10-K 1 d644790d10k.htm 10-K 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

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

For the fiscal year ended December 31, 2013

OR

 

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

For the transition period from                      to                     

Commission file number: 001-32953

 

 

ATLAS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   43-2094238

(State or other jurisdiction or

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

Park Place Corporate Center One

1000 Commerce Drive, Suite 400

Pittsburgh, PA

  15275
(Address of principal executive offices)   Zip code

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

 

 

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

 

Title of each class

 

Name of each exchange on which registered

Common Units representing Limited Partnership Interests   New York Stock Exchange

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

None

Title of class

 

 

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

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

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

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

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

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

 

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

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

The aggregate market value of the voting and non-voting common units held by non-affiliates of the registrant, based on the closing price of such units on the last business day of the registrant’s most recently completed second quarter, June 30, 2013, was approximately $2.4 billion.

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

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


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ATLAS ENERGY, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

               Page  
PART I    Item 1:   

Business

     8   
   Item 1A:   

Risk Factors

     26   
   Item 1B:   

Unresolved Staff Comments

     60   
   Item 2:   

Properties

     61   
   Item 3:   

Legal Proceedings

     68   
   Item 4:   

Mine Safety Disclosures

     68   
PART II    Item 5:   

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

     68   
   Item 6:   

Selected Financial Data

     69   
   Item 7:   

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

     72   
   Item 7A:   

Quantitative and Qualitative Disclosures about Market Risk

     111   
   Item 8:   

Financial Statements and Supplementary Data

     116   
   Item 9:   

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     198   
   Item 9A:   

Controls and Procedures

     198   
   Item 9B:   

Other Information

     200   
PART III    Item 10:   

Directors, Executive Officers and Corporate Governance

     201   
   Item 11:   

Executive Compensation

     211   
   Item 12:   

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

     239   
   Item 13:   

Certain Relationships and Related Transactions, and Director Independence

     243   
   Item 14:   

Principal Accountant Fees and Services

     245   
PART IV    Item 15:   

Exhibits and Financial Statement Schedules

     245   

SIGNATURES

     254   

 

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GLOSSARY OF TERMS

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

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

Bcf. One billion cubic feet.

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

Bpd. Barrels per day.

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

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

Developed acreage. Acres spaced or assigned to productive wells.

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

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

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

Dth/d. Dekatherms per day.

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

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

FASB. Financial Accounting Standards Board.

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

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

GAAP. Generally Accepted Accounting Principles.

GPM. Gallons per minute.

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

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

Mcf. One thousand cubic feet.

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

 

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Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

MLP. Master Limited Partnership.

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

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcfd. One MMcf per day.

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

MMcfed. One MMcfe per day.

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

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

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil and condensate.

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

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

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

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

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

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

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

 

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

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

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

SEC. Securities Exchange Commission.

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

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

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

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

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

 

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FORWARD-LOOKING STATEMENTS

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

 

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

 

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

 

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

 

    changes in the market price of our common units;

 

    future financial and operating results;

 

    economic conditions and instability in the financial markets;

 

    resource potential;

 

    realized natural gas and oil prices;

 

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

 

    the accuracy of estimated natural gas and oil reserves;

 

    the financial and accounting impact of hedging transactions;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

    impact fees and severance taxes;

 

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

 

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

 

    general market, labor and economic conditions and related uncertainties;

 

    the ability to retain certain key customers;

 

    dependence on the gathering and transportation facilities of third parties;

 

    the availability of drilling rigs, equipment and crews;

 

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

 

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

 

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

 

    expirations of undeveloped leasehold acreage;

 

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

 

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

 

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

 

    ability to integrate operations and personnel from acquired businesses;

 

    exposure to new and existing litigations;

 

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

 

    development of alternative energy resources.

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

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

 

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PART I

 

ITEM 1: BUSINESS

General

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

 

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

 

    Atlas Pipeline Partners, L.P. (“APL”), a publicly-traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services in the southwestern region of the United States;

 

    Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At December 31, 2013, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot; and

 

    Certain natural gas and oil producing assets.

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

Atlas Resource Partners Overview

In February 2012, the board of directors of our General Partner (“the Board”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of our natural gas and oil development and production assets at that time and the partnership management business to ARP on March 5, 2012.

Our ownership in ARP consists of the following:

 

    all of the outstanding Class A units, representing 1,368,058 units at December 31, 2013, which entitles us to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP;

 

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

 

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

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

 

    Carrizo Barnett Shale Acquisition – On April 30, 2012, ARP acquired 277 Bcfe of proved reserves, including undeveloped drilling locations, in the core of the Barnett Shale from Carrizo Oil & Gas, Inc. (NASD: CRZO; “Carrizo”), for approximately $187.0 million (the “Carrizo Acquisition”). The assets included 198 gross producing wells generating approximately 31 MMcfed of production at the date of acquisition on over 12,000 net acres, all of which are held by production.

 

    Titan Barnett Shale Acquisition – On July 26, 2012, ARP acquired Titan Operating, L.L.C. (“Titan”), which owned approximately 250 Bcfe of proved reserves and associated assets in the Barnett Shale on approximately 16,000 net acres, which are 90% held by production, for approximately $208.6 million (the “Titan Acquisition”). Titan’s assets are located in close proximity to the assets acquired from Carrizo in the Barnett Shale. Net production from these assets at the date of acquisition was approximately 24 MMcfed, including approximately 370 Bpd of natural gas liquids. ARP believes there are over 300 potential undeveloped drilling locations on the Titan acreage.

 

    Equal Mississippi Lime Acquisition – On April 4, 2012, ARP entered into an agreement with Equal Energy, Ltd. (NYSE: EQU; TSX: EQU; “Equal”), to acquire a 50% interest in Equal’s approximately 14,500 net undeveloped acres in the core of the oil and liquids rich Mississippi Lime play in northwestern Oklahoma for approximately $18.0 million. On September 24, 2012, ARP acquired Equal’s remaining 50% interest in approximately 8,500 net undeveloped acres included in the joint venture, approximately 8 MMcfed of net production in the region at the date of acquisition and substantial salt water disposal infrastructure for $41.3 million (the “Equal Acquisition”). The transaction increased ARP’s position in the Mississippi Lime play to 19,800 net acres in Alfalfa, Grant and Garfield counties in Oklahoma.

 

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    DTE Fort Worth Basin Acquisition – On December 20, 2012, ARP acquired 210 Bcfe of proved reserves in the Fort Worth basin from DTE Energy Company (NYSE: DTE; “DTE”) for $257.4 million. The assets include 261 gross producing wells generating approximately 23 MMcfed of production at the date of acquisition on over 88,000 net acres, approximately 40% of which are held by production and approximately 33% are in continuous development. The acreage position includes approximately 75,000 net acres prospective for the oil and NGL-rich Marble Falls play, in which there are over 700 identified vertical drilling locations. ARP spud approximately 70 vertical wells during 2013 and plans to continue its development during 2014. ARP believes that there are further potential development opportunities through vertical down-spacing and horizontal drilling in the Marble Falls formation. The assets acquired from DTE are in close proximity to ARP’s other assets in the Barnett Shale.

 

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

 

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

Atlas Pipeline Partners Overview

Our ownership of APL consists of the following:

 

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

 

    all of the incentive distribution rights in APL, which entitles us to receive increasing percentages, up to a maximum of 48%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in 2007, we agreed to allocate up to $3.75 million of our incentive distribution rights per quarter back to APL, after we receive an initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”); and

 

    5,754,253 common units, representing an approximate 6.1% limited partner interest in APL.

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

 

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

 

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

 

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

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

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

 

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Within its gathering and processing operations, APL has ownership interests in and operates fourteen natural gas processing plants with aggregate capacity of approximately 1,500 MMcfd located in Oklahoma and Texas; a gas treating facility located in Oklahoma; and approximately 11,200 miles of active natural gas gathering systems located in Oklahoma, Kansas, Tennessee and Texas. APL’s gathering systems gather natural gas from oil and natural gas wells and central delivery points and deliver this gas to processing plants and third-party pipelines.

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

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

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

 

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

 

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

 

    Cardinal Midstream Acquisition – In December 2012, APL acquired 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.9 million in cash, including final purchase price adjustments (the “Cardinal Acquisition”). The assets of these companies represented the majority of the operating assets of Cardinal and include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas as follows:

 

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

 

    approximately 60 miles of gathering pipeline;

 

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

 

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

 

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

 

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

 

    the prospective Stonewall plant, for which construction is in process, with anticipated processing capacity of 120 MMcfd; and

 

    15 miles of NGL pipeline.

