10-K 1 d896820d10k.htm 10-K 10-K
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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, 2014

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: 001-36725

 

 

Atlas Energy Group, LLC

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   45-3741247

(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, Pennsylvania

  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

 

 

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

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  ¨    No  x

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  ¨    No  ¨

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

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x    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 equity securities held by non-affiliates of the registrant on March 2, 2015, based upon the closing price of $9.07 of the registrant’s common units as reported on the New York Stock Exchange was approximately $227.1 million. The registrant has elected to use March 2, 2015 as the calculation date, which was the initial regular-way trading date of the registrant’s common units on the New York Stock Exchange, since on June 30, 2014 (the last business day of the registrant’s second fiscal quarter), the registrant was a privately-held company.

As of March 23, 2015, there were 26,010,766 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


Table of Contents

ATLAS ENERGY GROUP, LLC 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

     57   
   Item 2:   

Properties

     57   
   Item 3:   

Legal Proceedings

     63   
   Item 4:   

Mine Safety Disclosures

     63   

PART II

   Item 5:   

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

     64   
   Item 6:   

Selected Financial Data

     64   
   Item 7:   

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

     67   
   Item 7A:   

Quantitative and Qualitative Disclosures about Market Risk

     101   
   Item 8:   

Financial Statements and Supplementary Data

     105   
   Item 9:   

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     160   
   Item 9A:   

Controls and Procedures

     160   
   Item 9B:   

Other Information

     163   

PART III

   Item 10:   

Directors, Executive Officers and Corporate Governance

     163   
   Item 11:   

Executive Compensation

     175   
   Item 12:   

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

     204   
   Item 13:   

Certain Relationships and Related Transactions, and Director Independence

     206   
   Item 14:   

Principal Accountant Fees and Services

     210   

PART IV

   Item 15:   

Exhibits and Financial Statement Schedules

     211   

SIGNATURES

     215   

 

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GLOSSARY OF TERMS

Unless the context otherwise requires, references below to “Atlas Energy Group, LLC,” “Atlas Energy Group,” “the Company,” “we,” “us,” “our” and “our company” refer to Atlas Energy Group, LLC and its consolidated subsidiaries. References below to “Atlas Energy” or “Atlas Energy, L.P.” refers to Atlas Energy, L.P. and its consolidated subsidiaries, unless the context otherwise requires.

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.

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

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

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

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 a natural gas liquid stream into its individual components.

GAAP. Generally Accepted Accounting Principles.

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

 

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

Mcf. One thousand cubic feet.

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

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

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

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

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.

NYSE. The New York Stock 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.

 

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

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

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

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

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

SEC. Securities and 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 in this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “might,” “plan,” “potential,” “predict” or “should” 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:

 

    our lack of operating history as a separate public company, and that our historical financial information is not necessarily representative of the results that we would have achieved had we been the owner or operator of our assets and may not be a reliable indicator of our future results;

 

    whether we are able to achieve some or all of the expected benefits of the separation from Atlas Energy;

 

    the fact that our primary assets are our partnership interests, including the IDRs, in ARP and, therefore, our cash flow is dependent on the ability of ARP to make distributions in respect of those partnership interests;

 

    our ability to operate the assets we will acquire in connection with the distribution, and the costs of such operation;

 

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

 

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

 

    changes in the differential between benchmark prices for oil and natural gas and wellhead prices that we and ARP achieve;

 

    effects of partial depletion or drainage by earlier offset drilling on our and ARP’s acreage;

 

    economic conditions and instability in the financial markets;

 

    changes in the market price of our common units;

 

    future financial and operating results;

 

    resource potential;

 

    success in efficiently developing and exploiting our and ARP’s 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 and ARP;

 

    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 our and ARP’s indebtedness that may adversely affect operational flexibility;

 

    effects of debt payment obligations on the distributable cash;

 

    potential changes in tax laws that 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;

 

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    the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

 

    access to sufficient amounts of carbon dioxide for tertiary recovery operations;

 

    impact fees and severance taxes;

 

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

 

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

 

    general market, labor and economic conditions and related uncertainties;

 

    the ability to retain certain key customers;

 

    dependence on the gathering and transportation facilities of third parties;

 

    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 and ARP’s business and operations;

 

    restrictions on hydraulic fracturing;

 

    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;

 

    development of alternative energy resources; and

 

    the effects of a cyber event or terrorist attack.

The foregoing list is not exclusive. Other factors that could cause actual results to differ from those implied by the forward-looking statements in this document are more fully described in “Item 1A: Risk Factors” of this annual report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included or incorporated by reference in this document speak only as of the date on which the statements were made. 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 except as required by law.

 

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PART I

 

ITEM 1: BUSINESS

General

We are a Delaware limited liability company formed in October 2011. At December 31, 2014, we were wholly-owned by Atlas Energy, L.P. (“Atlas Energy”), a then publicly-traded Delaware master limited partnership (NYSE: ATLS). On February 27, 2015, Atlas Energy transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution to its unitholders of our common units representing a 100% interest in us (the “Separation”). We refer to the assets and liabilities that were transferred to us by Atlas Energy in connection with the separation as “New Atlas”. Our common units began trading “regular-way” under the ticker symbol “ATLS” on the New York Stock Exchange on March 2, 2015. Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.

As the Separation was not consummated until after the completion of the historical periods covered by this Form 10-K, we, as the registrant, have provided the combined consolidated financial statements of New Atlas. As such, the remainder of the discussion within this section will reflect the New Atlas business transferred to us on February 27, 2015.

Our assets, assuming the Separation had been completed as of December 31, 2014, consist of:

 

    100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in 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 NGLs, 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;

 

    80.0% general partner interest and a 1.9% limited partner interest in the Development Subsidiary, a partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States (the “Development Subsidiary”);

 

    15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs; and

 

    direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013 (“Direct Gas & Oil Production Assets” or “Direct”).

Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our direct natural gas production business as well as the distributions paid to us by the MLPs in which we own interests. We, together with our predecessors and affiliates, have been involved in the energy industry since 1968. The Atlas Energy personnel which were responsible for managing our assets and capital raising continued to do so and became our employees upon completion of the Separation.

Atlas Resource Partners Overview

In February 2012, the board of directors of Atlas Energy’s general partner approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of Atlas Energy’s natural gas and oil development and production assets at that time and the partnership management business to ARP, which was consummated on March 5, 2012.

Our ownership in ARP consists of the following:

 

    all of the outstanding Class A units, representing 1,819,113 units at December 31, 2014, 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

 

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    an approximate 27.7% limited partner ownership interest (20,962,485 common units and 3,749,986 preferred limited partner units) in ARP at December 31, 2014.

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.

ARP’s primary business objective is to generate growing yet stable cash flows through the development and acquisition of mature, long-lived natural gas, oil and natural gas liquids properties. As of December 31, 2014, ARP’s estimated proved reserves were 1,429 Bcfe, including reserves net to ARP’s equity interest in its Drilling Partnerships. Of ARP’s estimated proved reserves, approximately 77% were proved developed and approximately 71% were natural gas. For the year ended December 31, 2014, ARP’s average daily net production was approximately 270.0 MMcfe. Through December 31, 2014, ARP owns production positions in the following areas:

 

    ARP’s Barnett Shale and Marble Falls play in the Fort Worth Basin in northern Texas where it has ownership interests in approximately 715 wells and 399 Bcfe of total proved reserves with average daily production of 79.9 MMcfe for the year ended December 31, 2014;

 

    ARP’s coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Central Appalachian Basin in southern West Virginia and southwestern Virginia, and the County Line area of Wyoming where it has ownership interests in approximately 3,440 wells and 523 Bcfe of total proved reserves with average daily production of 120.8 MMcfe for the year ended December 31, 2014;

 

    ARP’s Appalachia Basin where it has ownership interests in approximately 8,127 wells and 144 Bcfe of total proved reserves with average daily production of 40.7 MMcfe for the year ended December 31, 2014, including 280 wells in the Marcellus and Utica Shales;

 

    ARP’s Eagle Ford Shale in southern Texas where it has ownership interests in approximately 24 wells and 64 Bcfe of total proved reserves with average daily production of 2.1 Bcfe for the year ended December 31, 2014;

 

    ARP’s Rangely field in northwest Colorado where it has non-operated ownership interests in approximately 400 wells in the Rangely field and 176 Bcfe of total proved reserves with average daily production of 8.3 Bcfe for the year ended December 31, 2014;

 

    ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma where we own 109 Bcfe of total proved reserves with average daily production of 12.7 MMcfe for the year ended December 31, 2014; 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 15 Bcfe of total proved reserves with average daily production of 5.4 MMcfe for the year ended December 31, 2014.

ARP seeks to create substantial value by executing a strategy of acquiring properties with stable, long-life production, relatively predictable decline curves and lower risk development opportunities. Since it began operations in March 2012, ARP has acquired significant net proved reserves and production through the following transactions:

 

    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.

 

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    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”). 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.

 

    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 600 identified vertical drilling locations and further potential development opportunities through vertical down-spacing and horizontal drilling. The assets acquired from DTE are in close proximity to ARP’s other assets in the Barnett Shale.

 

    EP Energy 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”). The coal-bed methane producing natural gas assets included 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 in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. ARP believes there are approximately 1,200 potential undeveloped drilling locations on the acreage acquired.

 

    GeoMet Acquisition. On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. for approximately $97.9 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014 (the “GeoMet Acquisition”). The coal-bed methane producing natural gas assets include approximately 70 Bcfe of proved reserves with over 400 active wells generating 22 MMcfed on the date of acquisition in the Central Appalachian Basin in West Virginia and Virginia.

 

    Rangely Acquisition—On June 30, 2014, ARP completed the acquisition of a 25% non-operated net working interest in oil and NGL producing assets, representing approximately 47 MMBoe of reserves for $409.4 million in cash with an effective date of April 1, 2014 (the “Rangely Acquisition”). The assets are located in the Rangely field in northwest Colorado. The acquired assets are expected to provide ARP with a stable, high margin cash flow stream with a low-decline profile (average 3-4% annual decline rate over the past 15 years). The asset position is a tertiary oil recovery project using CO2 flood activity, and the production mix is 90% oil, with the remainder coming from NGLs. Chevron Corporation (NYSE: CVX; “Chevron”) will continue as operator of the assets.

 

    Eagle Ford Acquisition—On November 5, 2014, ARP and our Development Subsidiary completed the acquisition of interests in oil and natural gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas, including 4,000 operated gross acres and net reserves of 12 MMBoe as of July 1, 2014 (the “Eagle Ford Acquisition”). The purchase price was $339.2 million, of which $179.5 million was paid at closing by ARP and $19.7 million was paid by our Development Subsidiary, and approximately $140.0 million will be paid over the four quarters following closing. ARP will pay approximately $24.0 million of the deferred portion of the purchase price in three quarterly installments beginning March 31, 2015. Our Development Subsidiary will pay approximately $116.0 million of the deferred portion purchase price in four quarterly installments following closing. ARP may pay up to $20.0 million of our deferred portion of the purchase price with the issuance of its Class D Cumulative Redeemable Perpetual Preferred Units at a price of $25.00 per unit (“Class D ARP Preferred Units”). The acquisition has an effective date of July 1, 2014.

 

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Development Subsidiary Overview

During the year ended December 31, 2013, Atlas Energy formed a new subsidiary partnership to conduct natural gas and oil operations initially in the mid-continent region of the United States, specifically in the Marble Falls formation in the Fort Worth Basin and the Mississippi Lime area of the Anadarko Basin in Oklahoma.

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

At December 31, 2014, the Development Subsidiary had completed 2 wells in the Eagle Ford and 15 wells in the Marble Falls and Mississippi Lime. At December 31, 2014, after giving effect to the Separation, we owned an 1.9% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2% of the cash distributed without any obligation to make further capital contributions.

Lightfoot Overview

Lightfoot is a private investment vehicle that focuses on investing directly in master limited partnership-qualifying businesses and assets. Lightfoot investors include affiliates of, and funds under management by, GE EFS, us, BlackRock Investment Management, LLC, Magnetar Financial LLC, CorEnergy Infrastructure Trust, Inc. and Triangle Peak Partners Private Equity, LP. As of December 31, 2014, after giving effect to the Separation, we own an approximate 15.9% interest in Lightfoot’s general partner and a 12.0% interest in Lightfoot’s limited partner.

Lightfoot’s stated strategy is to make investments by partnering with, promoting and supporting strong management teams to build growth-oriented businesses or industry verticals. Lightfoot provides extensive financial and industry relationships and significant master limited partnership experience, which assist in growth via acquisitions and development projects by identifying:

 

    efficient operating platforms with deep industry relationships;

 

    significant expansion opportunities through add-on acquisitions and development projects;

 

    stable cash flows with fee-based income streams, limited commodity exposure and long-term contracts; and

 

    scalable platforms and opportunities with attractive fundamentals and visible future growth.

On November 6, 2013, ARCX, a master limited partnership owned and controlled by Lightfoot Capital Partners, L.P., began trading publicly on the NYSE. 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. Lightfoot has a significant interest in ARCX through its ownership of a 40.3% limited partner interest, Lightfoot Capital Partners, G.P., the general partner, and all of Lightfoot’s incentive distribution rights. Lightfoot intends to utilize ARCX to facilitate future organic expansions and acquisitions for its energy logistics business.

Direct Natural Gas and Oil Production Overview

On July 31, 2013, Atlas Energy 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”). As a result of Arkoma Acquisition, and after giving effect to the Separation, we have ownership interests in approximately 600 wells in the Arkoma Basin in eastern Oklahoma with average daily production of 5.1 MMcfe for the year ended December 31, 2014.

 

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Our operations include three reportable operating segments: ARP, New Atlas and Corporate and other (see “Item 8: Financial Statements and Supplementary Data – Note 16”).

SUBSEQUENT EVENTS

Term Loan Credit Facilities. On February 27, 2015, we entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto (the “Credit Agreement”). The Credit Agreement provides for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30 million (the “Interim Term Loan Facility”) and a Secured Senior Term A Loan Facility in an aggregate principal amount of approximately $97.8 million (the “Term A Loan Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The Interim Term Loan Facility matures on August 27, 2015 and the Term A Loan Facility matures on February 26, 2016. Our obligations under the Term Loan Facilities are secured on a first priority basis by security interests in all of our material subsidiaries, including all equity interests directly held by us and all tangible and intangible property. Borrowings under the Term Loan Facilities bear interest, at our option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by us for Eurodollar Loans and quarterly for ABR Loans.

We have the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility is repaid prior to the Term A Loan Facility. Subject to certain exceptions, we may also be required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

 

    if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, we must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

 

    if we dispose of all or any portion of the Arkoma assets (as defined in the Credit Agreement), we must prepay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

 

    if we or any of our restricted subsidiaries dispose of property or assets (including equity interests), we must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

 

    if we incur any debt or issue any equity, we must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

The Credit Agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. The Credit Agreement also requires that the Total Leverage Ratio (as defined in the Credit Agreement) be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

 

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Preferred Unit Purchase Agreement. On February 26, 2015, we entered into the Series A Preferred Unit Purchase Agreement (the “Series A Purchase Agreement”) with certain members of our management, two management members of the Board and an outside investor (the “purchasers”), pursuant to which, on February 27, 2015, we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A preferred units”), to the purchasers for a cash purchase price of $25.00 per unit (the “Private Placement”). We sold the Series A preferred units in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million cash transfer made by us to Atlas Energy required by the Separation agreement with Atlas Energy, which was a condition to the Separation and distribution of our common units (see “General”). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.

Atlas Resource Partners

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

 

    reduces the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million;

 

    permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million;

 

    permits an increase in the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels if the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%;

 

    following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and

 

    revises the maximum ratio of Total Funded Debt to EBITDA to be (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarters ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter.

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

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

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

 

    the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date;

 

    4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

 

    2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

 

    no premium for prepayments made following 36 months after the closing date.

 

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

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

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

Gas and Oil Production

Our consolidated gas and oil production operations consist of various shale plays in the United States, both through ARP and through New Atlas. Our direct gas and oil production results from certain coal-bed methane producing natural gas assets in the Arkoma Basin acquired by Atlas Energy on July 31, 2013 from EP Energy and wells drilled in the Marble Falls play by our Development Subsidiary. As of December 31, 2014, after giving effect to the Separation, we own a 1.9% limited partner interest in our Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions.

ARP has focused its natural gas, oil and NGL production operations in various shale plays throughout the United States, and its production includes direct interest wells and ownership interests in wells drilled through Drilling Partnerships. When ARP drills through a Drilling Partnership, it receives an interest in each Drilling Partnership proportionate to the value of ARP’s coinvestment in it and the value of the acreage ARP contributes to it, typically 30% of the overall capitalization of a particular partnership.

