venture companies. APL’s revolving credit facility contains customary covenants, including covenants to maintain specified financial ratios, restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its revolving 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. At December 31, 2014, APL was in compliance with these covenants.

At December 31, 2014, 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.

At December 31, 2014, ARP had $374.5 million outstanding of its 7.75% ARP Senior Notes, including $100.0 million of such notes issued in a private placement transaction on June 2, 2014 at an offering price of 99.5% of par value, yielding net proceeds of approximately $97.4 million. The net proceeds were used to partially fund the Rangely Acquisition (see “Recent Developments”). The 7.75% ARP Senior Notes were presented net of a $0.5 million unamortized discount as of December 31, 2014. ARP issued $275.0 million of its 7.75% ARP Senior Notes in a private placement transaction at par on January 23, 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 for 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.

At December 31, 2014, ARP had $323.9 million outstanding of its 9.25% ARP Senior Notes, including $75.0 million of such notes issued in a private placement transaction on October 14, 2014 at an offering price of 100.5% of par value, which yielded net proceeds of approximately $73.6 million. The 9.25% ARP Senior Notes issued in October 2014 were presented net of a $0.4 million unamortized premium as of December 31, 2014. ARP used the net proceeds from this offering to fund a portion of our Eagle Ford Acquisition (see “Recent Developments”). The 9.25% ARP Senior Notes issued in July 2013 were presented net of a $1.5 million unamortized discount as of December 31, 2014. Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. At any time on or after August 15, 2017, ARP may redeem some or all of its 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 its 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 its 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 its 9.25% ARP Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. Under certain conditions, including if we sell 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 its 9.25% ARP Senior Notes.

In connection with the issuance of the $75.0 million of 9.25% ARP Senior Notes on October 14, 2014, ARP entered into a registration rights agreement whereby ARP agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated not later than 270 days after the issuance of the 9.25% ARP Senior Notes. 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, ARP

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.

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

The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants, including limitations of our 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, 2014.

At December 31, 2014, APL had $500.0 million principal outstanding of 6.625% APL Senior Notes, $650.0 million principal outstanding of 5.875% APL Senior Notes, and $400.0 million principal outstanding of 4.75% APL Senior Notes (together with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”).

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 APL’s obligations under its revolving credit facility.

Indentures governing the APL Senior Notes contain covenants, including limitations of 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, 2014.

On January 15, 2015, TRP announced tender offers to redeem any and all of the outstanding APL Senior Notes in connection with, and conditioned upon, the consummation of the APL Merger. The APL Merger, however, is not conditioned on the consummation of the tender offers (see “Subsequent Events”).

On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding 8.75% APL Senior Notes and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% 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 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.

On September 28, 2012, APL issued $325.0 million of the 6.625% APL Senior Notes in a private placement transaction, at par. APL received net proceeds of $318.9 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on its revolving credit facility.

On December 20, 2012, APL issued $175.0 million of the 6.625% APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes were issued at a premium of 103.0% of the principal amount for a yield of 6.0%. APL received net proceeds of $176.1 million after underwriting commissions and other transaction costs and utilized the proceeds to partially finance the Cardinal Acquisition. Of the $176.1 million net proceeds, $176.5 million were received

during the year ended December 31, 2012, while additional expenses of $0.4 million were incurred during the year ended December 31, 2013.

The 6.625% APL Senior Notes are presented combined with a net $3.9 million unamortized premium as of December 31, 2014. 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 due on October 1, 2020 and are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

On February 11, 2013, APL issued $650.0 million of the 5.875% APL Senior Notes in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million and utilized the proceeds to redeem the 8.75% APL Senior Notes and repay a portion of the outstanding indebtedness under the 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 due on August 1, 2023 and are redeemable at any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

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. 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.

The following tables summarize our, ARP’s and APL’s contractual obligations at December 31, 2014 (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	$	237,000	$	1,800	$	5,400	$	229,800	$	—
ARP total debt		1,396,000		—		—		696,000		700,000
APL total debt		1,935,000		—		—		385,000		1,550,000
ATLS interest on total debt		72,732		15,347		30,225		27,160		—
Eagle Ford deferred payment⁽¹⁾		105,000		105,000		—		—		—
ARP interest on total debt		446,952		79,279		158,559		129,989		79,125
APL interest on total debt		696,783		100,537		201,074		197,666		197,506
ARP operating leases		17,545		3,903		6,397		4,152		3,093
APL operating leases		31,792		12,621		13,736		5,113		322
APL capital leases		229		224		5		—		—
Total contractual cash obligations⁽²⁾	$	4,939,033	$	318,711	$	415,396	$	1,674,880	$	2,530,046

We recognize gains on our subsidiaries’ 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 our subsidiaries’ common units over the book carrying amount per unit.

In July 2013, in connection with the closing of ARP’s EP Energy Acquisition, 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.

In October 2014, in connection with the Eagle Ford Acquisition (see “Recent Developments”), ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per Class D Preferred Unit, yielding net proceeds of approximately $77.4 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

The Class D ARP Preferred Units rank senior to ARP’s common units and Class C convertible preferred units with respect to the payment of distributions and distributions upon a liquidation event and equal with ARP’s Class B convertible preferred units. The Class D ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019, ARP may, at its option, redeem the Class D ARP Units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem the Class D ARP Preferred Units following certain changes of control, as described in the Certificate of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of the Class D ARP Preferred Units will have the option to convert the Class D ARP Preferred Units into a number of ARP common units per Class D unit as set

forth in the Certificate of Designation. If ARP exercises any of its redemption rights relating to the Class D ARP Preferred Units, the holders of such Class D ARP Preferred Units will not have the conversion right described above with respect to the Class D ARP Preferred Units called for redemption.

In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may 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 New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent. As of December 31, 2014, no units have been sold under this program.

In May 2014, in connection with the closing of the Rangely Acquisition (see “Recent Developments”), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

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.

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, 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. 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 the equity distribution agreement effective December 27, 2013.

For the years ended December 31, 2014 and 2013, in connection with the issuance of ARP’s common units, we recorded gains of $40.5 million and $27.3 million, respectively, within partners’ capital and a corresponding decrease in non-controlling interests on our consolidated balance sheet and consolidated statement of partners’ capital.

On May 12, 2014, APL entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup Global Markets Inc. (“Citigroup”), Wells Fargo Securities, LLC and MLV & Co. LLC, as sales agents. Pursuant to the 2014 EDA, APL may offer and sell from time to time through the sales agents, common units having an aggregate value up to $250.0 million. Sales are at market prices prevailing at the time of the sale. However, APL is currently restricted from selling common units by the APL Merger Agreement.

In November 2012, ARP entered into an Equity Distribution Agreement (the “2012 EDA” and together, with the 2014 EDA, the “EDAs”) with Citigroup. Pursuant to this program, APL offered and sold through Citigroup, as its sales agent, common units for $150.0 million. APL used the full capacity under the 2012 EDA during the year ended 2013.

During the years ended December 31, 2014 and 2013, APL issued 3,558,005 and 3,895,679 common units, respectively, under the EDAs for proceeds of $121.6 million and $137.8 million, respectively, net of $1.2 million and $2.8 million, respectively, in commissions paid to the sales agents. APL also received capital contributions from the us as general partner of $2.5 million and $2.9 million, respectively, during the years ended December 31, 2014 and 2013, to maintain our 2.0% general partner interest in APL. The net proceeds from the common unit offerings and our general partner contributions were utilized for general partnership purposes. As of December 31, 2014, APL had $127.0 million remaining capacity under the 2014 EDA.

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. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition.

On May 7, 2013 APL completed the private placement of $400.0 million of its Class D APL Preferred Units to third party investors, at a negotiated price per unit of $29.75 for net proceeds of $397.7 million. The Class D APL Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. APL also received a capital contribution from us as general partner of $8.2 million to maintain our 2.0% general partner interest in APL. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition.

On January 22, 2015, APL exercised its right under the certificate of designation of the Class D APL Preferred Units to convert all outstanding Class D APL Preferred Units, plus any unpaid distributions, into common limited partner units. As a result of the conversion, 15,389,575 common limited partner units were issued.

On March 17, 2014, APL issued 5,060,000 of its Class E APL Preferred Units to the public at an offering price of $25.00 per Class E APL Preferred Unit. The Class E APL Preferred Units are listed on the New York Stock Exchange under the symbol “APLPE”. APL received $122.3 million in net proceeds, which were used to pay down the revolving credit facility. APL will make cumulative cash distributions on the Class E APL Preferred Units from the date of original issue. The cash distributions will be payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, when, and if, declared by APL’s board of directors. The initial distribution on the Class E APL Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million. Thereafter, APL will pay cumulative distributions in cash on the Class E APL Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year.

On January 15, 2015, APL paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on its Class E APL Preferred Units, representing the cash distribution for the period October 15, 2014 through January 14, 2015.

On January 27, 2015, APL delivered notice of its intention to redeem all outstanding shares of its Class E APL Preferred Units. The redemption of the Class E APL Preferred Units will occur immediately prior to the close of the APL Merger. APL expects the APL Merger to close on February 27, 2015 and, accordingly, the redemption date would also be on February 27, 2015. The Class E APL Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E APL Preferred Units as of the redemption date.

For the year ended December 31, 2014, in connection with the issuance of APL’s common units, we recorded a $2.7 million gain within partner’s capital and a corresponding decrease in non-controlling interests on our consolidated balance sheet and consolidated statement of partners’ capital. At December 31, 2013, in connection with the issuance of APL’s common units, we recorded an $11.9 million gain within partners’ capital and a corresponding decrease in non-controlling interests on our consolidated balance sheet and consolidated statement of partners’ capital.

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.

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.

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”, recent increases in natural gas and oil drilling have driven an increase in the supply of natural gas and oil 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, 2014, the Partnership recognized $562.6 million of asset impairments related to oil and gas properties primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. 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, we 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. These impairments related to the carrying amount of these gas and oil properties being in excess of our Development Subsidiary’s and ARP’s estimates of their fair values at December 31, 2014, 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 commodity 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.

During the year ended December 31, 2014, ARP recorded an $18.1 million goodwill non-cash impairment loss within asset impairment on our consolidated statement of operations related to an impairment of goodwill in its gas and oil production reporting unit due to a decline in overall commodity prices. There were no goodwill impairments recognized by ARP during the year ended December 31, 2013 and 2012. 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, 2014 and 2012.

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 and our rabbi trust assets. 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. Investments held in our rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 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 $400.3 million and $14.9 million of net derivative assets at December 31, 2014 and 2013, respectively, APL had net derivative assets of $66.0 million and net derivative liabilities of $11.8 million at December 31, 2014 and 2013, 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, 2014 would have resulted in a $6.5 million non-cash change, net of non-controlling interests, to net loss for the year ended December 31, 2014.

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 years ended December 31, 2014, 2013 and 2012, we and our subsidiaries completed several acquisitions of oil and gas properties and related assets. 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.

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 independent third-party reserve engineers, to prepare reports of our and ARP’s proved reserves (see “Item 2: Properties”).

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.

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.

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, 2014 and December 31, 2013 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

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.

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, 2014. 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, 2014, we had $237.0 million of outstanding borrowings under our term loan facility, ARP had $696.0 million of outstanding borrowings under its revolving credit facility and APL had $385.0 million of outstanding borrowings under its senior secured revolving credit facility. At December 31, 2014, 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, 2015 by $13.2 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, 2015 of approximately $4.9 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.

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

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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, 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 27, 2015 expressed an unqualified opinion.

	December 31,
ASSETS	2014		2013
Current assets:
Cash and cash equivalents	$	83,210	$	23,501
Accounts receivable		355,817		279,464
Current portion of derivative asset		232,266		2,066
Subscriptions receivable		32,398		47,692
Prepaid expenses and other		44,196		27,612
Total current assets		747,887		380,335
Property, plant and equipment, net		5,669,262		4,910,875
Intangible assets, net		596,952		697,234
Investment in joint ventures		177,212		248,301
Goodwill		379,402		400,356
Long-term derivative asset		168,000		30,868
Other assets, net		127,921		124,672
	$	7,866,636	$	6,792,641
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	2,624	$	2,924
Accounts payable		210,746		149,279
Liabilities associated with drilling contracts		40,611		49,377
Accrued producer liabilities		161,208		152,309
Current portion of derivative liability		—		17,630
Accrued interest		53,419		47,402
Accrued well drilling and completion costs		92,910		40,899
Accrued liabilities		224,251		87,435
Total current liabilities		785,769		547,255
Long-term debt, less current portion		3,567,946		2,886,120
Deferred income taxes, net		30,914		33,290
Asset retirement obligations		108,101		91,214
Other long-term liabilities		13,161		11,886
Commitments and contingencies
Partners’ Capital:
Common limited partners’ interests		154,273		361,511
Accumulated other comprehensive income		54,008		10,338
		208,281		371,849
Non-controlling interests		3,152,464		2,851,027
Total partners’ capital		3,360,745		3,222,876
	$	7,866,636	$	6,792,641

	Years Ended December 31,
	2014			2013			2012
Revenues:
Gas and oil production	$	475,758		$	273,906		$	92,901
Well construction and completion		173,564			167,883			131,496
Gathering and processing		2,836,322			2,139,694			1,219,815
Administration and oversight		15,564			12,277			11,810
Well services		24,959			19,492			20,041
Gain (loss) on mark-to-market derivatives		133,883			(28,764	)		31,940
Other, net		8,653			(6,973	)		13,440
Total revenues		3,668,703			2,577,515			1,521,443
Costs and expenses:
Gas and oil production		184,296			100,178			26,624
Well construction and completion		150,925			145,985			114,079
Gathering and processing		2,420,759			1,802,618			1,009,100
Well services		10,007			9,515			9,280
General and administrative		217,371			197,976			165,777
Chevron transaction expense		—			—			7,670
Depreciation, depletion and amortization		444,622			308,533			142,611
Asset impairment		580,654			81,880			9,507
Total costs and expenses		4,008,634			2,646,685			1,484,648