 

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

 

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

 

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

 

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

 

    approximately 275 miles of low pressure gathering lines;

 

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

 

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

 

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

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

Lightfoot Overview

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

Our Exploration and Production Operations Overview

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

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

 

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Contractual Revenue Arrangements

Natural Gas and Oil Production

Natural Gas. We and ARP market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the majority of our and ARP’s production areas are as follows:

 

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

 

    Mississippi Lime - Southern Star;

 

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

 

    Raton – ANR, Panhandle, and NGPL;

 

    Black Warrior Basin – Southern Natural;

 

    Arkoma – Enable Gas; and

 

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

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

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

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

For the year ended December 31, 2013, Enterprise Products Operating LLC, Chevron and Empire Pipeline Corporation accounted for approximately 19%, 11% and 10% of ARP’s total natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Drilling Partnerships

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

 

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

 

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

 

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

 

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

 

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Gathering and Processing

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

 

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

 

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

 

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

 

    the contract terms with each producer; and

 

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

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

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

 

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APL typically sells natural gas to purchasers downstream of its processing plants priced at various first-of-month indices as published in Inside FERC. Additionally, APL sells swing gas, which is natural gas sold on a daily basis at various Platt’s Gas Daily midpoint prices. The SouthOK system has access to Enogex, LLC; MarkWest Energy Partners, L.P.’s Arkoma Connector Pipeline; Natural Gas Pipeline Company of America; ONEOK Gas Transportation, LLC and Southern Star Central Gas Pipeline, Inc. Through its Section 311 intrastate transmission pipeline, the SouthTX system has access to Enterprise Intrastate, LLC; Kinder Morgan Tejas Pipeline LLC; Natural Gas Pipeline Company of America; Tennessee Gas Pipeline Company, LLC; Texas Eastern Transmission, LLC; and Transcontinental Gas Pipe Line. The WestOK system has access to Enogex LLC; Panhandle Eastern Pipe Line Company, LP and Southern Star Central Gas Pipeline, Inc. The WestTX system has access to Atmos Energy Corporation; El Paso Natural Gas Company; Kinder Morgan Tejas Pipeline, LLC; and Northern Natural Gas Company.

APL sells its NGL production at SouthOK and WestOK, to ONEOK Hydrocarbon, L.P. (“ONEOK”) under three separate agreements. The WestOK agreement has a term expiring in 2014; the Velma agreement within SouthOK has a term expiring at the end of 2016; and the Arkoma agreement within SouthOK has a term expiring in 2024. APL sells its NGL production at SouthTX, WestTX and the Chaney Dell plant in WestOK to DCP NGL Services, LLC, a subsidiary of DCP Midstream, LLC (“DCP”). We also sell our NGL production at SouthTX to Crosstex Energy Services, L.P. APL has signed agreements with DCP to sell its NGL production from its WestOK and Velma processing facilities upon the expiration of each of the ONEOK agreements. The DCP agreements each have a term of fifteen years. All NGL agreements are priced at the average daily Oil Price Information Service (“OPIS”) price for the month for the selected market, subject to reduction by a “Base Differential” for transportation and fractionation fees and, if applicable, quality adjustment fees.

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

For the year ended December 31, 2013, ONEOK, Tenaska Marketing Ventures, Inc. and DCP accounted for approximately 29%, 17%, and 14%, respectively, of APL’s consolidated total third-party revenues, respectively, excluding the impact of all financial derivative activity, with no other single customer accounting for more than 10% for this period.

Commodity Risk Management

Natural Gas and Oil Production

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

Gathering and Processing

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

 

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

 

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

 

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

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

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

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

Competition

Natural Gas and Oil Production

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

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

Gathering and Processing

In APL’s gathering and processing segment, it competes for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by Access Midstream Partners, L.P.; Caballo Energy, LLC; Carrera Gas Company; Crosstex Energy Services; L.P., DCP Midstream, LLC; Devon Energy Corporation; Duke Energy Corporation; Energy Transfer Partners, L.P.; Enable Midstream Partners, L.P.; Enterprise Products Partners, L.P.; Howard Energy Partners, LLC; Kinder Morgan Energy Partners, L.P.; Lumen Midstream Partners LLC; Mustang Fuel Corporation; ONEOK Field Services Company, LLC; Regency Energy Partners, L.P.; SemGas, L.P.; Southcross Energy Partners, L.P.; Superior Pipeline Company, LLC; Targa Resources Partners L.P.; TexStar Midstream Services, L.P. and West Texas Gas, Inc.

 

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

 

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

 

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

 

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

 

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

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

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

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

 

    fees charged under its contracts;

 

    the quality and efficiency of its operations;

 

    its responsiveness to a customer’s needs; and

 

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

Environmental Matters and Regulation

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

 

    restricting the way waste disposal is handled;

 

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

 

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

 

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

 

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

 

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

 

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

 

    imposing substantial liabilities for pollution resulting from operations; and

 

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

 

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Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

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

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

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

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

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

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

 

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Our and ARP’s operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. APL currently owns or leases, and has in the past owned or leased, numerous properties that for many years were used for the measurement, gathering, field compression and processing of natural gas. Although we, ARP and APL each believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by them or on or under other locations, including off-site locations, where such substances have been taken for disposal. There may be evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us, ARP or APL. However, none of these spills or releases appears to be material to our financial condition and we believe all of them have been or will be appropriately remediated. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our, ARP or APL’s control. These properties, and the substances disposed or released on them, may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination.

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

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

Air Emissions. Our, ARP and APL’s operations are subject to the federal Clean Air Act, as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require obtaining pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Various air quality regulations are periodically reviewed by the EPA and are amended as deemed necessary. The EPA may also issue new regulations based on changing environmental concerns.

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

While we, ARP and APL will likely be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions, we, ARP and APL believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companies.

 

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

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

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

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions, and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us, ARP and APL to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

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

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

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

 

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

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

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

APL’s gathering operations could be adversely affected should it be subject in the future to the application of state or federal regulation of rates and services. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. APL cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate natural gas pipelines in particular. Overall, the legislation attempts to increase supply sources by calling for various studies of the overall resource base and attempting to promote deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the provisions of primary interest to APL as an operator of natural gas gathering lines and sellers of natural gas focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement.

 

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Regarding infrastructure development, the Energy Policy Act includes provisions confirming FERC has exclusive jurisdiction over the siting of liquefied natural gas (“LNG”) terminals; provides for market-based rates for certain new underground natural gas storage facilities placed into service after the date of enactment; shortens depreciable life for gathering facilities; statutorily designates FERC as the lead agency for federal authorizations and permits relating to interstate natural gas pipelines and LNG terminals; provides for the assembly of a consolidated record for all federal decisions relating to necessary authorizations and permits with respect to interstate natural gas pipelines and LNG terminals; and provides for expedited judicial review of any agency action involving the permitting of such facilities and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act on a permit relating to an interstate natural gas pipeline or LNG terminal by a deadline set by FERC as lead agency.

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

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

Much of our and ARP’s natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974 (“SDWA”). This amendment effectively excluded hydraulic fracturing for oil, gas or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on ARP’s business and operations. For instance, the U.S. EPA published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” (“Draft Diesel Guidance”) on May 10, 2012 for public comment through August 23, 2012. In that Draft Diesel Guidance, the EPA asserts SDWA permitting authority over hydraulic fracturing activities that employ the injection of diesel fuel. The EPA submitted its draft guidance to the White House Office of Management and Budget in September 2013. The draft guidance submitted to the White House Office of Management and Budget was not published by the EPA, so it is not clear what changes may have been made to the guidance by the EPA as a result of the comments received during the 2012 public comment period. The EPA has not provided a specific timeframe for the release of the final guidance.

The U.S. Senate and House of Representatives considered legislative bills in the 111th and 112th Sessions of Congress that, if enacted, would have repealed the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act” (“Frac Act”), the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. In 2013, the Frac Act was re-introduced in the 113th Session of Congress. If enacted into law, the legislation as proposed could potentially result in significant regulatory oversight, which may include additional permitting, monitoring, recording, and recordkeeping requirements for us and ARP.

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

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

 

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

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

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

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Act”) was signed into law. The Act requires DOT and the U.S. Government Accountability Office to complete a number of reviews, studies, evaluations, and reports in preparation for potential rulemakings applicable to pipeline facilities. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. PHMSA is considering these and other provisions in the Act and has sought public comment on changes to a number of regulations related to pipeline safety. On September 25, 2013, PHMSA issued a final rule implementing changes in its administrative procedures required by the Act, but the rulemaking process is continuing with respect to aspects of the Act related to pipeline safety regulations. At this time, APL cannot predict what effect, if any, the future application of such regulations might have on its operations, but the midstream natural gas industry could be required as a result to incur additional capital expenditures and increased operating costs.

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

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. The gas processed at APL’s Velma gas plant contains high levels of hydrogen sulfide. ARP conducts its natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. Both APL and ARP employ numerous safety precautions at their respective operations to ensure the safety of their employees. There are various federal and state environmental and safety requirements for handling sour gas, and APL and ARP are in substantial compliance with all such requirements.

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

 

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

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well, while the impact fee for unconventional vertical wells was $10,000 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our and ARP’s wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we and ARP can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and a fee of $0.000667 per Mcf of gas produced and $.00625 per barrel of crude. New Mexico imposes a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax equal to 0.19% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas. Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% of oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, 7% per Mcf of natural gas and a petroleum excise tax of $0.095 on the gross production of oil and gas.

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

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

A number of federal agencies, including but not limited to the EPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, EPA is conducting a study that evaluates any potential impacts of hydraulic fracturing on drinking water and ground water. EPA released a progress report on this study on December 21, 2012 that did not present any conclusions, but notes that results will be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board. The Department of Interior’s Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands on May 24, 2013, and a final rule is expected to be issued in 2014.

