10-K 1 atls-10k_20151231.htm 10-K atls-10k_20151231.htm

 

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, 2015

OR

o

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 Liability Company Interests

 

OTCQX

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  o    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  o    No  x

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

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

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.  o

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  o

 

Accelerated filer  x

    

Non-accelerated filer  ¨

  

Smaller reporting company  o

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

The aggregate market value of the equity securities held by non-affiliates of the registrant, based upon the closing price of the registrant’s common units as reported on the New York Stock Exchange on the last business day of the registrant’s most recently completed second quarter, June 30, 2015, was approximately $125.4 million.

As of March 24, 2016, there were 26,027,992 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


ATLAS ENERGY GROUP, LLC AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

 

 

 

  

 

Page

PART I

 

Item 1:

  

Business

9

 

 

Item 1A:

  

Risk Factors

27

 

 

Item 1B:

  

Unresolved Staff Comments

58

 

 

Item 2:

  

Properties

58

 

 

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

104

 

 

Item 8:

  

Financial Statements and Supplementary Data

107

 

 

Item 9:

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

162

 

 

Item 9A:

  

Controls and Procedures

162

 

 

Item 9B:

  

Other Information

165

 

 

 

 

 

 

PART III

 

Item 10:

  

Directors, Executive Officers and Corporate Governance

165

 

 

Item 11:

  

Executive Compensation

175

 

 

Item 12:

  

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

198

 

 

Item 13:

  

Certain Relationships and Related Transactions, and Director Independence

200

 

 

Item 14:

  

Principal Accountant Fees and Services

204

 

 

 

 

 

 

PART IV

 

Item 15:

  

Exhibits and Financial Statement Schedules

205

 

 

 

 

 

 

SIGNATURES

211

 

 

2


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 barrel of crude oil, condensate or other liquid hydrocarbons equal to 42 United States gallons.

Bcf. One billion cubic feet of natural gas.

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.  Condensate is 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.  The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the 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. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or 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. An exploratory well is 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 or a stratigraphic test well.

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 in the United States of America.

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

MBbl. One thousand barrels of crude oil, condensate or other liquid hydrocarbons.

3


Mcf. One thousand cubic feet of natural gas; the standard unit for measuring volumes of natural gas.

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

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

MMBbl. One million barrels of crude oil, condensate or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcfe. MMcf of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude 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.

Natural Gas Liquids or NGLs. A mixture of light hydrocarbons that exist in the gaseous phase at reservoir conditions but are recovered as liquids in gas processing plants. NGL differs from condensate in two principal respects: (1) NGL is extracted and recovered in gas plants rather than lease separators or other lease facilities; and (2) NGL includes very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus (the main constituent of condensates).

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.

(i)

The area of the reservoir considered as proved includes:

(a)

The area identified by drilling and limited by fluid contacts, if any, and

(b)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

4


(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(a)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(b)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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

Proved Undeveloped Reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be 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 proved 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. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have 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 well bore in another formation from that in which the well has been previously completed.

Reserves. Reserves are estimated remaining quantities of oil and natural 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 natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

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.

5


Unproved Reserves.  Unproved Reserves are based on geoscience and/or engineering data similar to that used in estimates of Proved Reserves, but technical or other uncertainties preclude such reserves being classified as Proved. Unproved Reserves may be further categorized as Probable Reserves and Possible Reserves.

Working Interest. An operating interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and the responsibility to pay royalties and a share of the costs of drilling and production operations under the applicable fiscal terms. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100.00% working interest in a lease burdened only by a landowner’s royalty of 12.50% would be required to pay 100.00% of the costs of a well but would be entitled to retain 87.50% of the production.

 

 

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 limited 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 continue 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 partnership interests in AGP and, therefore, our cash flow is dependent on the ability of ARP and AGP to make distributions in respect of those partnership interests;  

 

our ability to meet our liquidity needs, including as a result of any reduction or elimination of distributions from ARP or AGP and their ability to meet their liquidity needs, and ability to satisfy covenants in our, ARP’s and AGP’s debt documents;

 

actions that we, ARP and AGP may take in connection with our and its liquidity needs, including the ability to service our, ARP’s and AGP’s debt;

 

restrictive covenants in our, ARP’s and AGP’s indebtedness that may adversely affect operational flexibility;

 

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, ARP and AGP achieve;

 

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

 

economic conditions and instability in the financial markets;

 

the impact of our common units being quoted on the OTCQX Best Market and not listed on a national securities exchange;

 

changes in the market price of our common units;

 

future financial and operating results;

 

economic conditions and instability in the financial markets;

 

effects of debt payment obligations on our distributable cash;

6


 

ARP’s ability to meet or exceed the continued listing standards of the New York Stock Exchange;

 

resource potential;

 

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

 

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;

 

potential changes in tax laws that may impair ARP’s ability to obtain capital funds through investment partnerships;

 

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

 

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

 

the 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, ARP and AGP 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 exploration and development costs;

 

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

 

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

7


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 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.  

 

 

8


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”). 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.

We, as the registrant, have provided our financial position and results of operations, including the assets and liabilities and related results of operations transferred to us, by our former parent, Atlas Energy, L.P. in our combined consolidated financial statements.

As of December 31, 2015, our operations primarily consisted of our ownership interests in the following:

 

·

100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% 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 2.1% limited partner interest in Atlas Growth Partners, L.P., a partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States (“AGP”); and a

 

·

15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”) its general partner, which incubate new MLPs and invest in existing MLPs.

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 2,161,445 units at December 31, 2015, which entitles us to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP;

 

·

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

 

·

an approximate 23.3% limited partner ownership interest (20,962,485 common units and 3,749,986 preferred limited partner units) in ARP at December 31, 2015.

9


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, 2015, ARP’s estimated proved reserves were 921 Bcfe, including reserves net to ARP’s equity interest in its Drilling Partnerships. Of ARP’s estimated proved reserves, approximately 82% were proved developed and approximately 66% were natural gas. For the year ended December 31, 2015, ARP’s average daily net production was approximately 266.4 MMcfe. At December 31, 2015, ARP owned 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 736 proved developed wells and 10 proved undeveloped locations totaling 139 Bcfe of total proved reserves with average daily production of 60.6 MMcfe for the year ended December 31, 2015;

 

·

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, 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, and the Arkoma Basin in eastern Oklahoma, where ARP established a position following the Arkoma Acquisition (see “Arkoma Acquisition”), where it has ownership interests in approximately 3,646 proved developed wells and 18 proved undeveloped locations totaling 378 Bcfe of total proved reserves with average daily production of 129.5 MMcfe for the year ended December 31, 2015;

 

·

ARP’s Appalachia Basin where it has ownership interests in approximately 8,620 wells, including approximately 271 wells in the Marcellus Shale, and 90 Bcfe of total proved reserves with average daily production of 34.1 MMcfe for the year ended December 31, 2015;

 

·

ARP’s Eagle Ford Shale in southern Texas where it has ownership interests in approximately 27 proved developed wells and 72 proved undeveloped locations in the Eagle Ford Shale totaling 115 Bcfe of total proved reserves with average daily production of 9.4 MMcfe for the year ended December 31, 2015;

 

·

ARP’s Rangely field in northwest Colorado where it has non-operated ownership interests in approximately 400 wells in the Rangely field and 170 Bcfe of total proved reserves with average daily production of 15.8 MMcfe for the year ended December 31, 2015;

 

·

ARP’s Mississippi Lime and Hunton plays in northwestern Oklahoma where ARP has ownership interests in approximately 108 proved developed wells and 18 Bcfe of total proved reserves with average daily production of 12.3 MMcfe for the year ended December 31, 2015; 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 11 Bcfe of total proved reserves with average daily production of 4.8 MMcfe for the year ended December 31, 2015.

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. Over the three years ended December 31, 2015, ARP has acquired significant net proved reserves and production through the following transactions:

 

·

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.

 

·

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.