Production Volumes

The following table presents our, ARP’s and our Development Subsidiary’s total net gas, oil and NGL production volumes and production per day during the years ended December 31, 2014, 2013 and 2012:

 

     Years Ended
December 31,
 
     2014      2013      2012  

Production per day:(1)(2)

        

New Atlas Direct:

        

Natural gas (Mcfd)

     11,528         5,085         —    

Oil (Bpd)

     —           —           —    

NGLs (Bpd)

     —           —           —    
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  11,528      5,085      —     
  

 

 

    

 

 

    

 

 

 

Development Subsidiary:

Natural gas (Mcfd)

  691      21      —    

Oil (Bpd)

  117      7      —    

NGLs (Bpd)

  88      3      —    
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  1,920      79     —     
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended
December 31,
 
     2014      2013      2012  

Atlas Resource:

        

Natural gas (Mcfd)

     226,526         158,886         69,408   

Oil (Bpd)

     3,436         1,329         330   

NGLs (Bpd)

     3,802         3,473         974   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  269,958      187,701      77,232   
  

 

 

    

 

 

    

 

 

 

Total production per day:

Natural gas (Mcfd)

  238,745      163,992      69,408   

Oil (Bpd)

  3,553      1,336      330   

NGLs (Bpd)

  3,891      3,476      974   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  283,406      192,866      77,232   
  

 

 

    

 

 

    

 

 

 

 

(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” represents 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.

Drilling Activity

The number of wells we, ARP and our Development Subsidiary drill will vary depending on, among other things, the amount of money we have available and the money raised by ARP through Drilling Partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table sets forth information with respect to the number of wells we and ARP drilled, both gross and for our and ARP’s interest, during the periods indicated (after giving effect to the Separation).

 

     Years Ended
December 31,
 
     2014      2013      2012  

New Atlas Direct:

        

Gross wells drilled

     —           —           —     

Our share of gross wells drilled

     —           —           —     

Gross wells turned in line

     —           —           —     

Net wells turned in line

     —           —           —     

Development Subsidiary:

        

Gross wells drilled

     11        2         —     

Our share of gross wells drilled(1)

     11        2         —     

Gross wells turned in line

     13        2         —     

Net wells turned in line(1)

     13        2         —     

Atlas Resource Partners:

        

Gross wells drilled

     129        103         105   

Our share of gross wells drilled(2)

     67        66         42   

Gross wells turned in line

     119        117         154   

Net wells turned in line(2)

     64        80         43   

 

(1)  Includes our Development Subsidiary’s percentage interest in the wells in which it has a direct ownership interest.
(2)  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.

 

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Neither we, ARP nor the Development Subsidiary operate any of the rigs or related equipment used in our and its drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us, ARP and the Development Subsidiary to streamline operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We and ARP perform regular inspection, testing and monitoring functions on each of our Drilling Partnerships and its operated wells.

As of December 31, 2014, after giving effect to the Separation, we, ARP and the Development Subsidiary had the following ongoing drilling activities:

 

     Gross      Net  
New Atlas Direct:    Spud      Total
Depth
     Completed      Spud      Total
Depth
     Completed  

Mississippi Lime – Horizontal

     7         2         1         3         1         1   

Utica – Horizontal

     4         —           —           1         —           —     

Marble Falls – Vertical

     —           9         3         —           3         1   

Eagle Ford Horizontal

     —           2         —           —           1         —     
     Gross      Net  
Development Subsidiary:    Spud      Total
Depth
     Completed      Spud      Total
Depth
     Completed  

Mississippi Lime – Horizontal

     —           —           —           —           —           —     

Utica – Horizontal

     —           —           —           —           —           —     

Marble Falls – Vertical

     —           —           —           —           —           —     

Eagle Ford Horizontal

     —           8         —           —           8         —     
     Gross      Net  
Atlas Resource Partners:    Spud      Total
Depth
     Completed      Spud      Total
Depth
     Completed  

Mississippi Lime – Horizontal

     7         2         1         3         1         1   

Utica – Horizontal

     4         —           —           2         —           —     

Marble Falls – Vertical

     —           9         3         —           3         1   

Eagle Ford – Horizontal

     —           2         —           —           2         —     

Commodity Risk Management

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 NGLs 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.

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 Zone 4 (200 Leg), Transco Leidy Line, Columbia Appalachia, NYMEX, Transco Zone 5;

 

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    Mississippi Lime—Southern Star;

 

    Barnett Shale and Marble Falls—primarily Waha;

 

    Raton—ANR, Panhandle and NGPL;

 

    Black Warrior Basin—Southern Natural;

 

    Eagle Ford—Transco Zone 1;

 

    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/pipeline charges. The oil and natural gas liquids production of ARP’s Rangely assets flows into a common carrier pipeline and is sold at prevailing market prices, less applicable transportation and oil quality differentials. We and ARP do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as 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, 2014, Tenaska Marketing Ventures, Chevron, Enterprise, and Interconn Resources LLC accounted for approximately 25%, 15%, 14% and 13% of natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Drilling Partnerships

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

 

    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 wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method.

 

    Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with the partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

 

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    Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

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

Competition

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 NGLs.

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.

Market

The availability of a ready market for natural gas and oil, and the price obtained, depends upon numerous factors beyond our control, as described in “Item 1A: Risk Factors—Risks Relating to Our Business.” Product availability and price are the principal means of competition in selling oil and natural gas. During the years ended 2014, 2013 and 2012, neither we nor our predecessors or affiliates experienced problems in selling our natural gas and oil, although prices have varied significantly during those periods.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. In addition, seasonal weather conditions and lease stipulations can limit our and ARP’s drilling and producing activities and other operations in certain areas. These seasonal anomalies may pose challenges for meeting well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. ARP has in the past drilled a greater number of wells during the winter months because it typically received the majority of funds from Drilling Partnerships during the fourth calendar quarter.

 

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Environmental Matters and Regulation

Our, ARP’s and our Development Subsidiary’s operations relating to drilling and waste disposal are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, we, ARP and our Development Subsidiary must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:

 

    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 threatened or 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 siting, drilling, completion, production, and plugging 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

 

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

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

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

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

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

 

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

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

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

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

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

On April 21, 2014, the U.S. Army Corps of Engineers and USEPA proposed a rule that would define ‘Waters of the United States,’ i.e., the scope of waters protected under the Clean Water Act, in light of several U.S. Supreme Court opinions (U.S. v. Riverside Bayview, Rapanos v. United States, and Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers). The U.S. Army Corps of Engineers and USEPA have stated that the proposed rule would enhance protection for nationwide public health and aquatic resources, and increase Clean Water Act program predictability and consistency.

 

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The public comment period concluded on November 14, 2014. USEPA is in the process of reviewing the more than 800,000 comments received on the proposed rule, and has indicated that a final rule may be issued in 2015. As drafted, this proposed rule may increase the costs of compliance and result in additional permitting requirements for some of our, ARP’s or our Development Subsidiary’s existing or future facilities. Additionally, USEPA’s Science Advisory Board released its review of USEPA’s Office of Research and Development’s draft “Connectivity of Streams and Wetlands to Downstream Waters: A Review and Synthesis of the Scientific Evidence” report issued October 17, 2014. USEPA released its final report publicly on January 15, 2015.

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

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

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

While we, ARP and our Development Subsidiary will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to obtain and maintain operating permits and approvals for air emissions, we believe that our, ARP’s and our Development Subsidiary’s operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companies.

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

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

 

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First, USEPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31,514 (June 3, 2010). Both the federal preconstruction review program, known as “PSD,” and the operating permit program are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain the requisite operating permits.

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

Second, USEPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. This subpart was most recently revised in November 2014, when USEPA finalized changes to calculation methods, monitoring and data reporting requirements, and other provisions. Shortly thereafter, in December 2014, USEPA proposed additional revisions to this subpart for public comment. In general, the Greenhouse Gas Reporting Rule requires certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to USEPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us, ARP and our Development Subsidiary to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

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

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus, future regulatory developments could have a positive impact on our, ARP’s and our Development Subsidiary’s businesses to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel. However, compliance with recently revised federal air rules, in addition to prospective compliance with the Obama Administration’s yet to be proposed rules to significantly reduce greenhouse gas emissions from the oil and gas sector, could adversely impact the natural gas industry and our businesses.

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

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

Energy Policy Act. Much of our, ARP’s and our Development Subsidiary’s natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974, or “SDWA.” This amendment effectively excluded hydraulic fracturing for oil, gas or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and

 

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state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on ARP’s business and operations. For instance, USEPA published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” on May 10, 2012. . In February 2014, USEPA released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on USEPA’s previous draft guidance, a factsheet and a memorandum to USEPA’s regional offices regarding implementation of the guidance. The process for implementing USEPA’s final guidance document may vary across states depending on the regulatory authority responsible for implementing the SDWA UIC program in each state.

The U.S. Senate and House of Representatives considered legislative bills in the 111th, 112th, and 113th Sessions of Congress that, if enacted, would have repealed the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act,” or “Frac Act,” the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. The Frac Act was recently re-introduced in the current 114th 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, ARP and our Development Subsidiary.

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

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

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

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2014, the impact fee for qualifying unconventional horizontal wells spudded during 2014 was $50,300 per well, while the impact fee for unconventional vertical wells was $10,100 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources.

States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our , ARP’s and our Development Subsidiary’s wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and oil produced and an oil field clean up regulatory fee of $0.000667 per Mcf of gas produced and $.00625 per barrel of crude. New Mexico imposes, among other taxes, a severance tax of up to 3.75% of the value of oil

 

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and gas produced, a conservation tax of up to 0.24% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas. Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% on oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, up to 7% per Mcf of natural gas and a petroleum excise tax of $0.095 on the gross production of oil and gas.

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

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

A number of federal agencies, including USEPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, USEPA is conducting a study that evaluates any potential effects of hydraulic fracturing on drinking water and ground water. USEPA released a progress report on this study on December 21, 2012 that did not provide any results or conclusions. On December 9, 2013, USEPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. Individual research projects associated with USEPA’s study were published in July 2014. Research results are expected to be released in draft form for review by the public and USEPA Science Advisory Board. USEPA has not provided a specific date for completion of the draft report after peer review, which may occur in 2015. The Department of Interior’s Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands on May 24, 2013. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A revised rule was reportedly sent to the White House Office of Management and Budget review in August 2014, and a final rule is expected to be issued in 2015.

In addition, state and local conservancy districts and river basin commissions have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. State regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include the following:

 

    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;

 

    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 federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for

 

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

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

Employees

We employed approximately 670 persons as of February 27, 2015, the distribution date. Some of our officers may spend a substantial amount of time managing the business and affairs of ARP, our Development Subsidiary and their affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our registration statement on Form 10, our annual report on Form 10-K, 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 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 Securities and Exchange Commission’s website at www.sec.gov. Any of our filings is also available at the Securities and Exchange Commission’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

You should carefully consider each of the following risks, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information in this report. Some of the risks described below relate to our, ARP’s and our Development Subsidiary’s businesses, while others relate principally to the securities markets and ownership of our common units. The risks and uncertainties our company faces are not limited to those set forth in the risk factors described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. In addition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In such case, the trading price of our common units could decline.

Risks Relating to Our Business

We have no operating history as a separate public company, and our historical financial information is not necessarily representative of the results that we would have achieved had we been the owner or operator of our assets and may not be a reliable indicator of our future results.

The historical information in this annual report refers to our business as operated by and integrated with Atlas Energy and is derived from the consolidated financial statements and accounting records of Atlas Energy. Therefore, the historical information does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a separate publicly traded company or as the owner or operator of our assets during the periods presented or those that we will achieve in the future, primarily as a result of the following factors:

 

    Before the Separation, our assets were operated by Atlas Energy, rather than as a separate company. Atlas Energy or one of its affiliates performed various corporate functions for us and/or our assets, including tax administration, cash management, accounting, information services, human resources, ethics and compliance programs, real estate management, investor and public relations, certain governance functions (including internal audit) and external reporting. Our historical financial results reflect allocations of corporate expenses from Atlas Energy for these and similar functions. These allocations may be less than the comparable expenses we would have incurred had we operated as a separate publicly traded company.

 

    The cost of capital for our business may be higher than Atlas Energy’s cost of capital prior to the Separation.

 

    Other significant changes may occur in our cost structure, management, financing and business operations as a result of our operations as a company separate from Atlas Energy managed by our board of directors.

We may not achieve some or all of the expected benefits of the Separation from Atlas Energy.

We may not be able to achieve the full strategic and financial benefits expected to result from the Separation from Atlas Energy, or such benefits may be delayed or not occur at all. These expected benefits include the following:

 

    The Separation will facilitate deeper understanding by investors of the different businesses of Atlas Energy and us, allowing investors to more transparently value the merits, performance and future prospects of each company, which could increase overall unitholder value.

 

    The Separation will create an acquisition currency in the form of units that will enable us to purchase, and to assist ARP in purchasing, developed and undeveloped resources to accelerate growth of our natural gas and oil production and development business. Current industry trends have created a significant opportunity for us to grow, and to assist ARP in growing, through the acquisition of assets being sold to close the funding gap created by the success of low-risk unconventional resources.

 

    The Separation will allow each business to more effectively pursue its own distinct operating priorities and strategies, and will enable the management of both companies to pursue unique opportunities for long-term growth and profitability.

 

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    The Separation will create independent equity structures that will afford each company direct access to capital markets and facilitate the ability to capitalize on its unique growth opportunities.

 

    The Separation will provide investors with two distinct and targeted investment opportunities with different investment and business characteristics, including opportunities for growth, capital structure, business model, and financial returns.

We may not achieve the anticipated benefits for a variety of reasons, including potential loss of synergies (if any) from operating as one company, potential for increased costs, potential disruptions to the businesses as a result of the Separation, potential for the two companies to compete with one another in the marketplace, and both the one-time and ongoing costs of the Separation. If we fail to achieve some or all of the benefits expected to result from the Separation, or if such benefits are delayed, our business, financial conditions and results of operations could be adversely affected.

Our primary assets are our partnership interests, including the IDRs, in ARP and, therefore, our cash flow is dependent on the ability of ARP to make distributions in respect of those partnership interests.

Our primary assets are our partnership interests, including the IDRs, in ARP. The amount of cash that ARP can distribute to its partners, including us, principally depends upon the amount of cash it generates from its operations, which will fluctuate from time to time and will depend on, among other things:

 

    the amount of natural gas and oil ARP produces;

 

    the price at which ARP sells its natural gas and oil;

 

    the level of ARP’s operating costs;

 

    ARP’s ability to acquire, locate and produce new reserves;

 

    the results of ARP’s hedging activities;

 

    the level of ARP’s interest expense, which depends on the amount of ARP’s indebtedness and the interest payable on it; and

 

    the level of ARP’s capital expenditures.

In addition, the actual amount of cash that ARP will have available for distribution will also depend on other factors, some of which are beyond ARP’s control, including:

 

    ARP’s ability to make working capital borrowings to pay distributions;

 

    the cost of acquisitions, if any;

 

    fluctuations in ARP’s working capital needs;

 

    timing and collectability of receivables;

 

    restrictions on distributions imposed by lenders;

 

    the strength of financial markets and our ability to access capital or borrow funds; and

 

    the amount, if any, of cash reserves we establish in our discretion as ARP’s general partner for the proper conduct of ARP’s business.

 

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Because of these factors, we cannot guarantee that ARP will have sufficient available cash to pay a specific level of cash distributions to its partners. You should also be aware that the amount of cash that ARP has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ARP may make cash distributions during periods when it records net losses and may not make cash distributions during periods when it records net income.

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

Our and ARP’s cash distribution policies, consistent with the terms of our limited liability company agreement and ARP’s limited partnership agreement, require that we distribute all of our available cash quarterly. However, our cash distribution policies are 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 future outstanding debt, elimination of future distributions from ARP, the effect of working capital requirements and anticipated cash needs of us or ARP.

 

    Our cash distribution policies are subject to restrictions on distributions under our credit facilities, such as material financial tests and covenants and limitations on paying distributions during an event of default.

 

    Our board of directors has the discretion to establish reserves for the prudent conduct of our and ARP’s business and for future cash distributions to our and ARP’s unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our and ARP’s unitholders.

 

    Our limited liability company agreement, including the cash distribution policy contained in it, may be amended by a vote of the holders of a majority of our common units. ARP’s partnership agreement may be similarly amended.

 

    Even if our cash distribution policies are not amended, the decision to make any distribution is at the discretion of our board of directors.

 

    We and ARP can issue additional units, including units that are senior to our respective common units, without the consent of our unitholders, subject to certain limitations under existing NYSE listing rules, and these additional units would dilute our common unitholders’ ownership interests in us and our ownership interest in ARP.

 

    Under Delaware law, neither we nor ARP may 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 policies and our ability to change them, 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.

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

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

 

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Our cash distribution policy limits our ability to grow.

Because we will 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, and we may not have enough cash to meet our needs if any of the following events occur:

 

    an increase in operating expenses;

 

    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.

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 limited liability company agreement on our ability to issue additional units, including units ranking senior to the common units.

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

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

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include the following:

 

    the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas and oil (such as that produced from our Marcellus Shale properties) on the domestic and global natural gas and oil supply;

 

    the level of industrial and consumer product demand;

 

    weather conditions;

 

    fluctuating seasonal demand;

 

    political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;

 

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

 

    the price level of foreign imports;

 

    actions of governmental authorities;

 

    the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;

 

    inventory storage levels;

 

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    the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;

 

    the price, availability and acceptance of alternative fuels;

 

    technological advances affecting energy consumption;

 

    speculation by investors in oil and natural gas;

 

    variations between product prices at sales points and applicable index prices; and

 

    overall economic conditions, including the value of the U.S. dollar relative to other major currencies.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2014, the NYMEX Henry Hub natural gas index price ranged from a high of $7.92 per MMBtu to a low of $2.75 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $107.62 per Bbl to a low of $53.27 per Bbl. Between January 1, 2015 and March 23, 2015, the NYMEX Henry Hub natural gas index price ranged from a high of $3.23 per MMBtu to a low of $2.58 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $53.53 per Bbl to a low of $43.46 per Bbl. If natural gas and oil prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

Economic conditions and instability in the financial markets could negatively affect our, ARP’s and our Development Subsidiary’s businesses which, in turn, could affect the cash we have to make distributions to our unitholders.