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

 

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

 

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

 

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    specific disposal regimens for hydraulic fracturing fluids;

 

    replacement/remediation of contaminated water assets; and

 

    minimum depth of hydraulic fracturing.

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

 

    noise control ordinances;

 

    traffic control ordinances;

 

    limitations on the hours of operations; and

 

    mandatory reporting of accidents, spills and pressure test failures.

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

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

Employees

As of December 31, 2013, we employed 1,074 persons.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports, available through our website at www.atlasenergy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). To view these reports, click on “Investor Relations”, then “SEC Filings”. You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, Pennsylvania 15275, telephone number (412) 489-0006. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

 

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ITEM 1A: RISK FACTORS

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

Risks Relating to Our Business

We may not have sufficient cash to pay distributions.

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

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

 

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

 

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

 

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

 

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

 

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

 

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

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

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

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

 

    our unitholders’ proportionate ownership interest in us will decrease;

 

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

 

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

 

    the ratio of taxable income to distributions may increase; and

 

    the market price of the common units may decline.

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

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

 

    an increase in our operating expenses;

 

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    an increase in general and administrative expenses;

 

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

 

    an increase in working capital requirements.

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

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

 

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

 

    pay distributions or redeem or repurchase our securities;

 

    prepay, redeem or repurchase debt;

 

    make loans, investments and acquisitions;

 

    enter into hedging arrangements;

 

    sell assets;

 

    enter into certain transactions with affiliates; and

 

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

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

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

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

 

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

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

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

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

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

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

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

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

 

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

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

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

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

 

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

 

    an inability to successfully integrate the businesses acquired;

 

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

 

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

 

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

 

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

 

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

 

    unforeseen difficulties encountered in operating in new geographic areas;

 

    customer or key employee losses at the acquired businesses; and

 

    the failure to realize expected growth or profitability.

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

 

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

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

 

    operating a significantly larger combined entity;

 

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

 

    integrating personnel with diverse business backgrounds and organizational cultures;

 

    consolidating operational and administrative functions;

 

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

 

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

 

    customer or key employee loss from the acquired businesses;

 

    a significant increase in indebtedness; and

 

    potential environmental or regulatory liabilities and title problems.

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

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

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

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

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

 

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

 

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

 

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

 

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

 

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

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

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

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

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

We are entitled to receive incentive distributions from APL, through our ownership of Atlas Pipeline GP, with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Atlas Pipeline GP agreed to allocate up to $3.75 million of incentive distributions per quarter back to APL. Atlas Pipeline GP’s incentive distribution rights entitle it to receive percentages increasing up to 48% of all cash distributed by APL, subject to the IDR Adjustment Agreement. Distribution by APL above $0.60 per common unit per quarter would result in Atlas Pipeline GP’s incremental cash distributions to be the maximum 48%. Atlas Pipeline GP’s percentage of the incremental cash distributions reduces from 48% to 23% if APL’s distribution is between $0.53 and $0.60, and to 13% if APL’s distribution is between $0.43 and $0.52, subject in both cases to the effect of the IDR Adjustment Agreement.

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

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

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

 

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

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

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

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

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

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

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

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

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

 

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Risks Related to Our Exploration and Production Operations

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

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

 

    the level of domestic and foreign supply and demand;

 

    the price and level of foreign imports;

 

    the level of consumer product demand;

 

    weather conditions and fluctuating and seasonal demand;

 

    overall domestic and global economic conditions;

 

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

 

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

 

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

 

    technological advances affecting energy consumption;

 

    domestic and foreign governmental relations, regulations and taxation;

 

    the impact of energy conservation efforts;

 

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

 

    the price and availability of alternative fuels.

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

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

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

 

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

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

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

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

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

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

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

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

We and ARP market the majority of our and its natural gas production to gas marketers directly or to third party plant operators who process and market our and ARP’s gas. Crude oil produced from our and ARP’s wells flow directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. Natural gas liquids are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. To the extent these and other key customers reduce the amount of natural gas, crude oil and natural gas liquids they purchase from us or ARP, our and ARP’s revenues and cash available for distributions to unitholders could temporarily decline in the event it is unable to sell to additional purchasers.

 

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

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

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

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

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

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

 

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

 

    unexpected operational events and drilling conditions;

 

    adverse weather conditions;

 

    facility or equipment malfunctions;

 

    title problems;

 

    pipeline ruptures or spills;

 

    compliance with environmental and other governmental requirements;

 

    unusual or unexpected geological formations;

 

    formations with abnormal pressures;

 

    injury or loss of life;

 

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

 

    fires, blowouts, craterings and explosions; and

 

    uncontrollable flows of natural gas or well fluids.

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

 

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

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

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

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

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

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

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

 

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

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

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

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

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Our and ARP’s estimates of future reserves and estimates of future production for its acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by its internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain; thus, proved reserves estimates may exceed actual acquired proved reserves. In connection with our and ARP’s assessments, we and ARP perform a review of the acquired properties that we believe are generally consistent with industry practices. However, such a review may not permit us or ARP to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Neither we nor ARP inspect every well. Even when we or ARP inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we or ARP pay to acquire oil and natural gas properties may exceed the value we or ARP realize.

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

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

We and ARP have acquired and may make additional acquisitions of undeveloped oil and gas properties from time to time, subject to available resources. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and other liabilities and other factors. Generally, it is not feasible for us or ARP to review in detail every individual property involved in a potential acquisition. In making acquisitions, we and ARP generally focus most of the title, environmental and valuation efforts on the properties that we or ARP believe to be more significant, or of higher-value. Even a detailed review of properties and records may not reveal all existing or potential problems, nor would it permit us or ARP to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. In addition, neither we nor ARP inspect in detail every well that we or ARP acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when it performs a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively impact our or ARP’s financial condition and results of operations.

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

 

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

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

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

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

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

 

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

 

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

 

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

 

    In September 2012, the Texas Railroad Commission approved new proposed regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid. In June 2013, the SEC adopted amendments to the Texas Administrative Code regarding casing, cementing, drilling, completion and well control.

 

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

 

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In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. A recent update regarding local land use restrictions in Pennsylvania occurred on December 19, 2013, when the Pennsylvania Supreme Court issued its Robinson Township v. Commonwealth of Pennsylvania ruling, which invalidated a key section of the 2012 Oil and Gas Act that placed limits on the regulatory authority of local governments. While the total impact of the Pennsylvania Supreme Court’s ruling is not clear and will occur over an extended period of time, an immediate impact of the ruling may be increased regulatory impediments and disputes at the local government level. If state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. Generally, federal, state and local restrictions and requirements are applied consistently to similar types of producers (e.g., conventional, unconventional, etc.), regardless of size of the producing company.

Although, to date, the hydraulic fracturing process has not generally been subject to regulation at the federal level, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. A few of these initiatives are listed here, although others may exist now or be implemented in the future. In April 2012, President Obama established an Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources with the purpose of coordinating the policies and activities of agencies regarding unconventional gas development. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act. In May 2012, the EPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. After reviewing comments submitted on the draft guidance, which were due by August 23, 2012, the EPA submitted its draft guidance to the White House Office of Management and Budget in September 2013. EPA’s draft guidance submitted to the White House Office of Management and Budget was not published, so it is not clear what changes may have been made to the guidance by EPA as a result of the comments received during the 2012 public comment period. At present, we are not aware of EPA’s timeframe to release the final guidance. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, the EPA is currently studying the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA issued a progress report regarding the hydraulic fracturing study on December 21, 2012. However, the progress report did not provide any results or conclusions. On December 9, 2013, EPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. Research results are expected to be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board. The EPA has not provided an anticipated date for completion of the report after peer review. The EPA is also proposing to issue a draft criteria document updating the water quality criteria for chloride in summer 2014, and a proposed rule regarding effluent limitation guidelines for natural gas extraction from shale gas in 2014. On May 4, 2012, the U.S. Department of the Interior, Bureau of Land Management proposed a rule that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands. On May 24, 2013, the Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A final rule is expected to be issued in 2014.

 

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Certain members of U.S. Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, and Congress has asked the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing. In addition, Congress requested, the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. On December 16, 2013, the U.S. Energy Information Administration published an abridged version of its Annual Energy Outlook 2014 with projections to 2040 report, with the full report to be released in Spring 2014. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could result in initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or one or more other regulatory mechanisms. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform hydraulic fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could be significantly affected. Some of the potential effects of changes in Federal, state or local regulation of hydraulic fracturing operations could include, but are not limited to, the following: additional permitting requirements, permitting delays, increased costs, changes in the way operations, drilling and/or completion must be conducted, increased recordkeeping and reporting, and restrictions on the types of additives that can be used, among other potential effects that are not listed here. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that ARP is ultimately able to produce from its reserves.

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

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

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

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

 

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

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

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

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

Impact fees and severance taxes could materially increase liabilities.