10


 

·

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 $408.9 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 AGP 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 $342.0 million, ARP’s initial share of the aggregate purchase price was $206.5 million and AGP’s share was $135.5 million. The Eagle Ford Acquisition had an effective date of July 1, 2014. On July 8, 2015, AGP sold to ARP, for a purchase price of $1.4 million, AGP’s interest in a portion of the acreage it acquired in the Eagle Ford Acquisition. On September 21, 2015, ARP and AGP, in accordance with the terms of the Eagle Ford shared acquisition and operating agreement, agreed that ARP would fund AGP’s remaining two deferred purchase price installments of $16.2 million and $20.1 million to be paid on September 30, 2015 and December 31, 2015, respectively. In conjunction with this agreement, AGP assigned ARP a portion of its non-operating Eagle Ford assets that had an allocated value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by ARP. The transaction was approved by ARP’s and AGP’s respective conflicts committees.  As a result, ARP’s final share of the aggregate purchase price was $242.8 million and AGP’s share was $99.2 million.

 

·

Arkoma Acquisition—On June 5, 2015, ARP completed the acquisition of our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”).

Atlas Growth 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.

AGP’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, 2015, AGP’s estimated proved reserves were 53.5 Bcfe. Of the estimated proved reserves, approximately 22% were proved developed and approximately 87% were oil. For the year ended December 31, 2015, AGP’s average daily net production was approximately 5.0 MMcfe. Through December 31, 2015, AGP owned production positions in the following areas:

 

·

Marble Falls play in the Fort Worth Basin in northern Texas where AGP has ownership interests in approximately 13 wells and 0.1 Bcfe of total proved reserves with average daily production of 0.9 MMcfe for the year ended December 31, 2015;

 

·

the Eagle Ford Shale in southern Texas where AGP has ownership interests in approximately 10 wells in the Eagle Ford Shale and 53.2 Bcfe of total proved reserves with average daily production of 4.1 MMcfe for the year ended December 31, 2015; and

 

·

the Mississippi Lime play in northwestern Oklahoma where AGP has ownership interests in approximately 2 wells and 0.2 Bcfe of total proved reserves with average daily production of 0.1 MMcfe for the year ended December 31, 2015;

At December 31, 2015, after giving effect to the Separation, we owned a 2.1% limited partner interest in AGP 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, 2015, we own an approximate 15.9% interest in Lightfoot’s general partner and a 12.0% interest in Lightfoot’s limited partner.

11


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 27.1% 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”).  On June 5, 2015, ARP completed the acquisition of these assets for approximately $31.5 million, net of purchase price adjustments.

Our operations include three reportable operating segments: ARP, AGP and Corporate and other (see “Item 8: Financial Statements and Supplementary Data – Note 15”).

SUBSEQUENT EVENTS

 

First Lien Credit Agreement Amendment. On March 30, 2016, we and New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to that certain Credit Agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).

 

The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.8 million of the outstanding principal and interest. The Third Amendment amended the First Lien Credit Agreement to, among other things:

 

 

·

provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement;

 

·

shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;

 

·

modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;

 

·

allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;

 

·

provide that the First Lien Credit Agreement may be prepaid without premium;

 

·

replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;

12


 

·

prohibit the payment of cash distributions on our common and preferred units;

 

·

require the receipt of quarterly distributions from AGP and Lightfoot; and

 

·

add a cross-default provision for defaults by ARP.

Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement.

The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.

Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.

The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.

The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.

In connection with the Second Lien Credit Agreement, we agreed to issue within 30 days to the Lenders, warrants (the “Warrants”) to purchase up to 15% of our outstanding common units representing limited partner interests at an exercise price of $0.20 per unit. The Warrants will be subject to customary anti-dilution provisions. We also agreed to enter into a registration rights agreement pursuant to which we will agree to register the offer and resale of the common units underlying the Warrants on terms and conditions acceptable to the Lenders.

Cash Distributions. On January 28, 2016, we declared a monthly cash distribution of $0.3 million for the month ended December 31, 2015 related to our Series A convertible preferred units (“Series A Preferred Units”). The distribution was paid on February 12, 2016 to unitholders of record at the close of business on February 8, 2016.

On March 8, 2016, we declared a monthly cash distribution of $0.3 million for the month ended January 31, 2016 related to our Series A Preferred Units. The distribution was paid on March 16, 2016 to unitholders of record at the close of business on March 9, 2016.

NYSE Compliance. On January 7, 2016, we were notified by the NYSE that we were not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual, because the average closing price of our common units had been less than $1.00 for 30 consecutive trading days.  We also were notified by the NYSE on December 23, 2015, that we were not in compliance with the NYSE’s continued listing criteria under Section 802.01B of the NYSE Listed Company Manual, because our average market capitalization had been less than $50 million for 30 consecutive trading days and our stockholders’ equity had been less than $50 million. On March 18, 2016, we were notified by the NYSE that it determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of our common units at the close of trading on March 18, 2016. Our common units began trading on the OTCQX on Monday, March 21, 2016 under the ticker symbol: ATLS.

Atlas Resource Partners

Senior Notes Repurchase. In January and February 2016, ARP executed transactions to repurchase portions of its senior unsecured notes.  Through the end of February 2016, ARP has repurchased approximately $20.3 million of its 7.75% Senior Notes due 2021 and approximately $12.1 million of its 9.25% Senior Notes due 2021 for approximately $5.5 million.  As a result of these transactions, ARP will recognize approximately $25.9 million as gain on early extinguishment of debt in the first quarter of 2016.

13


Cash Distributions. On January 28, 2016, ARP declared a monthly distribution of $0.0125 per common unit for the month of December 31, 2015. The $2.0 million distribution, including approximately $39,000 and $0.6 million to us as the general partner and as holder of common units and Class C preferred limited units, respectively, was paid on February 12, 2016 to unitholders of record at the close of business on February 8, 2016.

On February 24, 2016, ARP declared a monthly distribution of $0.0125 per common unit for the month of January 31, 2016. The $2.0 million distribution, including approximately $39,000 and $0.6 million to us as the general partner and as holder of common units and Class C preferred limited units, respectively, was paid on March 16, 2016 to unitholders of record at the close of business on March 9, 2016.

On March 29, 2016, ARP declared a monthly distribution of $0.0125 per common unit for the month of February 29, 2016. The $2.0 million distribution, including approximately $39,000 and $0.6 million to us as the general partner and as holder of common units and Class C preferred limited units, respectively, will be paid on April 14, 2016 to unitholders of record at the close of business on April 8, 2016.

On January 15, 2016, ARP paid a quarterly distribution of $0.5390625 per Class D cumulative redeemable perpetual preferred unit (“Class D ARP Preferred Unit”), or $2.2 million, for the period from October 15, 2015 through January 14, 2016, to Class D Preferred Unitholders of record as of January 4, 2016.

On January 15, 2016, ARP paid a quarterly distribution of $0.671875 per Class E cumulative redeemable perpetual preferred unit (“Class E ARP Preferred Unit”), or $0.2 million, for the period from October 15, 2015 through January 14, 2016, to Class E Preferred Unitholders of record as of January 4, 2016.

On March 22, 2016, ARP declared a quarterly distribution of $0.5390625 per Class D ARP Preferred Unit, or $2.2 million, for the period from January 15, 2016 through April 14, 2016, which will be paid on April 15, 2016, to Class D Preferred Unitholders of record as of April 1, 2016.

On March 22, 2016, ARP declared a quarterly distribution of $0.671875 per Class E ARP Preferred Unit, or $0.2 million, for the period from January 15, 2016 through April 14, 2016, which will be paid on April 15, 2016, to Class E Preferred Unitholders of record as of April 1, 2016.

NYSE Compliance. On January 12, 2016, ARP was notified by the NYSE that it was not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual, because the average closing price of its common units had been less than $1.00 for 30 consecutive trading days.  ARP is working to remedy this situation in a timely manner as set forth in the applicable NYSE rules in order to maintain its listing on the NYSE.

Atlas Growth

On February 5, 2016, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended December 31, 2015. The aggregate $4.2 million distribution, including $0.1 million to us as the general partner, was paid on February 12, 2016 to unitholders of record at the close of business on December 31, 2015.

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 AGP. Our direct gas and oil production results from wells drilled in the Eagle Ford Shale, Mississippi Lime and Marble Falls plays by AGP. As of December 31, 2015, we own a 2.1% limited partner interest in AGP 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.

