10-K 1 atls-10k_20161231.htm 10-K atls-10k_20161231.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2016

OR

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

For the transition period from _____ to _____

Commission file number: 001-36725

 

Atlas Energy Group, LLC

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

45-3741247

(State or other jurisdiction or incorporation or organization)

 

(I.R.S. Employer Identification No.)

Park Place Corporate Center One

1000 Commerce Drive, Suite 400

Pittsburgh, Pennsylvania

 

15275

(Address of principal executive offices)

 

Zip code

 

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

 

 

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

None

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

Common Units representing Limited Liability Company Interests

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

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

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

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

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

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

 

Large accelerated filer  

 

Accelerated filer  

    

Non-accelerated filer  

  

Smaller reporting company  

 

 

 

 

 

 

Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

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

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, 2016, was approximately $13.2 million.

As of April 12, 2017, there were 26,061,818 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


 

ATLAS ENERGY GROUP, LLC

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

 

 

 

  

 

Page

PART I

 

Item 1:

  

Business

8

 

 

Item 1A:

  

Risk Factors

20

 

 

Item 1B:

  

Unresolved Staff Comments

43

 

 

Item 2:

  

Properties

43

 

 

Item 3:

  

Legal Proceedings

46

 

 

Item 4:

  

Mine Safety Disclosures

46

 

 

 

 

 

 

PART II

 

Item 5:

  

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

47

 

 

Item 6:

  

Selected Financial Data

48

 

 

Item 7:

  

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

49

 

 

Item 7A:

  

Quantitative and Qualitative Disclosures about Market Risk

73

 

 

Item 8:

  

Financial Statements and Supplementary Data

75

 

 

Item 9:

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

125

 

 

Item 9A:

  

Controls and Procedures

125

 

 

Item 9B:

  

Other Information

126

 

 

 

 

 

 

PART III

 

Item 10:

  

Directors, Executive Officers and Corporate Governance

126

 

 

Item 11:

  

Executive Compensation

136

 

 

Item 12:

  

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

155

 

 

Item 13:

  

Certain Relationships and Related Transactions, and Director Independence

156

 

 

Item 14:

  

Principal Accountant Fees and Services

159

 

 

 

 

 

 

PART IV

 

Item 15:

  

Exhibits and Financial Statement Schedules

161

 

 

 

 

 

 

SIGNATURES

167

 

2


 

GLOSSARY OF TERMS

Unless the context otherwise requires, all references in this report 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.

 

“Atlas Energy” or “Atlas Energy, L.P.” refer to Atlas Energy, L.P. and its consolidated subsidiaries

 

“Titan” refer to Titan Energy, LLC, our wholly owned subsidiary and the successor to Atlas Resource Partners, L.P. (“ARP”)

 

“Titan Management” refer to Titan Energy Management, LLC, our wholly owned subsidiary

 

“AGP” refer to Atlas Growth Partners, L.P., our wholly owned subsidiary, and “AGP GP” refer to Atlas Growth Partners GP, LLC, AGP’s general partner

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

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.

common units. Our common units representing limited liability company interests.

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.

Drilling Partnerships. Tax-advantaged investment partnerships of which we were a sponsor and manager and in which we co-invested, to finance a portion of our natural gas, crude oil and NGLs production activities.

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, an extension well, a service well or a stratigraphic test well (as such terms are defined in the federal securities laws).

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.

3


 

gross acres or gross wells. A gross well or gross acre is a well or acre in which the registrant owns a working interest.

LLC Agreement. Our Third Amended and Restated Limited Liability Company Agreement, as amended from time to time.

MLP. Master limited partnership.

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

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.

MMBtu. One million British thermal units.

MMcfe. One million cubic feet 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. A new well or net acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions of whole numbers.

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.

Plan Effective Date. September 1, 2016, the date that Titan emerged from the Chapter 11 Filings.

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:

4


 

 

(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.