In an effort to offset budget deficits and fund state programs, many states have imposed impact fees and/or severance taxes on the natural gas industry. In February 2012, Pennsylvania implemented an impact fee for unconventional wells drilled in the Commonwealth. An unconventional gas well is a well that is drilled into an unconventional formation, which would include the Marcellus shale. The impact fee, which changes from year to year, is computed using the prior year’s trailing 12 month NYMEX natural gas price and is based upon a tiered pricing matrix. For example, based upon natural gas prices for 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well and the impact fee for unconventional vertical wells was $10,000 per well. The impact fee is due by April 1 of the year following the year that a horizontal unconventional well is spudded or a vertical unconventional well is put into production. The fee will continue for 15 years for a horizontal unconventional well and 10 years for a vertical unconventional well. ARP estimates that the impact fee for its wells including the wells in its Drilling Partnerships will be in excess of $1.7 million for the year ended December 31, 2013.

 

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Ohio Governor John Kasich has proposed a severance tax on gas, oil and natural gas liquids produced from high-volume producing formations that are recovered through hydraulic fracturing. Under the proposed tax plan, oil and natural gas liquids recovered through hydraulic fracturing in the Utica and Marcellus shales would be taxed at 1.5% of annual gross sales in the first year and 4% per year for each year thereafter. Natural gas would be taxed yearly at 1% of gross sales. The proposed plan also levies a $25,000 up front impact fee for each well drilled in the state. The Governor’s proposal was rejected by the General Assembly, and not included in the State’s biennial budget bill (H.B. 59) adopted on June 30, 2013. The General Assembly is considering an alternative bill, H.B.375, introduced on December 4, 2013, that would significantly change Ohio’s severance tax on the production of oil and gas. The tax on the production of oil and gas from conventional wells would be lowered to $0.10/Bbl oil and $0.015/Mcf natural gas. The tax on the production of oil and gas from unconventional wells would become 1% of net proceeds at the wellhead for both oil and gas for the first five years of production, increasing to 2% thereafter, but dropping again to 1% when production falls below 17 barrels of oil per day per quarter or 100 Mcf gas per day per quarter.

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

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

How we and ARP plan, design, drill, install, operate and abandon natural gas wells and associated facilities are matters subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

 

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

 

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

 

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

 

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

 

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

Complying with these requirements is expected to increase costs and prompt delays in natural gas production. There can be no assurance that we or ARP will be able to obtain all necessary permits and, if obtained, that the costs associated with obtaining such permits will not exceed those that previously had been estimated. It is possible that the costs and delays associated with compliance with such requirements could cause us or ARP to delay or abandon the further development of certain properties.

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

 

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

There is an inherent risk that we or ARP may incur environmental costs and liabilities due to the nature of the businesses and the substances handled. For example, an accidental release from one of our or ARP’s wells could subject it or the applicable subsidiary to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our or ARP’s compliance costs and the cost of any remediation that may become necessary. Neither we nor ARP may be able to recover remediation costs under our insurance policies.

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

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

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

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

 

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

 

    actual prices received for natural gas;

 

    the amount and timing of actual production;

 

    the amount and timing of capital expenditures;

 

    supply of and demand for natural gas; and

 

    changes in governmental regulations or taxation.

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

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

Risks Related to ARP’s Drilling Partnerships

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

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

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

ARP has sponsored limited and general partnerships to finance certain of its development drilling activities. Accordingly, the amount of development activities that ARP will undertake depends in large part upon its ability to obtain investor subscriptions to invest in these partnerships. ARP has raised $150.0 million, $127.1 million and $141.9 million in calendar years 2013, 2012 and 2011, respectively. In the future, ARP may not be successful in raising funds through these Drilling Partnerships at the same levels, and it also may not be successful in increasing the amount of funds it raises. ARP’s ability to raise funds through its Drilling Partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by ARP’s historical track record of generating returns and tax benefits to the investors in its existing partnerships.

In the event that ARP’s Drilling Partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, ARP may have difficulty in maintaining or increasing the level of Drilling Partnership fundraising. In this event, ARP may need to seek financing for drilling activities through alternative methods, which may not be available, or which may be available only on a less attractive basis than the financing it realized through these Drilling Partnerships, or it may determine to reduce drilling activity.

 

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

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

Fee-based revenues may decline if ARP is unsuccessful in sponsoring new Drilling Partnerships.

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

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

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

Risks Related to APL

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

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

 

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

 

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

 

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

 

    the volume of natural gas APL gathers;

 

    efficiency of APL’s gathering systems and processing plants;

 

    expiration of significant contracts;

 

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

 

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

 

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

 

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    the availability of local, intrastate and interstate transportation systems;

 

    the availability of fractionation capacity;

 

    the expenses incurred in providing its gathering services;

 

    the cost of acquisitions and capital improvements;

 

    required principal and interest payments on APL’s debt;

 

    fluctuations in working capital;

 

    prevailing economic conditions;

 

    fuel conservation measures;

 

    alternate fuel requirements;

 

    the strength and financial resources of APL’s competitors;

 

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

 

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

 

    technical advances in fuel economy and energy generation devices.

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

 

    the level of capital expenditures APL makes;

 

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

 

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

 

    APL’s debt service requirements; and

 

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

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

 

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

APL has historically experienced minimal collection issues with its counterparties; however its revenue and receivables are highly concentrated in a few key customers and therefore it is subject to risks of loss resulting from nonpayment or nonperformance by key customers. In an attempt to reduce this risk, APL has established credit limits for each counterparty and it attempts to limit its credit risk by obtaining letters of credit or other appropriate forms of security. Nonetheless, APL has key customers whose credit risk cannot realistically be otherwise mitigated. Furthermore, although APL evaluates the creditworthiness of its counterparties, it may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose APL to an increased risk of nonpayment or other default under its contracts and other arrangements with them. Any material nonpayment or nonperformance by its key customers could impact its cash flow and ability to make required debt service payments and pay distributions.

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

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

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

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

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

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

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

 

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

During 2013, Atoka Midstream, LLC; Chesapeake Energy Corporation; COG Operating LLC; Endeavor Energy Resources LP; Energen Resources Corporation; Laredo Petroleum Inc.; Parsley Energy, LP; Pioneer; SandRidge Exploration and Production, LLC; Vanguard Permian, LLC; Woolsey Operating Company LLC; and XTO Energy Inc. accounted for a significant amount of APL’s natural gas supply. If these producers reduce the volumes of natural gas they supply to APL, its gross margin and cash flow could be reduced unless it obtains comparable supplies of natural gas from other producers.

APL may face increased competition in the future.

APL faces competition for well connections.

 

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

 

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

 

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

 

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

Some of APL’s competitors have greater financial and other resources than it does. If these companies become more active in APL’s service areas, APL may not be able to compete successfully with them in securing new well connections or retaining current well connections. In addition, customers who are significant producers of natural gas may develop their own gathering and processing systems in lieu of using those operated by APL. If APL does not compete successfully, the amount of natural gas it gathers and processes will decrease, reducing its gross margin and cash flow.

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

APL’s gathering systems principally serve as intermediate transportation facilities between wells connected to APL’s systems and the intrastate or interstate pipelines to which it delivers natural gas. APL’s plant tailgate pipelines, including the Driver Residue Pipeline and the APL SouthTex Ttransmission Section 311 pipeline, provide essential links between APL’s processing plants and intrastate and interstate pipelines that move natural gas to market. APL delivers NGLs to intrastate or interstate pipelines at the tailgates of the plants. If one or more of the pipelines or fractionation facilities to which APL delivers natural gas and NGLs has service interruptions, capacity limitations or otherwise cannot or do not accept natural gas or NGLs from APL, and APL cannot arrange for delivery to other pipelines or fractionation facilities, the amount of natural gas APL gathers and processes may be reduced. Since APL’s revenues depend upon the volumes of natural gas it gathers and natural gas and NGLs it sells or transports, this could result in a material reduction in APL’s gross margin and cash flow.

 

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

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

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

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

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

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

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

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

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

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

 

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

 

    difficulties in obtaining capital for additional construction and operating costs;

 

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

 

    additional construction and operating costs exceeding budget estimates;

 

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

 

    difficulties in obtaining consistent supplies of natural gas; and

 

    terms in operating agreements that are not favorable to APL.

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

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

 

    inability to identify suitable acquisition candidates;

 

    inability to make acquisitions on economically acceptable terms for various reasons, including limitations on access to capital and increased competition for a limited pool of suitable assets;

 

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

 

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

 

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

 

    difficulties in integrating operations and systems; and

 

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

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

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

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

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

 

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

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

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

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

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

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

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

 

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

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

 

    perform ongoing assessments of pipeline integrity;

 

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

 

    improve data collection, integration and analysis;

 

    repair and remediate the pipeline as necessary; and

 

    implement preventative and mitigating actions.

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

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

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

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

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

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

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

 

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

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

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

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

Oil and gas operators can be impacted by litigation brought against the agencies which regulate the oil and gas industry. The outcomes of such activities can impact operations.

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

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

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

 

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

 

    inadvertent damage from construction and farm equipment;

 

    leakage of natural gas, NGLs and other hydrocarbons;

 

    fires and explosions;

 

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

 

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

 

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

 

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

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

APL’s assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures. If operations at any of APL’s processing plants were to be curtailed, or closed, whether due to natural catastrophe, accident, environmental regulation, periodic maintenance, or for any other reason, APL’s ability to process natural gas from the relevant gathering system and, as a result, its ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, its gross margin and cash flow could be materially reduced.