14


Production Volumes

The following table presents ARP’s and AGP’s total net gas, oil and NGL production volumes and production per day during the years ended December 31, 2015, 2014 and 2013:

 

 

 

Years Ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Production per day:(1)(2)

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Resource:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

216,613

 

 

 

238,054

 

 

 

163,971

 

Oil (Bpd)

 

 

5,139

 

 

 

3,436

 

 

 

1,329

 

NGLs (Bpd)

 

 

3,155

 

 

 

3,802

 

 

 

3,473

 

Total (Mcfed)

 

 

266,374

 

 

 

281,486

 

 

 

192,786

 

Atlas Growth:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

557

 

 

 

691

 

 

 

21

 

Oil (Bpd)

 

 

667

 

 

 

117

 

 

 

7

 

NGLs (Bpd)

 

 

81

 

 

 

88

 

 

 

3

 

Total (Mcfed)

 

 

5,047

 

 

 

1,920

 

 

 

79

 

Total production per day:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

217,170

 

 

 

238,745

 

 

 

163,992

 

Oil (Bpd)

 

 

5,806

 

 

 

3,553

 

 

 

1,336

 

NGLs (Bpd)

 

 

3,236

 

 

 

3,891

 

 

 

3,476

 

Total (Mcfed)

 

 

271,421

 

 

 

283,406

 

 

 

192,866

 

 

(1)

Production quantities consist of the sum of (i) the proportionate share of production from wells in which AGP 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.

15


Production Revenues, Prices and Costs

Our subsidiaries’ production revenues and estimated gas, oil and natural gas liquids reserves are substantially dependent on prevailing market prices for natural gas and oil prices. The following table presents our production revenues and average sales prices for our natural gas, oil and natural gas liquids production for the years ended December 31, 2015, 2014, and 2013, along with our average production costs, taxes, and transportation and compression costs in each of the reported periods: 

 

 

 

Years Ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Atlas Resource

 

 

 

 

 

 

 

 

 

 

 

 

Production revenues (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

217,236

 

 

$

318,920

 

 

$

193,050

 

Oil revenue

 

 

122,273

 

 

 

110,070

 

 

 

44,160

 

Natural gas liquids revenue

 

 

17,490

 

 

 

41,061

 

 

 

36,394

 

Total revenues

 

$

356,999

 

 

$

470,051

 

 

$

273,604

 

Atlas Growth

 

 

 

 

 

 

 

 

 

 

 

 

Production revenues (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

518

 

 

$

1,009

 

 

$

28

 

Oil revenue

 

 

10,959

 

 

 

3,770

 

 

 

241

 

Natural gas liquids revenue

 

 

369

 

 

 

928

 

 

 

33

 

Total revenues

 

$

11,846

 

 

$

5,707

 

 

$

302

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

Production revenues (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

217,754

 

 

$

319,929

 

 

$

193,078

 

Oil revenue

 

 

133,232

 

 

 

113,840

 

 

 

44,401

 

Natural gas liquids revenue

 

 

17,859

 

 

 

41,989

 

 

 

36,427

 

Total revenues

 

$

368,845

 

 

$

475,758

 

 

$

273,906

 

 

Average sales price:(1)

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Resource

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(2)(3)

 

$

3.41

 

 

$

3.76

 

 

$

3.48

 

Total realized price, before hedge(2)

 

$

2.23

 

 

$

3.93

 

 

$

3.25

 

Oil (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(3)

 

$

84.30

 

 

$

87.76

 

 

$

91.01

 

Total realized price, before hedge

 

$

44.19

 

 

$

82.22

 

 

$

95.88

 

NGLs (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(3)

 

$

22.40

 

 

$

29.59

 

 

$

28.71

 

Total realized price, before hedge

 

$

12.77

 

 

$

29.39

 

 

$

29.43

 

Atlas Growth

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(2)(3)

 

$

2.55

 

 

$

4.00

 

 

$

3.63

 

Total realized price, before hedge(2)

 

$

2.55

 

 

$

4.00

 

 

$

3.63

 

Oil (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(3)

 

$

46.83

 

 

$

88.61

 

 

$

93.16

 

Total realized price, before hedge

 

$

44.98

 

 

$

88.61

 

 

$

93.16

 

NGLs (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(3)

 

$

12.51

 

 

$

28.80

 

 

$

34.88

 

Total realized price, before hedge

 

$

12.51

 

 

$

28.80

 

 

$

34.88

 

 

Production costs (per Mcfe):(1)

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Resource

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses(4)

 

$

1.34

 

 

$

1.27

 

 

$

1.08

 

Production taxes

 

 

0.19

 

 

 

0.27

 

 

 

0.18

 

Transportation and compression

 

 

0.24

 

 

 

0.25

 

 

 

0.25

 

Total

 

$

1.76

 

 

$

1.80

 

 

$

1.50

 

Atlas Growth

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

0.83

 

 

$

2.47

 

 

$

2.32

 

Production taxes

 

 

0.31

 

 

 

0.48

 

 

 

0.45

 

Transportation and compression

 

 

0.07

 

 

 

 

 

 

 

Total

 

$

1.21

 

 

$

2.95

 

 

$

2.77

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses(4)

 

$

1.33

 

 

$

1.28

 

 

$

1.08

 

Production taxes

 

 

0.19

 

 

 

0.27

 

 

 

0.18

 

Transportation and compression

 

 

0.23

 

 

 

0.25

 

 

 

0.25

 

Total

 

$

1.75

 

 

$

1.81

 

 

$

1.50

 

 

(1)

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

16


(2)

Excludes the impact of subordination of ARP’s production revenue to investor partners within ARP’s Drilling Partnerships. Including the effect of this subordination, the average realized gas sales prices were $3.36 per Mcf ($2.19 per Mcf before the effects of financial hedging), $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging), and $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging) for the years ended December 31, 2015, 2014 and 2013, respectively.

(3)

Includes the impact of $0.5 million of cash settlements for the year ended December 31, 2015, on AGP’s oil derivative contracts which were entered into subsequent to the Company’s decision to discontinue hedge accounting beginning on January 1, 2015. Includes the impact of cash settlements on ARP’s commodity derivative contracts not previously included within accumulated other comprehensive income following our decision to de-designate hedges beginning on January 1, 2015, consisting of $48.6 million associated with natural gas derivative contracts, $35.8 million associated with crude oil derivative contracts, and $8.3 million associated with natural gas liquids derivative contracts for the year ended December 31, 2015 (see “Item 8. Financial Statements – Note 8”).

(4)

Excludes the effects of our proportionate share of lease operating expenses associated with subordination of ARP’s total production revenue to investor partners within its Drilling Partnerships. Including the effects of these costs, ARP’s total lease operating expenses per Mcfe were $1.32 per Mcfe ($1.74 per Mcfe for total production costs), $1.25 per Mcfe ($1.77 per Mcfe for total production costs), and $1.00 per Mcfe ($1.42 per Mcfe for total production costs) for the years ended December 31, 2015, 2014 and 2013, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $1.31 per Mcfe ($1.73 per Mcfe for total production costs), $1.26 per Mcfe ($1.78 per Mcfe for total production costs), and $1.00 per Mcfe ($1.42 per Mcfe for total production costs) for the years ended December 31, 2015, 2014 and 2013, respectively.

Drilling Activity

The number of wells ARP and AGP drill will vary depending on, among other things, the amount of money they 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 ARP and AGP drilled, both gross and for ARP’s and AGP’s interest, during the periods indicated.

 

 

 

Years Ended December 31,

 

 

 

2015(4)

 

 

2014(4)

 

 

2013(4)

 

Atlas Resource Partners:

 

 

 

 

 

 

 

 

 

 

 

 

Gross wells drilled

 

 

28

 

 

 

129

 

 

 

103

 

Net wells drilled(1)

 

 

17

 

 

 

67

 

 

 

66

 

Gross wells turned in line(3)

 

 

36

 

 

 

119

 

 

 

117

 

Net wells turned in line(1) (3)

 

 

15

 

 

 

64

 

 

 

80

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Growth:

 

 

 

 

 

 

 

 

 

 

 

 

Gross wells drilled

 

 

 

 

 

13

 

 

 

2

 

Net wells drilled(2)

 

 

 

 

 

11

 

 

 

2

 

Gross wells turned in line(3)

 

 

6

 

 

 

15

 

 

 

2

 

Net wells turned in line(2) (3)

 

 

6

 

 

 

13

 

 

 

2

 

 

(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.