(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 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. The United States 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 SEC (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,

5


 

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.

undeveloped acreage or undeveloped acres. Undeveloped acreage encompasses those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved 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 within this report include forward-looking statements.  These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology.  In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements.  We have based these forward-looking statements on our current expectations, assumptions, estimates and projections.  While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control.  These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.  Some of the key factors that could cause actual results to differ from our expectations include:

 

actions that we may take in connection with our liquidity needs, including the incurrence of amounts of cancellation of indebtedness income;

 

the fact that our cash flow is substantially dependent on the ability of Titan and AGP to make distributions, but neither                 Titan nor AGP is current paying distributions;

 

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

 

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

 

economic conditions and instability in the financial markets;

 

the impact of our common units being quoted on the OTCQX 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;

 

success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves and meeting substantial capital investment needs;

 

the accuracy of estimated natural gas and oil reserves;

 

the financial and accounting impact of hedging transactions;

 

potential changes in tax laws and environmental and other regulations that may affect our business;

 

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;

 

impact fees and severance taxes;

 

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

 

general market, labor and economic conditions and related uncertainties;

6


 

 

the ability to retain certain key employees and customers;

 

dependence on the gathering and transportation facilities of third parties;

 

the availability of drilling rigs, equipment and crews;

 

expirations of undeveloped leasehold acreage;

 

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

 

exposure to new and existing litigation; and

 

development of alternative energy resources.

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

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7


 

PART I

ITEM 1: BUSINESS

General

We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our combined and consolidated subsidiaries.

On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). 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.

Our operations primarily consisted of our ownership interests in the following:

 

During the period September 1, 2016 to December 31, 2016, Titan, an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States. Titan Management holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests and to appoint four of seven directors). As discussed further below, Titan is the successor to the business and operations of ARP;

 

Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 24,712,471 common limited partner units) in ARP.  As discussed further below, ARP was the predecessor to the business and operations of Titan;

 

all of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in AGP, a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas; and

 

12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of our board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt.

 

Our cash flows and liquidity are substantially dependent upon AGP’s annual management fee and distributions from AGP, Lightfoot, and Titan. Neither AGP nor Titan are currently paying distributions. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP) for financial reporting purposes, AGP’s annual management fee and distributions from Lightfoot are currently our only sources of liquidity to satisfy our obligations under our credit agreements.  In addition, the obligations under our first lien credit agreement mature in September 2017. As a result, we continue to face liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet. Please see “Risk Factors—Risks Related to Our Business— Our long term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time, and we are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet.”

AGP Overview

 

AGP’s primary business objective is to generate an attractive total return, consisting of current distributions and capital appreciation, through the acquisition of oil and gas assets in North America. As of December 31, 2016, AGP’s estimated proved reserves were 23 Bcfe. Of the estimated proved reserves, approximately 30% were proved developed and approximately 87% were oil. For the year ended December 31, 2016, its average daily net production was approximately 5.7 MMcfe.

On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order retain its cash flow and reinvest in its business and assets  At this time, AGP can provide no certainty as to when or if distributions will be reinstituted.

As of December 31, 2016, AGP’s production positions were in the following areas:

8


 

Eagle Ford. The Eagle Ford Shale is an Upper Cretaceous-age formation that is prospective for horizontal drilling in approximately 26 counties across South Texas. Target vertical depths range from 4,000 to some 11,000+ feet with thickness from 40 to over 400 feet. The Eagle Ford formation is considered to be the primary source rock for many conventional oil and gas fields including the prolific East Texas Oil Field, one of the largest oil fields in the contiguous United States. AGP owns oil, natural gas and NGL interests in approximately 2,833 net acres, of which 1,592 are undeveloped, non-producing net acres and 704 are developed net acres, in the Eagle Ford Shale in Atascosa County, Texas. AGP acquired its Eagle Ford position through a series of acquisitions in 2014 and 2015 for approximately $100 million. During the year, AGP averaged 5.3 MMcfe/d net production volumes. AGP estimates 23 Bcfe of total proved reserves for its Eagle Ford position, of which 89% are oil.