Operating income (loss)		(339,931	)		(69,170	)		36,795
Gain (loss) on asset sales and disposal		45,522			(2,506	)		(6,980	)
Interest expense		(173,357	)		(132,581	)		(46,520	)
Loss on early extinguishment of debt		—			(26,601	)		—
Net loss before tax		(467,766	)		(230,858	)		(16,705	)
Income tax (benefit) expense		(2,376	)		(2,260	)		176
Net loss		(465,390	)		(228,598	)		(16,881	)
Loss (income) attributable to non-controlling interests		273,132			153,231			(35,532	)
Net loss attributable to common limited partners	$	(192,258	)	$	(75,367	)	$	(52,413	)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$	(3.71	)	$	(1.47	)	$	(1.02	)
Weighted average common limited partner units outstanding:
Basic and Diluted		51,810			51,387			51,327


	Common Limited Partners’ Capital					Accumulated Other Comprehensive			Non-Controlling			Total Partners’
	Units		Amount			Income			Interest			Capital
Balance at January 1, 2012		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	)
Net issued and unissued units under incentive plans		87,220		17,837			—			21,651			39,488
Non-controlling interests’ capital contribution		—		—			—			804,768			804,768
Atlas Pipeline Partners L.P. purchase price allocation		—		—			—			89,440			89,440
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
Net issued and unissued units under incentive plans		47,982		22,532			—			31,773			54,305
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
Distributions to non-controlling interests		—		—			—			(345,681	)		(345,681	)
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests		—		—			—			11,720			11,720
Net issued and unissued units under incentive plans		548,737		42,739			—			30,186			72,925
Distributions paid to common limited partners		—		(99,996	)		—			—			(99,996	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(5,431	)		—			(6,408	)		(11,839	)
Distributions payable		—		—			—			(17,249	)		(17,249	)
Gain on sale of subsidiary unit issuances		—		47,708			—			(47,708	)		—
Non-controlling interests’ capital contributions		—		—			—			829,089			829,089
Other comprehensive income		—		—			43,670			120,620			164,290
Net loss		—		(192,258	)		—			(273,132	)		(465,390	)
Balance at December 31, 2014		51,962,301	$	154,273		$	54,008		$	3,152,464		$	3,360,745

			Years Ended December 31,
	2014				2013				2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(465,390		)	$	(228,598	)	$	(16,881	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		444,622				308,533			142,611
Asset impairment		580,654				81,880			9,507
Amortization of deferred financing costs		18,305				17,649			6,720
Non-cash compensation expense		77,354				55,008			40,300
(Gain) loss on asset sales and disposal		(45,522		)		2,506			6,980
Deferred income tax (benefit) expense		(2,376		)		(2,260	)		176
Loss on early extinguishment of debt		—				26,601			—
Distributions paid to non-controlling interests		(352,089		)		(246,013	)		(123,171	)
Equity (income) loss in unconsolidated companies		12,871				2,142			(7,863	)
Distributions received from unconsolidated companies		6,959				8,422			8,131
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(214,203		)		(58,035	)		(85,308	)
Accounts payable and accrued liabilities		93,617				69,773			89,074
Net cash provided by operating activities		154,802				37,608			70,276
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(873,383		)		(718,040	)		(500,759	)
Net cash paid for acquisitions		(741,522		)		(1,756,744	)		(1,150,150	)
Net proceeds from asset sales and disposal		133,946				1,236			—
Investment in joint ventures		(8,061		)		(13,366	)		—
Other		127				(9,693	)		404
Net cash used in investing activities		(1,488,893		)		(2,496,607	)		(1,650,505	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		2,664,000				2,474,000			1,846,599
Repayments under credit facilities		(2,156,400		)		(2,317,025	)		(1,335,174	)
Net proceeds from issuance of subsidiary long-term debt		170,596				1,538,488			495,374
Repayments of subsidiary long-term debt		—				(365,822	)		—
Net proceeds from subsidiary equity offerings		829,089				1,252,307			611,606
Distributions paid to unitholders		(99,996		)		(77,598	)		(51,837	)
Contributions from non-controlling interests		11,720				17,021			—
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt		—				(25,581	)		—
Deferred financing costs, distribution equivalent rights and other		(25,209		)		(50,070	)		(26,935	)
Net cash provided by financing activities		1,393,800				2,445,720			1,539,633
Net change in cash and cash equivalents		59,709				(13,279	)		(40,596	)
Cash and cash equivalents, beginning of year		23,501				36,780			77,376
Cash and cash equivalents, end of year	$	83,210			$	23,501		$	36,780

Atlas Energy, L.P., (the “Partnership” or “Atlas Energy”) is a publicly-traded Delaware master limited partnership (NYSE: ATLS). At December 31, 2014, the Partnership’s operations primarily consisted of its ownership interests in the following:

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.

The consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries, all of which are wholly-owned at December 31, 2014, except for ARP, APL and 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 years’ consolidated financial statements have been reclassified to conform to the current year presentation.

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.

In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million ARP common units and 3.8 million newly-created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). 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 December 23, 2014, 3,796,900 of Class B ARP preferred units were voluntarily converted into common units. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 4), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay a future quarterly distribution at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In March 2014, APL issued 5.1 million of its Class E cumulative redeemable perpetual preferred units (“Class E APL Preferred Units”). The initial distribution on the Class E APL Preferred Units was $0.67604 per unit, representing the distribution for the period March 17, 2014 through July 14, 2014. Subsequent to July 14, 2014, APL paid a quarterly distribution of $0.515625 per unit. In May 2013, APL issued Class D convertible preferred units (“Class D APL Preferred Units”), which received distributions of additional Class D APL Preferred Units for the first four full quarterly periods following their issuance in May 2013, and thereafter will receive distributions in Class D APL Preferred Units, or a combination of Class D APL Preferred Units and cash (see Note 15). At December 31, 2014 and 2013, $738.7 million and $547.3 million, respectively, related to ARP’s and APL’s preferred units is included within non-controlling interests on the Partnership’s consolidated statements of partners’ capital.

The Partnership’s consolidated financial statements include APL’s 95% ownership interest in certain 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”). 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).

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.

During the year ended December 31, 2014, the Development Subsidiary issued $81.7 million of its common limited partner units, which was included within non-controlling interests in partners’ capital on the Partnership’s consolidated balance sheet. During the year ended December 31, 2014, the Development Subsidiary paid $1.4 million to unitholders, which was included within distributions paid to non-controlling interests on the Partnership’s consolidated statement of cash flows. For the year ended December 31, 2014, in connection with the issuance of the Development Subsidiary’s common units, the Partnership recorded gains of $4.5 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated statement of partners’ capital (see Note 15).

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. Actual results could differ from those estimates.

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.

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 their customers. At December 31, 2014 and 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

The Partnership had $23.7 million and $19.7 million of inventory at December 31, 2014 and 2013, 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.

The Partnership receives contributions from limited partner investors of its Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker-dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which is then delivered to Anthem. The investor contributions are then remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. ARP recognizes the contributions associated with the executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable.

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.

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.

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.

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 by ARP for the year ended December 31, 2014 and 2012.

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, 2014, the Partnership recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. 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, ARP recognized $9.5 million of asset impairments related to 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.

These impairments related to the carrying amounts of these gas and oil properties being in excess of the Development Subsidiary’s and ARP’s estimates of their fair values at December 31, 2014, 2013, and 2012 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 commodity prices at the date of measurement.

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 were 5.6%, 5.9% and 5.8% for the years ended December 31, 2014, 2013 and 2012, respectively. The aggregate amounts of interest capitalized by ARP and APL were $25.7 million, $21.7 million and $10.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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 acquisitions of assets from TEAK Midstream, LLC (“TEAK”) in 2013 (the “TEAK Acquisition”) (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 TEAK Acquisition, APL recognized $450.0 million of customer relationships with an estimated useful life of 13 years.

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, 2014 and 2013 (in thousands):

Amortization expense on intangible assets was $80.3 million, $69.3 million and $24.0 million for the years ended December 31, 2014, 2013 and 2012 respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $74.3 million; 2016 - $74.2 million; 2017 - $68.1 million; 2018 - $59.6 million; and 2019 - $59.6 million.

The following table reflects the carrying amounts of goodwill by reportable operating segments at December 31, 2014 and December 31, 2013 (in thousands):

At December 31, 2014, the Partnership had $379.4 million of goodwill, which consisted of $13.6 million related to acquisitions previously consummated by ARP and $365.8 million related to acquisitions previously consummated by APL. The change in ARP’s goodwill during the year end December 31, 2014 is related to goodwill impairment related to its gas and oil production reporting unit as a result of a decline in commodity prices. The change in APL’s goodwill during the year ended December 31, 2014 is primarily related to a $2.8 million decrease in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (see Note 4).

ARP and APL test goodwill for impairment at each year end by comparing their respective reporting unit estimated fair values to carrying values, with the exception of APL’s SouthTX reporting unit which is tested as of April 30, 2014. 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.

As a result of its impairment evaluation at December 31, 2014, ARP recognized an $18.1 million goodwill impairment charge within asset impairments on the Partnership’s consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. During the years ended December 31, 2013 and 2012, no impairment indicators arose and no goodwill impairments were recognized for ARP by the Partnership.

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.

During the years ended December 31, 2014 and 2012, no impairment indicators arose and no goodwill impairments were recognized for APL by the Partnership.

The Partnership’s consolidated financial statements include APL’s previous interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) which was sold in May 2014 (see Note 5); and APL’s 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 Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (the “T2 Joint Ventures”), which were acquired as part of APL’s 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”) (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 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 equity investment on the Partnership’s consolidated balance sheet with an offsetting reduction to equity income on the Partnership’s consolidated statements of operations. Equity method investments are subject to impairment evaluation as necessary when events and circumstances indicate the carrying value of an equity investment may be less than its fair value. APL noted no indicators of impairment for its equity method investments, and thus no impairment charges were recognized for the years ended as of December 31, 2014, 2013 and 2012.

The Partnership’s consolidated financial statements also include its interest in Lightfoot which is accounted for under the equity method of accounting (see Note 7).

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).

The Partnership enters into certain financial contracts to manage its 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 a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met.

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, 2014 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

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 record 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, 2014, 2013 and 2012.

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 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014, except for an ongoing examination by the Texas Comptroller of Public Accounts related to APL’s Texas Franchise Tax for franchise report years 2008 through 2011.

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 in 2012, 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, 2014 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).

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).

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):

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):

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, 2014 and 2013. 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.

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 their temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2014 and 2013, the Partnership had $86.5 million and $51.4 million, respectively, in deposits at various banks, of which $81.6 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. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end.

The Partnership and its subsidiaries sell natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2014, ARP had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, 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, ARP had three customers within its gas and oil production segment 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 within its gas and oil production segment that individually accounted for approximately 43% and 11% of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.

For the year ended December 31, 2014, APL had three customers that individually accounted for approximately 26%, 13% and 11%, respectively, of its consolidated total third party 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%, respectively, of its consolidated total third party revenues, 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%, respectively, of its consolidated total third party revenues, excluding the impact of all financial derivative activity.

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”).

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, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%. ARP recognizes its Drilling Partnership management fees in the following manner:

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%.

Atlas Pipeline. APL’s revenue primarily consists of the sale of natural gas and NGLs, along with the fees earned from its gathering, processing and treating 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 and condensate, if any, off 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. Revenue related to fees for providing natural gas gathering, processing and treating services is recognized based on throughput volumes during the period, with throughput volumes generally measured at the wellhead. In connection with its gathering, processing and treating operations, APL enters into the following types of contractual relationships with its producers and shippers:

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.

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. During 2014, APL renegotiated most of its Keep-Whole contracts and converted them into POP contracts.

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

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 of $260.7 million and $191.8 million at December 31, 2014 and 2013, respectively, which were included in accounts receivable within its consolidated balance sheets. APL’s accrued purchase costs at December 31, 2014 and 2013 are included within accrued producer liabilities within the Partnership’s consolidated balance sheets.

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).

In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-17, Business Combinations (Topic 805) – Pushdown Accounting (“Update 2014-17”). The amendments in Update 2014-17 provide an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The amendments in Update 2014-17 also provide U.S. GAAP guidance on whether and at what threshold an acquired entity that is a business can apply pushdown accounting in its separate financial statements. The amendments in Update 2014-17 became effective on November 18, 2014. After the effective date, an acquired entity can make an election to apply the guidance to future change-in-control events or to its most recent change-in-control event. However, if the financial statements for the period in which the most recent change-in-control event occurred already have been issued or made available to be issued, the application of this guidance would be a change in accounting principle. The Partnership adopted the requirements of Update 2014-17 upon its effective date of November 18, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application was permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no 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 adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“Update 2015-02”). The amendments in Update 2015-02 are intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The amendments simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in Update 2015-02 are effective for periods beginning after December 31, 2015. Early adoption is permitted, including adoption in an interim period. The Partnership will adopt the

requirements of Update 2015-02 upon its effective date of January 1, 2016, and is evaluating the impact of adoption on its financial position, results of operations or related disclosures.

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Partnership will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2017, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Partnership will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

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 the former owner of its general partner, Atlas Energy, Inc. (“AEI”), including the following exploration and production assets that were transferred to ARP on March 5, 2012:

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.

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 values of the assets acquired and liabilities assumed by the Partnership, including the effect of cash transaction adjustments, as of February 17, 2011 (in thousands):

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.