Our, ARP’s and our Development Subsidiary’s 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. Any of these events may adversely affect our, ARP’s and our Development Subsidiary’s revenues and ability to fund capital expenditures and, in the future, may affect the cash that we have available to fund our operations, pay required debt service on our credit facilities and make distributions to our unitholders.

Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our, ARP’s and our Development Subsidiary’s 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 to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively affect our, ARP’s and our Development Subsidiary’s access to liquidity needed for our businesses and affect flexibility to react to changing economic and business conditions. We may be unable to execute our growth strategies, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively affect our businesses.

A weakening of the current economic situation could have an adverse impact on producers, key suppliers or other customers, or on our or ARP’s lenders, causing them to fail to meet their obligations. Market conditions could also affect our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and ARP’s cash flow and ability to pay distributions could be affected 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.

Restrictions in our term loan credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Our term loan credit facility limits our ability to, among other things:

 

    incur or guarantee additional debt;

 

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    redeem or repurchase units or make distributions under certain circumstances;

 

    make certain investments and acquisitions;

 

    incur certain liens or permit them to exist;

 

    enter into certain types of transactions with affiliates;

 

    merge or consolidate with another company; and

 

    transfer, sell or otherwise dispose of assets.

Our term loan credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratios and tests.

The provisions of our term loan credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our term loan credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Our debt obligations could restrict our ability to pay cash distributions and have a negative impact on our financing options and liquidity position.

Our debt obligations could have important consequences to us and our investors, including:

 

    requiring a substantial portion of our cash flow to make interest payments on this debt;

 

    making it more difficult to satisfy debt service and other obligations;

 

    increasing the risk of a future credit ratings downgrade of our debt, which could increase future debt costs and limit the future availability of debt financing;

 

    increasing our vulnerability to general adverse economic and industry conditions;

 

    reducing the cash flow available to fund capital expenditures and other corporate purposes and to grow our business;

 

    limiting our flexibility in planning for, or reacting to, changes in our business and the industry;

 

    placing us at a competitive disadvantage relative to our competitors that may not be as leveraged with debt;

 

    limiting our ability to borrow additional funds as needed or take advantage of business opportunities as they arise; and

 

    limiting our ability to pay cash distributions.

To the extent that we incur additional indebtedness, the risks described above could increase. In addition, our actual cash requirements in the future may be greater than expected. Our cash flow may not be sufficient to repay all of the outstanding debt as it becomes due, and we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms, or at all, to refinance our debt.

 

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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 ARP 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 oil and are considered normal sales of natural gas and oil. We generally limit these arrangements to smaller quantities than those we project to be available at any delivery point.

In addition, we and ARP 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, which we refer to as the Dodd-Frank 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. In addition, these arrangements expose us to risks of financial loss if, among other circumstances:

 

    production is substantially less than expected

 

    a counterparty is unable to satisfy its obligations; or

 

    there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

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

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

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

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

With the objective of enhancing the predictability of future revenues, from time to time we and ARP enter into natural gas, NGLs 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 businesses.

The Dodd-Frank Act is intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. These statutory requirements are implemented through regulation, primarily through rules adopted by the Commodity Futures Trading Commission. Many market participants are newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants are subject to new reporting and recordkeeping requirements. The new regulations may require us to comply with certain clearing and trade-execution requirements in connection with our existing or future derivative activities. As commercial end-users which use swaps to hedge or mitigate commercial risk, rather than for speculative purposes, we and ARP are permitted to opt out of the clearing and exchange trading requirements, but we could nevertheless be exposed to greater liquidity and credit risk with respect to our hedging transactions if we do not use cleared and exchange-traded swaps.

The new regulations could significantly increase the cost of derivative contracts; materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks we and ARP encounter; reduce our and ARP’s ability to monetize or restructure our derivative contracts in existence at that time; and increase our exposure to less creditworthy counterparties. If we and ARP reduce or change the way we use derivative instruments as a result of the legislation or regulations, our and ARP’s results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our and ARP’s ability to plan for and fund capital expenditures. The legislation was also intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our and ARP’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 and ARP’s consolidated financial position, results of operations and/or cash flows.

The scope and costs of the risks involved in our or our subsidiaries’ acquisitions may prove greater than estimated at the time of the acquisition, and our subsidiaries may be unsuccessful in integrating the operations from future acquisitions and realizing the anticipated benefits of these acquisitions.

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.

 

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Our decision to acquire oil and natural gas properties depends in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, seismic data and other information, the results of which are often inconclusive and subject to various interpretations. The scope and cost of these risks may be materially greater than estimated at the time of the acquisition. Our future acquisition costs may also 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.

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

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 the 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 business or future prospects, and result in significant decreases in gross margin and cash flows.

ARP 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 has 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. The payment of distributions on additional ARP common units may increase the risk of ARP being unable to make distributions at its prior per unit distribution levels. To the extent new ARP limited partner units are senior to the ARP 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 will disproportionately affect the amount of cash distributions to which we are entitled.

We are entitled to receive incentive distributions from ARP with respect to any particular quarter only if ARP distributes more than $0.46 per common unit for such quarter. Our incentive distribution rights in ARP entitle us 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 our incremental cash distributions to be the maximum 48%. Our percentage of the incremental cash

 

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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. As a result, lower quarterly cash distributions per share from ARP have the effect of disproportionately reducing the amount of all incentive distributions that we receive as compared to cash distributions we receive on our 2.0% general partner interest in ARP.

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

We are ARP’s general partner and own the incentive distribution rights in ARP that entitle us to receive increasing percentages of cash distributed by ARP as it reaches certain target distribution levels in any quarter. To facilitate acquisitions by ARP, we may elect to limit the incentive distributions we are entitled to receive with respect to a particular acquisition or unit issuance contemplated by ARP. This is because a potential acquisition might not be accretive to ARP’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, the cash flows associated with that acquisition could be accretive to ARP’s common unitholders as well as substantially beneficial to us. In doing so, our board of directors (which is also ARP’s board of directors) would be required to consider obligations to ARP’s investors and its obligations to us.

ARP’s common unitholders have the right to remove us as 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 the ability to manage them.

We currently manage ARP through our ownership of its general partner interest. ARP’s partnership agreement gives common unitholders of ARP the right to remove the general partner of ARP upon the affirmative vote of holders of 66 2/3% of ARP’s outstanding common units. If we were removed as general partner of ARP, we would receive cash or common units in exchange for our 2.0% general partner interest and the incentive distribution rights, but we would lose the ability to manage ARP. Although the common units or cash we would receive are intended under the terms of ARP’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 we are not fully reimbursed or indemnified for obligations and liabilities we incur in managing the business and affairs of ARP, the value of our common units could decline.

In our capacity as the general partner of ARP, we may make expenditures on ARP’s behalf for which we will seek reimbursement from ARP. In addition, under Delaware partnership law, we have, in our capacity as ARP’s general partner, unlimited liability for the obligations of ARP, such as ARP’s debts and environmental liabilities, except for those contractual obligations of ARP that are expressly made without recourse to the general partner. To the extent we incur obligations on behalf of ARP, we are entitled to be reimbursed or indemnified by ARP. If ARP is unable or unwilling to reimburse or indemnify us, we may be unable to satisfy these liabilities or obligations, which would reduce the value of our common units.

If in the future we cease to manage and control ARP 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 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, such as the purchase and sale of 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.

If we had to register as an investment company, we would also be unable to qualify as a partnership for U.S. federal income tax purposes and would be 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 rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced, which would result in a material reduction in distributions to you and a reduction in the value of our common units.

 

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If we fail to develop or 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 common 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 develop and 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 develop or 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 common units.

We may have been able to receive better terms from unaffiliated third parties than the terms provided in our agreements with Atlas Energy.

The agreements related to our Separation from Atlas Energy, including the separation and distribution agreement, employee matters agreement and other agreements, were negotiated in the context of our Separation from Atlas Energy and Atlas Energy’s merger with Targa Resources. We were still part of Atlas Energy at that time and, accordingly, these agreements may not reflect terms that would have been reached between unaffiliated parties. The terms of the agreements that were negotiated in the context of our Separation relate to, among other things, allocation of assets, liabilities, rights, indemnifications and other obligations between Atlas Energy and us as well as certain ongoing arrangements between Atlas Energy and us. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us.

Atlas Energy may fail to perform under various transaction agreements that were executed as part of the Separation.

In connection with the Separation, we and Atlas Energy entered into a separation and distribution agreement, an employee matters agreement and certain other agreements to effect the Separation and distribution and provide a framework for our relationship with Atlas Energy after the Separation. These agreements provide for the allocation between Atlas Energy and us of the employees, assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after our Separation from Atlas Energy and govern the relationship between us and Atlas Energy subsequent to the completion of the Separation. We rely on Atlas Energy to satisfy its performance and payment obligations under these agreements. If Atlas Energy and/or Targa Resources is unable to satisfy Atlas Energy’s obligations under these agreements, including indemnification obligations, we could incur operational difficulties or losses.

A cyber incident or terrorist attack could result in information theft, data corruption, operational disruption and/or financial loss.

We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future cyber or terrorist attacks than other targets in the United States. Deliberate attacks on, or security breaches in our systems or infrastructure, or the systems or infrastructure of third parties or the cloud, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, challenges in maintaining our books and records and other operational disruptions and third party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

 

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Risks Relating to Our, ARP’s and our Development Subsidiary’s Exploration and Production Operations

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

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

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our, ARP’s and our Development Subsidiary’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 can.

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

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

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

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

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

The natural gas and oil industry is capital intensive. Because we distribute our available cash to our unitholders each quarter in accordance with the terms of our limited liability company agreement, and ARP distributes its available cash to its unitholders, we expect that each of us will rely primarily on external financing sources such as commercial bank borrowings and the issuance of debt and equity securities to fund any expansion and investment capital expenditures. If we, ARP or our Development Subsidiary 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 may be unable to increase or maintain our inventories of properties and reserve base, or be forced to curtail drilling or other activities. This could cause our, ARP’s and our Development Subsidiary’s revenues to decline and diminish its and our ability to service any debt that any of us may have at such time. If we, ARP or our Development Subsidiary do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our respective business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on our units.

 

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

We, ARP and our Development Subsidiary market the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market our gas. Crude oil produced from our, ARP’s and our Development Subsidiary’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. 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. For the year ended December 31, 2014, Tenaska Marketing Ventures, Chevron, Enterprise and Interconn Resources LLC accounted for approximately 25%, 15%, 14% and 13% of natural gas, crude oil and natural gas liquids production revenue, respectively, with no other single customer accounting for more than 10% for this period. To the extent these and other key customers reduce the amount of natural gas, crude oil and NGLs they purchase from us, ARP or our Development Subsidiary, our revenues and cash available for distributions to unitholders could temporarily decline in the event we are unable to sell to additional purchasers.

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

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

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

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

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

Our, ARP’s and our Development Subsidiary’s drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our, ARP’s or our Development Subsidiary’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;

 

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

Although we, ARP and our Development Subsidiary maintain insurance against various losses and liabilities arising from operations, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we 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, ARP’s or our Development Subsidiary’s results of operations.

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

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our, ARP’s and our Development Subsidiary’s natural gas and oil reserves and production and, therefore, cash flow and income are highly dependent on our success in efficiently developing and exploiting reserves and economically finding or acquiring additional recoverable reserves. Our, ARP’s and our Development Subsidiary’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, including, for ARP, principally from the sponsorship of new Drilling Partnerships, all of which are subject to the risks discussed elsewhere in this section.

A decrease in commodity prices could subject our, ARP’s and our Development Subsidiary’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, ARP and our Development Subsidiary test our 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 economic interests and our 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 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.

 

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Further declines in the price of commodities may cause the carrying value of our, ARP’s and our Development Subsidiary’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.

Our, ARP’s and our Development Subsidiary’s acquisitions may prove to be worth less than the amount 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, ARP’s and our Development Subsidiary’s estimates of future reserves and estimates of future production for our acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by our internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain, which means that proved reserves estimates may exceed actual acquired proved reserves. We perform a review of the acquired properties that we believe is generally consistent with industry practices. Nevertheless, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we 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 pay to acquire oil and natural gas properties may exceed the value we realize.

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

We, ARP and our Development Subsidiary 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 to review in detail every individual property involved in a potential acquisition. In making acquisitions, we generally focus most of the title, environmental and valuation efforts on the properties that we 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 to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect in detail every well that any of us acquires. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we perform a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively affect our, ARP’s or our Development Subsidiary’s financial condition and results of operations.

Even if we 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, the indemnity may not be fully enforceable, the amount of recoverable losses may be limited by floors and caps, or the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on the ability to recover the costs related any potential problem could materially affect our, ARP’s or our Development Subsidiary’s financial condition and results of operations.

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

Production associated with the assets ARP acquired in the Rangely acquisition is dependent on CO2 tertiary recovery operations in the Rangely Field. The crude oil and NGL production from these tertiary recovery operations depends, in large part, on having access to sufficient amounts of CO2. The ability to produce oil and NGLs from these assets would be hindered if the supply of CO2 was limited due to, among other things, problems with the Rangely Field’s current CO2 producing wells

 

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and facilities, including compression equipment, or catastrophic pipeline failure. Any such supply limitation could have a material adverse effect on the results of operations and cash flows associated with these tertiary recovery operations. ARP’s anticipated future crude oil and NGL production from tertiary operations is also dependent on the timing, volumes and location of CO2 injections and, in particular, on the operator’s ability to increase its combined purchased and produced volumes of CO2 and inject adequate amounts of CO2 into the proper formation and area within the Rangely Field.

Ownership of our, ARP’s and our Development Subsidiary’s oil, gas and NGLs production depends on good title to our respective properties.

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

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

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

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

 

    On December 17, 2014, New York Governor Andrew Cuomo’s administration said it would ban hydraulic fracturing for shale gas development throughout the state. Dr. Howard Zucker, the Acting Commissioner of Health, announced that the state Department of Health completed its long-awaited public health review report, which recommended prohibiting hydraulic fracturing in New York. Dr. Zucker cited significant uncertainties regarding risks to public health in concluding that hydraulic fracturing should not proceed in New York until more research is completed. Based upon the Department of Health report, New York State Department of Environmental Conservation Commissioner Joe Martens announced that it will soon issue a legally-binding findings statement that will prohibit hydraulic fracturing in the state. Martens noted that the public health risks associated with hydraulic fracturing outweigh its potential economic benefits, particularly in light of the number of municipalities that have banned natural gas drilling within their borders.

 

   

Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. On February 14, 2012, legislation was passed in Pennsylvania requiring, among other things, disclosure of chemicals used in hydraulic fracturing. We refer to this legislation as the “2012 Oil and Gas Act.” To implement the new legislative requirements, on December 14, 2013 the Pennsylvania Department of Environmental Protection, which we refer to as 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 update existing requirements regarding containment of regulated substances, waste disposal, site restoration and reporting releases, and 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 submitting water withdrawal information necessary to secure a required water management plan. The public comment period on the proposed amendments to PADEP’s proposed amendments at 25 Pa. Code Chapter 78, Subchapter C closed on March 14, 2014, and PADEP is in the process of reviewing and considering over 24,000 comments received during the comment period. Additionally, PADEP announced in June 2014 that it also intends to propose amendments to its present environmental regulations at 25 Pa. Code Chapter 78, Subchapters D (relating to well drilling, operation and plugging) and H (relating to underground gas storage). PADEP has indicated that it will bifurcate its 25 Pa. Code Chapter 78 regulations into two parts as a result of a legislative bill that passed in July 2014 as a companion to Pennsylvania’s budget for 2014 to 2015. 25 Pa. Code Chapter 78 will apply to conventional wells and 25 Pa. Code Chapter 78A will apply to unconventional wells. In January 2015, PADEP issued the results of its Technologically Enhanced Naturally Occurring Radioactive Materials Study, which analyzed levels of radioactivity

 

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associated with oil and gas development in Pennsylvania. Initiated in January 2013, the study evaluated radioactivity levels in flowback waters, treatment solids, and drill cuttings, in addition to the transportation, storage and disposal of these materials. According to the study, PADEP concluded that there is little potential for harm to workers or the public from radiation exposure due to oil and gas development, as well as provided recommendations for further study to be conducted.

 

    Ohio has in recent years expanded its oil and gas regulatory program. In June 2012, Ohio passed legislation that made several significant amendments to the state’s oil and gas laws, including additional permitting requirements, chemical disclosure requirements, and site investigation requirements for horizontal wells. In June 2013, legislation was adopted imposing sampling requirements and disposal restrictions on certain drilling wastes containing naturally occurring radioactive material and requiring the state regulatory authority to adopt rules on the design and operation of facilities that store, recycle, or dispose of brine or other oil and natural gas related waste materials. In February 2014, the regulatory authority proposed rules imposing detailed construction standards on well pads, and in April 2014, Ohio announced new standard drilling permit conditions to address concerns regarding seismic activity in certain parts of the state.