Marble Falls. The Marble Falls play is Pennsylvanian-age formation located above the Barnett Shale and beneath the Atoka at depths of approximately 5,500 feet and ranges in thickness from 50 and 500 feet. AGP owns oil, natural gas and natural gas liquids interests in approximately 2,208 net acres, of which 770 are undeveloped, non-producing net acres and 1,438 are developed net acres in the Marble Falls formation and the Barnett Shale, in Jack County, Texas. During the year, AGP averaged 0.32 MMcfe/d net production volumes. AGP estimates 0.5 Bcfe of total proved reserves for its North Texas positions, of which 100% are proved developed and producing (“PDP”).

 

Mississippi Lime. The Mississippi Lime formation is an expansive carbonate hydrocarbon system and is located at depths between 4,000 and 7,000 feet between the Pennsylvanian-aged Morrow formation and the Devonian-age world-class source rock Woodford Shale formation. The Mississippi Lime formation can reach 600 feet in gross thickness, with a targeted porosity zone between 50 and 100 feet thickness. AGP owns a non-operated 21.25% working interest in two wells in the Mississippi Lime formation in Garfield County, Oklahoma, operated by SandRidge Energy, Inc. During the year, AGP averaged 0.043 MMcfe/d net production volumes. AGP estimates 0.15 Bcfe of proved reserves in its Mississippi Lime positions, of which 45% are gas.

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, 2016, we own an approximate 15.9% interest in Lightfoot’s general partner and a 12.0% interest in Lightfoot’s limited partner.

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

 

efficient operating platforms with deep industry relationships;

 

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

 

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

 

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

On November 6, 2013, ARCX, a master limited partnership owned and controlled by Lightfoot Capital Partners, L.P., began trading publicly on the NYSE. ARCX is focused on the terminalling, storage, throughput and transloading of crude oil and petroleum products in the East Coast, Gulf Coast and Midwest regions of the United States. ARCX’s cash flows are primarily fee-based under multi-year contracts. Lightfoot has a significant interest in ARCX through its ownership of a 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.

Titan Overview

Titan is a publicly traded (OTCQX: TTEN) Delaware limited liability company and independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States with a focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas. Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”) in which it co-invests, to finance a portion of its natural gas, crude oil and natural gas liquids production activities. Titan Management holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s member’ equity, subject to potential dilution in the event of future

9


 

equity interests) and to appoint four of seven directors.  As discussed further below, Titan is the successor to the business and operations of ARP

Recent Developments

ARP Restructuring and Emergence from Chapter 11 Proceedings

On July 25, 2016, we, solely with respect to certain sections thereof,  along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% Senior Notes due 2021 (the “7.75% Senior Notes”) and the 9.25% Senior Notes due 2021 (the “9.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties agreed, subject to certain terms and conditions, to support ARP’s Restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

ARP operated its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired by the Plan and were satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

 

the First Lien Lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche.

 

the Second Lien Lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, the Second Lien Lenders received a pro rata share of 10% of the common equity interests of Titan, subject to dilution by a management incentive plan.

 

Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of the common equity interests of Titan, subject to dilution by a management incentive plan.

 

all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.

 

ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended.

 

Titan Management received a Series A Preferred Share of Titan, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests and to appoint four of seven directors)  and certain other rights. Four of the seven initial members of the board of directors of Titan are designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in Titan’s limited liability company agreement), subject to the

10


 

 

receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of Titan unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses.

In connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our  combined consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a result of these changes, our combined consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our combined financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.

On the Plan Effective Date, we determined that Titan is a variable interest entity based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions.

AGP’s Primary Offering Suspension. On November 2, 2016, AGP’s management decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. At this time, AGP can provide no certainty as to when or if its primary offering efforts will be reinstituted.

AGP’s Cash Distributions Suspension. On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets. At this time, AGP can provide no certainty as to when or if distributions will be reinstituted.