On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $409.4 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 9) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 15). The Rangely Acquisition had an effective date of April 1, 2014. The Partnership’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing.

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 $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 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):

Revenues and net income of $41.5 million and $18.8 million, respectively, have been included in the Partnership’s consolidated statement of operations related to the Rangely Acquisition for the year ended December 31, 2014.

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 combined consolidated financial statements reflect the operating results of the acquired business commencing July 31, 2013 with the transaction closing.

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 Partnership’s combined 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 EP Energy Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

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).

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

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 combined 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 of Titan, based on their estimated fair values at the date of the acquisition (in thousands):

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 Atlas Energy. 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 combined 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 Carrizo Acquisition, based on their estimated fair values at the date of the acquisition (in thousands):

On May 7, 2013, APL completed the TEAK Acquisition for $974.7 million in cash, including final purchase price adjustments, less cash received. Through the TEAK Acquisition, APL acquired natural gas gathering and processing facilities in Texas, which included a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), and a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (collectively, the “T2 Joint Ventures”).

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

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 for the year ended December 31, 2013. 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.

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

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).

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):

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).

The following data presents pro forma revenues, net loss and basic and diluted net loss per unit for the Partnership as if the Rangely, EP Energy and TEAK acquisitions, including the related borrowings, net proceeds from the issuances of debt and issuances of common and preferred limited partner units had occurred on January 1, 2013. 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 Rangely, EP Energy and TEAK acquisitions and related offerings had occurred on January 1, 2013 or the results that will be attained in future periods (in thousands, except per share data; unaudited):

On November 5, 2014, ARP and the Development Subsidiary completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $339.2 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $179.5 million was paid in cash by ARP and $19.7 million was paid by the Development Subsidiary at closing, and approximately $140.0 million will be paid over the four quarters following closing. The deferred portion of the purchase price represents a non-cash transaction for statement of cash flow purposes during the year ended December 31, 2014. ARP will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. The Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing. ARP may pay up to $20.0 million of its deferred portion of the purchase price by issuing ARP’s 8.625% Class D cumulative redeemable perpetual preferred units (“Class D Preferred Units”) at a price of $25.00 per unit (see Note 13). In connection with the closing of the Eagle Ford Acquisition, ARP’s revolving credit facility was amended to increase the borrowing base to $900.0 million and to make certain amendments to allow for the deferred purchase payments (see Note 9). The Eagle Ford Acquisition had an effective date of July 1, 2014. The Partnership recorded $2.8 million of gains on mark-to-market derivatives in conjunction with the entering into derivative instruments upon signing the Eagle Ford Acquisition.

On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

On September 20, 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.

On July 31, 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 April 2012, ARP acquired a 50% interest in approximately 14,500 net undeveloped acres in the oil and NGL area of the Mississippi Lime play in northwestern Oklahoma for $18.0 million from subsidiaries of Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equal”). The transaction was funded through borrowings under ARP’s revolving credit facility. Concurrent with the purchase of acreage, ARP and Equal entered into a participation and development agreement for future drilling in the Mississippi Lime play. ARP served as the drilling and completion operator, while Equal undertook production operations, including water disposal. In September 2012, ARP acquired Equal’s remaining 50% interest in the undeveloped acres, as well as approximately 8 MMcfed of net production in the Mississippi Lime region and salt water disposal infrastructure for $41.3 million, including $1.3 million related to certain post-closing adjustments. Both transactions were financed 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.

On May 14, 2014, APL completed the sale of two subsidiaries, which held an aggregate 20% interest in WTLPG, to a subsidiary of Martin Midstream Partners LP (NYSE: MMLP). APL received $131.0 million in proceeds, net of selling costs and final working capital adjustments, which were used to pay down APL’s revolving credit facility (see Note 9). As a result of the sale, APL recorded a $47.8 million gain on asset dispositions, which is included in the Partnership’s consolidated statements of operations for the year ended December 31, 2014.

WTLPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. Prior to the sale of WTLPG, APL accounted for its subsidiaries’ ownership interest in WTLPG under the equity method of accounting, with recognition of income of WTLPG as equity income in joint ventures on RemainCo’s consolidated statements of operations.

On May 7, 2013, APL acquired the T2 Joint Ventures as part of the TEAK Acquisition (see Note 4). The T2 Joint Ventures are operated by a subsidiary of Southcross Holdings, L.P. (“Southcross”), the investor owning the remaining interests. The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners and have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures.

APL evaluated whether the T2 Joint Ventures should be subject to consolidation. The T2 Joint Ventures do meet the qualifications of a 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, it does not have controlling financial interests in these entities. Since APL shares equal management rights with Southcross and Southcross is the operator of the T2 Joint Ventures, APL determined that it is not the primary beneficiary of the VIEs and should not consolidate the T2 Joint Ventures. APL accounts for its investment in the T2 Joint Ventures under the equity method, since APL does not have a controlling financial interest, but does have a significant influence. APL’s maximum exposure to loss as a result of its involvement with the T2 Joint Ventures includes its equity investment, any additional capital contribution commitments and APL’s share of any approved operating expenses incurred by the VIEs.

The following tables present the values of APL’s equity method investments as of December 31, 2014 and 2013 and equity income (loss) in joint ventures for the years ended December 31, 2014 and 2013 (in thousands):

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

During year ended December 31, 2014, the Partnership and its subsidiaries recognized $45.5 million of gain on asset sales and disposal, primarily related to APL’s gain on the sale of WTLPG, partially offset by ARP’s loss on the sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement. 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.

During the year ended December 31, 2014, the Partnership recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on the Partnership’s consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. 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.

These impairments related to the carrying amounts of gas and oil properties being in excess of the Development Subsidiary’s and ARP’s estimates of their fair values at December 31, 2014, 2013 and 2012 and ARP’s intention not to drill on certain expiring unproved acreage. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the date of measurement.

During the years ended December 31, 2014 and 2013, the Partnership recognized $39.7 million and $8.7 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Partnership’s consolidated statements of cash flows.

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

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 $17.7 million, $14.4 million and $6.7 million for the years ended December 31, 2014, 2013 and 2012, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the year ended December 31, 2014, ARP recognized $0.6 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under its revolving credit facility. During the year ended December 31, 2013, ARP recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its 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 year ended December 31, 2012.

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% unsecured senior notes due 2018 (“8.75% APL Senior Notes”) to loss on early extinguishment of debt on the Partnership’s consolidated statement of operations (see Note 9). There was no accelerated amortization of deferred financing costs for APL during the years ended December 31, 2014 and 2012.

ARP notes receivable. At December 31, 2014 and 2013, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net 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 each of the years ended December 31, 2014 and 2013, $0.1 million, respectively, of interest income, was recognized within other, net on the Partnership’s consolidated statement of operations. There was no interest income recognized for the year ended December 31, 2012. At December 31, 2014 and 2013, ARP recorded no allowance for credit losses within the Partnership’s consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable.

Investment in Lightfoot. At December 31, 2014, the Partnership owned an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% 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, 2014, 2013 and 2012, the Partnership recognized equity income of approximately $1.1 million, $2.6 million and $1.5 million, respectively, within other, net on the Partnership’s consolidated statements of operations. During the years ended December 31, 2014, 2013 and 2012, the Partnership received net cash distributions of $1.7 million, $1.0 million and $0.9 million, respectively.

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”.

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 where a reasonable estimate of the fair value of that liability could 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, the 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.

ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At December 31, 2014, the Drilling Partnerships had $47.6 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. As of December 31, 2014, ARP has withheld approximately $1.6 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. 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):

The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations. During the years ended December 31, 2014 and 2013, the Partnership incurred $0.1 million and

$1.3 million, respectively, of future plugging and abandonment costs within purchase accounting related to the acquisition it consummated during the period. During the years ended December 31, 2014, 2013 and 2012, ARP incurred $7.0 million, $16.7 million and $15.6 million, respectively, of future plugging and abandonment liabilities within purchase accounting related to the acquisitions it consummated during the period. The Partnership did not incur any future plugging and abandonment costs related to acquisitions during the year ended December 31, 2012 (see Note 4).

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, 2014, $237.0 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, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility 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 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. At December 31, 2014, 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 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. 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.

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, 2014, 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 the required ratio of Total Funded Debt (as defined in the credit facility) to EBITDA (as defined in the credit facility). At December 31, 2014, 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 2.0 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, 2014, the Partnership has not guaranteed any of ARP’s or APL’s debt obligations.

On November 24, 2014, ARP entered into a Fifth Amendment to its Second Amended and Restated Credit Agreement dated July 31, 2013 with Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto, among ARP as borrower, the 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 with a current borrowing base of $900.0 million and a maximum facility amount of $1.5 billion scheduled to mature in July 2018.

The Fifth Amendment was entered into in connection with the previously announced restructuring of ARP’s general partner and the sale of ATLS and its midstream assets (see Note 19). Among other things, the Fifth Amendment amended several definitions for the purpose of ensuring that the sale does not result in a Change of Control or Event of Default as defined in the ARP Credit Agreement.

On September 24, 2014, in connection with its Eagle Ford Acquisition (see Note 4), ARP entered into a fourth amendment to the ARP Credit Agreement. In connection with the closing of the Eagle Ford Acquisition, the borrowing base under ARP’s revolving credit facility was increased from $825.0 million to $900.0 million. The fourth amendment amended the ARP Credit Agreement to permit the guarantee by ARP of certain deferred purchase price obligations and contingent indemnity obligations in connection with the Eagle Ford Acquisition, and, with certain constraints, to permit ARP and its subsidiaries to enter into certain derivative instruments related to the producing wells to be acquired in the Eagle Ford Acquisition.

On June 30, 2014, in connection with the Rangely Acquisition (see Note 4), ARP entered into a third amendment to the ARP Credit Agreement. Among other things, pursuant to the third amendment:

ARP’s borrowing base is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At December 31, 2014, $696.0 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 $4.4 million was outstanding at December 31, 2014. 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 1.50% 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 0.50% 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 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.9%.

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, 2014. 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 on June 30, 2014, September 30, 2014 and December 31, 2014, 4.25 to 1.0 as of the last day of the quarter ending March 31, 2015, 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. Based on the definitions contained in the ARP Credit Agreement, at December 31, 2014, ARP’s ratio of current assets to current liabilities was 1.2 to 1.0, and its ratio of Total Funded Debt to EBITDA was 3.6 to 1.0.

On February 23, 2015, ARP entered into a Sixth Amendment to the ARP Credit Agreement (the “Sixth Amendment”) and a Second Lien Credit Agreement (the “Second Lien Credit Agreement”) (see Note 19).

At December 31, 2014, ARP had $374.5 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”), including $100.0 million of such notes issued in a private placement transaction on June 2, 2014 at an offering price of 99.5% of par value, yielding net proceeds of approximately $97.4 million. The net proceeds were used to partially fund the Rangely Acquisition (see Note 4). The 7.75% ARP Senior Notes were presented net of a $0.5 million unamortized discount as of December 31, 2014. 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 for 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.

ARP entered into registration rights agreements with respect to its 7.75% ARP Senior Notes. Under the registration rights agreements, ARP agreed to (a) file exchange offer registration statements with the SEC to exchange the privately issued notes for registered notes, (b) cause the exchange offer for the $275.0 million of 7.75% ARP Senior Notes issued on January 23, 2013 to be consummated not later than 365 days after the issuance of such notes and (c) cause the exchange offer for the $100.0 million of 7.75% ARP Senior Notes issued on June 2, 2014 to be consummated not later than 270 days after the issuance of such notes. A registration statement relating to the exchange offer for the $275.0 million of 7.75% ARP

Senior Notes issued January 23, 2013 was declared effective on December 2, 2013, and the exchange offer for such notes was completed on January 2, 2014. A registration statement relating to the exchange offer for the $100.0 million of 7.75% ARP Senior Notes issued June 2, 2014 was declared effective on October 17, 2014 and the exchange offer for such notes was completed on November 18, 2014.

At December 31, 2014, ARP had $323.9 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”), including $75.0 million of such notes issued in a private placement transaction on October 14, 2014 at an offering price of 100.5% of par value, which yielded net proceeds of approximately $73.6 million. The 9.25% ARP Senior Notes issued in October 2014 were presented net of a $0.4 million unamortized premium as of December 31, 2014. The 9.25% ARP Senior Notes issued in July 2013 were presented net of a $1.5 million unamortized discount as of December 31, 2014. ARP used the net proceeds from this offering to fund a portion of its Eagle Ford Acquisition (see Note 4). Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. 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 109.250%. 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 $250.0 million of 9.25% ARP Senior Notes on July 30, 2013, ARP entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014.

The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% 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.

The indentures governing the 7.75% ARP Senior Notes and 9.25% 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, 2014.

At December 31, 2014, APL had an $800.0 million senior secured revolving credit facility with a syndicate of banks that matures in August 2019. Borrowings under the revolving credit facility bear interest, at APL’s option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (2) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for borrowings on the revolving credit facility, at December 31, 2014, was 2.7%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $4.2 million was outstanding at December 31, 2014. These outstanding letters of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheets. At December 31, 2014, APL had $410.8 million of remaining committed capacity under its revolving credit facility.

Borrowings under the revolving credit facility are secured by (i) a lien on and security interest in all the Partnership’s property and that of its subsidiaries, except for the assets owned by Atlas Pipeline Mid-Continent WestOk, LLC (“WestOK

LLC”) and Atlas Pipeline Mid-Continent WestTex, LLC (“WestTX LLC”), entities in which APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) by the guaranty 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 APL’s ability to (1) incur additional indebtedness, (2) make certain acquisitions, loans or investments, (3) make distribution payments to its unitholders if an event of default exists, or (4) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries, without approval of the lenders. APL is unable to borrow under its revolving 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 that constitute an event of default for 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 its general partner.