Disruption due to political uncertainties, civil unrest or the threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact APL’s results of operations and its ability to raise capital.

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

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

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

Risks Relating to the Ownership of Our Common Units

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

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

 

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

 

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

 

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

 

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    changes in market valuations of similar companies;

 

    departures of key personnel;

 

    commencement of or involvement in litigation;

 

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

 

    variations in the amount of our cash distributions;

 

    future issuances and sales of our units; and

 

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

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

Increases in interest rates could adversely affect our unit price.

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

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

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

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

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

 

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

 

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

 

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

 

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

 

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

 

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

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

Our cash distribution policy limits our ability to grow.

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

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

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

 

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

 

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

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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.

 

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Risks Related to Our Conflicts of Interest

Although we control ARP, APL and our new Development Subsidiary through our ownership of their general partners, each entity’s general partner owes fiduciary duties to them and their unitholders, which may conflict with our interests.

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

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

 

    the allocation of shared overhead expenses;

 

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

 

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

 

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

 

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

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

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

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

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

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

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

 

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Tax Risks to Unitholders

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

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

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

 

ITEM 1B: UNRESOLVED STAFF COMMENTS

None.

 

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ITEM 2: PROPERTIES

Natural Gas, Oil and NGL Reserves

The following tables summarize information regarding our and ARP’s estimated proved natural gas and oil reserves as of December 31, 2013. Proved reserves are the estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our and ARP’s direct ownership interests in oil and gas properties as well as the reserves attributable to ARP’s percentage interests in the oil and gas properties owned by Drilling Partnerships in which ARP owns partnership interests. All of the reserves are located in the United States. We and ARP base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared by Wright & Company, Inc., an independent third-party engineer. We and ARP have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our and ARP’s estimated proved reserves at December 31, 2013 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we and ARP make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our and ARP’s estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 31, 2013 and 2012, and are listed below as of the dates indicated:

 

     December 31,  

Unadjusted Prices(1)

   2013      2012  

Natural gas (per Mcf)

   $ 3.67       $ 2.76   

Oil (per Bbl)

   $ 96.78       $ 94.71   

Natural gas liquids (per Bbl)

   $ 30.10       $ 33.91   

Average Realized Prices, Before Hedge(1) (2)

             

Natural gas (per Mcf)

   $ 3.25       $ 2.53   

Oil (per Bbl)

   $ 95.86       $ 92.26   

Natural gas liquids (per Bbl)

   $ 29.43       $ 31.97   

 

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

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

The preparation of our and ARP’s natural gas, oil and NGL reserve estimates were completed in accordance with prescribed internal control procedures by reserve engineers. For the periods presented, Wright and Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our and ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our and ARP’s senior engineering staff and management, with final approval by the Chief Operating Officer and President.

 

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

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

 

     Proved Reserves at
December 31,
 

Atlas Energy:

   2013      2012  

Proved reserves:

     

Natural gas proved developed reserves (MMcf) (1):

     38,941         —     

Oil proved developed reserves (MBbl)(1):

     —           —     

NGL proved developed reserves (MBbl):

     —           —     

Total developed proved reserves (MMcfe)(1) (2)

     38,941         —     
  

 

 

    

 

 

 

Standardized measure of discounted future cash flows (in thousands)(4)

   $ 40,099       $ —     
  

 

 

    

 

 

 
     Proved Reserves at
December 31,
 

Atlas Resource:

   2013      2012  

Proved reserves:

     

Natural gas reserves (MMcf)(1):

     

Proved developed reserves

     727,927         338,655   

Proved undeveloped reserves(3)

     236,907         235,119   
  

 

 

    

 

 

 

Total proved reserves of natural gas

     964,834         573,774   

Oil reserves (MBbl)(1):

     

Proved developed reserves

     3,458         3,400   

Proved undeveloped reserves(3)

     11,530         5,469   
  

 

 

    

 

 

 

Total proved reserves of oil

     14,988         8,869   
  

 

 

    

 

 

 

NGL reserves (MBbl):

     

Proved developed reserves

     7,676         7,885   

Proved undeveloped reserves(3)

     11,281         8,177   
  

 

 

    

 

 

 

Total proved reserves of NGL

     18,957         16,062   
  

 

 

    

 

 

 

Total proved reserves (MMcfe)(1)

     1,168,507         723,359   
  

 

 

    

 

 

 

Standardized measure of discounted future cash flows (in thousands)(4)

   $ 1,039,192       $ 623,676   
  

 

 

    

 

 

 

 

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(1) “MMcf” represents million cubic feet; “MMcfe” represents million cubic feet equivalents; and “MBbl” represents thousand barrels. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.
(2) At December 31, 2013, there were no proved undeveloped reserves related to our oil and gas properties.
(3) ARP’s ownership in these reserves is subject to reduction as it generally makes capital contributions, which includes leasehold acreage associated with ARP’s proved undeveloped reserves, to its Drilling Partnerships in exchange for an equity interest in these partnerships, which is approximately 30%, which effectively will reduce ARP’s ownership interest in these reserves from 100% to its respective ownership interest as ARP makes these contributions.
(4) Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we and ARP are limited partnerships, no provision for federal or state income taxes has been included in the December 31, 2013 and 2012 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at th time of the reserve estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells on which a relatively major expenditure is required for recompletion.

Proved Undeveloped Reserves (“PUDS”)

PUD Locations. As of December 31, 2013, there were no PUD locations related to our natural gas and oil reserves and ARP had 598 PUD locations totaling approximately 373,773 Bcfe’s of natural gas, oil and NGLs. These PUDS are based on the definition of PUD’s in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

Historically, the primary focus of ARP’s drilling operations has been in the Appalachian Basin. Subsequent to our acquisition in the Arkoma Basin and ARP’s acquisitions in the Barnett Shale and Marble Falls play, the Mississippi Lime play, and the Raton Basin, the Black Warrior Basin and the County Line area of Wyoming during the years ended December 31, 2013 and 2012, we and ARP will continue to integrate those areas and increase our and ARP’s proved reserves through organic leasing as well as drilling on our and ARP’s existing undeveloped acreage.

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

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

Atlas Resource

 

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

 

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

 

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

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

 

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Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which we and ARP have a working interest as of December 31, 2013. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we and ARP have an interest, directly or through ARP’s ownership interests in Drilling Partnerships, and net wells are the sum of our and ARP’s fractional working interests in gross wells, based on the percentage interest ARP owns in the Drilling Partnership that owns the well:

 

     Number of productive wells(1)(2)  

Atlas Energy:

   Gross      Net  

Barnett/Marble Falls:

     

Gas wells

     2         1   

Oil wells

     —           —     
  

 

 

    

 

 

 

Total

     2         1   
  

 

 

    

 

 

 

Coal-bed Methane(3):

     

Gas wells

     584         451   

Oil wells

     —           —     
  

 

 

    

 

 

 

Total

     584         451   
  

 

 

    

 

 

 

Total:

     

Gas wells

     586         452   

Oil wells

     —           —     
  

 

 

    

 

 

 

Total

     586         452   
  

 

 

    

 

 

 
     Number of productive wells(1)(2)  

Atlas Resource:

   Gross      Net  

Appalachia:

     

Gas wells

     7,681         3,767   

Oil wells

     495         355   
  

 

 

    

 

 

 

Total

     8,176         4,122   
  

 

 

    

 

 

 

Coal-bed Methane(3):

     

Gas wells

     2,955         2,172   

Oil wells

     —           —     
  

 

 

    

 

 

 

Total

     2,955         2,172   
  

 

 

    

 

 

 

Barnett/Marble Falls:

     

Gas wells

     569         470   

Oil wells

     52         35   
  

 

 

    

 

 

 

Total

     621         505   
  

 

 

    

 

 

 

Mississippi Lime/Hunton:

     

Gas wells

     66         47   

Oil wells

     —           —     
  

 

 

    

 

 

 

Total

     66         47   
  

 

 

    

 

 

 

Other operating areas(4):

     

Gas wells

     782         240   

Oil wells

     2         1   
  

 

 

    

 

 

 

Total

     784         241   
  

 

 

    

 

 

 

Total:

     

Gas wells

     12,053         6,696   

Oil wells

     549         391   
  

 

 

    

 

 

 

Total

     12,602         7,087   
  

 

 

    

 

 

 

 

(1) There were no exploratory or dry wells drilled by us during the years ended December 31, 2013, 2012 and 2011. There were no exploratory wells drilled by ARP during the years ended December 31, 2013, 2012 and 2011; there were no gross or net dry wells within ARP’s operating areas during the year ended December 31, 2013. During the year ended December 31, 2012, there were 8 gross (3 net) ARP dry wells drilled in the Niobrara shale. During the year ended December 31, 2011, there were 14 gross (5 net) ARP dry wells drilled in the Niobrara shale.
(2) Includes ARP’s proportionate interest in wells owned by 86 Drilling Partnerships for which it serves as managing general partner and various joint ventures. This does not include royalty or overriding interests in 610 ARP wells and 14 of our wells.
(3) Our coal-bed methane includes our production in the Arkoma Basin in eastern Oklahoma. Coal-bed methane for ARP includes its production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming.
(4) Other operating areas include ARP’s production located in the Chattanooga, New Albany and Niobrara shales.