Gas and Oil Production

For the year ended December 31, 2016, our combined consolidated gas and oil production revenues, expenses, and volumes consisted of AGP’s gas and oil production activities and ARP’s gas and oil production activities through July 27, 2016. We deconsolidated ARP for financial reporting purposes as of the date of the Chapter 11 Filings and therefore our 2016 combined consolidated financial statements will not be comparable to our 2015 and 2014 combined consolidated financial statements.

Production Volumes

The following table presents our total net gas, oil and NGL production volumes and production per day for the periods indicated:

11


 

 

 

 

Years Ended December 31

 

 

 

2016(2)

 

 

2015

 

 

2014

 

Production per day:(1)

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Resource Partners:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

105,940

 

 

 

216,613

 

 

 

163,971

 

Oil (Bpd)

 

 

2,370

 

 

 

3,436

 

 

 

1,329

 

NGLs (Bpd)

 

 

1,300

 

 

 

3,802

 

 

 

3,473

 

Total (Mcfed)

 

 

127,956

 

 

 

281,486

 

 

 

192,786

 

Atlas Growth Partners:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

422

 

 

 

557

 

 

 

691

 

Oil (Bpd)

 

 

799

 

 

 

667

 

 

 

117

 

NGLs (Bpd)

 

 

73

 

 

 

81

 

 

 

88

 

Total (Mcfed)

 

 

5,657

 

 

 

5,047

 

 

 

1,920

 

Total production per day:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

106,362

 

 

 

217,170

 

 

 

238,745

 

Oil (Bpd)

 

 

3,169

 

 

 

5,806

 

 

 

3,553

 

NGLs (Bpd)

 

 

1,373

 

 

 

3,236

 

 

 

3,891

 

Total (Mcfed)

 

 

133,612

 

 

 

271,421

 

 

 

283,406

 

 

 

(1)

Production quantities consist of the sum of (i) the proportionate share of production from wells in which AGP has and ARP had 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 had 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)

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.

 

12


 

Production Revenues, Prices and Costs

Our 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 production revenues and average sales prices for our direct interest natural gas, oil and NGL production, along with average production costs, which include lease operating expenses, taxes and transportation and compression costs, for the periods indicated: 

 

 

 

Years Ended December 31,

 

 

 

2016 (4)

 

 

2015

 

 

2014

 

Atlas Resource Partners

 

 

 

 

 

 

 

 

 

 

 

 

Production revenues (in thousands):(4)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

74,320

 

 

$

217,236

 

 

$

318,920

 

Oil revenue

 

 

38,628

 

 

 

122,273

 

 

 

110,070

 

Natural gas liquids revenue

 

 

5,194

 

 

 

17,490

 

 

 

41,061

 

Total revenues

 

$

118,142

 

 

$

356,999

 

 

$

470,051

 

Atlas Growth Partners

 

 

 

 

 

 

 

 

 

 

 

 

Production revenues (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

358

 

 

$

518

 

 

$

1,009

 

Oil revenue

 

 

11,121

 

 

 

10,959

 

 

 

3,770

 

Natural gas liquids revenue

 

 

372

 

 

 

369

 

 

 

928

 

Total revenues

 

$

11,851

 

 

$

11,846

 

 

$

5,707

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

Production revenues (in thousands):(4)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

74,678

 

 

$

217,754

 

 

$

319,929

 

Oil revenue

 

 

49,749

 

 

 

133,232

 

 

 

113,840

 

Natural gas liquids revenue

 

 

5,566

 

 

 

17,859

 

 

 

41,989

 

Total revenues

 

$

129,993

 

 

$

368,845

 

 

$

475,758

 

Average sales price:

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Resource Partners

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(1)(2)

 

$

3.47

 

 

$

3.41

 

 

$

3.76

 

Total realized price, before hedge(1)

 

$

1.83

 

 

$

2.23

 

 

$

3.93

 

Oil (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(2)

 

$

74.75

 

 

$

84.30

 