 

    For wells spudded January 1, 2014 and after, the Texas Railroad Commission adopted new rules regarding well casing, cementing, drilling, completion and well control for ensuring hydraulic fracturing operations do not contaminate nearby water resources. Recent Railroad Commission rules and regulations focus on prevention of waste, as evidenced by regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid approved in September 2012, and more stringent permitting for venting/flaring of casinghead gas and gas well gas beginning in January 2014.

 

    A new West Virginia rule that became effective July 1, 2013 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. In 2014, West Virginia revised its solid waste regulations to allow landfills to increase their tonnage limits specifically for natural gas drilling wastes, along with requiring more stringent controls and radiation testing of landfills located in the state.

In addition to state law, local land use restrictions, such as municipal ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Recent changes regarding local land use restrictions in Pennsylvania occurred because of decisions of the Pennsylvania Supreme and Commonwealth Courts. On December 19, 2013, when the Pennsylvania Supreme Court issued its Robinson Township v. Commonwealth of Pennsylvania ruling, which invalidated key sections of the 2012 Oil and Gas Act that placed limits on the regulatory authority of local governments. Additionally, the Pennsylvania Supreme Court remanded a number of issues to the Commonwealth Court for further decision. On July 17, 2014, the Commonwealth Court ruled on the remanded issues. The cumulative effect of the Supreme and Commonwealth Court rulings is that all of the challenged provisions relating to local ordinances contained in the 2012 Oil and Gas Act are invalid, except for the definitions section and most of the updated preemption language in the 2012 Oil and Gas Act that was included from the 1984 Oil and Gas Act. While the total impact of these rulings are not clear and will occur over an extended period of time, an immediate impact of the rulings has been increased regulatory impediments and disputes at the local government level, as well as validity challenges initiated by private landowners alleging that local ordinances do not adequately protect health, safety, and welfare.

On June 30, 2014, the New York Court of Appeals issued its opinion in Wallach v. Town of Dryden affirming local zoning laws adopted by two upstate municipalities that prohibited oil and gas-related activities within their borders. Specifically, the Court of Appeals ruled that there was nothing within the plain language, statutory scheme and legislative history of the New York Oil, Gas and Solution Mining Law that manifested an intent by the legislature to preempt a municipality’s home rule authority to regulate land use. On October 16, 2014, the New York Court of Appeals denied a request by the petitioner – the bankruptcy trustee for Norse Energy – to re-hear arguments in the case. If state, local or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. Generally, federal, state and local restrictions and requirements are applied consistently to similar types of producers (e.g., conventional, unconventional, etc.), regardless of size of the producing company.

Although, to date, the hydraulic fracturing process has not generally been subject to regulation at the federal level, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. A few of these initiatives are listed here, although others

 

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may exist now or be implemented in the future. In April 2012, President Obama established an Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources with the purpose of coordinating the policies and activities of agencies regarding unconventional gas development. EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act. In May 2012, EPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. In February 2014, EPA released its revised final guidance document on Safe Drinking Water Act underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on EPA’s previous draft guidance, a fact sheet and a memorandum to EPA’s regional offices regarding implementation of the guidance. The process for implementing EPA’s final guidance document may vary across the states depending on the regulatory authority responsible for implementing the Safe Drinking Water Act underground injection control program in each state. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, EPA is currently studying the potential environmental effects of hydraulic fracturing on drinking water and groundwater.

EPA issued a progress report regarding the hydraulic fracturing study on December 21, 2012. However, the progress report did not provide any results or conclusions. On December 9, 2013, EPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. Individual research projects associated with EPA’s study were published in July 2014. Research results are expected to be released in draft form for review by the public and EPA’s Science Advisory Board. EPA has not provided a specific date for completion of the draft report after peer review, which may occur in 2015. In 2013, EPA indicated that it intended to propose a draft water quality criteria document that would update the aquatic life water quality criteria for chloride by the summer of 2014. However, EPA has yet to propose the draft water quality criteria document and it has not provided an updated timeframe for the proposal. EPA announced in its September 2014 “Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans” document that it intends to continue a rulemaking effort to potentially revise the effluent limitation guidelines for the Oil and Gas Extraction Point Source Category to address pretreatment standards for shale gas extraction. EPA proposed in that same document a detailed study of centralized waste treatment facilities that accept oil and gas extraction wastewater. The public comment period on the Preliminary 2014 Effluent Guidelines Program Plan closed on November 17, 2014. EPA is evaluating the comments submitted and will next prepare and issue the Final 2014 Effluent Guidelines Program Plan. On May 4, 2012, the U.S. Department of the Interior, Bureau of Land Management proposed a rule that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands. On May 24, 2013, the Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A revised rule was reportedly sent to the White House Office of Management and Budget review in August 2014, and a final rule is expected to be issued in 2015.

Certain members of the U.S. Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, and Congress has asked the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing. In addition, Congress requested the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. On December 16, 2013, the U.S. Energy Information Administration published an abridged version of its Annual Energy Outlook 2014 with projections to 2040 report, with the full report released on May 7, 2014. The next Annual Energy Outlook is reported to be in March 2015 by U.S. Energy Information Administration. These ongoing proposed studies, depending on their degree of pursuit and any meaningful results obtained, could result in initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or one or more other regulatory mechanisms. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform hydraulic fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by EPA or other federal agencies, our fracturing activities could be significantly affected.

Some of the potential effects of changes in federal, state or local regulation of hydraulic fracturing operations could include the following:

 

    additional permitting requirements and permitting delays;

 

    increased costs;

 

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    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.

Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we, ARP or our Development Subsidiary are ultimately able to produce from our reserves.

The third parties on whom we, ARP and our Development Subsidiary 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, ARP and our Development Subsidiary 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 pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our, ARP’s or our Development Subsidiary’s business, financial condition, results of operations and our ability to make distributions to unitholders.

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

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

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

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

Significant physical effects of climate change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

 

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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, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities or our 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 our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We 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.

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

A significant portion of our, ARP’s and our Development Subsidiary’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, ARP’s and our Development Subsidiary’s operations and financial performance. For example, the 2012 Oil and Gas Act requires the development, submission and approval of a water management plan before withdrawing or using water from water sources in Pennsylvania to drill or hydraulically fracture an unconventional well. The requirements of these plans continue to be modified by proposed amendments to state regulations and agency policies and guidance. For Pennsylvania operations located in the Susquehanna River Basin, the Susquehanna River Basin Commission regulates consumptive water uses, water withdrawals, and the diversions of water into and out of the Susquehanna River Basin, and specific approvals are required prior to initiating drilling activities. In June 2012, Ohio passed legislation that established a water withdrawal and consumptive use permit program in the Lake Erie watershed. If certain withdrawal thresholds are triggered due to water needs for a particular project, we will be required to develop a Water Conservation Plan and obtain a withdrawal permit for that project. West Virginia also requires that if a certain amount of water is withdrawn water management plans are required and/or registration and reporting requirements are triggered.

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

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

In August 2012, EPA published final rules that established new and revised requirements for emissions from oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants to address emissions of hazardous air pollutants frequently associated with oil and natural gas production, processing, transmission and storage activities. The New Source Performance Standards require operators, beginning January 1, 2015, to reduce volatile organic compounds emissions from oil and natural gas production facilities by conducting “green completions” for hydraulic fracturing, that is, recovering rather than venting or flaring the gas and NGLs that come to the surface during completion of the fracturing process. The New Source Performance Standards also established new notification and reporting requirements, more stringent leak detection standards for natural gas processing plants, and specific requirements regarding emissions from compressors, storage tanks, and other sources. In 2013, EPA made significant changes to the New Source Performance Standards applicable to storage vessels, and in December 2014, EPA finalized additional revisions to the New Source Performance Standards, including revisions to the green completion requirements. Compliance with recently revised New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our, ARP’s and our Development Subsidiary’s businesses.

 

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

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. Pennsylvania’s Oil and Gas Act of 2012, passed in February 2012, implemented an impact fee for unconventional wells drilled in the Commonwealth. An unconventional gas well is a well that is drilled into an unconventional formation, which would include the Marcellus Shale. The impact fee, which changes from year to year, is computed using the prior year’s trailing 12- month NYMEX natural gas price and is based upon a tiered pricing matrix. Based upon natural gas prices for 2014, the impact fee for qualifying unconventional horizontal wells spudded during 2014 was $50,300 per well and the impact fee for unconventional vertical wells was $10,100 per well. The impact fee is due by April 1 of the year following the year that a horizontal unconventional well is spudded or a vertical unconventional well is put into production. The fee will continue for 15 years for a horizontal unconventional well and 10 years for a vertical unconventional well. ARP estimates that the impact fee for its wells including the wells in its Drilling Partnerships will be approximately $1.0 million for the year ended December 31, 2014. If new laws implementing additional taxes and fees become applicable, our operating costs may materially increase.

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

Because we, ARP and our Development Subsidiary handle natural gas, NGLs and oil, we 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, ARP and our Development Subsidiary 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, or “RCRA,” and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our, ARP’s and our Development Subsidiary’s facilities;

 

    the federal Comprehensive Environmental Response, Compensation, and Liability Act, or “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 or our Development Subsidiary or at locations to which we 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.

 

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Complying with these requirements is expected to increase costs and prompt delays in natural gas production. There can be no assurance that we 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, ARP or our Development Subsidiary 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 EPA and/or the appropriate state agency. In some cases, 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. EPA, the United States Army Corps of Engineers and the United States Department of Justice have been actively pursuing instances of unpermitted stream and wetland impacts, particularly for activities occurring in West Virginia. We also understand that EPA has taken an increased interest in assessing operator compliance with the Spill Prevention, Control and Countermeasures regulations, set forth at 40 CFR Part 112.

Certain environmental statutes, including RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where certain substances have been disposed of or otherwise released, whether caused by our, ARP’s or our Development Subsidiary’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 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, ARP’s or our Development Subsidiary’s wells could subject us 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 compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under our insurance policies.

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

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

 

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

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

 

    actual prices received for natural gas and oil;

 

    the amount and timing of actual production;

 

    the amount and timing of capital expenditures;

 

    supply of and demand for natural gas and oil; and

 

    changes in governmental regulations or taxation.

The timing of both the production and incurrence of expenses in connection with the development and production of natural gas and oil 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 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 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 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 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 PV-10 and standardized measure.

Risks Relating to ARP’s Drilling Partnerships

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

ARP or one 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.

 

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

ARP has sponsored limited and general partnerships to finance certain of its development drilling activities. Accordingly, the amount of development activities that ARP will undertake depends in large part upon its ability to obtain investor subscriptions to invest in these partnerships. ARP has raised $166.8 in 2014, $150.0 million in 2013 and $127.1 million in 2012. In the future, ARP may not be successful in raising funds through these Drilling Partnerships at these same levels, and it also may not be successful in increasing the amount of funds it raises. ARP’s ability to raise funds through its Drilling Partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by ARP’s historical track record of generating returns and tax benefits to the investors in its existing partnerships.

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

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

Under current federal tax laws, there are tax benefits to investing in Drilling Partnerships, including deductions for intangible drilling costs and depletion deductions. Both the Obama Administration’s budget proposal for fiscal year 2016 and other recently introduced legislation included 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 (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 in future years and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. The repeal of these oil and gas tax benefits, if it happens, would result in a substantial decrease in tax benefits associated with an investment in ARP’s Drilling Partnerships. These or other changes to federal tax law may make investment in the Drilling Partnerships less attractive and, thus, reduce ARP’s ability to obtain funding from this significant source of capital funds.

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

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

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

ARP has agreed to subordinate a portion of its share of production revenues, net of corresponding production costs, to specified returns to the investor partners in the Drilling Partnerships, typically 10% to 12% per year for the first five to eight years of distributions. Thus, ARP’s revenues from a particular Drilling Partnership will decrease if the Drilling Partnership does not achieve the specified minimum return. For the year ended December 31, 2014, $5.3 million of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced ARP’s cash distributions received from the Drilling Partnerships. For the year ended December 31, 2013, the subordinated amount, net or corresponding production costs, was $9.6 million and for the year ended December 31, 2012, it was $6.3 million.

Risks Relating to the Ownership of Our Common Units

We cannot be certain that an active trading market for our common units will develop or be sustained and our unit price may fluctuate significantly. If the unit price declines, you could lose a significant part of your investment.

 

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We cannot guarantee that an active trading market will develop or be sustained for our common units. 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 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;

 

    fluctuations in natural gas and oil prices;

 

    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 quarterly 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 our Development Subsidiary’s financing costs to increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our, ARP’s and our Development Subsidiary’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 our Development Subsidiary’s ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could affect our, ARP’s and our Development Subsidiary’s ability to make cash distributions at our 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.

We may issue additional common units without the consent of our unitholders, which will dilute existing members’ ownership interest in us and may increase the risk that we will not have sufficient available cash to make distributions.

Our limited liability company agreement authorizes us to issue an unlimited number of limited liability company interests of any type without the approval of our unitholders on terms and conditions established by our board of directors at

 

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any time subject to certain limitations under NYSE listing rules. 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.

In addition, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

Certain provisions of our limited liability company 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 liability company 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, and this classified board provision could have the effect of making the replacement of incumbent directors more time consuming and difficult;

 

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

 

    the inability of our common unitholders to call a special meeting;

 

    the inability of our common unitholders to remove directors; and

 

    the ability of our directors, and not unitholders, to fill vacancies on our board of directors.

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

With limited exceptions, our limited liability company agreement restricts the voting rights of unitholders that own 20% or more of our common units.

Our limited liability company agreement prohibits any person or group that owns 20% or more of our common units then outstanding, other than persons who acquire common units with the prior approval of our board of directors, from voting on any matter.

Our unitholders who fail to furnish certain information requested by our board of directors or who our board of directors determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.

 

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We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any member. Our board of directors may require any member or transferee to furnish information about his nationality, citizenship or related status. If a member fails to furnish information about his nationality, citizenship or other related status within a reasonable period after a request for the information or our board of directors determines after receipt of the information that the member is not an eligible citizen, the member may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information.

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

If our board of directors determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our members, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our board of directors may adopt such amendments to our limited liability company agreement as it determines are necessary or appropriate to obtain proof of the U.S. federal income tax status of our members (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rate that can be charged to customers by our subsidiaries or who fails to comply with the procedures instituted by our board of directors to obtain proof of the U.S. federal income tax status.

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 U.S. 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 U.S. 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 U.S. federal income tax purposes or otherwise be subject to U.S. 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.

 

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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 their 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.

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

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

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

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

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

We will 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 will 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 and our Development Subsidiary’s capital and profits interest within a 12-month period will result in the termination of our, ARP’s and our Development Subsidiary’s partnership for U.S. federal income tax purposes.

We will be considered to have terminated our partnership for U.S. 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 our Development Subsidiary will be considered to have terminated their partnerships for U.S. federal income tax purposes if

 

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there is a sale or exchange of 50% or more of the total interest in their capital and profits within a 12-month period. The termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of U.S. 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 U.S. federal income tax rate on ordinary income is 39.6% plus a 3.8% Medicare surtax on investment income. As a result, a unitholder may incur a tax liability in excess of the amount of cash it receives from the sale.

Unitholders may be subject to state and local taxes and return filing requirements, including in states where they do not live, 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 our Development Subsidiary 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 our Development Subsidiary presently anticipate that substantially all of our income will be generated in Alabama, Colorado, Indiana, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, West Virginia and Wyoming. As we make acquisitions or expand our businesses, 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.

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

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

 

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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.

Risks Relating to Our Conflicts of Interest

Although we control ARP and our Development Subsidiary, we owe duties to each such entity and its 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 between us (as the general partner of ARP), on the one hand, and ARP and its limited partners, on the other hand, as well as between the general partner of our Development Subsidiary, on the one hand, and our Development Subsidiary and its limited partners, on the other hand. Our directors and officers and our Development Subsidiary’s general partner each have a duty to manage each limited partnership in a manner beneficial to us, its owner. At the same time, these directors and officers have a duty to manage each partnership in a manner they believe is beneficial to the partnership’s interests. Our board of directors and the board of directors of our Development Subsidiary’s general partner, or our or our Development Subsidiary’s respective 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.

Conflicts of interest may arise in the following situations, among others:

 

    the allocation of shared overhead expenses;

 

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

 

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

 

    the decision as to whether the limited 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 our officers and directors may have actual or potential conflicts of interest because of their positions, and their duties may conflict with those of the officers and directors of ARP and our Development Subsidiary’s general partners.

Our officers and directors have duties to manage our business in a manner beneficial to us but since we are also the general partner of ARP, our directors and officers have duties to manage ARP in a manner beneficial to ARP. Certain of our executive officers and non-independent directors also serve as executive officers and directors of our Development Subsidiary’s general partner, and, as a result, have duties to manage our Development Subsidiary in a manner beneficial to it. Consequently, these directors and officers may encounter situations in which their 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

 

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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 for some of these persons. Their positions, and the ownership of such equity or 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.