On August 28, 2014, APL entered into a Second Amended and Restated Credit Agreement (the “Revised APL Credit Agreement”) which, among other changes:

As of December 31, 2014, APL was in compliance with all covenants under the credit facility.

At December 31, 2014, APL had $500.0 million principal outstanding of the 6.625% APL Senior Notes, $650.0 million principal outstanding of the 5.875% unsecured senior notes due August 1, 2023 (“5.875% APL Senior Notes”), and $400.0 million of the 4.75% APL Senior Notes (with the 6.625% APL Senior Notes and 5.875% APL Senior Notes, the “APL Senior Notes”).

Indentures governing the APL Senior Notes contain covenants, including limitations of 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, without consent. APL is in compliance with these covenants as of December 31, 2014.

The 6.625% APL Senior Notes are presented combined with a net $3.9 million unamortized premium as of December 31, 2014. 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 due on October 1, 2020 and redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

On December 20, 2012, APL issued $175.0 million of the 6.625% APL Senior Notes in a private placement transaction. The 6.625% APL Senior Notes were issued at a premium of 103.0% of the principal amount for a yield of 6.0%. APL received net proceeds of $176.1 million after underwriting commissions and other transaction costs and utilized the proceeds to partially finance the Cardinal Acquisition (see Note 4). Of the $176.1 million net proceeds, $176.5 million were received during the year ended December 31, 2012, while additional expenses of $0.4 million were incurred during the year ended December 31, 2013.

On February 11, 2013, APL issued $650.0 million of the 5.875% APL Senior Notes in a private placement transaction. The 5.875% APL Senior Notes were issued at par. APL received net proceeds of $637.3 million after underwriting commissions and other transactions costs and utilized the proceeds to redeem the 8.75% APL Senior Notes and repay a portion of the outstanding indebtedness under the 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 due on August 1, 2023, and redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

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 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.

On January 28, 2013, APL commenced a cash tender offer for any and all of its outstanding 8.75% APL Senior Notes and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% APL Senior Notes (“8.75% 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 outstanding 8.75% APL Senior Notes not purchased in connection with the January 28, 2013 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. During the year ended December 31, 2013, APL recorded 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; $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium.

The aggregate amount of the Partnership’s, ARP’s and APL’s debt maturities is as follows (in thousands):

Cash payments for interest by the Partnership and its subsidiaries were $170.7 million, $96.6 million and $38.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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. To manage the risk of regional commodity price differences, the Partnership and its subsidiaries occasionally enter into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership and its subsidiaries receive or pay a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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.

The Partnership and ARP apply the principles of hedge accounting for derivatives qualifying as hedges. Accordingly, the Partnership and ARP 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 ARP 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 ARP 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 ARP 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 within gas and oil production revenues 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.

APL does not apply the principles of hedge accounting to its derivative instruments. Accordingly, any 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.

APL recognizes the portion relating to commodity derivatives within gathering and processing revenues on the Partnership’s consolidated statement of operations as the derivative instruments are settled.

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 $400.3 million and $14.9 million at December 31, 2014 and 2013, respectively. Of the $54.0 million of deferred gains in accumulated other comprehensive income within partners’ capital on the Partnership’s consolidated balance sheet related to derivatives at December 31, 2014, if the fair values of the instruments remain at current market values, the Partnership will reclassify $27.2 million of gains 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 $26.8 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. In 2014 and 2013, approximately $2.5 million and $3.9 million of derivative gains were reclassified from other comprehensive income (loss) related to derivative instruments entered into during the years ended December 31, 2014 and 2013, respectively.

The following table summarizes the Partnership’s and ARP’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):

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):

During the year ended December 31, 2014 and 2013, the Partnership recorded gains of $0.7 million and $0.5 million on settled derivative contracts within its consolidated statements of operations. These gains and losses were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. No gains or losses were recorded on settled derivative contracts within the Partnership’s consolidated statement of operations for the year ended December 31, 2012 as the Partnership had no derivative contracts in 2012. 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, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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 3). 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 into other, net on the Partnership’s consolidated statement of operations 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.

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):

During the year ended December 31, 2013, ARP entered into contracts which provided the option to enter into swaptions up through September 30, 2013 for production volumes related to assets acquired from EP Energy (see Note 4). In connection with these swaption contracts, ARP paid premiums of $14.5 million, which represented their fair value on the date the transactions were initiated and 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 their 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.

During the year ended December 31, 2012, ARP entered into swaptions 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 and were initially recorded as derivative assets on the Partnership’s consolidated balance sheet and were fully amortized as of June 30, 2012. For the year ended December 31, 2012, ARP recorded approximately $4.6 million of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts.

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. 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.

ARP recognized losses of $7.1 million and gains of $9.7 million and $19.3 million for the years ended December 31, 2014, 2013, and 2012, respectively, on settled contracts covering commodity production. These gains and loss 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, 2014, 2013, and 2012, respectively, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At December 31, 2014, ARP had net cash proceeds of $0.2 million related to 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.

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, 2014 and 2013, net unrealized derivative assets of $2.8 million and $1.4 million, respectively, were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.

At December 31, 2014, 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.

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):

The following table summarizes APL’s derivatives not designated as hedges, which are included within gain (loss) on mark-to market derivatives on the Partnerships consolidated statements of operations:

The fair value of the derivatives included in the Partnership’s consolidated balance sheets for the periods indicated was as follows (in thousands):

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.

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) and investments held in the Partnership’s rabbi trust (see Note 17). 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. Investments held within the Partnership’s rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements.

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 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 assets and liabilities. 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, ARP’s and APL’s assets and liabilities measured at fair value at December 31, 2014 and 2013 was as follows (in thousands):

	Level 1		Level 2			Level 3			Total
As of December 31, 2014
Assets, gross
Rabbi trust	$	3,925	$	—		$	—		$	3,925
Commodity swaps		—		5,562			—			5,562
ARP Commodity swaps		—		261,680			—			261,680
ARP Commodity puts		—		2,767			—			2,767
ARP Commodity options		—		5,320			—			5,320
APL Commodity swaps		—		50,585			64,693			115,278
APL Commodity options		—		8,774			1,353			10,127
Total assets, gross		3,925		334,688			66,046			404,659
Liabilities, gross
Commodity swaps		—		—			—			—
ARP Commodity swaps		—		(401	)		—			(401	)
ARP Commodity options		—		(67	)		—			(67	)
APL Commodity swaps		—		—			—			—
APL Commodity options		—		—			—			—
Total liabilities, gross		—		(468	)		—			(468	)
Total assets, fair value, net	$	3,925	$	334,220		$	66,046		$	404,191
As of December 31, 2013
Assets, gross
Rabbi trust	$	3,705	$	—		$	—		$	3,705
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 assets, gross		3,705		47,238			1,622			52,565
Liabilities, gross
Commodity swaps		—		(152	)		—			(152	)
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	$	3,705	$	26,673		$	(11,756	)	$	18,622

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						NGL Call Options					Total
	Gallons			Amount			Gallons			Amount			Gallons			Amount		Amount
Balance – January 1, 2013		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	)
Deferred option premium recognition⁽³⁾		—			—			—			(13,053	)		—		—			(13,053	)
Balance – December 31, 2013		130,158		$	(11,966	)		6,300		$	210			—		—		$	(11,756	)
New contracts⁽¹⁾		70,560			—			5,040			200			5,040		(200	)		—
Cash settlements from unrealized (gain) loss⁽²⁾⁽³⁾		(84,546	)		3,406			(8,190	)		100			(3,780	)	(121	)		3,385
Net change in unrealized gain (loss)⁽²⁾		—			73,253			—			1,448			—		200			74,901
Deferred option premium recognition⁽³⁾		—			—			—			(605	)		—		121			(484	)
Balance – December 31, 2014		116,172		$	64,693			3,150		$	1,353			1,260		—		$	66,046

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, 2014 and December 31, 2013 (in thousands):

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):

APL had $14.6 million and $14.5 million of NGL linefill at December 31, 2014 and 2013, 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 some counterparties will be settled at various periods in the future and is defined as a Level 3 asset, which is valued at fair value 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 an increase of $0.1 million and a decrease of $0.4 million as of December 31, 2014 and 2013, 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. During the year ended December 31, 2014, the contracts related to this linefill on the WestTX and SouthTX systems were revised and the settlement and valuation was converted from a FIFO method to a fair value method.

The following table provides a summary of changes in fair value of APL’s NGL linefill for the years ended December 31, 2014 and 2013 (in thousands):

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, 2014 and 2013, 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 $3,382.9 million and $2,841.7 million, respectively, compared with the carrying amounts of $3,570.6 million and $2,889.0 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 Level 3 values.

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 7).

Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2014 and 2013 was as follows (in thousands):

The Partnership and its subsidiaries estimate the fair value of its 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, 2014, 2013 and 2012, the Partnership recognized $580.7 million, $38.0 million and $9.5 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 and Goodwill).

During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions (see Note 4). During the year ended December 31, 2013, the Partnership completed the Arkoma Acquisition, ARP completed the EP Energy Acquisition and 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 estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford, Rangely and GeoMet acquisitions as of the respective acquisition dates, which are reflected in the Partnership’s consolidated balance sheet as of December 31, 2014, are subject to change as the final valuations for these transactions have 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 valuations 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 in contingent payments, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. Sufficient volumes were achieved in December 2012, and APL paid the first contingent payment of $6.0 million in January 2013. As of December 31, 2014, the fair value of the remaining contingent 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 amount APL could pay related to the remaining contingent payment is up to $6.0 million.

APL owns a taxable subsidiary. The components of the federal and state income tax expense (benefit) for APL’s taxable subsidiary for the years ended December 31, 2014, 2013 and 2012 are as follows (in thousands):

As of December 31, 2014 and 2013, APL had non-current net deferred income tax liabilities of $30.9 million and $33.3 million, respectively. The components of net deferred tax liabilities as of December 31, 2014 and 2013 consist of the following (in thousands):

As of December 31, 2014, APL had net operating loss carry forwards for federal income tax purposes of approximately $44.7 million, which expire at various dates from 2029 to 2034. 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.

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 Partnerships’ revenues 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, 2014, 2013 and 2012, $0.3 million, $0.3 million and $0.4 million 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 for the year ended 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.

The Partnership leases office space and equipment under leases with varying expiration dates. Rental expense was $32.6 million, $24.4 million and $9.6 million for the years ended December 31, 2014, 2013 and 2012, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):

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. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of December 31, 2014, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.

While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the years ended December 31, 2014, 2013, and 2012, $5.3 million, $9.6 million, and $6.3 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses.

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 the Eagle Ford Acquisition (see Note 4), ARP guaranteed the Development Subsidiary’s deferred purchase obligation, whereby ARP provided a guaranty of timely payment of the deferred portion of the purchase price that is to be paid by the Development Subsidiary. Pursuant to the agreement between ARP and the Development Subsidiary, ARP will have the right to receive some or all of the assets acquired by the Development Subsidiary in the event of its failure to contribute its portion of any deferred payments. The deferred purchase obligation is included within accrued liabilities on the Partnership’s consolidated balance sheet at December 31, 2014.

In connection with ARP’s GeoMet 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, 2014 were as follows: 2015— $2.5 million; 2016— $2.4 million; 2017— $2.0 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.9 million.

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, 2014 were as follows: 2015— $8.3 million; 2016— $2.1 million; and 2017 to 2019— 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 $28.3 million, $34.8 million and $10.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. The unrecorded future fixed and determinable portion of the obligations as of December 31, 2014 was as follows: 2015 - $20.7 million; 2016 to 2017 - $23.9 million per year; 2018 - $21.8 million; and 2019 - $16.9 million.

As of December 31, 2014, the Partnership and its subsidiaries are committed to expend approximately $198.0 million on drilling and completion expenditures, pipeline extensions, compressor station upgrades and processing facility upgrades.

The Partnership and its subsidiaries are party to various routine legal proceedings arising in the ordinary course of its business. The Partnership does not believe that any of these actions, individually or in the aggregate, will have a material adverse effect on is financial condition or results of operations.

Since the announcement on October 13, 2014 of the Merger and the APL Merger (see Note 19), the Partnership, APL and the other parties to the Atlas Mergers have been named as defendants in putative stockholder class action complaints challenging the transactions. Although Atlas Energy Group, LLC (“Atlas Energy Group”) has not been named as a defendant in these complaints, certain of the Partnership’s expected officers have been named as defendants, and the litigation could delay or impede the consummation of the separation and distribution.

As of February 24, 2015, the Partnership is aware that it, its general partner, TRC, GP Merger Sub (a subsidiary of TRC created in connection with the Merger), and the members of the Partnership’s board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in two putative stockholder class action complaint challenging the Atlas merger filed in the Court of Common Pleas for Allegheny County, Pennsylvania. These cases are captioned: Rick Kane v. Atlas Energy, L.P., et al., Case No. GD-14-019658 (Pa. Ct. Comm. Pls. Oct. 22, 2013) and Jeffrey Ayers v. Atlas Energy, L.P., et al., Case No. GD-14-020255 (Pa. Ct. Comm. Pls. Nov. 3, 2014) (the “ATLS Lawsuits”). The ATLS Lawsuits were consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit”), although the Kane litigation has since been voluntarily dismissed. The Partnership is also aware that APL, APL’s general partner, the Partnership, TRC, TRP, TRP GP, MLP Merger Sub (a subsidiary of TRP created in connection with the APL Merger), and the members of the APL board, including Edward E. Cohen and Jonathan Z. Cohen, New Atlas’s expected Chief Executive Officer and Executive Chairman, have been named as defendants in five putative stockholder class action complaints challenging the APL Merger, four filed in the Court of Common Pleas for Allegheny County, Pennsylvania and one filed in the District Court of Tulsa County, Oklahoma. These cases are captioned: Michael Envin v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-019245 (Pa. Ct. Comm. Pls. Oct. 17, 2013), Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020108 (Pa. Ct. Comm. Pls. Oct. 31, 2014), Mike Welborn v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-020729 (Pa. Ct. Comm. Pls. Nov. 10, 2014), Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., Case No. GD-14-22208 (Pa. Ct. Comm. Pls. Dec. 5, 2014) and William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., Case No. CJ-2014-04087 (Okla. D. Ct. Oct. 28, 2014) (the “APL Lawsuits” and, together with the ATLS Lawsuits, the “Lawsuits”). The Evnin, Greenthal, Welborn and Feldbaum APL Lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). The Federman lawsuit has subsequently been voluntarily dismissed.

unitholders, and omitting material information from the Proxy Statements. The Lawsuits further allege that those breaches were aided and abetted by some combination of the Partnership, APL, TRC, TRP, or various affiliates of those entities named above. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses, and costs.