(2)

Includes AGP’s percentage interest in the wells in which it has a direct ownership interest.

(3)

Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.

(4)

Neither ARP nor AGP drilled any exploratory wells during the years ended December 31, 2015, 2014 and 2013; neither ARP nor AGP had any gross or net dry wells within their operating areas during the years ended December 31, 2015, 2014 and 2013.

Neither ARP nor AGP operate any of the rigs or related equipment used in their respective drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables ARP and AGP 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. ARP and AGP perform regular inspection, testing and monitoring functions on each of our Drilling Partnerships and its operated wells.

As of December 31, 2015, ARP and AGP had the following ongoing drilling activities:

 

 

 

Gross

 

Net

 

Atlas Growth:

 

Spud

 

Total

Depth

 

Completed

 

Spud

 

Total

Depth

 

Completed

 

Eagle Ford Horizontal

 

 

 

2

 

 

 

2

 

 

17


 

 

Gross

 

Net

 

Atlas Resource:

 

Spud

 

Total

Depth

 

Completed

 

Spud

 

Total

Depth

 

Completed

 

Eagle Ford – Horizontal

 

2

 

8

 

 

1

 

1

 

 

 

Commodity Risk Management

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

Contractual Revenue Arrangements

Natural Gas and Oil Production

Natural Gas. ARP and AGP market the majority of their natural gas production to gas marketers directly or to third party plant operators who process and market 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 production area and pricing indices for the majority of 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, 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).

ARP and AGP 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 ARP’s and AGP’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. ARP and AGP 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.

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For the year ended December 31, 2015, Tenaska Marketing Ventures, Chevron, Enterprise, and Interconn Resources LLC accounted for approximately 21%, 15%, 11% and 11% of ARP’s natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period. For the year ended December 31, 2015, Enterprise Crude Oil LLC, Shell Trading Company and Midcoast Energy Partners L.P. accounted for approximately 59%, 28% and 12% of AGP’s 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.

 

·

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. AGP 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. AGP 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. ARP’s and AGP’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, ARP’s, and AGP’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 ARP’s and AGP’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 our subsidiaries do. Moreover, ARP also

19


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 natural gas, oil and NGLs.

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 ARP’s and AGP’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.

Environmental Matters and Regulation

ARP’s and AGP’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 AGP 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 ARP’s and AGP’s operating costs.

We believe that ARP’s and AGP’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

20


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 ARP’s and AGP’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 ARP’s and AGP’s proposed exploration and production activities on federal lands, if any, require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling. The Solid Waste Disposal Act, including RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (the “EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that 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 ARP’s and AGP’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.

ARP’s and AGP’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 ARP and AGP 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 ARP’s and AGP’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

21


may be costly. Further, much of ARP’s and AGP’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 (“USACE”) and the EPA proposed a rule that would define ‘Waters of the United States’ (“WOTUS”), 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 public comment period concluded on November 14, 2014 and the EPA received hundreds of thousands of comments on the proposed rule. On May 27, 2015, the EPA and USACE announced the final rule redefining the extent of the agencies’ jurisdiction over WOTUS, and the final rule was published in the Federal Register on June 29, 2015 with an effective date of August 28, 2015. The final rule was immediately challenged by multiple parties, including individual states, in both United States District Courts and U.S. Circuit Courts of Appeals. On October 9, 2015, the 6th Circuit Court of Appeals found that the petitioners, totaling 18 states, demonstrated a “substantial possibility of success on the merits of the claim” and issued a nationwide stay of the WOTUS final rule.  Currently, this nationwide stay is in place and the litigation in both the U.S. District and Circuit Courts is ongoing.  Additionally, there have been legislative efforts by the General Assembly to nullify the rule, specifically a joint resolution of Congress passed under authority of the Congressional Review Act that was vetoed by President Obama on January 19, 2016. As drafted, the final rule is broader in scope then the current rule, and will increase the costs of compliance and result in additional permitting requirements for some of our existing or future facilities.

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 ARP’s and AGP’s operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. ARP’s and AGP’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. Air permits contain various emissions and operational limitations, and may require specific emission control technologies to limit emissions. Various air quality regulations are periodically reviewed by the EPA and are amended as deemed necessary. The EPA may also issue new regulations based on changing environmental concerns.

Recent revisions to federal Clean Air Act rules impose additional emissions control requirements and practices on ARP’s or AGP’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. ARP’s and AGP’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 ARP’s and AGP’s operations are in substantial compliance with the requirements of the Clean Air Act and comparable state laws and regulations.

While ARP and AGP 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 ARP’s and AGP’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 AGP 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 ARP’s and AGP’s operations. We believe that we are all in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

 

On October 22, 2015, the EPA responded to an October 24, 2012 petition to the EPA requesting that the oil and gas extraction industrial sector be added to the sectors with reporting requirements covered by Section 313 of the Emergency Planning and Community Right-to-Know Act (the Toxics Release Inventory or “TRI”).  In its response, the EPA stated that it intends to propose a rulemaking that would subject natural gas processing facilities that employ more than 10 people to annual TRI reporting, but that the

22


EPA will not propose that well sites, compressor stations, pipelines, and other oil and gas extraction industrial sector facilities be subject to TRI reporting.  

 

Additionally, the White House Office of Management and Budget received OSHA’s final “Occupational Exposure to Crystalline Silica” rule on December 21, 2015.  The final rule has not been published, but is expected to follow OSHA’s proposed rule from September 12, 2013 that would impose a new exposure limit for silica and with it various new requirements.  The federal 2015 Fall Unified Agenda and Regulatory Plan lists February 2016 as the target release date for the final rulemaking.  OSHA has previously addressed respirable silica from the oil and gas industry operations back in December 2014 when it released a “Hydraulic Fracturing and Flowback Hazards Other than Respirable Silica” safety alert.  If finalized, the rule would likely result in significant costs for the oil and gas industry to comply with the new 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 business. However, Congress has been actively considering climate change legislation. More directly, the EPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (Dec. 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two final rules relating to greenhouse gases that will affect our businesses.

 

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

 

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

 

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (Oct. 2009). Subsequent revisions, additions and clarifications were promulgated, including a rule subpart specifically addressing the natural gas industry. This particular subpart was most recently revised in October 2015, 80 Fed. Reg. 64262 (Oct. 22, 2015), when the EPA finalized changes to calculation methods, monitoring and data reporting requirements, and other provisions.  Shortly thereafter, in January 2016, the EPA proposed additional revisions to the broader Greenhouse Gas Reporting 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 the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us 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 was 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. This national methane reduction strategy targeting the oil and gas sector is related to the Obama Administration’s broader Climate Action Plan of 2013.  Multiple federal agencies, including the EPA and the U.S. Department of the Interior’s Bureau of Land Management, which we refer to as the BLM, are involved in implementing the national methane reduction strategy.

 

In August 2015, the EPA proposed a broad suite of regulatory measures to implement the national methane reduction strategy, as well as to reduce emissions of ozone-forming volatile organic compounds (“VOCs”) and clarify air permitting requirements for the oil and gas sector.  The proposed measures include: (1) a revised New Source Performance Standards (“NSPS”) rule for oil and natural gas production, transmission, and distribution that would expand existing requirements for sources of VOCs and establish new requirements for sources of methane; (2) draft Control Techniques Guidelines that direct states to adopt regulations for reducing VOC emissions from existing oil and gas facilities in certain ozone nonattainment areas and states in the Ozone Transport Region; (3) a

23


Federal Implementation Plan for certain oil and gas operations located in Indian country; and (4) a rule defining the circumstances in which oil and gas equipment and activities are to be considered part of a source that is subject to “major source” permitting requirements under the Clean Air Act.  The EPA accepted public comments on these proposals through early December 2015.  The proposals are expected to be finalized in 2016.

 

Consistent with the Obama Administration’s methane reduction strategy, on January 22, 2016, BLM released a proposed rule to update standards for venting, flaring, and equipment leaks from oil and gas production activities on onshore Federal and Indian leases.  BLM’s existing requirements are more than three decades old.  According to BLM, the proposed rule would ensure that operators use modern best practices to minimize waste of produced natural gas and reduce emissions of methane and VOCs.  