 

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Developed and Undeveloped Acreage

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

 

     Developed acreage (1)      Undeveloped acreage(2)  

Atlas Energy:

   Gross (3)      Net (4)      Gross (3)      Net (4)  

Oklahoma

     143,195         97,194         67,640         28,481   

Arkansas

     1,016         439         368         334   

Texas

     320         63         1,005         197   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     144,531         97,696         69,013         29,012   
  

 

 

    

 

 

    

 

 

    

 

 

 
     Developed acreage (1)      Undeveloped acreage(2)  

Atlas Resource:

   Gross (3)      Net (4)      Gross (3)      Net (4)  

Pennsylvania

     152,297         75,439         2,918         2,918   

New Mexico

     124,862         124,862         447,713         447,713   

Ohio(5)

     110,297         100,044         103,313         100,870   

Texas

     86,097         59,489         69,259         57,532   

Alabama

     57,097         51,897         39,994         37,173   

Indiana

     32,969         24,533         134,084         73,086   

Wyoming

     29,737         5,677         830         156   

Colorado

     24,851         18,242         20,278         20,278   

Tennessee

     20,463         8,471         148,103         145,923   

Oklahoma

     19,366         15,737         3,325         2,012   

New York

     13,254         11,965         22,278         20,256   

Other

     3,291         675         3,625         3,437   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     674,581         497,031         995,720         911,354   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(3) A gross acre is an acre in which we or ARP own a working interest. The number of gross acres is the total number of acres in which we or ARP own a working interest.
(4) Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.
(5) Includes ARP’s Utica Shale natural gas and oil rights on approximately 2,735 acres under new leases taken in Ohio that remain undeveloped.

 

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The leases for our and ARP’s developed acreage generally have terms that extend for the life of the wells, while the leases on our and ARP’s undeveloped acreage have terms that vary from less than one year to five years. There are no concessions for undeveloped acreage as of December 31, 2013. As of December 31, 2013, leases covering approximately 407 of our 29,012 net undeveloped acres, or 1.4%, are scheduled to expire on or before December 31, 2014 while leases covering approximately 22,558 of ARP’s 911,354 net undeveloped acres, or 2.5%, are scheduled to expire on or before December 31, 2014. An additional 4.0% and 0.5% of ARP’s net undeveloped acres are scheduled to expire in each of the years 2015 and 2016, respectively.

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

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

Atlas Pipeline Partners

APL’s principal facilities consist of 14 natural gas processing plants; 18 gas treating facilities; approximately 11,200 miles of active 2 inch to 30 inch diameter natural gas gathering lines; and approximately 2,200 miles of NGL transportation pipeline through its 20% interest in WTLPG. Substantially all of APL’s gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. In a few cases, property for gathering system purposes was purchased in fee. All of APL’s compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

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

Gas Processing Facilities

 

Facility

  

Location

   Year Constructed    Design
Throughput
Capacity
(MMcfd)
     2013
Average
Utilization
Rate
 

Atoka plant

   Atoka County, OK    2006      20      

Coalgate plant

   Coal County, OK    2007      80      

Tupelo plant

   Coal County, OK    2011      120      

Velma plant

   Stephens County, OK    Updated 2003      100      

Velma V-60 plant

   Stephens County, OK    2012      60      
        

 

 

    

 

 

 

Total SouthOK

           380         100 %(1) 
        

 

 

    

 

 

 

Silver Oak I

   Bee County, TX    2012      200      
        

 

 

    

 

 

 

Total SouthTX

           200         66
        

 

 

    

 

 

 

Waynoka I plant

   Woods County, OK    2006      200      

Waynoka II plant

   Woods County, OK    2012      200      

Chaney Dell plant

   Major County, OK    2012      30      

Chester plant

   Woodward County, OK    1981      28      
        

 

 

    

 

 

 

 

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Facility

  

Location

   Year Constructed      Design
Throughput
Capacity
(MMcfd)
     2013
Average
Utilization
Rate
 

Total WestOK

           458         100 %(1) 

Consolidator plant

   Reagan County, TX      2009         150      

Driver plant

   Midland County, TX      2013         200      

Midkiff plant

   Reagan County, TX      1990         60      

Benedum plant

   Upton County, TX      Updated 1981         45      
        

 

 

    

 

 

 

Total WestTX

           455         72
        

 

 

    

 

 

 

Total

           1,493         88 %(1) 
        

 

 

    

 

 

 

 

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

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

Natural Gas Gathering Systems

 

System

   Location    Approximate
Active Miles
of Pipe
 

SouthOK

   Southern Oklahoma and Northern Texas      1,300   

SouthTX

   Southern Central Texas      500   

WestOK

   North Central Oklahoma and Southern Kansas      5,700   

WestTX

   West Texas      3,600   

Tennessee

   Tennessee      70   

Barnett Shale

   Central Texas      20   
     

 

 

 

Total

     11,190   
     

 

 

 

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

 

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

 

ITEM 3: LEGAL PROCEEDINGS

We and our subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See “Item 8: Financial Statements and Supplementary Data – Note 14”.

 

ITEM 4: MINE SAFETY DISCLOSURES

Not applicable.

PART II

 

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

Our common units trade on the New York Stock Exchange under the symbol “ATLS.” At the close of business on February 25, 2014, the closing price of our common limited partner units was $40.64, and there were 189 holders of record of our common limited partner units. The following table sets forth the high and low sales price per unit of our common limited partner units as reported by the New York Stock Exchange and the cash distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2013 and 2012:

 

     High      Low      Cash Distribution
per Common
Limited Partner
Declared(1)
 

Year ended December 31, 2013:

        

Fourth quarter

   $ 55.89       $ 41.79       $ 0.46   

Third quarter

   $ 55.70       $ 44.80       $ 0.46   

Second quarter

   $ 53.60       $ 43.13       $ 0.44   

First quarter

   $ 44.56       $ 34.74       $ 0.31   

Year ended December 31, 2012:

        

Fourth quarter

   $ 36.57       $ 31.15       $ 0.30   

Third quarter

   $ 36.75       $ 29.95       $ 0.27   

Second quarter

   $ 39.35       $ 27.83       $ 0.25   

First quarter

   $ 35.40       $ 23.51       $ 0.25   

 

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

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

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

 

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ITEM 6: SELECTED FINANCIAL DATA

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

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

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

 

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

 

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

 

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

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

 

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

 

     Years Ended December 31,  
     2013     2012     2011     2010     2009  

Statement of operations data:

   (in thousands, except per unit data)  

Revenues:

          

Gas and oil production

   $ 273,906      $ 92,901      $ 66,979      $ 93,050      $ 112,979   

Well construction and completion

     167,883        131,496        135,283        206,802        372,045   

Gathering and processing

     2,139,694        1,219,815        1,329,418        944,609        714,145   

Administration and oversight

     12,277        11,810        7,741        9,716        15,554   

Well services

     19,492        20,041        19,803        20,994        17,859   

Gain (loss) on mark-to-market derivatives

     (28,764     31,940        (20,453     (5,944     (35,815

Other, net

     (6,973     13,440        31,803        17,437        15,295   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     2,577,515        1,521,443        1,570,574        1,286,664        1,212,062   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

          

Gas and oil production

     100,178        26,624        17,100        23,323        25,557   

Well construction and completion

     145,985        114,079        115,630        175,247        315,546   

Gathering and processing

     1,802,618        1,009,100        1,123,051        789,548        605,222   

Well services

     9,515        9,280        8,738        10,822        9,330   

General and administrative

     197,976        165,777        80,584        37,561        38,932   

Chevron transaction expense

     —          7,670        —          —          —     

Depreciation, depletion and amortization

     308,533        142,611        109,373        115,655        119,396   

Asset impairment

     81,880        9,507        6,995        50,669        166,684   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     2,646,685        1,484,648        1,461,471        1,202,825        1,280,667   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (69,170     36,795        109,103        83,839        (68,605

Gain (loss) on asset sales and disposal

     (2,506     (6,980     256,292        (13,676     108,947   

Interest expense

     (132,581     (46,520     (38,394     (90,448     (104,053

Loss on early extinguishment of debt

     (26,601     —          (19,574     (4,359     (2,478
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before tax

     (230,858     (16,705     307,427        (24,644     (66,189

Income tax (benefit) expense

     (2,260     176        —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations

     (228,598     (16,881     307,427        (24,644     (66,189

Income (loss) from discontinued operations

     —          —          (81     321,155        84,148   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     (228,598     (16,881     307,346        296,511        17,959   

 

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     Years Ended December 31,  
     2013     2012     2011     2010     2009  

Statement of operations data:

   (in thousands, except per unit data)  

(Income) loss attributable to non-controlling interests

     153,231        (35,532     (257,643     (245,764     (53,924
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) after non-controlling interests

     (75,367     (52,413     49,703        50,747        (35,965

(Income) loss not attributable to common limited partners (results of operations of the Transferred Business as of and prior to February 17, 2011, the date of acquisition)

     —          —          (4,711     (22,813     40,000   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners.