Additionally, a putative stockholder class action and derivative lawsuit, captioned Inspired Investors v. Perkins et. al., Case No. 2015-04961, was filed purportedly on behalf of Targa Resources shareholders in the District Court of Harris County, Texas on January 28, 2015 and amended on February 23, 2015. The lawsuit names the Partnership and the individual members of the board of directors of TRC as defendants and TRC as a nominal defendant. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the Merger and omitting purportedly material information from the registration statement on Form S-4 that TRC initially filed with the SEC on November 20, 2014 and most recently amended on January 22, 2015. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest and costs.

The Partnership recognizes gains on its subsidiaries’ 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 its subsidiaries’ common units over the book carrying amount per unit.

In July 2013, in connection with ARP’s EP Energy Acquisition (see Note 4), the Partnership purchased 3,746,986 of ARP’s 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.

In October 2014, in connection with the Eagle Ford Acquisition (see Note 4), ARP issued 3,200,000 8.625% ARP Class D Preferred Units at a public offering price of $25.00 per Class D ARP Preferred Unit, yielding net proceeds of approximately $77.4 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 16). ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

The Class D ARP Preferred Units rank senior to ARP’s common units and Class C ARP convertible preferred units with respect to the payment of distributions and distributions upon a liquidation event and equal with ARP’s Class B convertible preferred units. The Class D ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019, ARP may, at its option, redeem the Class D ARP Preferred Units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem the Class D ARP Preferred Units following certain changes of control, as described in the Certificate of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of the Class D ARP Preferred Units will have the option to convert the Class D ARP Preferred Units into a number of ARP common units per Class D unit as set forth in the Certificate of Designation. If ARP exercises any of its redemption rights relating to the Class D ARP Preferred Units, the holders of such Class D ARP Preferred Units will not have the conversion right described above with respect to the Class D ARP Preferred Units called for redemption.

In May 2014, in connection with the closing of the Rangely Acquisition (see Note 4), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

In March 2014, in connection with the GeoMet Acquisition (see Note 4), ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million. The units were registered under the Securities Act, pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.

In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 4), ARP issued 3,749,986 of its newly created Class C convertible preferred units to ATLS, 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 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, ATLS, 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 common units of ARP at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

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. 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 this 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 had 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. On December 23, 2014, 3,796,900 of the ARP Class B preferred units were voluntarily converted into common units.

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.

At December 31, 2014 and 2013, in connection with the issuance of ARP’s common units, the Partnership recorded gains of $40.5 million and $27.3 million within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet and consolidated statement of partners’ capital.

In February 2012, the board of directors of ATLS’ general partner approved the distribution of approximately 5.24 million of the Partnership’s common limited partner units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 Partnership common limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012.

On May 12, 2014, APL entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup, Wells Fargo Securities, LLC and MLV & Co. LLC, as sales agents. Pursuant to this program, APL may offer and sell from time to time through its sales agents, common units having an aggregate value up to $250.0 million. Sales are at market prices prevailing at the time of the sale. However, APL is currently restricted from selling common units by the APL merger agreement (see Note 19).

During the year ended December 31, 2014, APL issued 3,558,005 common units, under the 2014 EDA for proceeds of $121.6 million, net of $1.2 million in commissions paid to the sales agents. APL also received capital contributions from the Partnership, as general partner, of $2.5 million during the year ended December 31, 2014 to maintain its 2.0% general partner interest in APL. The net proceeds from the common unit offerings and General Partner contributions were utilized for general partnership purposes.

On March 17, 2014, APL issued 5,060,000 of its Class E APL Preferred Units to the public at an offering price of $25.00 per Class E APL Preferred Unit. APL received $122.3 million in net proceeds. The proceeds were used to pay down APL’s revolving credit facility.

APL made cumulative cash distributions on the Class E APL Preferred Units from the date of original issue, which were payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The initial distribution on the Class E APL Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million, representing the distribution for the period March 17, 2014 through July 14, 2014. Thereafter, APL paid cumulative distributions in cash on the Class E APL Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year. On October 15, 2014, APL paid a cash distribution of $2.6 million on its outstanding Class E APL Preferred Units, representing the cash distribution for the period from July 15, 2014 through October 14, 2014. On January 15, 2015, APL paid a cash distribution of $2.6 million on its outstanding Class E APL Preferred Units, representing the cash distribution for the period from October 15, 2014 through January 14, 2015. For the year ended December 31, 2014, APL allocated net income of $8.2 million to the Class E APL Preferred Units for the dividends earned during the period, which was recorded within income (loss) from non-controlling interests on the Partnership’s consolidated statements of operations.

On May 7, 2013, APL completed a private placement of $400.0 million of its Class D APL Preferred Units to third party investors, 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 contributed $8.2 million to maintain its 2.0% general partnership interest upon the issuance of the Class D APL Preferred Units. APL used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see Note 4). The Class D APL Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act. APL had the

right to convert the Class D APL Preferred Units plus any unpaid distributions, in whole but not in part, beginning one year following their issuance, into common units.

The fair value of APL’s common units on the Commitment Date was $36.52 per unit, resulting in an embedded beneficial conversion discount (“discount”) on the Class D APL Preferred Units of $91.0 million. APL recognized the fair value of the Class D APL Preferred Units with the offsetting intrinsic value of the discount within non-controlling interests on the Partnership’s consolidated balance sheets as of December 31, 2014 and 2013. The discount is being accreted and recognized as imputed dividends over the term of the Class D APL Preferred Units as a reduction to APL’s net income attributable to the common limited partners and the Partnership, as general partner. APL’s Class D Preferred Units are presented combined with a net $16.0 million and $61.5 million unaccreted discount within non-controlling interests on the Partnership’s consolidated balance sheets as of December 31, 2014 and 2013, respectively. APL recorded $45.5 million and $29.5 million in the years ended December 31, 2014 and 2013, respectively, within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations to recognize the accretion of the discount.

The Class D APL Preferred Units received distributions of additional Class D APL Preferred Units in each of the quarterly periods following their issuance in May 2013. The amount of the distribution was determined based upon the cash distribution per unit paid each quarter on APL’s common limited partner units plus a preferred yield premium. APL recorded Class D APL Preferred Unit distributions in kind of $42.6 million and $23.6 million for the years ended December 31, 2014 and 2013, respectively, within income (loss) attributable to non-controlling interests on the Partnership’s consolidated statements of operations. APL considers preferred unit distributions in kind to be a non-cash financing activity.

On January 22, 2015, APL exercised its right under the certificate of designation of the Class D APL Preferred Units (“Class D APL Certificate of Designation”) to convert all outstanding Class D APL Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D APL Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued.

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 during the year ended December 31, 2013, 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 December 2012, APL sold 10,507,033 common units in a public offering at a price of $31.00 per unit, yielding net proceeds of approximately $319.3 million, including $6.7 million contributed by the Partnership to maintain its 2.0% general partner interest. APL utilized the net proceeds from the common unit offering to partially finance the Cardinal Acquisition (see Note 4).

In November 2012, APL entered into an equity distribution program with 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, the Partnership issued 3,895,679 and 275,429 common units, respectively, under the equity distribution program for proceeds of $137.8 million and $8.7 million, respectively, net of $2.8 million and $0.2 million, respectively, in commissions incurred from Citigroup, and other expenses. 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. The net proceeds from the common unit offering were utilized for general partnership purposes.

For the year ended December 31, 2014, in connection with the issuance of APL’s common units, the Partnership recorded a $2.7 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet and consolidated statement of partner’s capital. At December 31, 2013, in connection with the issuance of APL’s common units, the Partnership recorded an $11.9 million gain within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheet and consolidated statement of partners’ capital.

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, 2012 through December 31, 2014 were as follows (in thousands, except per unit amounts):

On January 28, 2015, the Partnership declared a cash distribution of $0.52 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $27.1 million distribution was paid on February 19, 2015 to unitholders of record at the close of business on February 9, 2015.

ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. 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 for the period from January 1, 2013 through December 31, 2014 were as follows (in thousands, except per unit amounts):

Date Cash Distribution Paid	For Quarter/Month 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’s Class A Units
May 15, 2012	March 31, 2012	$	0.1200	⁽¹⁾	$	3,144	$	—	$	64
August 14, 2012	June 30, 2012	$	0.4000		$	12,891	$	—	$	263
November 14, 2012	September 30, 2012	$	0.4300		$	15,510	$	1,652	$	350
February 14, 2013	December 31, 2012	$	0.4800		$	21,107	$	1,841	$	618

May 15, 2013	March 31, 2013	$	0.5100		$	22,428	$	1,957	$	946
August 14, 2013	June 30, 2013	$	0.5400		$	32,097	$	2,072	$	1,884
November 14, 2013	September 30, 2013	$	0.5600		$	33,291	$	4,248	$	2,443
February 14, 2014	December 31, 2013	$	0.5800		$	34,489	$	4,400	$	2,891

March 17, 2014	January 31, 2014	$	0.1933		$	12,718	$	1,467	$	1,055
April 14, 2014	February 28, 2014	$	0.1933		$	12,719	$	1,466	$	1,055
May 15, 2014	March 31, 2014	$	0.1933		$	12,719	$	1,466	$	1,054
June 13, 2014	April 30, 2014	$	0.1933		$	15,752	$	1,466	$	1,279
July 15, 2014	May 31, 2014	$	0.1933		$	15,752	$	1,466	$	1,279
August 14, 2014	June 30, 2014	$	0.1966		$	16,029	$	1,492	$	1,377
September 12, 2014	July 31, 2014	$	0.1966		$	16,028	$	1,493	$	1,378
October 15, 2014	August 31, 2014	$	0.1966		$	16,032	$	1,491	$	1,378

At December 31, 2014, ARP had 3.2 million of its 8.625% Class D ARP Preferred Units outstanding (see Note 15). On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015. ARP will pay future cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.

On January 28, 2015, ARP declared a monthly distribution of $0.1966 per common unit for the month of December 31, 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to the Partnership as general partner and preferred limited partners, respectively, was paid on February 13, 2015 to unitholders of record at the close of business on February 9, 2015.

On February 23, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of January 2015. The $9.9 million distribution, including $0.2 million and $0.4 million to the Partnership as general partner and preferred limited partners, respectively, will be paid on March 17, 2015 to unitholders of record at the close of business on March 10, 2015.

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, 2012 through December 31, 2014 were as follows (in thousands, except per unit amounts):

$8.1 million to the Partnership as general partner, was paid on February 13, 2015 to unitholders of record at the close of business on January 21, 2015.

On January 15, 2015, APL paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on its outstanding Class E APL Preferred Units, representing the cash distribution for the period from October 15, 2014 through January 14, 2015 (see Note 15).

In 2011, the Partnership established an excess 401(k) plan relating to certain executives. In connection with the plan, the Partnership established a “rabbi” trust for the contributed amounts. At December 31, 2014 and 2013, the Partnership reflected $3.9 million and $3.7 million, respectively, related to the value of the rabbi trust within other assets, net on its consolidated balance sheets (see Note 7), and recorded corresponding liabilities of $3.9 million and $3.7 million, as of the same dates within other long-term liabilities on its consolidated balance sheets. During the year ended December 31, 2014, the Partnership distributed $1.8 million to participants related to the rabbi trust. No amounts were distributed during the year ended December 31, 2013.

The Board of Directors of the Partnership’s general partner (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, 2014, the Partnership had 4,911,209 phantom units and unit options outstanding under the 2010 LTIP, with 283,650 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):

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, 2014, there are 1,601,974 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013 and 2012, the Partnership paid $4.3 million, $3.1 million and $2.0 million, respectively, with respect to the 2010 LTIP DERs.

The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:

At December 31, 2014, the Partnership had approximately $35.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.1 years.

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 1,770,877 unit options outstanding under the 2010 LTIP at December 31, 2014 that will vest within the following twelve months. For the years ended December 31, 2014, 2013 and 2012, the Partnership received cash of $0.6 million, $0.1 million and $0.1 million, respectively, from the exercise of options.

The following table sets forth the 2010 LTIP unit option activity for the periods indicated:

At December 31, 2014, the Partnership had approximately $1.1 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 0.3 years. 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 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, 2014, the Partnership had 1,721,121 phantom units and unit options outstanding under the 2006 LTIP, with 133,951 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.

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, 2014, 311,387 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013 and 2012, respectively, the Partnership paid approximately $1.1 million, $0.4 million and approximately $42,000 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:

At December 31, 2014, the Partnership had approximately $14.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.7 years.

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, 2014 that will vest within the following twelve months. For the year ended December 31, 2012, the Partnership received cash of $0.2 million from the exercise of options. No cash was received from the exercise of options for the years ended December 31, 2014 and 2013.