Our affiliates and ARP or our Development Subsidiary may in certain circumstances compete with us or with each other, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, and this could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our limited liability company agreement nor the partnership agreements of ARP or our Development Subsidiary prohibit ARP, our Development Subsidiary or our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, our affiliates or ARP or our Development Subsidiary. In addition, ARP, our Development Subsidiary and their affiliates may acquire, develop or dispose of additional assets related to the production and development of oil, natural gas and NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. As a result, competition among these entities could adversely affect our, ARP’s and our Development Subsidiary’s results of operations and cash available for paying required debt service on our credit facilities or making distributions.

Pursuant to the terms of our limited liability company agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our directors or executive officers or any of their affiliates. Some of these executive officers and directors also serve as officers of ARP and our Development Subsidiary. No such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any unitholder for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, ARP, our Development Subsidiary and their affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us on an operations basis.

Our limited liability company agreement eliminates our directors’ and officers’ fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our directors and officers.

Our limited liability company agreement contains provisions that eliminate any fiduciary standards to which our directors and officers and their affiliates could otherwise be held by state fiduciary duty laws. Instead, our directors and officers are accountable to us and our unitholders pursuant to the contractual standards set forth in our limited liability company agreement. Our limited liability company agreement reduces the standards to which our directors and officers would otherwise be held by state fiduciary duty law and contains provisions restricting the remedies available to unitholders for actions taken by our directors or officers or their affiliates. For example, it provides that:

 

    whenever our board of directors or officers make a determination or take, or decline to take, any other action in such capacity, our directors and officers are required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard (including fiduciary standards) imposed by Delaware law or any other law, rule or regulation or at equity;

 

    our directors and officers will not have any liability to us or our unitholders for decisions made in their capacity as a director or officer so long as they acted in good faith, meaning they believed that the decision was not adverse to our interests; and

 

    our directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

 

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It will be presumed that, in making decisions and taking, or declining to take, actions, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. The existence of all conflicts of interest disclosed in our registration statement on Form 10, and any actions of our directors and officers taken in connection with such conflicts of interest, have been approved by all of our unitholders pursuant to our limited liability company agreement.

By accepting or purchasing a common unit, a unitholder agrees to be bound by the provisions of the limited liability company agreement, including the provisions discussed above and, pursuant to the terms of our limited liability company agreement, is treated as having consented to various actions contemplated in our limited liability company agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

 

ITEM 1B: UNRESOLVED STAFF COMMENTS

None.

 

ITEM 2: PROPERTIES

Natural Gas and Oil Reserves

The following tables summarize information regarding our and ARP’s estimated proved natural gas and oil reserves as of December 31, 2014. Proved reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our and ARP’s direct ownership interests in oil and gas properties as well as the reserves attributable to ARP’s percentage interests in the oil and gas properties owned by Drilling Partnerships in which ARP owns partnership interests. All of the reserves are located in the United States. We and ARP base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared independent third-party engineers. We and ARP have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve reports related to our and ARP’s estimated proved reserves at December 31, 2014 are included as Exhibits 99.1 through 99.3 to this report. In accordance with SEC guidelines, we and ARP make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our and ARP’s estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 31, 2014 and 2013, and are listed below as of the dates indicated:

 

     December 31,  

Unadjusted Prices(1)

   2014      2013  

Natural gas (per Mcf)

   $ 4.35       $ 3.67   

Oil (per Bbl)

   $ 94.99       $ 96.78   

NGLs (per Bbl)

   $ 30.21       $ 30.10   

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

             

Natural gas (per Mcf)

   $ 3.93       $ 3.25   

Oil (per Bbl)

   $ 82.42       $ 95.86   

NGLs (per Bbl)

   $ 29.37       $ 29.43   

 

(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, 2014 and 2013. Including the effect of this subordination, the average realized sales price was $3.84 per Mcf before the effects of financial hedging and $2.99 per Mcf before the effects of financial hedging for years ended December 31, 2014 and 2013, 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.

 

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The preparation of our and ARP’s natural gas, oil and NGL reserve estimates were completed in accordance with prescribed internal control procedures by reserve engineers. Other than for ARP’s Rangely assets, for the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 38 years of experience in the estimation and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. For ARP’s Rangely assets, Cawley, Gillespie and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 32 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our and ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 16 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our and ARP’s senior engineering staff and management, with final approval by the Chief Operating Officer and President.

Results of drilling, testing and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas, oil and NGLs may be different from those estimated by our independent third-party engineers in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. Our and ARP’s estimated standardized measure values may not be representative of the current or future fair market value of proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas, oil and NGL prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

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

 

     Proved Reserves at
December 31,
 
     2014      2013  

Proved reserves:

     

Natural gas reserves (MMcf):(1)

     

Proved developed reserves

     889,073         766,872   

Proved undeveloped reserves(2)(3)

     175,804         236,907   
  

 

 

    

 

 

 

Total proved reserves of natural gas

  1,064,877      1,003,779   
  

 

 

    

 

 

 

Oil reserves (MBbl):(1)

Proved developed reserves

  31,150      3,459   

Proved undeveloped reserves(2)(3)

  31,799      11,530   
  

 

 

    

 

 

 

Total proved reserves of oil

  62,949      14,989   
  

 

 

    

 

 

 

NGL reserves (MBbl):

Proved developed reserves

  12,210      7,676   

Proved undeveloped reserves(2)(3)

  11,170      11,281   
  

 

 

    

 

 

 

Total proved reserves of NGL

  23,380      18,957   
  

 

 

    

 

 

 

Total proved reserves (MMcfe)(1)

  1,582,853      1,207,455   
  

 

 

    

 

 

 

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

$ 2,236,764    $ 1,079,291   
  

 

 

    

 

 

 

 

(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, 2014, there were no proved undeveloped reserves related to our oil and gas properties.

 

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(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 taxed as partnerships, no provision for federal or state income taxes has been included in the December 31, 2014 and 2013 calculations of standardized measure, which is, therefore, the same as the PV-10 value. Standardized measure for the years ended December 31, 2014 and 2013 includes approximately ($36.7) million and $2.0 million related to the present value of future cash flows from plugging and abandonment of wells, including the estimated salvage value. These amounts were not included in the summary reserve reports that appear in Exhibits 99.1 through 99.3 in this report.

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

Proved Undeveloped Reserves (“PUDs”)

PUD Locations. As of December 31, 2014, there were no PUD locations related to our natural gas and oil reserves and ARP had 426 PUD locations totaling approximately 331.9 Bcfe of natural gas, oil and NGLs. These PUDS are based on the definition of PUD’s in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

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

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

Changes in PUDs. Changes in PUDS that occurred during the year ended December 31, 2014 were due to ARP’s:

 

    addition of approximately 50.5 Bcfe due to ARP’s drilling activity in the Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls play;

 

    addition of approximately 29.2 Bcfe due to ARP’s acquisition of acreage in the Raton and Black Warrior Basins;

 

    addition of approximately 31.8 Bcfe due to ARP’s acquisition of acreage in the Eagle Ford Shale; partially offset by

 

    negative revisions of approximately 147.2 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. Costs incurred related to the development of our and our subsidiary’s PUDs were approximately $177.7 million, $103.3 million, and $79.4 million for the years ended December 31, 2014, 2013, and 2012, respectively. During the years ended December 31, 2014, 2013, and 2012, approximately 41.2 Bcfe, 58.4 Bcfe, and 30.6 Bcfe of our and our subsidiary’s reserves, respectively, were converted from PUDs to proved developed reserves. Of the 30.6 Bcfe of reserves converted from PUDs to proved developed reserves during the year ended December 31, 2012, 29.8 Bcfe is related to PUDs acquired and developed during the year. See “Item 1. Business” for further information. As of December 31, 2014, there were no PUDs that had remained undeveloped for five years or more.

 

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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, 2014. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we and ARP have an interest, directly or through ARP’s ownership interests in Drilling Partnerships, and net wells are the sum of our and ARP’s fractional working interests in gross wells, based on the percentage interest ARP owns in the Drilling Partnership that owns the well:

 

     Number of productive wells(1)(2)  

New Atlas Direct and Development Subsidiary

   Gross      Net  

Barnett/Marble Falls:

     

Gas wells

     8         8   

Oil wells

     5         5   
  

 

 

    

 

 

 

Total

  13      13   
  

 

 

    

 

 

 

Coal-bed Methane(3):

Gas wells

  594      449   

Oil wells

  —        —     
  

 

 

    

 

 

 

Total

  594      449   
  

 

 

    

 

 

 

Mississippi Lime:

Gas wells

  2      —     

Oil wells

  —        —     
  

 

 

    

 

 

 

Total

  2      —     
  

 

 

    

 

 

 

Eagle Ford:

Gas wells

  —        —     

Oil wells

  10      10   
  

 

 

    

 

 

 

Total

  10      10   
  

 

 

    

 

 

 

Total:

Gas wells

  604      457   

Oil wells

  15      15   
  

 

 

    

 

 

 

Total

  619      472   
  

 

 

    

 

 

 

 

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     Number of Productive Wells(1)(2)  

Atlas Resource Partners

   Gross      Net  

Appalachia:

     

Gas wells

     7,634         3,751   

Oil wells

     493         354   
  

 

 

    

 

 

 

Total

  8,127      4,105   
  

 

 

    

 

 

 

Coal-bed Methane(3):

Gas wells

  3,440      2,584   

Oil wells

  —        —     
  

 

 

    

 

 

 

Total

  3,440      2,584   
  

 

 

    

 

 

 

Barnett/Marble Falls:

Gas wells

  565      469   

Oil wells

  150      99   
  

 

 

    

 

 

 

Total

  715      568   
  

 

 

    

 

 

 

Mississippi Lime/Hunton:

Gas wells

  99      61   

Oil wells

  —        —     
  

 

 

    

 

 

 

Total

  99      61   
  

 

 

    

 

 

 

Rangely/Eagle Ford:

Gas wells

  —        —     

Oil wells

  424      123   
  

 

 

    

 

 

 

Total

  424      123   
  

 

 

    

 

 

 

Other operating areas(4):

Gas wells

  763      237   

Oil wells

  2      1   
  

 

 

    

 

 

 

Total

  765      238   
  

 

 

    

 

 

 

Total:

Gas wells

  12,501      7,102   

Oil wells

  1,069      577   
  

 

 

    

 

 

 

Total

  13,570      7,679   
  

 

 

    

 

 

 

 

(1)  There were no exploratory or dry wells drilled by us during the years ended December 31, 2014, 2013 and 2012. There were no exploratory wells drilled by ARP during the years ended December 31, 2014, 2013 and 2012; there were no gross or net dry wells within ARP’s operating areas during the years ended December 31, 2014 and 2013. During the year ended December 31, 2012, there were eight gross (three net) ARP dry wells drilled in the Niobrara Shale.
(2)  Includes ARP’s proportionate interest in wells owned by 67 Drilling Partnerships for which it serves as managing general partner and various joint ventures. This does not include royalty or overriding interests in 646 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, the County Line area of Wyoming, and the Central Appalachian Basin in Virginia and West Virginia.
(4)  Other operating areas include ARP’s production located in the Chattanooga, New Albany Shale and the Niobrara Shale.

Developed and Undeveloped Acreage

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

 

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     Developed acreage(1)      Undeveloped acreage(2)  

New Atlas Direct and Development Subsidiary:

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

Oklahoma

     101,936         73,408         66,910         28,029   

Texas

     6,988         6,980         1,174         1,129   

Arkansas

     1,016         559         368         334   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

  109,940      80,947      68,452      29,492   
  

 

 

    

 

 

    

 

 

    

 

 

 
     Developed acreage(1)      Undeveloped acreage(2)  

Atlas Resource Partners:

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

West Virginia

     387,478         157,699         3,946         2,047   

Pennsylvania

     154,445         74,819         2,358         2,327   

New Mexico

     126,246         126,246         447,713         447,713   

Ohio(5)

     109,736         101,345         100,431         98,154   

Texas

     83,384         72,085         65,572         53,224   

Alabama

     56,200         55,218         40,488         37,104   

Colorado

     39,778         31,663         20,924         20,924   

Indiana

     32,388         24,781         61,949         54,648   

Wyoming

     29,737         5,677         830         156   

Oklahoma

     22,253         18,266         13,170         11,060   

Tennessee

     20,119         8,409         45,108         44,908   

New York

     13,254         12,122         20,957         18,936   

Virginia

     6,489         6,040         —           —     

Other

     1,290         207         3,014         2,829   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

  1,082,797      694,577      826,460      794,030   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(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 10,608 net acres under new leases taken in Ohio that remain undeveloped.

The leases for our and ARP’s developed acreage generally have terms that extend for the life of the wells, while the leases on our and ARP’s undeveloped acreage have terms that vary from less than one year to five years. There are no concessions for undeveloped acreage as of December 31, 2014. As of December 31, 2014, none of the leases covering our approximately 29,492 net undeveloped acres, or 0.0%, are scheduled to expire on or before December 31, 2015, while leases covering approximately 40,103 of ARP’s 794,030 net undeveloped acres, or 5.1%, are scheduled to expire on or before December 31, 2015. An additional 0.7% and 1.6% of ARP’s net undeveloped acres are scheduled to expire in each of the years 2016 and 2017, respectively.

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

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

 

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ITEM 3: LEGAL PROCEEDINGS

We and our subsidiaries are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that any of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See “Item 8: Financial Statements and Supplementary Data – Note 12”.

 

ITEM 4: MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

 

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

Our common units began trading on March 2, 2015 and are listed on the New York Stock Exchange (“NYSE”) and are traded under the ticker symbol “ATLS”. From March 2, 2015 through March 23, 2015, the highest sales price for our common units on the NYSE was $10.25 per unit and the lowest sales price for our common units on the NYSE was $5.81 per unit. On March 23, 2015, there were 166 holders of record of our common units.

 

ITEM 6: SELECTED FINANCIAL DATA

The following selected historical combined consolidated financial data table reflects our financial position and results of operations, including the assets and liabilities and related results of operations transferred to us (“New Atlas”), by our former parent, Atlas Energy, L.P. (“Atlas Energy”). New Atlas consists of Atlas Energy’s interests in the following:

 

    100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities;

 

    80.0% general partner interest and a 1.9% limited partner interest in the Development Subsidiary, a partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States (the “Development Subsidiary”);

 

    15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs; and

 

    direct natural gas development and production assets in the Arkoma Basin in eastern Oklahoma, which Atlas Energy acquired in July 2013.

The selected historical combined consolidated financial and other operating data presented below should be read in conjunction with our audited combined consolidated financial statements and accompanying notes (see “Item 8: Financial Statements and Summary Data”) and “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Our combined consolidated financial information may not be indicative of our future performance and does not necessarily reflect what our financial position and results of operations would have been had we operated as an independent, publicly traded company during the periods presented.

We have derived the selected financial data set forth in the following table for each of the years ended December 31, 2014, 2013 and 2012, with the exception of combined consolidated balance sheet data for the year ended December 31, 2012, from our combined consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the selected financial data for the year ended December 31, 2011, with the exception of combined consolidated balance sheet data for the year ended December 31, 2011, from our combined consolidated financial statements not included in this report, which have been audited by Grant Thornton LLP. We derived the financial data for the year ended December 31, 2010, as well as combined consolidated balance sheet data for the year ended December 31, 2011, from our unaudited combined consolidated financial statements, which are not included in this report. The unaudited combined consolidated financial statements have been prepared on the same basis as the audited combined consolidated financial statements and, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the information set forth herein.

The combined consolidated financial statements include our accounts and that of our consolidated subsidiaries, all of which are wholly owned at December 31, 2014, except for ARP 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 and our Development Subsidiary, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and our Development Subsidiary into our combined consolidated financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and our Development Subsidiary are reflected as income (loss) attributable to non-controlling interests in our combined consolidated statements of operations and as a component of equity on our combined consolidated balance sheets. Throughout this section, when we refer to “our” combined consolidated financial statements, we are referring to the consolidated results for us and our wholly owned subsidiaries and the consolidated results of ARP and our Development Subsidiary, adjusted for non-controlling interests.

 

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On February 17, 2011, Atlas Energy acquired certain producing natural gas and oil properties, an investment management business that 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 Atlas Energy’s 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 combined 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 combined 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 equity;

 

    Retrospectively adjusted our combined consolidated balance sheets, our combined consolidated statements of operations, our combined consolidated statements of equity, our combined consolidated statements of comprehensive income (loss) and our combined 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 combined 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’s 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 Atlas Energy’s general partner (the “Atlas Energy 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 Atlas Energy Board also approved the distribution of approximately 5.24 million ARP common units to its unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of Atlas Energy’s common units owned on the record date of February 28, 2012.