 

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

 

In addition to domestic regulatory developments, the United States is a participant in multi-national 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 (e.g., the “Paris Agreement,” reached at the United Nations Conference on Climate Change in December 2015) that could have an impact on our business.

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 ARP’s and AGP’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 ARP’s and AGP’s natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974, or “SDWA.” This amendment effectively excluded hydraulic fracturing for oil, gas or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on ARP’s business and operations. For instance, the EPA released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels in February 2014, along with responses to selected substantive public comments on the EPA’s previous draft guidance, a fact sheet and a memorandum to the EPA’s regional offices regarding implementation of the guidance. The process for implementing the EPA’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 re-introduced in the current 114th Session of Congress and referred to the Committee on Environment and Public Works; 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.

We believe ARP’s and AGP’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 AGP conduct its natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. ARP and AGP 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 AGP 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

24


parties and may reduce ARP’s or AGP’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 ARP or AGP 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 2015, the impact fee for qualifying unconventional horizontal wells spudded during 2015 was $45,300 per well, while the impact fee for unconventional vertical wells was $9,100 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 ARP’s and AGP’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,  a regulatory tax of $.001875 per barrel and the oil field clean-up fee of $.00625 per barrel of crude. New Mexico imposes, among other taxes, a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax of up to 0.24% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas. Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% on oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, up to 7% per Mcf of natural gas and a petroleum excise tax of .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 AGP’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 ARP and AGP have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

 

A number of federal agencies, including the EPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, the EPA is conducting a study that evaluates any potential effects of hydraulic fracturing on drinking water and ground water. On December 9, 2013, the 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 the EPA’s study were published in July 2014. On June 4, 2015, the EPA released its draft “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources” (the “Draft Assessment”), in addition to nine new peer-reviewed scientific reports that formed the basis for certain findings included in the Draft Assessment.  The scope of  the Draft Assessment focuses on potential impacts to drinking water resources by hydraulic fracturing, specifically the following water activities that the EPA has identified as the “hydraulic fracturing water cycle” in the Draft Assessment: water acquisition from ground or surface waters; chemical mixing at the well site; well injection of hydraulic fracturing fluids; the collection and handling of wastewater from hydraulic fracturing (such as flowback and produced water); and wastewater treatment and waste disposal.  The EPA revealed in its Draft Assessment that it has not found any evidence that hydraulic fracturing activities are performed in a way that leads to widespread, systemic impacts on drinking water resources.  The EPA did identify specific instances where hydraulic fracturing activities may have led to impacts to drinking water; however, the EPA noted that those instances are minimal when compared to the number of hydraulically fractured wells in the United States.  Notice of the Draft Assessment was published in the June 5, 2015 Federal Register, and several public teleconference calls and a public meeting were held by the EPA’s Science Advisory Board (SAB) to discuss the Draft Assessment.  On January 7, 2016, the SAB released a Draft Review of the EPA’s Draft Assessment.  The Draft Review includes many recommendations to the EPA that SAB believes the EPA should consider to improve the Draft Assessment.  These recommendations include, but are not limited to: revising its draft finding that the EPA found no “evidence that hydraulic fracturing mechanisms have led to widespread, systemic impacts on drinking water resources,” as the SAB found the statement to be ambiguous and therefore require clarification and

25


additional explanation; adding further discussion on the Pavillion, Wyoming; Parker County, Texas; and Dimock, Pennsylvania investigations; collecting and add new data regarding the chemicals used during hydraulic fracturing and the content of flowback water; and adding Best Management Practices and suggested improvements to each stage of the hydraulic fracturing process.

 

BLM proposed a rule on May 11, 2012 that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands. On May 24, 2013, BLM published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. On March 26, 2015, BLM issued a final rule updating the regulations governing hydraulic fracturing on federal and Indian lands.   Among the many new requirements, the final rule requires operators planning to conduct hydraulic fracturing to design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate usable water, as well as requires operators to monitor cementing operations during well completion.  Additionally, the final rule requires that companies publicly disclose the chemicals used in the hydraulic fracturing process, subject to limited exceptions for trade secret materials; comply with safety standards for storage of produced water in rigid enclosed, covered, or netted and screened above-ground tanks, with very limited exceptions allowing use of pits that must be approved by BLM on a case-by-case basis; and submit detailed information to the BLM on proposed operations, including but not limited to well geology, location of faults and fractures, estimated volume of fluid to be used, and estimated direction and length of fractures.  The final rule also provides that for certain circumstances in which specific state or tribal regulations are equally or more protective than the BLM’s new rules, the state or tribe may obtain a variance for that specific regulation.  The final rule was set to go into effect on June 24, 2015.  However on June 23, 2015, the U.S. District Court for the District of Wyoming announced a stay on the effective date of the rule in State of Wyoming v. Dep't of Interior, No. 2:15-cv-00043, a lawsuit that involves several states and industry associations who requested that the Court grant a preliminary injunction of the final rule.  On September 30, 2015, the U.S. District Court granted the preliminary injunction, thus enjoining the final rule.

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, potentially subject to trade secret/confidential proprietary information protections, 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 amendment or expansion, frequently increasing the regulatory burden on the industry. 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 ARP’s or AGP’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. ARP’s and AGP’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.

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Employees

We employed approximately 619 persons as of December 31, 2015. Some of our officers may spend a substantial amount of time managing the business and affairs of ARP, AGP 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, our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports, available through our website at www.atlasenergy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. To view these reports, click on “Investor Relations”, then “SEC Filings”. The other information contained on or hyperlinked from our website does not constitute part of this report. 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.

 

 

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 AGP’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 limited 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.

 

Much of 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.

 

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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 from the Separation from Atlas Energy, or such benefits may be delayed or not occur at all. These expected benefits include the following:

 

 

The facilitation of a 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 creation of an acquisition currency in the form of units that may 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.

 

 

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

 

 

The creation of independent equity structures which afford each company direct access to capital markets and facilitate the ability to capitalize on its unique growth opportunities.

 

 

 

Providing 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 and potential for the two companies to compete with one another in the marketplace. 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 partnership interests in AGP, and, therefore, our cash flow is dependent on the ability of ARP and AGP to make distributions in respect of those partnership interests.

 

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

 

 

the amount of natural gas and oil they produce;

 

 

the price at which they sells their natural gas and oil;

 

 

the level of their operating costs;

 

 

their ability to acquire, locate and produce new reserves;

 

 

the results of their hedging activities;

 

 

the level of their interest expense, which depends on the amount of  indebtedness and the interest payable on it; and

 

 

the level of their capital expenditures.

 

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

 

 

their ability to make working capital borrowings to pay distributions;

 

 

the cost of acquisitions, if any;

 

 

fluctuations in their working capital needs;

 

 

timing and collectability of receivables;

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restrictions on distributions imposed by lenders;

 

 

requirements to repay outstanding borrowings;

 

 

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

 

 

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

 

 

 

Because of these factors, we cannot guarantee that ARP or AGP will have sufficient available cash to pay a specific level of cash distributions, if any, to its partners. You should also be aware that the amount of cash that ARP and AGP have available for distribution depend primarily upon their 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, while each of ARP and AGP may make cash distributions during periods when it records net losses, it may not be able to make cash distributions during periods when it records net income.

 

Our operations require liquidity for normal operating expenses, servicing our debt, capital expenditures and distributions to our unitholders.

Our primary liquidity requirements, in addition to normal operating expenses, are for servicing our debt, capital expenditures and distributions to our unitholders. In general, we expect to fund our liquidity needs through cash distributions received with respect to our ownership interest in ARP, our Development Subsidiaries, Lightfoot and our cash generated from operations.  As discussed above, our cash flow is dependent on the ability of ARP and AGP to make distributions in respect of their partnership interests. Due to the steep decline in commodity prices, our ability to obtain funding in the equity or capital markets has been, and may continue to be, constrained, and there can be no assurances that our liquidity requirements will continue to be satisfied given current commodity prices.  If our sources of liquidity are not sufficient to fund our current or future liquidity needs, including as a result of any reduction or elimination of distributions from ARP or AGP, we may be required to take other actions, such as:

 

·

refinancing, restructuring or reorganizing all or a portion of our debt or capital structure;

 

·

obtaining alternative financing;

 

·

selling assets;

 

·

reducing or delaying capital investments;  

 

·

seeking to raise additional capital;

 

·

continuing to take, and potentially increasing, our cost saving measures to reduce costs, including renegotiation contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs; or

 

·

revising or delaying our other strategic plans.