The following table sets forth the 2006 LTIP unit option activity for the periods indicated:

At December 31, 2014, the Partnership had approximately $17,000 of unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.6 years. 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.

ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the general partner and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under ARP’s 2012 LTIP, the ARP LTIP Committee may grant awards of phantom units, restricted units, or unit options for an aggregate of 2,900,000 common limited partner units of ARP. At December 31, 2014, ARP had 2,257,492 phantom units, restricted units and restricted options outstanding under the ARP LTIP with 135,663 phantom units, restricted units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value.

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):

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, 2014, 317,587 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013, and 2012, ARP paid $2.0 million, $1.9 million, and $0.7 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as non-controlling interests on the Partnership’s consolidated balance sheets.

The following table sets forth the ARP LTIP phantom unit activity for the periods indicated:

At December 31, 2014, ARP had approximately $6.7 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.7 years.

ARP Unit Options. The exercise price of each ARP unit option is determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of ARP’s common unit on the date of grant of the option. The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. 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 361,325 unit options outstanding under the ARP LTIP at December 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the years ended December 31, 2014, 2013, and 2012.

The following table sets forth the ARP LTIP unit option activity for the periods indicated:

At December 31, 2014, ARP had approximately $1.0 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.1 years. 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.

APL has a 2004 Long-Term Incentive Plan (“2004 APL LTIP”) and a 2010 Long-Term Incentive Plan (“2010 APL LTIP” and collectively with the 2004 LTIP, the “APL LTIPs”) in which officers, employees, non-employee managing board members of APL’s general partner, employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by its 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, 2014, APL had 1,684,289 phantom units outstanding under the APL LTIPs, with 139,218 phantom units

and unit options available for grant. APL generally issues new common units for phantom units and unit options that have vested and have been exercised.

Phantom units granted to employees under the APL LTIPs generally had vesting periods of four years. However, in February 2014, the APL granted 227,000 phantom units with a vesting period of three years. The APL LTIP Committee determines the vesting paid for phantom units. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of the board automatically vest upon a change of control, as defined in the APL LTIPs. At December 31, 2014, there were 614,415 units outstanding under the APL LTIPs that 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, 2014 and 2012, APL purchased and retired 66,321 and 24,052 common units, respectively, for a cost of $2.2 million and $0.7 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.

All phantom units outstanding under the APL LTIPs at December 31, 2014 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $4.3 million, $3.1 million and $2.0 million during the years ended December 31, 2014, 2013 and 2012, respectively. These amounts were recorded as reductions of non-controlling interests on the Partnership’s consolidated balance sheets.

The following table sets forth the APL LTIPs phantom unit activity for the periods indicated:

At December 31, 2014, APL had approximately $27.9 million of unrecognized compensation expense related to APL’s 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 1.9 years.

An APL unit option entitles a grantee to purchase an APL common limited partner unit upon payment of the exercise price for APL’s option after completion of vesting of the APL unit option. The exercise price of APL’s unit option is equal to the fair market value of the APL’s common unit on the date of grant of the option. The APL Compensation Committee determines how the exercise price may be paid by the grantee as well as the vesting and exercise period for APL’s unit options.

APL had no unit options outstanding at December 31, 2014, and there were no exercises of APL’s unit options during the years ended December 31, 2014, 2013 and 2012.

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,
	2014			2013			2012
Atlas Resource:
Revenues	$	685,560		$	467,655		$	267,629
Operating costs and expenses		(425,000	)		(348,812	)		(246,267	)
Depreciation, depletion and amortization expense		(233,731	)		(136,763	)		(52,582	)
Asset impairment		(573,774	)		(38,014	)		(9,507	)
Loss on asset sales and disposal		(1,869	)		(987	)		(6,980	)
Interest expense		(62,144	)		(34,324	)		(4,195	)
Segment loss	$	(610,958	)	$	(91,245	)	$	(51,902	)

Atlas Pipeline:
Revenues	$	2,961,113		$	2,102,113		$	1,252,674
Operating costs and expenses		(2,483,160	)		(1,863,510	)		(1,052,826	)
Depreciation, depletion and amortization expense		(202,543	)		(168,617	)		(90,029	)
Asset impairment		—			(43,866	)		—
Gain (loss) on asset sales and disposal		47,381			(1,519	)		—
Interest expense		(93,147	)		(89,637	)		(41,760	)
Loss on early extinguishment of debt		—			(26,601	)		—
Segment income (loss)	$	229,644		$	(91,637	)	$	68,059

Corporate and other:
Revenues	$	22,030		$	7,747		$	1,140
Operating costs and expenses		(72,822	)		(41,690	)		(33,613	)
Depreciation, depletion and amortization expense		(8,348	)		(3,153	)		—
Asset impairment		(6,880	)		—			—
Gain on asset sales and disposal		10			—			—
Interest expense		(18,066	)		(8,620	)		(565	)
Segment loss	$	(84,076	)	$	(45,716	)	$	(33,038	)

Reconciliation of segment income (loss) to net loss:
Segment income (loss):
Atlas Resource	$	(610,958	)	$	(91,245	)	$	(51,902	)
Atlas Pipeline		229,644			(91,637	)		68,059
Corporate and other		(84,076	)		(45,716	)		(33,038	)
Net loss	$	(465,390	)	$	(228,598	)	$	(16,881	)
Reconciliation of segment revenues to total revenues:
Segment revenues:
Atlas Resource	$	685,560		$	467,655		$	267,629
Atlas Pipeline		2,961,113			2,102,113			1,252,674
Corporate and other		22,030			7,747			1,140
Total revenues	$	3,668,703		$	2,577,515		$	1,521,443

Capital expenditures:
Atlas Resource	$	212,634		$	263,537		$	127,226
Atlas Pipeline		647,747			450,560			373,533
Corporate and other		13,002			3,943			—

Merger with Targa Resources Corp. On October 13, 2014, the Partnership entered into a definitive merger agreement with Targa Resources Corp. (“TRC”; NYSE: TRGP) (the “Merger Agreement”), pursuant to which TRC agreed to acquire the Partnership through a newly formed, wholly-owned subsidiary of TRC (the “Merger”). Upon completion of the Merger, holders of the Partnership’s common units will have the right to receive, for each Partnership common unit, (i) 0.1809 TRC shares, and (ii) $9.12 in cash.

Concurrently with the execution of the Merger Agreement, APL entered into a definitive merger agreement (the “APL Merger Agreement”) with the Partnership, TRC, Targa Resources Partners LP (“TRP”; NYSE: NGLS), pursuant to which TRP agreed to acquire APL through a newly formed, wholly-owned subsidiary of TRP (the “APL Merger”). Upon completion of the APL Merger, holders of APL’s common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each APL common unit.

Concurrent with the execution of the Merger Agreement and the APL Merger Agreement, the Partnership agreed to (i) transfer its assets and liabilities, other than those related to APL, to Atlas Energy Group, which is currently a wholly-owned subsidiary of the Partnership and (ii) immediately prior to the Merger, effect a pro rata distribution to the Partnership’s unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”). Atlas Energy Group’s assets, assuming the Spin-Off had been completed as of December 31, 2014, consist of:

The closing of the Merger is subject to approval by holders of a majority of the Partnership’s common units, approval by a majority of the holders of TRC common stock voting at a special meeting held to approve the issuance of TRC shares in the Merger and other closing conditions, including the closing of the APL Merger and the Spin-Off. On February 20, 2015, we and TRC each held special meetings, where holders of a majority of our common units approved the Merger and a majority of the holders of TRC common stock voting at the TRC special meeting approved the issuance of TRC shares in the Merger. In addition, holders of a majority of APL’s common units approved the APL Merger at a special meeting held on the same day. Completion of each of the APL Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger.

Following the announcement on October 13, 2014 of the Merger, the Partnership, the Partnership’s general partner, TRC, Trident GP Merger Sub LLC (“GP Merger Sub”) and the members of the General Partner’s board have been named as defendants in two putative unitholder class action lawsuits challenging the Merger. In addition, the Partnership, APL, Atlas Pipeline Partners GP LLC (“APL GP”), TRC, TRP, Targa Resources GP LLC (“TRP GP”), Trident MLP Merger Sub LLC (“MLP Merger Sub”) and the members of the managing board of APL GP have been named as defendants in five putative unitholder class action lawsuits challenging the APL Merger. The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for the Partnership’s unitholders in the Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs.

At this time, the Partnership cannot reasonably estimate the range of possible loss as a result of the lawsuits. See “Part I. Item 3. Legal Proceedings” for more information regarding these lawsuits.

Cash Distribution. On January 28, 2015, the Partnership declared a cash distribution of $0.52 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $27.1 million distribution was paid on February 19, 2015 to unitholders of record at the close of business on February 9, 2015.

Credit Facility Amendment. On February 23, 2015, ARP entered the Sixth Amendment with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which amendment amends the ARP Credit Agreement. Among other things, the Sixth Amendment:

The Amendment was approved by the lenders and was effective on February 23, 2015.

Second Lien Term Loan Facility. On February 23, 2015, ARP entered into a Second Lien Credit Agreement with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “Term Loan Facility”). The Term Loan Facility matures on February 23, 2020.

Cash Distributions. On January 28, 2015, ARP declared a cash distribution of $0.1966 per common unit for the month of December 2014. The $18.9 million distribution, including $1.4 million and $0.7 million to the Partnership as general partner and preferred limited partners, respectively, was paid on February 13, 2015 to holders of record as of February 9, 2015.

On February 23, 2015, ARP declared a cash distribution of $0.1083 per common unit for the month of January 2015. The $9.9 million distribution, including $0.2 million and $0.4 million to the Partnership as general partner and preferred limited partners, respectively, will be paid on March 17, 2015 to holders of record as of March 10, 2015.

Notice of Preferred Unit Redemption. On January 27, 2015, APL delivered notice of its intention to redeem all outstanding shares of its Class E APL Preferred Units. The redemption of the Class E APL Preferred Units will occur immediately prior to the close of the APL Merger. APL expects the APL Merger to close on February 27, 2015 and, accordingly, the redemption would also be on February 27, 2015. The Class E APL Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E APL Preferred Units as of the redemption date. TRP has agreed to deposit the funds for such redemption with APL’s paying agent.

Conversion of Preferred Units. On January 22, 2015, APL exercised its right under the Class D APL Certificate of Designation to convert all outstanding Class D APL Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D APL Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued.

Redemption of APL Senior Notes. On January 15, 2015, TRP announced cash tender offers to redeem any and all of the outstanding $500.0 million aggregate principal amount of the 6.625% APL Senior Notes; $400.0 million aggregate principal amount of the 4.75% APL Senior Notes; and $650.0 million aggregate principal amount of the 5.875% APL Senior Notes. TRP made the cash tender offers in connection with, and conditioned upon, the consummation of the APL Merger. The APL Merger, however, is not conditioned on the consummation of the tender offers. On February 2, 2015, TRP announced as of January 29, 2015, it had received tenders pursuant to its previously announced cash tender offers on January 15, 2015 from holders representing:

Also on February 2, 2015, TRP announced a change of control cash tender offer for any and all of the outstanding $500.0 million of the 6.625% APL Senior Notes. TRP made the change of control cash tender offer in connection with, and conditioned upon, the consummation of the Merger with APL. The Merger with APL, however, is not conditioned on the consummation of the change in control cash tender offer. The change in control cash tender offer was made independently of TRP’s January 15, 2015 cash tender offers.

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, 2014. Other than for ARP’s Rangely assets, 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 38 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. For ARP’s Rangely assets, Cawley, Gillespie, and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 32 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 16 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, 2014, 2013 and 2012 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, 2014, 2013 and 2012, 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.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership and ARP are as follows (unaudited):


	Gas (Mcf)		Oil (Bbls)⁽¹⁾		NGLs (Bbls)⁽¹⁾
Balance, January 1, 2012	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⁽³⁾	(27,760,192	)	(153,413	)	206,091
Production	(25,403,318	)	(120,736	)	(356,550	)
Balance, December 31, 2012⁽⁴⁾	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	)
Purchase of reserves in-place	493,481,302		1,964		55,187
Transfers to limited partnerships	(2,485,210	)	(239,910	)	(258,381	)
Revisions⁽⁵⁾	(88,484,468	)	(1,412,371	)	(3,826,744	)
Production	(59,849,442	)	(485,226	)	(1,267,590	)
Balance, December 31, 2013	1,003,779,503		14,988,824		18,957,016
Extensions, discoveries and other additions⁽²⁾	58,461,204		3,372,177		3,986,986
Sales of reserves in-place	(169,035	)	(1,519	)	(11,326	)
Purchase of reserves in-place	88,635,059		51,168,449		3,567,531
Transfers to limited partnerships	(4,887,095	)	(684,613	)	956,810
Revisions	5,947,622		(4,639,546	)	(2,689,372	)
Production	(86,889,803	)	(1,254,247	)	(1,387,865	)
Balance, December 31, 2014	1,064,877,455		62,949,525		23,379,780

Proved developed reserves at:
January 1, 2012	138,403,225		1,638,083		—
December 31, 2012	338,655,324		3,400,447		7,884,778
December 31, 2013	766,872,394		3,459,260		7,676,389
December 31, 2014	889,073,136		31,150,298		12,209,825

Proved undeveloped reserves at:
January 1, 2012	19,273,206		8,216		—
December 31, 2012	235,118,932		5,468,389		8,177,120
December 31, 2013	236,907,109		11,529,564		11,280,627
December 31, 2014	175,804,319		31,799,227		11,169,954

⁽¹⁾ Oil includes NGL information at January 1, 2012, which was less than 500 MBbls.

⁽²⁾ Principally includes increases of proved reserves due to the addition of Marble Falls wells.

⁽³⁾ 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.