 

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

 

     Year Ended December 31,  
     2014     2013     2012     2011     2010  
Statement of operations data:    (in thousands, except per unit data)  

Revenues:

          

Gas and oil production

   $ 475,758      $ 273,906      $ 92,901      $ 66,979      $ 93,050   

Well construction and completion

     173,564        167,883        131,496        135,283        206,802   

Gathering and processing

     14,107        15,676        16,267        17,746        14,087   

Administration and oversight

     15,564        12,277        11,810        7,741        9,716   

Well services

     24,959        19,492        20,041        19,803        20,994   

Other, net

     4,558        (14,135     (3,346     16,527        2,126   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  708,510      475,099      269,169      264,079      346,775   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

Gas and oil production

  184,296      100,178      26,624      17,100      23,323   

Well construction and completion

  150,925      145,985      114,079      115,630      175,247   

Gathering and processing

  15,525      18,012      19,491      20,842      20,221   

Well services

  10,007      9,515      9,280      8,738      10,822   

General and administrative

  90,476      89,957      75,475      27,688      11,381   

Chevron transaction expense

  —        —       7,670      —       —    

Depreciation, depletion and amortization

  242,079      139,916      52,582      31,938      40,758   

Asset impairment

  580,654      38,014      9,507      6,995      50,669   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

  1,273,962      541,577      314,708      228,931      332,421   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

  (565,452   (66,478   (45,539   35,148      14,354   

Gain (loss) on asset sales and disposal

  (1,859   (987   (6,980   90      (2,947

Interest expense

  (73,435   (39,712   (4,548   (4,244   —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

$ (640,746 $ (107,177 $ (57,067 $ 30,994    $ 11,407   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance sheet data (at period end):

Property, plant and equipment, net

$ 2,419,289    $ 2,186,683    $ 1,302,228    $ 525,454    $ 508,484   

Total assets

  3,026,315      2,455,870      1,526,652      732,641      668,144   

Total debt, including current portion

  1,542,585      1,091,959      357,050      —       —    

Total equity

  915,215      1,043,996      868,804      485,348      400,794   

Cash flow data:

Net cash provided by operating activities

$ 76,087    $ 3,841    $ 13,524    $ 83,410    $ 59,586   

Net cash used in investing activities

  (962,947   (1,053,524   (837,825   (57,984   (98,745

Net cash provided by financing activities

  934,593      1,037,038      792,863      29,282      39,159   

Capital expenditures

  (225,636   (267,480   (127,226   (47,324   (93,608

 

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

The historical financial statements included in this Annual Report reflect substantially all the assets, liabilities and operations of our and Atlas Energy’s controlled subsidiaries contributed to us on February 27, 2015. We refer to our, Atlas Energy’s and such subsidiaries’ assets, liabilities and operations as New Atlas. The discussion and analysis presented below refer to and should be read in conjunction with “Item 6: Selected Financial Data” and “Item 8: Financial Statements and Supplementary Data”, which contains the combined consolidated financial statements of New Atlas. The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. The words “believe,” “expect,” “anticipate,” “project,” and similar expressions, among others, generally identify “forward-looking statements,” which 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” and “Forward-Looking Statements”. We believe the assumptions underlying the combined consolidated financial statements are reasonable. However, our predecessor’s combined consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future or what they would have been had our predecessor been a separate, stand-alone company during the periods presented.

Unless the context otherwise requires, references in this annual report to “New Atlas,” “the Company,” “we,” “us,” “our” and “our company,” when used in a historical context or in the present tense, refer to the businesses and subsidiaries that are currently owned by Atlas Energy Group, LLC or that Atlas Energy contributed to Atlas Energy Group, LLC in connection with the separation and distribution on February 27, 2015 and refer to Atlas Energy Group, LLC, a Delaware limited liability company, and its combined subsidiaries. References in this Annual Report to “Atlas Energy” or “Atlas Energy, L.P.” refer to Atlas Energy, L.P., a Delaware limited partnership, and its consolidated subsidiaries, unless the context otherwise requires. References in this annual report to “ARP” or “Atlas Resource Partners” refer to Atlas Resource Partners, L.P., a Delaware limited partnership. References to “Atlas Energy Group, LLC” or “Atlas Energy Group, LLC” prior to the separation refer to Atlas Energy Group, LLC, a Delaware limited liability company that is currently the general partner of ARP at December 31, 2014. References in this information statement to “AEI” refer to Atlas Energy, Inc. the former owner of Atlas Energy’s general partner.

GENERAL

We are a Delaware limited liability company formed in October 2011. At December 31, 2014, we were wholly-owned by Atlas Energy, L.P. (“Atlas Energy”), a then publicly-traded Delaware master limited partnership (NYSE: ATLS). On February 27, 2015, Atlas Energy transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution to its unitholders of our common units representing a 100% interest in us (the “Separation”). We refer to the assets and liabilities that were transferred to us by Atlas Energy in connection with the Separation as “New Atlas”. Our common units began trading “regular-way” under the ticker symbol “ATLS” on the New York Stock Exchange on March 2, 2015. Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.

As the Separation was not consummated until after the completion of the historical periods covered by this Form 10-K, we, as the registrant, have provided the combined consolidated financial statements of New Atlas. As such, the remainder of the discussion within this section will reflect the New Atlas business transferred to us on February 27, 2015.

Our assets, assuming the Separation had been completed as of December 31, 2014, consist of:

 

    100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in 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 NGLs, 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;

 

    80.0% general partner interest and a 1.9% limited partner interest in the Development Subsidiary, a partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States (the “Development Subsidiary”);

 

    15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs; and

 

    direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013 (“Direct Gas & Oil Production Assets” or “Direct”).

 

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We do not anticipate that increased costs solely from becoming an independent, publicly traded company will have an adverse effect on our growth rate in the future.

FINANCIAL PRESENTATION

Our combined consolidated financial statements were derived from the accounts of Atlas Energy and its controlled subsidiaries. Because a direct ownership relationship did not exist among all the various entities comprising our combined consolidated financial statements, Atlas Energy’s net investment in us is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive our financial statements. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements. Actual balances and results could be different from those estimates.

In connection with Atlas Energy’s merger with Targa and our concurrent unit distribution, we were required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with generally accepted accounting principles, we included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within our historical financial statements. In addition, all of Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio.

Our combined consolidated financial statements contain our accounts and those of our combined consolidated subsidiaries, all of which are wholly-owned at December 31, 2014, except for ARP and our Development Subsidiary, which we control. Due to the structure of our ownership interests in ARP and our Development Subsidiary, in accordance with generally accepted accounting principles, we consolidate the financial statements of ARP and our Development Subsidiary into our combined consolidated financial statements rather than present our ownership interests as equity investments. As such, the non-controlling interests in ARP and our Development Subsidiary are reflected as income (loss) attributable to non-controlling interests in our combined consolidated statements of operations and as a component of partners’ capital on our combined consolidated balance sheets. Throughout this section, when we refer to “our” combined consolidated financial statements, we are referring to the combined consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP and our Development Subsidiary, adjusted for non-controlling interests in ARP and our Development Subsidiary. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements.

SUBSEQUENT EVENTS

Term Loan Credit Facilities. On February 27, 2015, we entered into a Credit Agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders from time to time party thereto (the “Credit Agreement”). The Credit Agreement provides for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30 million (the “Interim Term Loan Facility”) and a Secured Senior Term A Loan Facility in an aggregate principal amount of approximately $97.8 million (the “Term A Loan Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The Interim Term Loan Facility matures on August 27, 2015 and the Term A Loan Facility matures on February 26, 2016. Our obligations under the Term Loan Facilities are secured on a first priority basis by security interests in all of our material subsidiaries, including all equity interests directly held by us and all tangible and intangible property. Borrowings under the Term Loan Facilities bear interest, at our option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by us for Eurodollar Loans and quarterly for ABR Loans.

We have the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility is repaid prior to the Term A Loan Facility. Subject to certain exceptions, we may also be required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following:

 

   

if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, we must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of

 

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the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement);

 

    if we dispose of all or any portion of the Arkoma assets (as defined in the Credit Agreement), we must prepay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition;

 

    if we or any of our restricted subsidiaries dispose of property or assets (including equity interests), we must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and

 

    if we incur any debt or issue any equity, we must repay the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity.

The Credit Agreement contains customary covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. The Credit Agreement also requires that the Total Leverage Ratio (as defined in the Credit Agreement) be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00.

Preferred Unit Purchase Agreement. On February 26, 2015, we entered into the Series A Preferred Unit Purchase Agreement (the “Series A Purchase Agreement”) with certain members of our management, two management members of the Board and an outside investor (the “purchasers”), pursuant to which, on February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly issued Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A preferred units”), to the purchasers for a cash purchase price of $25.00 per unit in a privately negotiated transaction (the “Private Placement”). We sold the Series A preferred units in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million cash transfer made by us to Atlas Energy required by the Separation agreement with Atlas Energy, which was a condition to the Separation and distribution of our common units (see “Item 1: Business—General”). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.

Atlas Resource

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

 

    reduces the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million;

 

    permits the incurrence of second lien debt in an aggregate principal amount up to $300.0 million;

 

    permits an increase in the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels if the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%;

 

    following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and

 

    revises the maximum ratio of Total Funded Debt to EBITDA to be (i) 5.25 to 1.0 as of the last day of the quarters ended on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ended on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarters ended on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter.

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

 

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

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

 

    the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date;

 

    4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date;

 

    2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and

 

    no premium for prepayments made following 36 months after the closing date.

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

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

 

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

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

On February 23, 2015, ARP declared a monthly distribution of $0.1083 per common unit for the month of January 2015. The $10.1 million distribution, including $0.2 million and $0.6 million, to us, as general partner and preferred limited partners, respectively, was paid on March 17, 2015 to unitholders of record at the close of business on March 10, 2015.

RECENT DEVELOPMENTS

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

Atlas Resource

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

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

Equity Distribution Program. On August 29, 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent (see “Issuances of Units”). As of December 31, 2014, no units have been sold under this program.

 

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

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

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

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

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

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas and Oil Production

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

 

    Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline Zone 4 (200 Leg), Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5;

 

    Mississippi Lime - Southern Star;

 

    Barnett Shale and Marble Falls- primarily Waha;

 

    Raton – ANR, Panhandle, and NGPL;

 

    Black Warrior Basin – Southern Natural;

 

    Eagle Ford – Transco Zone 1;

 

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

 

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ARP holds firm transportation obligations on Colorado Interstate Gas for the benefit of production from the Raton Basin in the New Mexico/Colorado Area. The total of firm transportation held is approximately 82,500 dth/d at a weighted average rate of $0.2575/MMBtu under contracts expiring in 2016. ARP also holds firm transportation obligations on East Tennessee Natural Gas, Columbia Gas Transmission and Equitrans for the benefit of production from the central Appalachian Basin. The total of firm transportation held is approximately 25,000 dth/d, 15,500 dth/d and 2,300 dth/d, respectively, under contracts expiring between the years 2015 and 2022.

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

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as indicated above and our and our subsidiaires’ 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 our subsidiaries do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2014, Tenaska Marketing Ventures, Chevron, Enterprise, and Interconn Resources LLC accounted for approximately 25%, 15%, 14% and 13% of 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

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

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

 

    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 wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days, using the percentage of completion method.

 

    Administration and oversight. For each well drilled by a Drilling Partnership, ARP currently receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with the partnership agreement and recognized at the initiation of a well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed; and

 

    Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

 

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

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

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 natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and early 2015, particularly in December 2014 and January 2015. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we and our subsidiaries 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 our subsidiaries’ 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 our subsidiaries’ success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. We and our subsidiaries face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. We and our subsidiaries attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced.

 

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RESULTS OF OPERATIONS

Gas and Oil Production

Production Profile. At December 31, 2014, our consolidated gas and oil production revenues and expenses consisted of our and our subsidiaries’ gas and oil production activities. Currently, our gas and oil production entails the production generated by our assets acquired in the Arkoma Acquisition. Our Development Subsidiary’s gas and oil production emanates from its wells drilled in the Marble Falls and Mississippi Lime plays. ARP has focused its natural gas, crude oil and NGL production operations in various plays throughout the United States. ARP previously had certain agreements which restricted its ability to drill additional wells in certain areas of Pennsylvania, New York and West Virginia, including portions of the Marcellus Shale, which expired on February 17, 2014. Through December 31, 2014, we and our subsidiaries 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 E&P Company, L.P. in July 2013 (the “Arkoma Acquisition”);

 

    the Eagle Ford Shale in south Texas, in which ARP and our Development Subsidiary acquired acreage and producing wells in November 2014;

 

    our Development Subsidiary’s and ARP’s Barnett Shale and Marble Falls play, both in the Fort Worth Basin in northern Texas. The Barnett Shale contains mostly dry gas and the Marble Falls play contains liquids rich gas and oil. ARP established its position following its acquisitions of assets from Carrizo Oil & Gas, Inc., Titan Operating, LLC and DTE Energy Company during 2012. We refer to these acquisitions as the “Carrizo”, “Titan” and “DTE” acquisitions. Our Development Subsidiary acquired leasehold acreage within the Marble Falls play shortly after commencing operations during 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, where ARP established a position following its acquisition of certain assets from EP Energy during 2013, which is also referred to as the “EP Energy Acquisition”, as well as the Cedar Bluff area of West Virginia and Virginia, where ARP established a position following its acquisition of assets from GeoMet Inc. in May 2014 (see “Recent Developments”);

 

    ARP’s Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production, where ARP has a 25% non-operated net working interest position following ARP’s acquisition on June 30, 2014, which is referred to as the “Rangely Acquisition” (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;

 

    our Development Subsidiary’s and ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area, where our Development Subsidiary participated in non-operated well drilling during 2014 and ARP established a position following ARP’s acquisition from Equal in 2012; and

 

    ARP’s other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables us 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 our subsidiaries drilled and the number of wells we and our subsidiaries turned in line, both gross and for our respective interests, during the years ended December 31, 2014, 2013 and 2012:

 

     Year Ended December 31,  
     2014      2013      2012  

New Atlas Direct:

        

Gross wells drilled

     —           —           —     

Our share of gross wells drilled

     —           —           —     

Gross wells turned in line

     —           —           —     

Net wells turned in line

     —           —           —     
     Year Ended December 31,  
     2014      2013      2012  

Development Subsidiary:

        

Gross wells drilled

     11        2         —     

Our share of gross wells drilled

     11        2         —     

Gross wells turned in line

     13        2         —     

Net wells turned in line

     13        2         —     
     Year Ended December 31,  
     2014      2013      2012  

Atlas Resource:

        

Gross wells drilled

     129        103         105   

Share of gross wells drilled(1)

     67        66         42   

Gross wells turned in line

     119        117         154   

Net wells turned in line(1)

     64        80         43   

 

(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, 2014, 2013, and 2012:

 

     Year Ended December 31,  
     2014      2013      2012  

Production:(1)(2)

        

Atlas Resource:(3)

        

Appalachia:

        

Natural gas (MMcf)

     13,928         13,397         12,403   

Oil (000’s Bbls)

     139         121         102   

NGLs (000’s Bbls)

     15         8         4   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  14,852      14,171      13,036   
  

 

 

    

 

 

    

 

 

 

Coal-bed Methane:

Natural gas (MMcf)

  44,080      17,465      —     

Oil (000’s Bbls)

  —        —        —     

NGLs (000’s Bbls)

  —        —        —     
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  44,080      17,465      —     
  

 

 

    

 

 

    

 

 

 

Barnett/Marble Falls:

Natural gas (MMcf)

  20,937      23,744      10,561   

Oil (000’s Bbls)

  389      295      10   

NGLs (000’s Bbls)

  985      1,004      173   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  29,180      31,539      11,661   
  

 

 

    

 

 

    

 

 

 

 

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     Year Ended December 31,  
     2014      2013      2012  

Rangely/Eagle Ford:

        

Natural gas (MMcf)

     64         —           —     

Oil (000’s Bbls)

     561         —           —     

NGLs (000’s Bbls)

     63         —           —     
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  3,810      —        —     
  

 

 

    

 

 

    

 

 

 

Mississippi Lime/Hunton:

Natural gas (MMcf)

  2,486      1,779      510   

Oil (000’s Bbls)

  156      63      3   

NGLs (000’s Bbls)

  205      118      30   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  4,648      2,859      705   
  

 

 

    

 

 

    

 

 

 

Other operating areas:

Natural gas (MMcf)

  1,187      1,609      1,929   

Oil (000’s Bbls)

  9      7      6   

NGLs (000’s Bbls)

  121      138      150   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  1,965      2,477      2,865   
  

 

 

    

 

 

    

 

 

 

Total Atlas Resource:

Natural gas (MMcf)

  82,682      57,993      25,403   

Oil (000’s Bbls)

  1,254      485      121   

NGLs (000’s Bbls)

  1,388      1,268      357   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  98,535      68,511      28,267   
  

 

 

    

 

 

    

 

 

 

New Atlas Direct:

Natural gas (MMcf)

  4,208      1,856      —     

Oil (000’s Bbls)

  —        —        —     

NGLs (000’s Bbls)

  —        —        —     
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  4,208      1,856      —     
  

 

 

    

 

 

    

 

 

 

Development Subsidiary:

Natural gas (MMcf)

  252      8      —     

Oil (000’s Bbls)

  43      3      —     

NGLs (000’s Bbls)

  32      1      —     
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  701      29      —     
  

 

 

    

 

 

    

 

 

 

Total production:

Natural gas (MMcf)

  87,142      59,857      25,403   

Oil (000’s Bbls)

  1,297      488      121   

NGLs (000’s Bbls)

  1,420      1,269      357   
  

 

 

    

 

 

    

 

 

 

Total (MMcfe)

  103,443      70,396      28,267   
  

 

 

    

 

 

    

 

 

 

Production per day:(1)(2)

Atlas Resource:(3)

Appalachia:

Natural gas (Mcfd)

  38,160      36,705      33,889   

Oil (Bpd)