Our ability to take these actions will depend on, among other things, the conditions of the capital markets and our financial condition at such time.  Additionally, ARP and AGP each have their own liquidity needs and, to the extent their respective sources of liquidity are not sufficient to fund their current or future liquidity needs, they also may take certain actions, including those listed above.  Due to the steep decline in commodity prices, we, ARP or AGP may not be able to obtain funding in the equity or capital markets on acceptable terms as the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards and reduced and, in some cases, ceased to provide any new funding.  We cannot assure you that we, ARP or AGP would be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that would be permitted under the terms of the applicable debt instruments or in a manner that does not negatively impact the price of our or their securities.  Additionally, there can be no assurance that the above actions would allow us, ARP or AGP, as applicable, to meet debt obligations and capital requirements.

 

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

 

Our and ARP’s and AGP’s cash distribution policies, consistent with the terms of our limited liability company agreement and ARP and AGP’s limited partnership agreements, 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 outstanding debt, reduction or elimination of future distributions from ARP or AGP, the effect of working capital requirements and anticipated cash needs of us, ARP or AGP.

 

 

·

Our cash distribution policies are subject to restrictions on distributions under our term loan credit facility, such as material financial and other covenants and limitations on paying distributions during an event of default. More specifically, the recent Third Amendment to the First Lien Credit Agreement and the Second Lien Credit Agreement prohibit us from paying cash distributions on our common and preferred units.

 

 

·

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

 

 

·

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 also be 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, and these additional units would dilute our common unitholders’ ownership interests in us and our ownership interest in ARP.

 

 

·

Under Delaware law, neither we, ARP nor AGP 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.

 

Our cash distribution policy limits our ability to grow.

 

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Because we distribute our available cash, if any, 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;

 

·

a decrease in ARP or AGP’s distributions to us, including as a result of any restrictions in their ability to make such distributions or a reduction in their liquidity; or

 

·

an increase in working capital requirements.

 

If we issue additional units or incur debt to fund our operations, acquisitions and expansion or 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 make distributions.

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

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil, which have declined substantially. Lower commodity prices may reduce the amount of natural gas and oil that we 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. Continued 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, 2015, the NYMEX Henry Hub natural gas index price ranged from a high of $3.23 per MMBtu to a low of $1.76 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $61.43 per Bbl to a low of $34.73 per Bbl. Between January 1, 2016 and March 24, 2016, the NYMEX Henry Hub natural gas index price ranged from a high of $2.47 per MMBtu to a low of $1.64 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $41.45 per Bbl to a low of $26.21 per Bbl.

A continuation of the prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, and ability to commence and continue cash distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural gas sales to reduce the impact of commodity price fluctuations. However, the entire exposure of our operations from commodity price volatility is not currently hedged, and we may not be able to hedge such exposure going forward. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be further diminished.

In addition, low oil and natural gas prices have reduced, and may in the future further reduce, the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices.

 

Oil prices and natural gas prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Approximately 18% of our 2015 total revenues were derived from oil and condensate sales. Approximately 80% of our 2015 total production was natural gas, on a “Mcf-equivalent” basis. Any additional decreases in prices of oil and natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to commence distributions, perhaps materially.

 

During the year ended December 2015, the spot WTI market price at Cushing, Oklahoma has declined from a high of $61.43 per Bbl to a low of $34.73 per Bbl. During the nine years prior to December 31, 2015, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.76 per MMBtu in 2015. Between January 1, 2015 and December 31, 2015, the Henry Hub spot market price of natural gas ranged from a high of $3.23 per MMBtu to a low of $1.76 per MMBtu. The reduction in prices has been caused by many factors, including substantial increases in U.S. oil and natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. The International Energy Agency (“IEA”) forecasts steady or a slightly declining U.S. production growth and a slowdown in global demand growth in 2016.

This environment could cause the prices for oil and natural gas to remain at current levels or to fall to even lower levels. If prices for oil and natural gas continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil and natural gas will negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.  

 

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

 

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the Chinese economy, and the United States real estate market have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and could lead to a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids produced from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and potential cash available for distribution.

 

The above factors can also cause volatility in the markets and affect our, ARP’s and AGP’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 AGP’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, respond to competitive pressures or service our debt, any of which could negatively affect our businesses.

 

A continuing or 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 and AGP’s cash flow and ability to pay distributions could be affected which in turn affects our ability to commence distributions 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;

 

·

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.  In addition, the recent Third Amendment to our First Lien Credit Agreement and the Second Lien Credit Agreement incorporate the financial covenants from ARP’s credit facility and adds a cross-default provision for defaults by ARP.

 

If we are unable to meet any of the covenants in our term loan credit facility or if ARP is unable to meet covenants in its credit facilities or the indentures governing its senior notes, we and ARP may be required to enter into discussions with our respective lenders or take other actions, such as: refinancing, restructuring or reorganizing all or a portion of our debt or capital structure; obtaining alternative financing; selling assets; reducing or delaying capital investments; seeking to raise additional capital; continuing

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to take, and potentially increasing, our cost saving measures to reduce costs, including renegotiation contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs; or revising or delaying our other strategic plans, which may negatively impact the price of our securities.  A breach of any of the covenants in these credit facilities or the indentures governing ARP’s senior notes, respectively, could result in an event of default thereunder as well as a cross-default under such defaulting party’s other debt agreements and, in either case, our credit agreement. Upon the occurrence of an event of default, the lenders under these credit facilities or holders of ARP’s notes, as applicable, could elect to declare all amounts outstanding immediately due and payable, which could result in a cross-default or cross-acceleration under such party’s other debt agreements, and the lenders could terminate all commitments to extend further credit. If we or ARP were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness, including, with respect to our term loan credit facility, the general partnership interests in ARP.  If our lenders elect to foreclose on the general partnership interests of ARP, a change of control would result under ARP’s credit facilities and indentures and the lenders or noteholders thereunder would have the right to require repayment of all obligations outstanding under such credit facilities and indentures and otherwise proceed against any collateral securing such obligations. We and ARP have pledged a significant portion of our respective assets as collateral under our respective credit facilities. If the lenders accelerate the repayment of borrowings, we or ARP may not have sufficient assets to repay the applicable credit facilities and other applicable liabilities, and there may be no assets remaining to be distributed to our respective unitholders (including us as a unitholder of ARP).  On March 30, 2016, we entered into a Third Amendment to our First Lien Credit Agreement and a new Second Lien Credit Agreement  that, among other things, modifies certain financial covenants, incorporates the ARP financial covenants, provides for a cross-default for defaults by ARP and prohibits us from paying distributions on our common and preferred units.

 

Our and ARP’s borrowings under our respective credit facilities are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk.  If interest rates increase, our and ARP’s debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same. The provisions of our term loan credit facility may also 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.

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

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

 

·

requiring a substantial portion of 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 and ARP’s debt, which could increase future debt costs and limit the future availability of debt financing;

 

 

·

increasing our and ARP’s 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 and ARP’s business;

 

 

·

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

 

 

·

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

 

 

·

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

 

 

·

limiting our and ARP’s ability to commence or pay cash distributions.

 

In addition, the recent Third Amendment to our First Lien Credit Agreement prohibits us from paying cash distributions on our common and preferred units.

 

 

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, ARP and AGP 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.

 

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In addition, we, ARP and AGP 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:

 

 

·

a counterparty is unable to satisfy its obligations;

 

·

production is less than expected; 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, ARP and AGP 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.

 

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 ongoing implementation of derivatives legislation adopted by the U.S. Congress 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, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized many of the regulations associated with the reform legislation, and is in the process of implementing position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC recently adopted final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants and financial end users (though non-financial end users are excluded from margin requirements).  While, as a non-financial end user, we are not subject to margin requirements, application of these requirements to our counterparties could affect the cost and availability of swaps we use for hedging.