⁽⁴⁾Prior to the Arkoma Acquisition on July 31, 2013, Partnership had no oil and gas reserves. At December 31, 2014, there were no proved undeveloped reserves related to Partnership’s oil and gas assets.

⁽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 Partnership and ARP during the periods indicated were as follows (in thousands):

Results of Operations from Oil and Gas Producing Activities. The results of operations related to Partnership’s and ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands):

⁽¹⁾ During the year ended December 31, 2014, the Partnership recognized $580.7 million of asset impairment consisting of $562.6 million related to oil and gas properties within property, plant, and equipment, net on the Partnership’s consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. 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.

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Partnership and ARP in their oil and gas activities during the periods indicated are as follows (in thousands):

⁽¹⁾ There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012.

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 and ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2014, 2013 and 2012, 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):

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 and ARP allocate taxable income to their owner, no recognition has been given to income taxes:

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 by our Development Subsidiary and ARP in the Eagle Ford Shale in Atacosa County, Texas. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2014, our disclosure controls and procedures were effective at the reasonable assurance level.

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, the operations of our Development Subsidiary’s and ARP’s newly acquired assets in the Eagle Ford Shale, which were acquired in November 2014, from its December 31, 2014 Sarbanes-Oxley 404 review (see “Item 8. Financial Statements and Supplemental Data – Note 4”). In connection with this acquisition, our Development Subsidiary and ARP have entered into a transition services agreement with the previous owner. As a result, the Development Subsidiary and ARP did not begin to perform substantially all accounting control functions related to the Eagle Ford Acquisition until February 6, 2015. The Eagle Ford Acquisition constituted 4.6% of our total assets as of December 31, 2014 and 0.3% of our total revenues for the year ended December 31, 2014. We are continuing to integrate this system’s 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 year ended December 31, 2014, ARP acquired certain assets in the Rangely field in northwestern Colorado. During the year ended December 31, 2013, we and ARP acquired certain assets from EP Energy, and APL acquired certain assets from TEAK which have been fully integrated into our existing internal control environment in 2014. Other than the previously mentioned items, there have been no changes in our internal control over financial reporting during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, 2014. 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, 2014, which is included herein.

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, 2014, 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 ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC, which are consolidated subsidiaries of the Partnership, whose financial statements reflect aggregate total assets and revenues constituting 4.6% and 0.3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014. As indicated in Management’s Report, the Eagle Ford Shale assets of ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC were acquired during 2014. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of ARP Eagle Ford, LLC and Atlas Growth Eagle Ford, LLC.

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, 2014, 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, 2014, and our report dated February 27, 2015 expressed an unqualified opinion on those financial statements.

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.

The following table sets forth information with respect to the executive officers and directors of our general partner:

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 Energy Group, 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.

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.

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.

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.

Jeffrey F. Kupfer has served as a director since March 2014. Since October 2009, he has served as Adjunct Professor of Policy and Management at Carnegie Mellon University’s H. John Heinz III College. From February 2011 to January 2014, Mr. Kupfer served as a senior advisor for policy and government affairs at Chevron and from September 2009 to February 2011, Mr. Kupfer served as a Senior Vice President at Atlas Energy, Inc. Before that, Mr. Kupfer held a number of high level positions in the U.S. Department of Energy. From March 2008 to January 2009, he was the Acting Deputy Secretary and Chief Operating Officer and from October 2006 to March 2008, he was the Chief of Staff. Mr. Kupfer also worked in the White House as a Special Assistant to the President for Economic Policy in 2006, as the Executive Director of the President’s Panel on Federal Tax Reform in 2005, and as Deputy Chief of Staff at the U.S. Treasury Department from 2001 to 2005. Mr. Kupfer brings to the Board extensive experience in the energy industry, as well his perspective as a former senior official in the U.S. government, which the Board views as complementary to the industry perspective of other Board members.

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) 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.

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 2014 our General Partner’s executive officers and directors and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements except for Mr. Kotek who inadvertently filed two Forms 4 late relating to two equity grants.

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 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. 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.

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.

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.

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.

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 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.

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 2014 (the “Named Executive Officers” or "NEOs") and to discuss why and how the 2014 compensation package for these executives was implemented. Following this discussion are tables that include compensation information for the NEOs. The NEOs for 2014 are as follows:

An understanding of our executive compensation program begins with our program objectives.

The Compensation Committee believes our executive compensation program includes key features that align the interests of our NEOs with our long-term strategic direction.

The 2014 compensation program for our NEOs consisted of the following components:

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 2014 and salaries for 2015 for the NEOs as follows:

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.

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.

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.

For 2014, the Compensation Committee engaged Mercer (US) Inc. (referred to as “Mercer”), 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.

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 revenues, which are near the median. The 2014 peer group is the same as the peer group used in 2013. The members of the peer group are:

Mercer’s analysis also included its compensation survey data for the oil and gas industry. Mercer’s analysis included:

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 Atlas Energy or its affiliated companies. In addition to reaffirming this on an annual basis, Atlas Energy also conducts a search of its accounts payable system to confirm that no Mercer affiliates are providing services outside of the compensation consulting services. As discussed in “Directors—Corporate Governance—Code of Business Conduct and Ethics” and “Certain Relationships and Related Party 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.

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 issues 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.

Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contribute to our success. Base salaries are not intended to compensate individuals for their extraordinary performance or for above average company performance.

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.

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. During 2014, each of the NEOs participated in the Atlas Energy Senior Executive Plan. 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 2014, the Compensation Committee approved 2014 bonus awards to be paid from a bonus pool. The theoretical bonus pool is equal to a maximum of 10% of the distributable cash flow of our entire enterprise, but actual amounts awarded have been much less. One of two goals for 2014 had to be met before any bonuses would be paid:

The goals are set early in the year, but actual awards are ultimately determined by the Compensation 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 its 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 2014 distributable cash flow, for each participant was as follows: Mr. E. Cohen, 3.40% ($15,600,000); Mr. J. Cohen, 3.00% ($13,700,000); Mr. Jones, 1.60% ($7,300,000); and Mr. McGrath, 0.80% ($3,700,000). Mr. Dubay did not participate in our Senior Executive Plan but only in the APL incentive program. While the final maximum bonus pool amount was $45.8 million, actual awards made to the NEOs totaled $5.35 million, or approximately 12% of the maximum bonus pool.

Pursuant to the terms of the our 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.

In exceptional circumstances, discretionary bonuses may be awarded to recognize individual and group performance without regard to limitations otherwise in effect.

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.

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. During 2014, Messrs. E. Cohen and J. Cohen were the only participants in the Deferred Compensation Plan. Currently, Messrs. E. Cohen and J. Cohen are the only participants in the Excess 401(k) Plan. For further details, please see the 2014 Non-Qualified Deferred Compensation table.

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 Herz 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:

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:

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.

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:

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 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.”

At the discretion of the Compensation Committee, we provide perquisites to our NEOs. In 2014, these benefits provided to the NEOs were limited to providing automobile allowances or automobile-related expenses to Messrs. E. Cohen, Jones and Herz.

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.

Following its review of Mercer’s analyses, in the fall of 2014, 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 January 2015, 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.

At our 2014 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 97% 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 2014. In addition, the annual review by the unitholders will provide the Committee with a current perspective on the compensation awarded to the NEOs.

As described above, Mercer’s market competitive assessment found that the base salaries of the NEOs were competitive with the 90th percentile of the peer group and the median of the survey, except for Mr. Jones’, which was competitive with the median of both groups, Mr. McGrath’s, which was competitive with the median and 75th percentile of the peer group and below the competitive range of the 25th percentile of the survey, and Mr. Dubay’s, which fell below the competitive range of the 25^th percentile of the survey. Taking that analysis into consideration, the Compensation Committee determined that the current base salaries for Messrs. E. Cohen, J. Cohen, McGrath, Dubay and Jones were appropriate for 2015.

After the end of the 2014 fiscal year, the 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 (other than Mr. Herz), the 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 the total unitholder return, including cash distributions, was–29% during 2014, which was consistent with the peer group median. The Compensation Committee also took into consideration that the 2014 return followed positive returns of 61% and 39% for 2012 and 2013, respectively, which were substantially higher than the peer companies’ average, and that the peer group’s average return had been far inferior to our return over that two year period. Our return during the three year period spanning 2012 through 2014 was approximately 55%, compared to the median peer return of approximately 8% for the same period. The distributable cash flow was approximately double the performance goal set by the Senior Executive Plan. Our E&P operations achieved a record high average production rate of approximately 285 million cubic feet equivalents of natural gas and oil in late 2014, approximately 10% higher than peak average daily production in 2013. We also increased its net production margin per million cubic feet equivalents by over 40% as a result of organic development and acquisitions, namely from the Rangely field (Colorado) and Eagle Ford (Texas) oil producing properties acquired during 2014. Net proved reserves increased by over 40% to almost 1.7 Tcfe.

The Compensation 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 three-year average of distributable cash flow allocable to us was $124.7 million, which was one and a half times the pre-determined minimum threshold of 80% of three-year average distributable cash flow of $82.6 million. The committee also determined that the production volume for 2014 was 1,893 MMcfed, which was two times 80% of the average production volume for the past three years of 908 MMcfed. The Compensation Committee reviewed the calculations of the maximum 2014 bonus pool, which was 10% of the adjusted distributable cash flow of $458 million. Although the Compensation Committee recognized the NEOs continued strong performance, it took into account the current challenging state of the industry and the year’s negative return to unitholders and decided to sharply reduce bonus payments from those paid in the prior year and make awards that were, on average, 68% less than the total amount of the 2013 awards, far below the maximum level for any of the NEOs.

At this time, in view of evolving corporate governance standards, the Compensation Committee decided to continue to implement a compensation strategy that is weighted toward providing variable compensation (bonus and equity awards) versus fixed salaries. This was consistent with the approach the committee took in 2013 in which, according to Mercer’s analysis, salary accounted for approximately 8% of the compensation of our Chief Executive Officer, as compared to 12% for the peer group median, and approximately 10% of the compensation of the other NEOs, as compared to 17% for the peer group median. The following table shows the maximum amounts that could have been awarded under the Senior Executive Plan and the breakdown of the cash awards actually granted:

The Compensation Committee did not award any other discretionary bonuses for 2014 (although the company did pay substantial bonuses independently of the committee process to other, non-NEO, employees).

APL also awarded Messrs. Cohen and Mr. Dubay each a cash bonus of $1 million on recognition of the strategic direction and insight they have provided with respect to APL’s executive management, financing activities and growth opportunities.

In June 2014, the APL compensation committee provided retention bonuses for a number of executives including several of the NEOs as follows: Mr. E. Cohen—20,000 phantom units; Mr. J. Cohen—20,000 phantom units; and

Mr. Dubay—20,000 phantom units. The awards 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.

To address the significant competition for capable energy executives, in June 2014, the Compensation Committee made continuity awards of ATLS phantom units (with DERs), to a number of executives including NEOs as follows: 240,000 phantom units to each of Messrs. E. Cohen and J. Cohen; 47,000 phantom units to Mr. McGrath; 60,000 phantom units to Mr. Jones and 40,000 phantom units to Mr. Dubay. The units vest 25% on each anniversary of the grant.

We have employment agreements with our NEOs that provide for severance compensation to be paid if their employment is terminated under certain conditions.

“Cause” is defined in Mr. E. Cohen and Mr. J. Cohen’s employment agreements as:

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 “2014 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:

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, 2014:

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 “2014 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.

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, 2014:

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:

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, 2014:

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:

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, 2014:

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.

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.

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.

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.

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.

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.

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.



	Option awards				Unit awards
Name	Exercisable	Unexercisable	Option exercise price ($)	Option expiration date	Number of units that have not vested(#)	Market value of units that have not vested($)
	—	—	N/A	N/A	240,000⁽¹²⁾	7,476,000
	—	—	N/A	N/A	20,000⁽¹³⁾	545,200
Sean P. McGrath	16,314⁽¹⁾	—	20.75	11/10/2016	—	—
	9,516⁽¹⁾	28,551⁽²⁾	20.44	3/25/2021	24,472⁽³⁾	762,303
	25,000⁽⁵⁾	25,000⁽¹⁴⁾	24.67	5/15/2022	25,000⁽¹⁵⁾	267,500
	—	—	N/A	N/A	8,756⁽¹⁶⁾	272,749
	—	—	N/A	N/A	29,680⁽¹⁷⁾	924,532
	—	—	N/A	N/A	47,000⁽¹⁸⁾	1,464,050
Jonathan Z. Cohen	217,530⁽¹⁾	—	20.75	11/10/2016	—	—
	135,956⁽¹⁾	407,869⁽²⁾	20.44	3/25/2021	203,934⁽³⁾	6,352,544
	—	—	N/A	N/A	50,000⁽⁴⁾	1,363,000
	175,000⁽⁵⁾	175,000⁽⁶⁾	24.67	5/15/2022	75,000⁽⁷⁾	802,500
	—	—	N/A	N/A	28,018⁽¹⁹⁾	872,761
	—	—	N/A	N/A	37,500⁽⁹⁾	1,022,250
	—	—	N/A	N/A	98,174⁽²⁰⁾	3,058,120
	—	—	N/A	N/A	50,000⁽¹¹⁾	1,363,000
	—	—	N/A	N/A	240,000⁽¹²⁾	7,476,000
	—	—	N/A	N/A	20,000⁽¹³⁾	545,200

Eugene N. Dubay	27,191⁽¹⁾	81,574⁽²⁾	20.44	3/25/2021	65,259⁽³⁾	2,032,818
	—	—	N/A	N/A	50,000⁽⁴⁾	1,363,000
	—	—	N/A	N/A	37,500⁽⁹⁾	1,022,250
	—	—	N/A	N/A	50,000⁽¹¹⁾	1,363,000
	—	—	N/A	N/A	40,000⁽²⁶⁾	1,246,000
	—	—	N/A	N/A	20,000⁽¹³⁾	545,200
Matthew A. Jones	108,765⁽¹⁾	—	20.75	11/10/2016	—	—
	54,382⁽¹⁾	163,148⁽²⁾	20.44	3/25/2021	122,361⁽³⁾	3,811,545
	112,500⁽⁵⁾	112,500⁽²¹⁾	24.67	5/15/2022	50,000⁽²²⁾	535,000
	—	—	N/A	N/A	19,263⁽²³⁾	600,042
	—	—	N/A	N/A	51,370⁽²⁴⁾	1,600,176
	—	—	N/A	N/A	60,000⁽²⁵⁾	1,869,000

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 table above reflects salary and matching contribution costs allocated to us.