  381      332      278   

NGLs (Bpd)

  41      22      10   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  40,689      38,825      35,618   
  

 

 

    

 

 

    

 

 

 

Coal-bed Methane:

Natural gas (Mcfd)

  120,768      47,848      —     

Oil (Bpd)

  —        —        —     

NGLs (Bpd)

  —        —        —     
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  120,768      47,848      —     
  

 

 

    

 

 

    

 

 

 

 

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     Year Ended December 31,  
     2014      2013      2012  

Barnett/Marble Falls:

        

Natural gas (Mcfd)

     57,361         65,053         28,855   

Oil (Bpd)

     1,066         808         28   

NGLs (Bpd)

     2,698         2,751         473   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  79,946      86,409      31,861   
  

 

 

    

 

 

    

 

 

 

Rangely/Eagle Ford: (4)

Natural gas (Mcfd)

  175           

Oil (Bpd)

  1,538           

NGLs (Bpd)

  173           
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  10,438           
  

 

 

    

 

 

    

 

 

 

Mississippi Lime/Hunton:

Natural gas (Mcfd)

  6,810      4,873      1,392   

Oil (Bpd)

  427      171      8   

NGLs (Bpd)

  561      322      81   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  12,734      7,834      1,926   
  

 

 

    

 

 

    

 

 

 

Other operating areas:

Natural gas (Mcfd)

  3,253      4,408      5,271   

Oil (Bpd)

  25      18      16   

NGLs (Bpd)

  330      378      410   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  5,384      6,786      7,827   
  

 

 

    

 

 

    

 

 

 

Total Atlas Resource:

Natural gas (Mcfd)

  226,526      158,886      69,408   

Oil (Bpd)

  3,436      1,329      330   

NGLs (Bpd)

  3,802      3,473      974   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  269,958      187,701      77,232   
  

 

 

    

 

 

    

 

 

 

New Atlas Direct:

Natural gas (Mcfd)

  11,528      5,085       

Oil (Bpd)

           

NGLs (Bpd)

           
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  11,528      5,085       
  

 

 

    

 

 

    

 

 

 

Development Subsidiary:

Natural gas (Mcfd)

  691      21       

Oil (Bpd)

  117      7       

NGLs (Bpd)

  88      3       
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  1,920      79       
  

 

 

    

 

 

    

 

 

 

Total production per day:

Natural gas (Mcfd)

  238,745      163,992      69,408   

Oil (Bpd)

  3,553      1,336      330   

NGLs (Bpd)

  3,891      3,476      974   
  

 

 

    

 

 

    

 

 

 

Total (Mcfed)

  283,406      192,866      77,232   
  

 

 

    

 

 

    

 

 

 

 

(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.

 

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(3)  Appalachia includes ARP’s production located in Pennsylvania, Ohio, New York and West Virginia; Coal-bed methane includes ARP’s production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming; Rangely/Eagle Ford includes ARP’s 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado and our Development Subsidiary’s and ARP’s production located in southern Texas; Other operating areas include ARP’s production located in the Chattanooga, New Albany and Niobrara Shales.
(4)  Rangely includes production from July 1, 2014, the date of the acquisition, through December 31, 2014; Eagle Ford includes production from November 5, 2014, the date of the acquisition, through December 31, 2014. Production per day represents production based on the full 365-day year ended December 31, 2014.

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents production revenues and average sales prices for our direct interest, our Development Subsidiary, and ARP’s natural gas, oil, and NGLs production for the years ended December 31, 2014, 2013 and 2012, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

 

     Year Ended December 31,  
     2014      2013      2012  

Production revenues (in thousands):

        

New Atlas Direct:

        

Natural gas revenue

   $ 16,094       $ 6,821       $ —     

Oil revenue

     —           —           —     

NGLs revenue

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total revenues

$ 16,094    $ 6,821    $ —     
  

 

 

    

 

 

    

 

 

 

Development Subsidiary:

Natural gas revenue

$ 1,009    $ 28    $ —     

Oil revenue

  3,770     241      —     

NGLs revenue

  928     33      —     
  

 

 

    

 

 

    

 

 

 

Total revenues

$ 5,707    $ 302    $ —     
  

 

 

    

 

 

    

 

 

 

Atlas Resource:

Natural gas revenue

$ 302,826    $ 186,229    $ 70,151   

Oil revenue

  110,070     44,160      11,351   

NGLs revenue

  41,061     36,394      11,399   
  

 

 

    

 

 

    

 

 

 

Total revenues

$ 453,957    $ 266,783    $ 92,901   
  

 

 

    

 

 

    

 

 

 

Total production revenues:

Natural gas revenue

$ 319,929    $ 193,078    $ 70,151   

Oil revenue

  113,840      44,401      11,351   

NGLs revenue

  41,989      36,427      11,399   
  

 

 

    

 

 

    

 

 

 

Total revenues

$ 475,758    $ 273,906    $ 92,901   
  

 

 

    

 

 

    

 

 

 

Average sales price:

New Atlas Direct:

Natural gas (per Mcf):(1)

Total realized price, after hedge

$ 3.82    $ 3.68    $ —     

Total realized price, before hedge

$ 3.98    $ 3.41    $ —     

Oil (per Bbl):(1)

Total realized price, after hedge

$ —      $ —      $ —     

Total realized price, before hedge

$ —      $ —      $ —     

NGLs (per Bbl):(1)

Total realized price, after hedge

$ —      $ —      $ —     

Total realized price, before hedge

$ —      $ —      $ —     

Development Subsidiary:

Natural gas (per Mcf):(1)

Total realized price, after hedge

$ 4.00    $ 3.63    $ —     

Total realized price, before hedge

$ 4.00    $ 3.63    $ —     

Oil (per Bbl):(1)

Total realized price, after hedge

$ 88.61    $ 93.16    $ —     

Total realized price, before hedge

$ 88.61    $ 93.16    $ —     

 

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     Year Ended December 31,  
     2014      2013      2012  

NGLs (per Bbl):(1)

        

Total realized price, after hedge

   $ 28.80       $ 34.88       $ —     

Total realized price, before hedge

   $ 28.80       $ 34.88       $ —     

Atlas Resource:

        

Natural gas (per Mcf):(1)

        

Total realized price, after hedge(2)

   $ 3.76       $ 3.47       $ 3.29   

Total realized price, before hedge(2)

   $ 3.93       $ 3.25       $ 2.60   

Oil (per Bbl):(1)

        

Total realized price, after hedge

   $ 87.76       $ 91.01       $ 94.02   

Total realized price, before hedge

   $ 82.22       $ 95.88       $ 91.32   

NGLs (per Bbl):(1)

        

Total realized price, after hedge

   $ 29.59       $ 28.71       $ 31.97   

Total realized price, before hedge

   $ 29.39       $ 29.43       $ 31.97   

Total:

        

Natural gas (per Mcf):(1)

        

Total realized price, after hedge(2)

   $ 3.76       $ 3.48       $ 3.29   

Total realized price, before hedge(2)

   $ 3.93       $ 3.25       $ 2.60   

Oil (per Bbl):(1)

        

Total realized price, after hedge

   $ 87.79       $ 91.02       $ 94.02   

Total realized price, before hedge

   $ 82.42       $ 95.86       $ 91.32   

NGLs (per Bbl):(1)

        

Total realized price, after hedge

   $ 29.57       $ 28.71       $ 31.97   

Total realized price, before hedge

   $ 29.37       $ 29.43       $ 31.97   

Production costs (per Mcfe):(1)

        

New Atlas Direct:

        

Lease operating expenses

   $ 0.86       $ 0.79       $ —     

Production taxes

     0.25         0.21         —     

Transportation and compression

     0.33         0.54         —     
  

 

 

    

 

 

    

 

 

 
$ 1.43    $ 1.54    $ —     
  

 

 

    

 

 

    

 

 

 

Development Subsidiary:

Lease operating expenses

$ 2.47    $ —      $ —     

Production taxes

  0.48      —        —     

Transportation and compression

  —        —        —     
  

 

 

    

 

 

    

 

 

 
$ 2.95    $ —      $ —     
  

 

 

    

 

 

    

 

 

 

Atlas Resource:

Lease operating expenses(3)

$ 1.29    $ 1.09    $ 0.82   

Production taxes

  0.27      0.18      0.12   

Transportation and compression

  0.25      0.24      0.24   
  

 

 

    

 

 

    

 

 

 
$ 1.81    $ 1.50    $ 1.19   
  

 

 

    

 

 

    

 

 

 

Total production costs:

Lease operating expenses(3)

$ 1.28    $ 1.08    $ 0.82   

Production taxes

  0.27      0.18      0.12   

Transportation and compression

  0.25      0.25      0.24   
  

 

 

    

 

 

    

 

 

 
$ 1.81    $ 1.50    $ 1.19   
  

 

 

    

 

 

    

 

 

 

 

(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 the years ended December 31, 2014, 2013 and 2012. Including the effect of this subordination, the average realized gas sales price was $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging), $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), and $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) for years ended December 31, 2014, 2013 and 2012, 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 the years ended December 31, 2014, 2013, and 2012. Including the effects of these costs, total lease operating expenses per Mcfe were $1.26 per Mcfe ($1.78 per Mcfe for total production costs), $1.00 per Mcfe ($1.42 per Mcfe for total production costs) and $0.58 per Mcfe ($0.94 per Mcfe for total production costs) for the years ended December 31, 2014, 2013 and 2012, respectively.

 

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Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total production revenues were $475.8 million for the year ended December 31, 2014, an increase of $201.9 million from $273.9 million for the year ended December 31, 2013. This increase consisted of a $125.0 million increase attributable to our and ARP’s newly acquired coal-bed methane assets, a $51.0 million increase attributable to ARP’s newly acquired Rangely and Eagle Ford assets, a $13.3 million increase attributable to our Development Subsidiary’s and ARP’s Mississippi Lime/Hunton assets, a $9.0 million increase attributable to our Development Subsidiary’s and ARP’s Barnett Shale/Marble Falls operations, and a $5.3 million increase attributable to ARP’s Appalachia assets due primarily to the Marcellus and Utica Shale wells drilled.

Total production costs were $184.3 million for the year ended December 31, 2014, an increase of $84.1 million from $100.2 million for the year ended December 31, 2013. This increase primarily consisted of a $53.7 million increase attributable to production costs associated with our and ARP’s newly acquired coal-bed methane assets, a $16.3 million increase attributable to ARP’s newly acquired Rangely assets and our and ARP’s Eagle Ford assets, an $11.1 million increase primarily attributable to new well connections, consisting of $6.3 million attributable to our Development Subsidiary’s and ARP’s Barnett Shale/Marble Falls assets, $3.5 million attributable to our Development Subsidiary’s and ARP’s Mississippi Lime/Hunton assets, and $1.3 million attributable to ARP’s Appalachia operations, and a $3.1 million decrease in the credit received against ARP’s lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe increased to $1.81 per Mcfe for the year ended December 31, 2014 from $1.50 per Mcfe for the comparable prior year period primarily as a result of the increases in our oil and natural gas liquids production.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total production revenues were $273.9 million for the year ended December 31, 2013, an increase of $181.0 million from $92.9 million for the year ended December 31, 2012. This increase primarily consisted of a $110.1 million increase primarily attributable to new wells drilled, consisting of a $92.6 million increase attributable to our Development Subsidiary’s and ARP’s Barnett Shale/Marble Falls operations, a $15.4 million increase attributable to ARP’s Mississippi Lime/Hunton assets and a $2.1 million increase attributable to ARP’s Appalachian assets, and a $72.9 million increase attributable to our and ARP’s newly acquired coal-bed methane 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 2013 acquisition of coal-bed methane assets, a $3.6 million increase in ARP’s Appalachia-based transportation, labor and other production costs, and a $1.4 million decrease in ARP’s credit received against its lease operating expenses pertaining to the subordination of its revenue within its Drilling Partnerships. Total production costs per Mcfe increased to $1.50 per Mcfe for the year ended December 31, 2013 from $1.19 per Mcfe for the comparable prior year period primarily as a result of the increase in ARP’s oil and natural gas liquids volumes during the period.

 

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Well Construction and Completion

Drilling Program Results. At December 31, 2014, our well construction and completion revenues and expenses consisted solely of ARP’s activities. The number of wells ARP drills will vary within ARP’s partnership management segment depending on the amount of capital it raises through its Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table presents the amounts of Drilling Partnership investor capital raised and deployed (in thousands), as well as the number of gross and net development wells ARP drilled for its Drilling Partnerships during the years ended December 31, 2014, 2013 and 2012. There were no exploratory wells drilled during the years ended December 31, 2014, 2013 and 2012.

 

     Year Ended December 31,  
     2014      2013      2012  

Drilling partnership investor capital:

        

Raised

   $ 166,798       $ 149,967       $ 127,071   

Deployed

   $ 173,564       $ 167,883       $ 131,496   

Gross partnership wells drilled:

        

Appalachia

        

Marcellus Shale

     —           —           10   

Utica

     4         3         5   

Ohio

     —           —           7   

Barnett/Marble Falls

     77         51         4   

Eagle Ford

     2         —           —     

Mississippi Lime/Hunton

     17         21         11   

Niobrara

     —           —           51   
  

 

 

    

 

 

    

 

 

 

Total

  100      75      88   
  

 

 

    

 

 

    

 

 

 

Net partnership wells drilled:

Appalachia

Marcellus Shale

  —        —        10   

Utica

  4      3      5   

Ohio

  —        —        7   

Barnett/Marble Falls

  64      25      2   

Eagle Ford

  1      —        —     

Mississippi Lime/Hunton

  16      21      9   

Niobrara

  —        —        51   
  

 

 

    

 

 

    

 

 

 

Total

  85      49      84   
  

 

 

    

 

 

    

 

 

 

 

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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,  
     2014      2013      2012  

Average construction and completion:

        

Revenue per well

   $ 2,227       $ 3,276       $ 1,444   

Cost per well

     1,937         2,849         1,253   
  

 

 

    

 

 

    

 

 

 

Gross profit per well

$ 290    $ 427    $ 191   
  

 

 

    

 

 

    

 

 

 

Gross profit margin

$     22,639    $     21,898    $     17,417   
  

 

 

    

 

 

    

 

 

 

Partnership net wells associated with revenue recognized(1):

Appalachia:

Marcellus Shale

  —         4      7   

Utica

  3      5      2   

Ohio

  —         —         8   

Barnett/Marble Falls

  60      24      2   

Eagle Ford

  1      —         —      

Mississippi Lime/Hunton

  14      18      7   

Chattanooga

  —         —         2   

Niobrara

  —         —         63   
  

 

 

    

 

 

    

 

 

 

Total

  78      51      91   
  

 

 

    

 

 

    

 

 

 

 

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

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

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Well construction and completion segment margin was $21.9 million for the year ended December 31, 2013, an increase of $4.5 million from $17.4 million for the year ended December 31, 2012. This increase consisted of a $12.1 million increase associated with ARP’s higher gross profit margin per well, partially offset by a $7.6 million decrease related to a lower number of wells recognized for revenue within ARP’s Drilling Partnerships. Average revenue and cost per well increased between periods due primarily to higher capital deployed for Utica Shale, Mississippi Lime play, and Marble Falls play wells within ARP’s Drilling Partnerships during the year ended December 31, 2013, compared with higher capital deployed for lower cost Niobrara Shale wells during the prior year period.

At December 31, 2014, our combined consolidated balance sheet includes $40.6 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 combined consolidated statements of operations. ARP expects to recognize this amount as revenue during 2015.

Administration and Oversight

At December 31, 2014, our 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

 

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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 Shale and the Utica Shales.

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

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

Well Services

At December 31, 2014, our well services revenues and expenses consisted solely of ARP’s activities. Well services revenue and expenses represent the monthly operating fees ARP charges and the work ARP’s service company performs, including work performed for ARP’s Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which ARP serves as operator.

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

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

Gathering and Processing

At December 31, 2014, our gathering and processing margin consisted solely of ARP’s activities. Gathering and processing revenues and expenses include gathering fees ARP charges to its Drilling Partnership wells and the related expenses and gross margin for ARP’s processing plants in the New Albany Shale and the Chattanooga Shale. 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 its gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Our net gathering and processing expense for the year ended December 31, 2014 was $1.4 million, a favorable movement of $0.9 million compared with net expense of $2.3 million for the year ended December 31, 2013. This favorable movement was principally due to a full year of gathering fees from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Our net gathering and processing expense for the year ended December 31, 2013 was $2.3 million, a favorable movement of $0.9 million compared with net expense of $3.2 million for the year ended December 31, 2012. This favorable decrease was principally due to an increase in gathering fees from ARP’s new Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which are utilizing ARP’s gathering pipeline.

 

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Other, Net

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Other, net for the year ended December 31, 2014 was income of $4.6 million as compared with expense of $14.1 million for the comparable prior year period. This $18.7 million favorable movement was primarily due to a $16.8 million decrease in premium amortization associated with our and ARP’s swaption derivative contracts for production volumes related to wells we and ARP acquired from EP Energy during the prior year period, and a $2.8 million increase attributable to ARP’s gain on mark-to-market derivatives in the current year in connection with it entering into derivative instruments upon signing the Eagle Ford Acquisition (see “Recent Developments”), partially offset by a $1.5 million decrease in income from our equity investment in Lightfoot.