 

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

 

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 commence 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;

 

36


 

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

 

ARP and AGP 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 or AGP common units may increase the risk of these entities 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 ARP nor AGP’s common units nor ARP’s 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 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 unit 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. Pursuant to a recent amendment to its senior credit facility, ARP is currently limited to a maximum common unit cash distribution of $0.15 per unit per year, which is far below the distribution amount that would be required for us to receive incentive distributions.

 

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

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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 or if AGP’s general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of AGP, their value, and therefore, 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.

 

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

 

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

 

If we cease to manage and control ARP or AGP, we may be deemed to be an investment company under the Investment Company Act of 1940 and would then 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 under the Investment Company Act of 1940, 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, any cash available for distribution to you would be substantially reduced, which could result in a material reduction in distributions to you, if any, with a possible corresponding reduction in the value of our common units.

 

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our 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 maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our 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

38


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.

 

Risks Relating to Our, ARP’s and AGP’s Exploration and Production Operations

 

Competition in the natural gas and oil industry is intense, which may hinder our, ARP’s and AGP’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 AGP 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 AGP’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 AGP 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 AGP’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.

 

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

 

Our, ARP’s and AGP’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 AGP’s ability to find economically recoverable quantities of natural gas and oil in these areas.

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Our, ARP’s and AGP’s operations require substantial capital expenditures to increase our asset bases. If we, ARP or AGP 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 commence or continue distributions.

 

The natural gas and oil industry is capital intensive. Because we distribute our available cash, if any, to our unitholders each quarter in accordance with the terms of our limited liability company agreement, and ARP distributes its available cash, if any, 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 AGP are unable to obtain sufficient capital funds on satisfactory terms, 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 AGP’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 AGP 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.

 

 

We, ARP and AGP 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 AGP’s revenues and available cash could decline.

 

We, ARP and AGP 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 AGP’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, 2015, Tenaska Marketing Ventures, Chevron, Enterprise, and Interconn Resources LLC accounted for approximately 21%, 15%, 11% and 11% of ARP’s natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period. For the year ended December 31, 2015, Enterprise Crude Oil LLC, Shell Trading Company and Midcoast Energy Partners L.P. accounted for approximately 59%, 28% and 12% of AGP’s natural gas, oil and NGL production revenues, 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 AGP, 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 AGP  receive for our production could significantly reduce our available cash and adversely affect our financial condition.

 

The prices that we, ARP and AGP 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 AGP receive could significantly reduce our, ARP’s or AGP’s available cash 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 AGP 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, 2015, leases covering approximately 4,702 of our 742,944 net undeveloped acres, or 0.6%, are scheduled to expire on or before December 31, 2016. An additional 1.6% of our net undeveloped acres are scheduled to expire in 2017 and 0.2% in 2018. 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.

 

ARP’s and AGP’s drilling activities are subject to many risks, including the risk that they 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. This risk is exacerbated by the current decline in oil and gas prices. In addition, ARP’s or AGP’s drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

 

higher costs, shortages or delivery delays of equipment and services;

 

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unexpected operational events and drilling conditions;

 

 

adverse weather conditions;

 

 

facility or equipment malfunctions;

 

 

title problems;

 

 

 

pipeline ruptures or spills;

 

 

compliance with environmental and other governmental requirements;

 

 

unusual or unexpected geological formations;

 

 

formations with abnormal pressures;

 

 

injury or loss of life and property damage to a well or third-party property;

 

 

leaks or discharges of toxic gases, brine, natural gas, oil, hydraulic fracturing fluid and wastewater from a well;

 

 

environmental accidents, 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 ARP’s and AGP’s receipt of drilling and production revenues, thereby reducing our, ARP’s and AGP’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, which may not fully be covered by insurance, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties, which could reduce our, ARP’s and AGP’s cash flow and our ability to commence distributions.

 

Although we, ARP and AGP 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 AGP’s results of operations.

 

Unless ARP and AGP replace their 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. ARP’s and AGP’s natural gas and oil reserves and production and, therefore, cash flow and income are highly dependent on their success in efficiently developing and exploiting reserves and economically finding or acquiring additional recoverable reserves. ARP’s and AGP’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, all of which are subject to the risks discussed elsewhere in this section.

 

The recent decrease in natural gas and oil prices, or any further decrease in commodity prices, could subject our, ARP’s and AGP’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 AGP 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

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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.

 

Prolonged depressed prices of natural gas and oil may cause the carrying value of our, ARP’s and AGP’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. For the year ended December 31, 2015, we recognized $974.0 million of asset impairment primarily related to oil and gas properties in ARP’s Barnett, Coal-bed Methane, Rangely, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, reduced by $85.8 million of future hedge gains reclassified from accumulated other comprehensive income.

 

Our, ARP’s and AGP’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 AGP’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 AGP 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 AGP 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 AGP’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 AGP’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.

 

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

 

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

 

Good and clear title to our, ARP’s and AGP’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 AGP from such properties.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our, ARP’s and AGP’s business, financial condition, results of operations and cash available for distribution.

 

 

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.   On June 29, 2015 the New York State Department of Environmental Conservation officially prohibited hydraulic fracturing in New York State by issuing its legally-binding Findings Statement.  According to the Findings Statement, the Department of Conservation concluded that “there are no feasible or prudent alternatives that would adequately avoid or minimize adverse environmental impacts and that address the scientific uncertainties and risks to public health” associated with hydraulic fracturing.

 

 

 

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. Pursuant to a legislative bill that passed in July 2014 as a companion to Pennsylvania’s budget for 2014 to 2015, PADEP bifurcated its proposed 25 Pa. Code Chapter 78 regulations into two parts. . As proposed, 25 Pa. Code Chapter 78 will apply to conventional wells and 25 Pa. Code Chapter 78A will apply to unconventional wells. On January 6, 2016, PADEP released a final-form rulemaking package of the Chapters 78 and 78a amendments. PADEP identified the key provisions of the final-form rulemaking package to include, but not be limited to, new requirements for operators to address potential impacts to public resources, as well as requirements for operators to identify and monitor abandoned, orphaned and inactive wells prior to hydraulic fracturing.  It will also mandate new containment practices and protection water resources, which includes rules for operator response to spill and remediation, and many other changes that will impact ARP’s and AGP’s operations.  Pennsylvania’s Environmental Quality

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Board is scheduled to meet February 3, 2016 to consider the proposed rulemakings, and PADEP anticipates that the final form rulemaking will likely be finalized in early summer 2016. 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). It is anticipated that these proposed amendments will be released in 2016. In January 2015, PADEP issued the results of its Technologically Enhanced Naturally Occurring Radioactive Materials Study, which analyzed levels of radioactivity 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 July 2015, the regulatory authority adopted 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 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 previous 1984 Oil and Gas Act. The total impact of these rulings in Robinson Township, which is ongoing before the Supreme Court, 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. Additionally, there is a pending challenge by an industry association regarding the Robinson Township decision and PADEP’s use of its Public Resources Form and Pennsylvania Natural Diversity Index Policy based on a provision of the 2012 Oil and Gas Act (58 C.S. § 3215(c)).  The petitioner is seeking a declaration from the Supreme Court that PADEP is enjoined from application and enforcement of that provision pursuant to the Court’s Robinson Township ruling.

 

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.

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Although, to date, the hydraulic fracturing process has not generally been subject to regulation at the federal level, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. A few of these initiatives are listed here, although others may exist now or be implemented in the future. In April 2012, President Obama established an Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources with the purpose of coordinating the policies and activities of agencies regarding unconventional gas development. USEPA 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, USEPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. In February 2014, USEPA 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 USEPA’s previous draft guidance, a fact sheet 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 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, USEPA is currently studying the potential impacts of hydraulic fracturing on drinking water and groundwater, and, in fact, released a Draft Assessment on June 4, 2015.