   $ (75,367   $ (52,413   $ 44,992      $ 27,934      $ 4,035   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

          

Continuing operations

   $ (75,367   $ (52,413   $ 45,002      $ (11,994   $ (7,287

Discontinued operations

     —          —          (10     39,928        11,322   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ (75,367   $ (52,413   $ 44,992      $ 27,934      $ 4,035   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

          

Basic:

          

Income (loss) from continuing operations attributable to common limited partners

   $ (1.47   $ (1.02   $ 0.91      $ (0.43   $ (0.26

Income (loss) from discontinued operations attributable to common limited partners

     —          —          —          1.44        0.41   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ (1.47   $ (1.02   $ 0.91      $ 1.01      $ 0.15   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted(1):

          

Income (loss) from continuing operations attributable to common limited partners

   $ (1.47   $ (1.02   $ 0.88      $ (0.43   $ (0.26

Income (loss) from discontinued operations attributable to common limited partners

     —          —          —          1.44        0.41   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners

   $ (1.47   $ (1.02   $ 0.88      $ 1.01      $ 0.15   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at period end):

                              

Property, plant and equipment, net

   $ 4,910.875      $ 3,502,609      $ 2,093,283      $ 1,849,486      $ 1,831,090   

Total assets

     6,792,641        4,597,194        2,684,771        2,435,262        2,838,007   

Total debt, including current portion

     2,889,044        1,540,343        524,140        601,389        1,262,183   

Total partners’ capital

     3,222,876        2,479,848        1,744,081        1,406,123        1,053,855   

Cash flow data:

                              

Net cash provided by operating activities

   $ 37,608      $ 70,276      $ 88,195      $ 157,253      $ 236,664   

Net cash provided by (used in) investing activities

     (2,496,607     (1,650,505     14,159        502,330        142,637   

Net cash provided by (used in) financing activities

     2,445,720        1,539,633        (25,225     (660,439     (385,483

Capital expenditures

     (718,040     (500,759     (292,750     (139,360     (209,576

 

(1) For the year ended December 31, 2013, approximately 3,995,000 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the year ended December 31, 2012, approximately 2,867,000 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. For the year ended December 31, 2010, approximately 180,000 units were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive. For the year ended December 31, 2009, approximately 187,000 units were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit because the inclusion of such common limited partner units would have been anti-dilutive.

 

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

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

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

BUSINESS OVERVIEW

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

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

 

    Atlas Resource Partners, L.P. (“Atlas Resources” or “ARP”), a publicly-traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities. At December 31, 2013, we owned 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 36.9% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in ARP;

 

    Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and NGL transportation services in the southwestern region of the United States. At December 31, 2013, we owned a 2.0% general partner interest, all of the incentive distribution rights, and an approximate 6.1% limited partner interest in APL;

 

    Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot L.P. (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. At December 31, 2013, we had an approximate 16% general partner interest and 12% limited partner interest in Lightfoot; and

 

    Certain natural gas and oil producing assets.

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

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

 

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

 

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

 

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

 

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

FINANCIAL PRESENTATION

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

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

 

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

 

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

 

    Adjusted the presentation of our consolidated statements of operations for any date prior to February 17, 2011 to reflect the results of operations attributable to the Transferred Business prior to the date of acquisition as a reduction of net income to determine income attributable to common limited partners. However, the Transferred Business’ historical financial statements prior to the date of acquisition do not reflect general and administrative expenses and interest expense. The Transferred Business was not managed by AEI as a separate business segment and did not have identifiable labor and other ancillary costs. The general and administrative and interest expenses of AEI prior to the date of acquisition, including the exploration and production business segment, related primarily to business activities associated with the business sold to Chevron Corporation (“Chevron”) in February 2011 and not activities related to the Transferred Business.

SUBSEQUENT EVENTS

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

 

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Atlas Resource

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

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

Distribution. On January 29, 2014, ARP declared a cash distribution of $0.58 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2013. The $41.8 million distribution, including $2.9 million and $4.4 million to us, as general partner, and preferred limited partners, respectively, was paid on February 14, 2014 to unitholders of record at the close of business on February 10, 2014.

Atlas Pipeline

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

RECENT DEVELOPMENTS

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

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

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

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

 

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

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

Atlas Resource

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

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

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

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

 

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

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

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

Atlas Pipeline

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

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

 

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

 

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

 

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

 

    approximately 275 miles of low pressure gathering lines;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

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

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

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

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

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

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas and Oil Production

Natural Gas. We and ARP market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our and ARP’s gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the majority of our and ARP’s production areas are as follows:

 

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

 

    Mississippi Lime - Southern Star;

 

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

 

    Raton – ANR, Panhandle, and NGPL;

 

    Black Warrior Basin – Southern Natural;

 

    Arkoma – Enable Gas; and

 

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

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

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

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

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

For the year ended December 31, 2013, Enterprise Products Operating LLC, Chevron and Empire Pipeline Corporation accounted for approximately 19%, 11% and 10% of ARP’s total natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Atlas Resources’ Drilling Partnerships

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

 

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

 

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

 

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

 

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

 

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Gathering and Processing

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

 

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

 

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

 

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

 

    the contract terms with each producer; and

 

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

GENERAL TRENDS AND OUTLOOK

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

Natural Gas and Oil Production

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

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

Gathering and Processing

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

 

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

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

RESULTS OF OPERATIONS

Gas and Oil Production

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

 

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

 

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

 

    ARP’s Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas, a hydro-carbon producing shale in which ARP established a position following its acquisitions of assets from Carrizo Oil & Gas, Inc. (“Carrizo”), Titan Operating, LLC (“Titan”) and DTE Energy Company (“DTE”) during 2012;

 

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

 

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

 

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

 

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

 

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

 

     Years Ended December 31,  
     2013      2012      2011  

Atlas Energy:

        

Gross wells drilled:

     2         —           —     

Our share of gross wells drilled:

     1         —           —     

Gross wells turned in line:

     2         —           —     
     Years Ended December 31,  
     2013      2012      2011  

Atlas Resource:

        

ARP gross wells drilled:

     103         105         160   

ARP’s share of gross wells drilled(1):

     66         42         31   

ARP gross wells turned in line:

     117         154         99   

 

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

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

 

     Years Ended December 31,  
     2013      2012      2011  

Production:(1)(2)

        

Atlas Energy:

        

Natural gas (MMcf)

     1,864         —           —     

Oil (000’s Bbls)

     3         —           —     

Natural gas liquids (000’s Bbls)

     1         —           —     
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     1,885         —           —     
  

 

 

    

 

 

    

 

 

 

Atlas Resource:

        

Natural gas (MMcf)

     57,993         25,403         11,462   

Oil (000’s Bbls)

     485         121         112   

Natural gas liquids (000’s Bbls)

     1,268         357         162   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     68,511         28,267         13,108   
  

 

 

    

 

 

    

 

 

 

Total production:

        

Natural gas (MMcf)

     59,857         25,403         11,462   

Oil (000’s Bbls)

     488         121         112   

Natural gas liquids (000’s Bbls)

     1,269         357         162   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     70,396         28,267         13,108   
  

 

 

    

 

 

    

 

 

 

Production per day:(1)(2)

        

Atlas Energy:

        

Natural gas (Mcfd)

     5,106         —           —     

Oil (Bpd)

     7         —           —     

 

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     Years Ended December 31,  
     2013      2012      2011  

Natural gas liquids (Bpd)

     3         —           —     
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     5,164         —           —     
  

 

 

    

 

 

    

 

 

 

Atlas Resource:

        

Natural gas (Mcfd)

     158,886         69,408         31,403   

Oil (Bpd)

     1,329         330         307   

Natural gas liquids (Bpd)

     3,473         974         444   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     187,701         77,232         35,912   
  

 

 

    

 

 

    

 

 

 

Total production per day:

        

Natural gas (Mcfd)

     163,992         69,408         31,403   

Oil (Bpd)

     1,336         330         307   

Natural gas liquids (Bpd)

     3,476         974         444   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

     192,866         77,232         35,912   
  

 

 

    

 

 

    

 

 

 

 

(1)  Production quantities consist of the sum of (i) the proportionate share of production from wells in which we and ARP have a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.
(2)  “MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.