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 $14.1 million as compared with expense of $3.3 million for the comparable prior year period. This $10.8 million unfavorable movement was primarily due to $16.8 million of premium amortization associated with our and ARP’s swaption derivative contracts for production volumes related to wells we and ARP acquired from EP Energy in the current year period, partially offset by a $4.6 million decrease in premium amortization associated with ARP’s swaption derivative contracts for production volumes related to wells it acquired from Carrizo in the prior year period, and a $1.1 million increase in income from our equity investment in Lightfoot.

Other Costs and Expenses

General and Administrative Expenses

The following table presents our and our subsidiaries’ general and administrative expenses for each of the respective periods (in thousands):

 

     Years Ended
December 31,
 
     2014      2013      2012  

General and Administrative expenses:

        

New Atlas Direct

   $ 6,381       $ 8,162       $ 6,352   

Development Subsidiary

     11,746         3,732         —      

Atlas Resource Partners

     72,349         78,063         69,123   
  

 

 

    

 

 

    

 

 

 

Total

$ 90,476    $ 89,957    $ 75,475   
  

 

 

    

 

 

    

 

 

 

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total general and administrative expenses increased to $90.5 million for the year ended December 31, 2014 from $90.0 million for the year ended December 31, 2013. Our $6.4 million of general and administrative expenses for the year ended December 31, 2014 represents a $1.8 million decrease from the comparable prior year period, due to a $1.1 million decrease in salaries, wages and other corporate activities and a $0.7 million decrease in third-party services. Our Development Subsidiary’s $11.7 million of general and administrative expenses for the year ended December 31, 2014 represents an $8.0 million increase from the comparable prior year period due to a $7.7 increase in salaries, wages, and other corporate activities and a $0.3 million increase in third-party services. ARP’s $72.3 million of general and administrative expenses for the year ended December 31, 2014 represents a $5.7 million decrease from the comparable prior year period, which was primarily due to a $12.1 million decrease in non-recurring transaction costs related to the acquisitions of assets in the current and prior year periods and a $4.6 million decrease in non-cash compensation expense, partially offset by a $7.0 million increase in salaries, wages and benefits, and a $3.9 million increase in other corporate activities due to the growth of ARP’s business.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total general and administrative expenses increased to $90.0 million for the year ended December 31, 2013 from $75.5 million for the year ended December 31, 2012. Our $8.2 million of general and administrative expenses for the year ended December 31, 2013 represents a $1.8 million increase from the comparable prior year period, due to a $1.7 million increase in salaries, wages and other corporate activities and a $0.1 million increase in third-party services. Our Development Subsidiary’s $3.7 million of general and administrative expenses for the year ended December 31, 2013 represents a $3.7 million increase from the comparable prior year period due to a $3.5 increase in salaries, wages, and other corporate activities and a $0.2 million increase in third-party services. 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, which was primarily due to a $7.7 million increase in non-recurring transaction costs related to ARP’s 2013 acquisitions of assets and a $1.8 million increase in non-cash compensation expense, partially offset by a $0.5 million decrease in other corporate activities.

 

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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 our and our subsidiaries’ depreciation, depletion and amortization expense for each of the respective periods (dollars in thousands):

 

     Years Ended
December 31,
 
     2014      2013      2012  

Depreciation, depletion and amortization:

        

New Atlas Direct

   $ 6,192       $ 3,020       $ —      

Development Subsidiary

     2,156         133         —      

Atlas Resource Partners

     233,731         136,763         52,582   
  

 

 

    

 

 

    

 

 

 

Total

$ 242,079    $ 139,916    $ 52,582   
  

 

 

    

 

 

    

 

 

 

Total depreciation, depletion and amortization increased to $242.1 million for the year ended December 31, 2014 compared with $139.9 million for the comparable prior year period, which was primarily due to a $98.8 million increase in our, our Development Subsidiary’s and ARP’s depletion expense resulting from the acquisitions consummated during 2014 and 2013.

Total depreciation, depletion and amortization increased to $139.9 million for the year ended December 31, 2013 compared with $52.6 million for the comparable prior year period, which was primarily due to an $85.9 million increase in our and ARP’s depletion expense resulting from the acquisitions consummated during 2013 and 2012.

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

 

     Years Ended
December 31,
 
     2014     2013     2012  

Depletion expense:

      

Total

   $ 231,638      $ 132,860      $ 47,000   

Depletion expense as a percentage of gas and oil production revenue

     49     49     51

Depletion per Mcfe

   $ 2.24      $ 1.89      $ 1.66   

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

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Depletion expense was $132.9 million for the year ended December 31, 2013, an increase of $85.9 million compared with $47.0 million for the year ended December 31, 2012. Depletion expense of gas and oil properties as a percentage of gas and oil revenues decreased to 49% for the year ended December 31, 2013, compared with 51% for the year ended December 31, 2012, which was primarily due to

 

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an increase in ARP’s oil and natural gas liquids revenues as a result of ARP’s acquisitions in 2012. 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.

Asset Impairment

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Asset impairment for the year ended December 31, 2014, was $580.7 million compared with $38.0 million for the comparable prior year period. The $580.7 million of asset impairment primarily consisted of $562.6 million of oil and gas impairment primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. In addition, $18.1 million of asset impairment is due to ARP’s goodwill impairment. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014 through the impairment testing date in January 2015. During the year ended December 31, 2013, ARP recognized $38.0 million of asset impairment related to impairments of gas and oil properties within property, plant and equipment, net on our consolidated balance sheet primarily for our shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. These impairments related to the carrying amounts of these gas and oil properties being in excess of our and our subsidiaries’ estimates of their fair values at December 31, 2014 and 2013 and our intention not to drill on certain expiring unproved acreage. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices in comparison to their carrying values at December 31, 2014 and 2013.

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

Loss on Asset Sales and Disposal

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. During the years ended December 31, 2014 and 2013, losses on asset sales and disposal were $1.9 million and $1.0 million, respectively. The $1.9 million loss on asset sales and disposal for year ended December 31, 2014 was primarily related to ARP’s sale of producing wells in its Niobrara Shale in connection with the settlement of a third party farm-out agreement and a $0.3 million loss from ARP’s involuntary conversion of its Mossy Oak compressor station. The $1.0 million loss on asset sales and 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.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. During the years ended December 31, 2013 and 2012, losses on asset sales and disposal were $1.0 million and $7.0 million, respectively. The $1.0 million loss on asset sales and 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.

 

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Interest Expense

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

 

     Years Ended
December 31,
 
     2014      2013      2012  

Interest Expense:

        

New Atlas Direct

   $ 11,291       $ 5,388       $ 353   

Atlas Resource Partners

     62,144         34,324         4,195   
  

 

 

    

 

 

    

 

 

 

Total

$ 73,435    $ 39,712    $ 4,548   
  

 

 

    

 

 

    

 

 

 

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Total interest expense increased to $73.4 million for the year ended December 31, 2014, compared with $39.7 million for the year ended December 31, 2013. This $33.7 million increase was due to our $5.9 million increase and a $27.8 million increase related to ARP. The $5.9 million increase in our interest expense consisted of a $6.2 million increase associated with our term loan facility, including a $0.6 million increase in the amortization of deferred financing costs, partially offset by a $0.3 million decrease associated with Atlas Energy’s credit facility. The $27.8 million increase in ARP’s interest expense consisted of a $20.7 million increase associated with interest expense on ARP’s Senior Notes, a $6.4 million increase associated with higher weighted-average outstanding borrowings under ARP’s revolving credit facility, a $0.2 million increase in the amortization of ARP’s 7.75% and 9.25% Senior Notes’ discounts, and interest that was capitalized on ARP’s ongoing capital projects, partially offset by a $0.4 million decrease associated with amortization of ARP’s deferred financing costs and a $0.3 million decrease in ARP’s commitment fees. The increase in interest expense related to ARP’s Senior Notes is primarily due to the issuance of an additional $100.0 million of ARP’s 7.75% Senior Notes due 2021 in June 2014 and an additional $75.0 million of ARP’s 9.25% Senior Notes due 2021 in October 2014, as well as a full year of interest expense related to the $275.0 million ARP 7.75% Senior Notes issued in January 2013 and $250.0 million of ARP’s 9.25% Senior Notes issued in July 2013. Our Development Subsidiary had no interest expense for the years ended December 31, 2014 and 2013.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Total interest expense increased to $39.7 million for the year ended December 31, 2013, compared with $4.5 million for the year ended December 31, 2012. This $35.2 million increase was due to our $5.0 million increase and a $30.1 million increase related to ARP. The $5.0 million increase in our interest expense consisted of $4.2 million associated with our term loan facility, a $0.5 million increase in the amortization of deferred financing costs primarily associated with our term loan facility and a $0.3 million increase associated with Atlas Energy’s 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 the 7.75% ARP Senior Notes in January 2013, a $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. Our Development Subsidiary had no interest expense for the years ended December 31, 2013 and 2012.

Loss Attributable to Non-Controlling Interests

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013. Loss attributable to non-controlling interests was $471.4 million for the year ended December 31, 2014, compared with a loss of $58.4 million for the comparable prior year period. Loss attributable to non-controlling interests includes an allocation of ARP’s and our Development Subsidiary’s net income (loss) to non-controlling interest holders. The increase in loss attributable to non-controlling interests between the year ended December 31, 2014, and the prior year comparable period was primarily due to an increase in ARP’s net loss between periods and a decrease in our ownership interests in ARP and our Development Subsidiary during the year ended December 31, 2014.

Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012. Loss attributable to non-controlling interests was $58.4 million for the year ended December 31, 2013, compared with a loss of $17.2 million for the year ended December 31, 2012. Loss attributable to non-controlling interests includes an allocation of ARP’s and our Development Subsidiary’s net income (loss) to non-controlling interest holders. The increase in loss attributable to non-controlling interests between the year ended December 31, 2013, and the prior year comparable period was primarily due to an increase in ARP’s net loss between periods and a decrease in our ownership interests in ARP during the year ended December 31, 2013.

 

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Liquidity and Capital Resources

General

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP, our Development Subsidiary, Lightfoot and our cash generated from operations. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and distributions to our unitholders, which we expect to fund through operating cash flow, and cash distributions received.

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

 

    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.

ARP relies on cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. ARP 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 term loan credit facility, ARP’s credit facility and other borrowings, the issuance of additional limited partner units, the sale of assets and other transactions.

Cash Flows—Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013

Net cash provided by operating activities of $76.1 million for the year ended December 31, 2014 represented a favorable movement of $72.3 million from net cash provided by operating activities of $3.8 million for the comparable prior year period. The $72.3 million favorable movement was derived principally from a favorable movement of $109.5 million in net loss, excluding non-cash items and a $32.3 million favorable movement in working capital, partially offset by a $69.5 million unfavorable movement in distributions paid to non-controlling interests. The non-cash charges which impacted net loss primarily included an increase of $542.6 million in goodwill and other asset impairment, an increase of $102.2 million in depreciation, depletion and amortization, a $2.1 million favorable movement in equity income and distributions related to unconsolidated subsidiaries, an increase of $0.9 million in loss on asset sales and disposal and an increase of $0.2 million in amortization of deferred financing costs, partially offset by an unfavorable movement of $533.6 million in net loss and an unfavorable movement of $4.9 million on non-cash compensation expense. The movement in working capital was due to a $68.9 million favorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s capital programs and the growth of ARP’s business during the year ended December 31, 2014, partially offset by a $36.6 million unfavorable movement in accounts receivable, prepaid expenses and other. The movement in cash distributions to non-controlling interest holders was due principally to increases in cash distributions of ARP.

Net cash used in investing activities of $962.9 million for the year ended December 31, 2014 represented a favorable movement of $90.6 million from net cash used in investing activities of $1,053.5 million for the comparable prior year period. This favorable movement was principally due to a $41.8 million decrease in capital expenditures, a $39.3 million decrease in net cash paid for our, our Development Subsidiary’s and ARP’s acquisitions and a $9.5 million favorable movement in other assets. See further discussion of capital expenditures under “Capital Requirements.”

Net cash provided by financing activities of $934.6 million for the year ended December 31, 2014 represented an unfavorable movement of $102.4 million from net cash provided by financing activities of $1,037.0 million for the comparable prior year period. This unfavorable movement was principally due to a decrease of $339.8 million in net

 

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proceeds from ARP’s long-term debt, an increase of $221.5 million in repayments of our term loan facility, Atlas Energy’s revolving credit facility and ARP’s then-existing term loan facility and revolving credit facility, and a $98.5 million unfavorable movement in net investment from (distribution to) Atlas Energy, partially offset by an increase of $285.4 million for our, Atlas Energy’s and ARP’s borrowings under our term loan facility, Atlas Energy’s revolving credit facility and ARP’s revolving credit facility, an increase of $258.8 million of net proceeds from our Development Subsidiary’s and ARP’s equity offerings and a $13.2 million favorable movement in deferred financing costs, distribution equivalent rights and other. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the combined 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 and ARP, which is generally common practice for our business and industries.

The deferred portion of the purchase price related to the Eagle Ford Acquisition (see “Recent Developments”) represented a non-cash transaction during the year ended December 31, 2014.

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

Net cash provided by operating activities of $3.8 million for the year ended December 31, 2013 represented an unfavorable movement of $9.7 million from net cash provided by operating activities of $13.5 million for the comparable prior year period. The $9.7 million unfavorable movement was derived principally from a $61.1 million unfavorable movement in distributions paid to non-controlling interests and a $17.6 million unfavorable movement in working capital, partially offset by a $69.0 million favorable movement in net 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. The movement in working capital was due to a $58.0 million unfavorable movement in accounts payable and accrued liabilities, primarily due to the timing of ARP’s capital program, partially offset by a $40.4 million favorable movement in accounts receivable, prepaid expenses and other. The non-cash charges which impacted net loss primarily included an increase of $87.3 million of depreciation, depletion and amortization, an increase of $28.5 million in asset impairment, an increase of $8.3 million in amortization of deferred financing costs and an increase of $1.9 million in compensation expense, partially offset by an unfavorable movement of $50.1 million in net loss, a decrease of $6.0 million in loss on asset sales and disposal and an unfavorable movement of $0.9 million in equity income and distributions related to unconsolidated subsidiaries.

Net cash used in investing activities of $1,053.5 million for the year ended December 31, 2013 represented an unfavorable movement of $215.7 million from net cash used in investing activities of $837.8 million for the comparable prior year period. This unfavorable movement was principally due to a $140.3 million increase in capital expenditures, a $71.0 million increase in net cash paid for our and ARP’s acquisitions and a $4.4 million unfavorable movement in other assets. See further discussion of capital expenditures under “Capital Requirements.”

Net cash provided by financing activities of $1,037.0 million for the year ended December 31, 2013 represented a favorable movement of $244.1 million from net cash provided by financing activities of $792.9 million for the comparable prior year period. This movement was principally due to a $510.4 million increase in net proceeds from the issuance of ARP’s long-term debt, a $434.9 million increase in our and ARP’s borrowings under our term loan facility and its revolving credit facilities and a $44.0 million favorable movement in the net investment from (distribution to) Atlas Energy, partially offset by a $580.4 million increase in repayments of our term loan facility and ARP’s revolving and term loan credit facilities, a $156.9 million decrease in net proceeds primarily from ARP’s equity offerings and a $7.9 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 term loan facility, Atlas Energy’s credit facility and ARP’s revolving and term loan credit facilities. The gross amount of borrowings and repayments under the revolving credit facilities included within net cash provided by financing activities in the combined 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 and ARP, which is generally common practice for our and ARP’s industries.

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

 

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Capital Requirements

At December 31, 2014, the capital requirements of our and our subsidiaries’ natural gas and oil production consist primarily of:

 

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

 

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

 

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

 

     Years Ended December 31,  
     2014      2013      2012  

New Atlas Direct and Development Subsidiary

        

Maintenance capital expenditures

   $ 1,200       $ 600       $ —     

Expansion capital expenditures

     11,802         3,343         —     
  

 

 

    

 

 

    

 

 

 

Total

$ 13,002    $ 3,943    $ —     
  

 

 

    

 

 

    

 

 

 

Atlas Resource Partners

Maintenance capital expenditures

$ 65,300    $ 31,500    $ 10,200   

Expansion capital expenditures

  147,334      232,037      117,026   
  

 

 

    

 

 

    

 

 

 

Total

$ 212,634    $ 263,537    $ 127,226   
  

 

 

    

 

 

    

 

 

 

Consolidated

Maintenance capital expenditures

$ 66,500    $ 32,100    $ 10,200   

Expansion capital expenditures

  159,136      235,380      117,026   
  

 

 

    

 

 

    

 

 

 

Total

$ 225,636    $ 267,480    $ 127,226   
  

 

 

    

 

 

    

 

 

 

New Atlas Direct and Development Subsidiary. During the year ended December 31, 2014, our total direct capital expenditures consisted primarily of gathering and processing costs. During the year ended December 31, 2014, our Development Subsidiary’s total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs.

During the year ended December 31, 2013, our total direct capital expenditures consisted primarily of gathering and processing, wells drilled, and leasehold acquisition costs. During the year ended December 31, 2013, our Development Subsidiary’s total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs.

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

During the year ended December 31, 2013, ARP’s $263.5 million of total capital expenditures consisted primarily of $110.8 million