 

In 2013, USEPA 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, USEPA has yet to propose the draft water quality criteria document and it has not provided an updated timeframe for the proposal. On April 7, 2015, USEPA published its “Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category” in the Federal Register, and accepted comments through July 17, 2015.  As proposed, the regulations would establish pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and gas extractive facilities to publicly-owned treatment works.  USEPA has proposed pretreatment standards for existing and new sources that would prohibit the indirect discharge of wastewater pollutants associated with onshore unconventional gas extraction facilities.  Additionally, USEPA published its “Final 2014 Effluent Guidelines Program Plan” on August 4, 2015 and confirmed its schedule for the aforementioned ongoing unconventional oil and gas extraction effluent guideline rulemaking, as well as announced a final decision to continue its detailed study to investigate centralized waste treatment facilities that accept oil and gas extraction wastewaters. On May 11, 2012, the U.S. Department of the Interior, Bureau of Land Management published a proposed rule that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal and Indian lands. On May 24, 2013, the Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. On March 26, 2015, BLM issued a final rule updating the regulations governing hydraulic fracturing on federal and Indian lands that was set to go into effect on June 24, 2015.  Subsequently on June 23, 2015 in a lawsuit filed by several states and industry associations before the U.S. District Court for the District of Wyoming (State of Wyoming v. Dep't of Interior, No. 2:15-cv-00043), a stay of the effective date of the BLM’s pending rule was lodged.  The petitioners specifically requested that Court grant a preliminary injunction of the final rule and, on September 30, 2015, the U.S. District Court granted the preliminary injunction thereby enjoining the final rule.

 

 

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. A subsequent Annual Energy Outlook 2015 was released on April 14, 2015, with the next coming June 2016. 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 USEPA 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 ARP or AGP are ultimately able to produce from our reserves.

 

The third parties on whom we, ARP and AGP 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 AGP  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 AGP’s business, financial condition, results of operations and our ability to commence and continue 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 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 may 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. The Obama Administration announced a formal methane reduction strategy in January 2015, and is taking actions to implement the strategy (see “Item 1. Business- Environmental Matters and Regulation - Greenhouse Gas Regulation and Climate Change”). 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, ARP’s and AGP’s equipment and operations could require ARP and AGP to incur costs to reduce emissions of greenhouse gases associated with its 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 ARP and AGP’s 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.

 

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, ARP and AGP’s exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to ARP and AGP’s facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to

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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 ARP and AGP’s 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. ARP and AGP’s 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.

 

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

 

A significant portion of ARP’s and AGP’s natural gas extraction activity utilizes hydraulic fracturing, which results in water that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on ARP’s and AGP’s operations and financial performance. For example, Pennsylvania’s 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.  

 

ARP and AGP’s ability to collect and dispose of flowback and produced water will affect production, and potential increases in the cost of wastewater treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could include restrictions on ARP and AGP’s ability to conduct hydraulic fracturing or disposal of wastewater, 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 of Natural Resources 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.

 

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

 

In 2012, USEPA established the NSPS rule for oil and natural gas production, transmission, and distribution, and also made significant revisions to the existing National Emission Standards for Hazardous Air Pollutants (“NESHAP”) rules for oil and natural gas production, transmission, and storage facilities. These rules require oil and natural gas production facilities to conduct “green completions” for hydraulic fracturing, which is recovering rather than venting the gas and natural gas liquids that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment.  Both the NSPS and NESHAP rules continue to evolve based on new information and changing environmental concerns. The NSPS rule was most recently revised in August 2015, 80 Fed. Reg. 48262 (Aug. 12, 2015), and it will be revised again when USEPA finalizes the rulemaking to implement the national methane reduction strategy (see “Item 1. Business- Environmental Matters and Regulation - Greenhouse Gas Regulation and Climate Change”). In November 2015, USEPA issued a formal request for data and information which suggests that the agency may revise the NESHAP rules in the near future.  In addition to these USEPA rules, BLM released a proposed rule in January 2016 to reduce oil and gas industry emissions and minimize waste of produced gas from Federal and Indian leases.      

States are also proposing increasingly stringent requirements for air pollution control and permitting for well sites and compressor stations. For example, in January 2016, the Governor of Pennsylvania announced a comprehensive new regulatory strategy for reducing methane emissions from new and existing oil and natural gas operations, including well sites, compressor stations, and pipelines. Implementation of this strategy will result in significant changes to the air permitting and pollution control standards that apply to the oil and gas industry in Pennsylvania.  It may also influence air programs in other oil and gas-producing states.  Moreover West Virginia issued General Permit 70-A for natural gas production facilities at the well site in 2013.  In response to industry concerns regarding the restrictiveness of the general permit, in November 2015, West Virginia issued General Permit 70-B which provides more flexibility for emission sources located at the well site.  

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Overall, compliance with new rules regulating air emissions from ARP’s or AGP’s operations could result in significant costs, including increased capital expenditures and operating costs, and could affect the results of their business.

 

 

Impact fees and severance taxes could materially increase liabilities.

 

In an effort to offset budget deficits and fund state programs, many states have imposed impact fees and/or severance taxes on the natural gas industry. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” on unconventional natural gas and oil production which includes the Marcellus Shale. The impact fee is based upon the year a well is spudded and varies, like most severance taxes, based upon natural gas prices.  For the year ended December 31, 2015, we estimated that the impact fee for our wells, including the wells in our Drilling Partnerships will approximately $880,000.  This is compared to an impact fee of approximately $1.0 million for the year ended December 31, 2014, an impact fee of approximately $1.7 million for the year ended December 2013 and an impact fee of approximately $2.0 for year ended December 31, 2012.

 

 

Because ARP and AGP 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 ARP and AGP 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 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 ARP or AGP 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.

 

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 ARP or AGP 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 USEPA and/or the appropriate state agency. In some cases, USEPA has taken a heightened role in enforcement activities targeting the oil and gas extraction sector. For example, in 2011, USEPA Region III requested the lead on all oil and gas related violations in the United States Army Corps of Engineers’ Pittsburgh District. USEPA, 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 USEPA 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 AGP’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 ARP’s or AGP’s wells could subject us to substantial liabilities

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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. ARP and AGP may not be able to recover remediation costs under their insurance policies.

 

ARP and AGP 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.

 

ARP’s and AGP’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 and oil we may produce and sell. A major risk inherent in a drilling plan is the need to obtain drilling permits from state agencies 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, Pennsylvania’s 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. PADEP’s proposed regulatory amendments associated with this legislation, when finalized will affect how natural gas operations are conducted in Pennsylvania. Moreover, PADEP has indicated that more regulatory amendments are likely to be proposed in 2016. 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. ARP and AGP 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 AGP’s reserves.

 

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our, ARP’s and AGP’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 AGP’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.

 

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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.

 

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 raised $59.3 million in 2015, $166.8 million in 2014 and $150.0 million in 2013. 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 2017 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.

 

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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, 2015, $1.7 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, 2014, the subordinated amount, net or corresponding production costs, was $5.3 million and for the year ended December 31, 2013, it was $9.6 million.

 

Risks Relating to the Ownership of Our Common Units

 

Our common units are quoted on the OTCQX and have a limited trading market.

As of March 21, 2016, our common units commenced being quoted on the OTCQX Best Market (the “OTCQX).  The OTCQX is not an exchange and the quotation of our common units on the OTCQX does not assure that a liquid trading market exists or will develop. Securities traded on the OTCQX marketplace generally have limited trading volume and exhibit a wider spread between the bid/ask quotations compared to securities traded on national securities exchanges such as the NYSE, on which our common units were previously listed. As a result, investors may find it difficult to dispose of, or to obtain accurate quotations of the price of, our common units. This significantly limits the liquidity of the common units and may adversely affect the market price of our common units.  Moreover, a significant number of institutional investors have investment policies that prohibit them from trading in securities on the OTCQX marketplace.  In addition, since our common units are quoted on the OTCQX, our common units are not “covered securities” for purposes of the Securities Act and our unitholders may face significant restrictions on the resale of our common units due to a state’s own securities laws, often called “blue sky” laws.  Not being listed on a national securities exchange and a limited trading market may also impair our ability to raise additional financing through public or private sales of equity securities and could also have other negative results, including the loss of institutional investor interest and fewer business development opportunities.

 

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

 

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

 

 

·

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

 

·

the public’s reaction to our 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;

 

·

limited trading liquidity in our common units as a result of our common units being quoted on the OTCQX and not listed on a national securities exchange;

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·

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.