Our general partner does not pay additional remuneration to officers or employees who also serve as board members. In 2014, 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 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.

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, 2014.

This report has been provided by the Compensation Committee of the Board of Directors of Atlas Energy GP, LLC.

The following table sets forth the number and percentage of common units owned, as of February 24, 2015, 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 2014 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.

The following table contains information about our 2006 Plan as of December 31, 2014:

The following table contains information about our 2010 Plan as of December 31, 2014:

The following table contains information about ARP’s 2012 Plan as of December 31, 2014:

The following table contains information about the APL’s 2004 Plan as of December 31, 2014:

The following table contains information about the APL’s 2010 Plan as of December 31, 2013:

The board of directors of our general partner has determined that Ms. Warren and Messrs. Arrendell, Biderman, Holtz, Jones and Kupfer 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, 2014, we were reimbursed $5.0 million and $5.1 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.

For the years ended December 31, 2014 and 2013, the accounting fees and services (in thousands) charged by Grant Thornton, LLP, our independent auditors, were as follows:

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 2014 and 2013.

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.

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 27, 2015.

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

Title of each class		Name of each exchange on which registered
Common Units representing Limited Partnership Interests		New York Stock Exchange


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

	Proved Reserves at December 31,
	2014		2013
Proved reserves:
Natural gas reserves (MMcf):⁽¹⁾
Proved developed reserves		889,073		766,872
Proved undeveloped reserves⁽²⁾⁽³⁾		175,804		236,907
Total proved reserves of natural gas		1,064,877		1,003,779

Oil reserves (MBbl):⁽¹⁾
Proved developed reserves		31,150		3,459
Proved undeveloped reserves⁽²⁾⁽³⁾		31,799		11,530
Total proved reserves of oil		62,949		14,989

NGL reserves (MBbl):
Proved developed reserves		12,210		7,676
Proved undeveloped reserves⁽²⁾⁽³⁾		11,170		11,281
Total proved reserves of NGL		23,380		18,957
Total proved reserves (MMcfe)⁽¹⁾		1,582,853		1,207,455
Standardized measure of discounted future cash flows (in thousands)⁽⁴⁾	$	2,236,764	$	1,079,291

	High		Low		Cash Distribution per Common Limited Partner Declared⁽¹⁾
Year ended December 31, 2014:
Fourth quarter	$	43.94	$	25.24	$	0.52
Third quarter	$	48.47	$	41.51	$	0.52
Second quarter	$	45.70	$	38.27	$	0.49
First quarter	$	48.78	$	40.13	$	0.46
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

			Page
PART I	Item 1:	Business	8
	Item 1A:	Risk Factors	29
	Item 1B:	Unresolved Staff Comments	66
	Item 2:	Properties	67
	Item 3:	Legal Proceedings	74
	Item 4:	Mine Safety Disclosures	75
PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	76
	Item 6:	Selected Financial Data	76
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	80
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk	122
	Item 8:	Financial Statements and Supplementary Data	126
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	207
	Item 9A:	Controls and Procedures	207
	Item 9B:	Other Information	210
PART III	Item 10:	Directors, Executive Officers and Corporate Governance	210
	Item 11:	Executive Compensation	219
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	242
	Item 13:	Certain Relationships and Related Transactions, and Director Independence	246
	Item 14:	Principal Accountant Fees and Services	247
PART IV	Item 15:	Exhibits and Financial Statement Schedules	248
SIGNATURES			255

	December 31,
Unadjusted Prices⁽¹⁾	2014		2013
Natural gas (per Mcf)	$	4.35	$	3.67
Oil (per Bbl)	$	94.99	$	96.78
Natural gas liquids (per Bbl)	$	30.21	$	30.10
Average Realized Prices, Before Hedge^{(1) (2)}
Natural gas (per Mcf)	$	3.87	$	3.25
Oil (per Bbl)	$	90.15	$	95.86
Natural gas liquids (per Bbl)	$	35.78	$	29.43

	Number of productive wells⁽¹⁾⁽²⁾
Atlas Energy	Gross		Net
Barnett/Marble Falls:
Gas wells		8		8
Oil wells		5		5
Total		13		13
Coal-bed Methane⁽³⁾:
Gas wells		594		449
Oil wells		—		—
Total		594		449
Mississippi Lime:
Gas wells		2		—
Oil wells		—		—
Total		2		—
Eagle Ford:
Gas wells		—		—
Oil wells		10		10
Total		10		10
Total:
Gas wells		604		457
Oil wells		15		15
Total		619		472

System	Location	Approximate Active Miles of Pipe

SouthOK	Southern Oklahoma and Northern Texas	1,500
WestOK	North Central Oklahoma and Southern Kansas	6,100
Total Oklahoma		7,600

SouthTX	Southern Central Texas	800
WestTX	West Texas	3,800
Barnett Shale	Central Texas	20
Total Texas		4,620

Tennessee	Tennessee	70

Total		12,290

			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	$	4,401	$	4,401	$	—	$	—	$	—
APL standby letters of credit		4,177		4,177		—		—		—
APL surety bonds		10,727		3,502		7,223		2		—
APL purchase commitments		179,135		179,135		—		—		—
APL throughput contracts		191,403		20,717		47,732		38,640		84,314
ARP other commercial commitments⁽¹⁾		39,731		20,101		8,203		4,555		6,872
Total commercial commitments	$	429,574	$	232,033	$	63,158	$	43,197	$	91,186

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

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

Production			Average Fixed Price
Period	Commodity	Volumes⁽¹⁾	($/Volume)

2015	Natural gas	27,010,000		4.18
2016	Natural gas	13,800,000		4.15
2017	Natural gas	6,600,000		4.11
2015	NGLs	71,442,000		1.22
2016	NGLs	34,650,000		1.03
2017	NGLs	10,080,000		1.04
2015	Crude oil	210,000		90.26
2016	Crude oil	30,000		90.00
Total fixed price swaps
2015	NGLs	3,150,000		0.94
2015	Crude oil	270,000		89.18
2015	NGLs	1,260,000		1.28

	December 31,						Estimated Useful Lives In Years
		2014			2013
Gross Carrying Amount:
Customer contracts and relationships	$	871,072		$	891,072			2–15
Partnership management and operating contracts		14,344			14,344			13
	$	885,416		$	905,416
Accumulated Amortization:
Customer contracts and relationships	$	(274,811	)	$	(194,801	)
Partnership management and operating contracts		(13,653	)		(13,381	)
	$	(288,464	)	$	(208,182	)
Net Carrying Amount:
Customer contracts and relationships	$	596,261		$	696,271
Partnership management and operating contracts		691			963
	$	596,952		$	697,234

	Years Ended December 31,
Continuing Operations:	2014			2013			2012
Net loss	$	(465,390	)	$	(228,598	)	$	(16,881	)
Loss (income) attributable to non-controlling interests		273,132			153,231			(35,532	)
Net loss attributable to common limited partners		(192,258	)		(75,367	)		(52,413	)
Less: Net income attributable to participating securities – phantom units⁽¹⁾		—			—			—
Net loss utilized in the calculation of net loss attributable to common limited partners per unit	$	(192,258	)	$	(75,367	)	$	(52,413	)

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



Assets:
Prepaid expenses and other		4,041
Property, plant and equipment		405,876
Other assets, net		2,888
Total assets acquired	$	412,805
Liabilities:
Accrued liabilities		2,117
Asset retirement obligation		1,305
Total liabilities assumed		3,422
Net assets acquired	$	409,383



Assets:
Prepaid expenses and other		$5,268
Property, plant and equipment		723,842

Total current assets		$729,110

Liabilities:
Accounts payable		2,747
Asset retirement obligation		16,728

Total liabilities assumed		19,475

Net assets acquired		$709,635



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



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



Assets:
Property, plant and equipment	$190,946
Liabilities:
Asset retirement obligation	3,903

Net assets acquired	$187,043

Assets:
Cash	$	8,074
Accounts receivable		11,055
Prepaid expenses and other		1,626
Total current assets		20,755
Property, plant and equipment		197,683
Intangible assets		430,000
Goodwill		186,050
Equity method investment in joint ventures		184,327
Total assets acquired	$	1,018,815
Liabilities:
Accounts payable and accrued liabilities		34,995
Other long term liabilities		1,075
Total liabilities assumed		36,070
Net assets acquired		982,745
Less cash received		(8,074	)
Net cash paid for acquisition	$	974,671

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

	December 31,						Estimated Useful Lives
	2014			2013			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	535,893		$	322,217
Pre-development costs		7,378			4,367
Wells and related equipment		3,096,562			2,231,213
Total proved properties		3,639,833			2,557,797
Unproved properties		217,321			211,851
Support equipment		37,359			23,258
Total natural gas and oil properties		3,894,513			2,792,906
Pipelines, processing and compression facilities		3,576,551			2,926,134			2–40
Rights of way		209,140			203,966			20–40
Land, buildings and improvements		19,607			30,216			3–40
Other		47,846			36,752			3–10
		7,747,657			5,989,974
Less – accumulated depreciation, depletion and amortization		(2,078,395	)		(1,079,099	)
	$	5,669,262		$	4,910,875

Years Ended December 31:
2015	$	2,624
2016		2,405
2017		232,200
2018		696,000
2019		385,000
Thereafter		2,250,000
Total principle maturities		3,568,229
Unamortized premiums		4,245
Unamortized discounts		(1,904	)
Total debt	$	3,570,570

	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, 2014
Current portion of derivative assets	$	2,893	$	—		$	2,893
Long-term portion of derivative assets		2,669		—			2,669
Total derivative assets	$	5,562	$	—		$	5,562
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

	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, 2014
Long-term portion of derivative assets	$	—		$	—	$	—
Long-term portion of derivative assets		—			—		—
Total 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	)

Offsetting Derivative Assets	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets
As of December 31, 2014:
Current portion of derivative assets	$	88,007	$	-		$	88,007
Long-term portion of derivative assets		37,398		-			37,398
Total derivative assets, net	$	125,405	$	-		$	125,405
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, net	$	8,953	$	(6,509	)	$	2,444

Offsetting Derivative Liabilities	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, 2014:
Current portion of derivative assets	$	-		$	-	$	-
Long-term portion of derivative assets		-			-		-
Total derivative liabilities, net	$	-		$	-	$	-
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	)
Long-term portion of derivative liabilities		(1,269	)		949		(320	)
Total derivative liabilities, net	$	(18,073	)	$	6,509	$	(11,564	)

	December 31		December 31,
	2014		2013
Current portion of derivative asset	$	232,266	$	2,066
Long-term derivative asset		168,000		30,868
Current portion of derivative liability		—		(17,630	)
Long-term derivative liability		—		(387	)
Total Partnership net asset	$	400,266	$	14,917


	Gallons	Third Party Quotes⁽¹⁾			Adjustments⁽²⁾			Total Amount
As of December 31, 2014
Propane swaps	101,556	$	50,201		$	—		$	50,201
Natural gasoline swaps	14,616		14,859			(367	)		14,492
Total NGL swaps – December 31, 2014	116,172	$	65,060		$	(367	)	$	64,693
As of December 31, 2013
Propane swaps	100,296	$	(10,260	)	$	—		$	(10,260	)
Isobutane 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	)


	Level 3 NGL Swap Fair			Adjustment based upon Regression Coefficient
	Value Adjustments			Lower 95%	Upper 95%	Average
As of December 31, 2014:
Natural gasoline	$	(367	)	0.9714	0.9748	0.9731
Total Level 3 adjustments – December 31, 2014	$	(367	)
As of December 31, 2013:
Isobutane	$	955		1.1184	1.1284	1.1234
Normal butane		322		1.0341	1.0386	1.0364
Natural gasoline		(813	)	0.9727	0.9751	0.9739
Total Level 3 adjustments – December 31, 2013	$	464


	Linefill Valued at Market			Linefill Valued on FIFO			Total NGL Linefill
	Gallons	Amount		Gallons	Amount		Gallons	Amount
Balance –January 1, 2013	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
Deliveries into NGL linefill	4,385		2,919	59,273		38,451	63,658		41,370
NGL linefill sales	(4,629)		(3,917)	(49,335)		(31,470)	(53,964)		(35,387)
Adjustments for linefill contract revision	11,982		9,846	(11,982)		(9,846)	-		-
Net change in NGL linefill valuation⁽¹⁾	-		(5,888)	-		-	-		(5,888)
Balance – December 31, 2014	17,526	$	7,699	9,494	$	6,913	27,020	$	14,612

Years Ended December 31,
2015	$	16,524
2016		11,917
2017		8,216
2018		7,314
2019		1,951
Thereafter		3,415
	$	49,337

Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distributions Paid to Common Limited Partners
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
February 19, 2014	December 31, 2013	$	0.46	$	23,681

May 20, 2014	March 31, 2014	$	0.46	$	23,865
August 19, 2014	June 30, 2014	$	0.49	$	25,435
November 20, 2014	September 30, 2014	$	0.52	$	27,015