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

 

     Years Ended December 31,  
     2013      2012      2011  

Production revenues (in thousands):

        

Atlas Energy:

        

Natural gas revenue

   $ 6,849       $ —         $ —     

Oil revenue

     241         —           —     

Natural gas liquids revenue

     33         —           —     
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 7,123       $ —         $ —     
  

 

 

    

 

 

    

 

 

 

Atlas Resource:

        

Natural gas revenue

   $ 186,229       $ 70,151       $ 49,096   

Oil revenue

     44,160         11,351         10,057   

Natural gas liquids revenue

     36,394         11,399         7,826   
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 266,783       $ 92,901       $ 66,979   
  

 

 

    

 

 

    

 

 

 

Total production revenues:

        

Natural gas revenue

   $ 193,078       $ 70,151       $ 49,096   

 

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     Years Ended December 31,  
     2013      2012      2011  

Oil revenue

     44,401         11,351         10,057   

Natural gas liquids revenue

     36,427         11,399         7,826   
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 273,906       $ 92,901       $ 66,979   
  

 

 

    

 

 

    

 

 

 

Average sales price:

        

Natural gas (per Mcf):(1)

        

Total realized price, after hedge(2)

   $ 3.48       $ 3.29       $ 4.98   

Total realized price, before hedge(2)

   $ 3.25       $ 2.60       $ 4.53   

Oil (per Bbl):(1)

        

Total realized price, after hedge

   $ 91.02       $ 94.02       $ 89.70   

Total realized price, before hedge

   $ 95.86       $ 91.32       $ 89.07   

Natural gas liquids (per Bbl) total realized price:(1)

   $ 28.71       $ 31.97       $ 48.26   

Production costs (per Mcfe):(1)

        

Atlas Energy:

        

Lease operating expenses

   $ 0.81       $ —         $ —     

Production taxes

     0.22         —           —     

Transportation and compression

     0.53         —           —     
  

 

 

    

 

 

    

 

 

 
   $ 1.56       $ —         $ —     
  

 

 

    

 

 

    

 

 

 

Atlas Resource:

        

Lease operating expenses(3)

   $ 1.09       $ 0.82       $ 1.09   

Production taxes

     0.18         0.12         0.10   

Transportation and compression

     0.24         0.24         0.43   
  

 

 

    

 

 

    

 

 

 
   $ 1.50       $ 1.19       $ 1.61   
  

 

 

    

 

 

    

 

 

 

Total production costs:

        

Lease operating expenses(3)

   $ 1.08       $ 0.82       $ 1.09   

Production taxes

     0.18         0.12         0.10   

Transportation and compression

     0.25         0.24         0.43   
  

 

 

    

 

 

    

 

 

 
   $ 1.50       $ 1.19       $ 1.61   
  

 

 

    

 

 

    

 

 

 

 

(1)  “Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.
(2)  Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for years ended December 31, 2013, 2012 and 2011. Including the effect of this subordination, the average realized gas sales price was $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) and $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging) for years ended December 31, 2013, 2012 and 2011, respectively.
(3)  Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for years ended December 31, 2013, 2012 and 2011. Including the effects of these costs, total lease operating expenses per Mcfe were $1.00 per Mcfe ($1.42 per Mcfe for total production costs), $0.58 per Mcfe ($0.94 per Mcfe for total production costs) and $0.80 per Mcfe ($1.41 per Mcfe for total production costs) for the years ended December 31, 2013, 2012 and 2011, respectively.

 

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

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

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

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

Well Construction and Completion

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

 

     Years Ended December 31,  
     2013      2012      2011  

Drilling partnership investor capital:

        

Raised

   $ 149,967       $ 127,071       $ 141,929   

 

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     Years Ended December 31,  
     2013      2012      2011  

Deployed

   $ 167,883       $ 131,496       $ 135,283   

Gross partnership wells drilled:

        

Marcellus Shale

     —           10         14   

Utica

     3         5         —     

Ohio

     —           7         3   

Barnett/Marble Falls

     51         4         —     

Mississippi Lime/Hunton

     21         11         —     

Chattanooga

     —           —           5   

Niobrara

     —           51         138   
  

 

 

    

 

 

    

 

 

 

Total

     75         88         160   
  

 

 

    

 

 

    

 

 

 

Net partnership wells drilled:

        

Marcellus Shale

     —           10         11   

Utica

     3         5         —     

Ohio

     —           7         3   

Barnett/Marble Falls

     25         2         —     

Mississippi Lime/Hunton

     21         9         —     

Chattanooga

     —           —           5   

Niobrara

     —           51         138   
  

 

 

    

 

 

    

 

 

 

Total

     49         84         157   
  

 

 

    

 

 

    

 

 

 

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

 

     Years Ended December 31,  
     2013      2012      2011  

Average construction and completion:

        

Revenue per well

   $ 3,276       $ 1,444       $ 886   

Cost per well

     2,849         1,253         757   
  

 

 

    

 

 

    

 

 

 

Gross profit per well

   $ 427       $ 191       $ 129   
  

 

 

    

 

 

    

 

 

 

Gross profit margin

   $ 21,898       $ 17,417       $ 19,653   
  

 

 

    

 

 

    

 

 

 

Partnership net wells associated with revenue recognized(1):

        

Marcellus Shale

     4         7         15   

Utica

     5         2         —     

Ohio

     —           8         2   

Barnett/Marble Falls

     24         2         —     

Mississippi Lime/Hunton

     18         7         —     

Chattanooga

     —           2         4   

New Albany/Antrim

     —           —           3   

Niobrara

     —           63         129   
  

 

 

    

 

 

    

 

 

 

Total

     51         91         153   
  

 

 

    

 

 

    

 

 

 

 

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

 

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

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

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

Administration and Oversight

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

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

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

Well Services

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

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

 

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

Gathering and Processing

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

 

     Years Ended December 31,  
     2013     2012     2011  

Gathering and Processing:

      

Atlas Resource:

      

Revenue

   $ 15,676      $ 16,267      $ 17,746   

Expense(1)

     (17,709     (19,056     (20,507
  

 

 

   

 

 

   

 

 

 

Gross Margin

   $ (2,033   $ (2,789   $ (2,761
  

 

 

   

 

 

   

 

 

 

Atlas Pipeline:

      

Revenue(1)

   $ 2,124,018      $ 1,203,548      $ 1,311,672   

Expense

     (1,784,909     (990,044     (1,102,544
  

 

 

   

 

 

   

 

 

 

Gross Margin

   $ 339,109      $ 213,504      $ 209,128   
  

 

 

   

 

 

   

 

 

 

Total: (1)

      

Revenue

   $ 2,139,694      $ 1,219,815      $ 1,329,418   

Expense

     (1,802,618     (1,009,100     (1,123,051
  

 

 

   

 

 

   

 

 

 

Gross Margin

   $ 337,076      $ 210,715      $ 206,367   
  

 

 

   

 

 

   

 

 

 

 

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

Generally, ARP charges a gathering fee to its Drilling Partnership wells equivalent to the fees it remits. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges its Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses within its partnership management segment, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

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

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

 

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

 

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

 

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

 

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

 

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

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

 

     Years Ended December 31,  
     2013      2012      2011  

Pricing:(1)

        

Average sales price:

        

Natural gas sales ($/Mcf)

   $ 3.44       $ 2.62       $ 3.86   

NGL sales ($/gallon)

   $ 0.91       $ 0.90       $ 1.20   

Condensate sales ($/barrel)

   $ 91.90       $ 87.88       $ 90.65   

Volumes:(1)

        

Gathered gas volume (Mcfd)

     1,426,835         1,026,996         592,130   

Processed gas volume (Mcfd)

     1,314,596         922,715         548,932   

Residue gas volume (Mcfd)

     1,112,137         777,605         445,094   

NGL volume (Bpd)

     114,690         76,807         54,120   

Condensate volume (Bpd)

     4,146         3,415         2,821   

 

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

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

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

 

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Gain (Loss) on Mark-to-Market Derivatives

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

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

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

Other, Net

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

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

OTHER COSTS AND EXPENSES

General and Administrative Expenses

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

 

     Years Ended December 31,  
     2013      2012      2011  

General and Administrative expenses:

        

Atlas Energy

   $ 39,052       $ 34,048       $ 16,694   

 

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     Years Ended December 31,  
     2013      2012      2011  

Atlas Resource

     78,063         69,123         27,536   

Atlas Pipeline

     80,861         62,606         36,354   
  

 

 

    

 

 

    

 

 

 

Total

   $ 197,976       $ 165,777       $ 80,584   
  

 

 

    

 

 

    

 

 

 

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

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

Chevron Transaction Expense

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

Depreciation, Depletion and Amortization

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

 

     Year Ended December 31,  
     2013      2012      2011  

Depreciation, depletion and amortization:

        

Atlas Energy

   $ 3,153       $ —         $ —     

Atlas Resource

     136,763         52,582         31,938   

Atlas Pipeline

     168,617         90,029         77,435   
  

 

 

    

 

 

    

 

 

 

Total

   $ 308,533       $ 142,611       $ 109,373   
  

 

 

    

 

 

    

 

 

 

 

 

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

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

 

     Years Ended December 31,  
     2013     2012     2011  

Depletion expense:

      

Total

   $ 132,860      $ 47,000      $ 27,430   

Depletion expense as a percentage of gas and oil production revenue

     49     51     41

Depletion per Mcfe

   $ 1.89      $ 1.66      $ 2.09   

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

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

 

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Asset Impairment

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

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

Gain (Loss) on Asset Sales and Disposals

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

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

 

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Interest Expense

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

 

     Years Ended December 31,  
     2013      2012      2011  

Interest Expense:

        

Atlas Energy

   $ 8,620       $ 565       $ 6,791   

Atlas Resource

     34,324         4,195         —     

Atlas Pipeline

     89,637         41,760         31,603   
  

 

 

    

 

 

    

 

 

 

Total

   $ 132,581       $ 46,520       $ 38,394   
  

 

 

    

 

 

    

 

 

 

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

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

 

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Loss on Early Extinguishment of Debt

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

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

Loss (Income) Attributable to Non-Controlling Interests

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

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

LIQUIDITY AND CAPITAL RESOURCES

General

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

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

 

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

 

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

 

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

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

 

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

 

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

 

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

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

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

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

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

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

 

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

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

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

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

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

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