 

$

87.76

 

Total realized price, before hedge

 

$

36.31

 

 

$

44.19

 

 

$

82.22

 

NGLs (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(2)

 

$

10.66

 

 

$

22.40

 

 

$

29.59

 

Total realized price, before hedge

 

$

10.66

 

 

$

12.77

 

 

$

29.39

 

Atlas Growth Partners

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge

 

$

2.32

 

 

$

2.55

 

 

$

4.00

 

Total realized price, before hedge

 

$

2.32

 

 

$

2.55

 

 

$

4.00

 

Oil (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge(2)

 

$

38.69

 

 

$

46.83

 

 

$

88.61

 

Total realized price, before hedge

 

$

38.00

 

 

$

44.98

 

 

$

88.61

 

NGLs (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Total realized price, after hedge

 

$

13.87

 

 

$

12.51

 

 

$

28.80

 

Total realized price, before hedge

 

$

13.87

 

 

$

12.51

 

 

$

28.80

 

Production costs (per Mcfe):(4)

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Resource Partners

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses(3)

 

$

1.20

 

 

$

1.34

 

 

$

1.27

 

Production taxes

 

 

0.19

 

 

 

0.19

 

 

 

0.27

 

Transportation and compression

 

 

0.23

 

 

 

0.24

 

 

 

0.25

 

Total(3)

 

$

1.62

 

 

$

1.76

 

 

$

1.80

 

Atlas Growth Partners

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

0.86

 

 

$

0.83

 

 

$

2.47

 

Production taxes

 

 

0.32

 

 

 

0.31

 

 

 

0.48

 

Transportation and compression

 

 

0.11

 

 

 

0.07

 

 

 

 

Total

 

$

1.28

 

 

$

1.21

 

 

$

2.95

 

Total (4)

 

 

 

 

 

 

 

 

 

 

 

 

13


 

 

 

Years Ended December 31,

 

 

 

2016 (4)

 

 

2015

 

 

2014

 

Lease operating expenses(3)

 

$

1.18

 

 

$

1.33

 

 

$

1.28

 

Production taxes

 

 

0.19

 

 

 

0.19

 

 

 

0.27

 

Transportation and compression

 

 

0.23

 

 

 

0.23

 

 

 

0.25

 

Total(3)

 

$

1.60

 

 

$

1.75

 

 

$

1.81

 

 

(1)

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 $3.41 per Mcf ($1.66 per Mcf before the effects of financial hedging), $3.36 per Mcf ($2.19 per Mcf before the effects of financial hedging), and $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging) for the years ended December 31, 2016, 2015 and 2014, respectively.

(2)

Includes the impact of $0.2 million and $0.5 million of cash settlements for the years ended December 31, 2016 and 2015, respectively, on AGP’s oil derivative contracts which were entered into subsequent to our 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. Cash settlements on ARP’s commodity derivative contracts excluded from production revenues consisted of $62.6 million and $48.6 million associated with natural gas derivative contracts and $26.5 million and $35.8 million associated with crude oil derivative contracts for the years ended December 31, 2016 and 2015, respectively. Cash settlements on ARP’s natural gas liquids derivative contracts excluded from production revenues were $8.3 million for the year ended December 31, 2015 (see “Item 8. Financial Statements – Note 8”).

(3)

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 $1.16 per Mcfe ($1.58 per Mcfe for total production costs), $1.32 per Mcfe ($1.74 per Mcfe for total production costs), and $1.25 per Mcfe ($1.77 per Mcfe for total production costs) for the years ended December 31, 2016, 2015 and 2014, respectively. Including the effects of these costs, our total lease operating expenses per Mcfe were $1.14 per Mcfe ($1.56 per Mcfe for total production costs), $1.31 per Mcfe ($1.73 per Mcfe for total production costs), and $1.26 per Mcfe ($1.78 per Mcfe for total production costs) for the years ended December 31, 2016, 2015 and 2014, respectively.

(4)

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.

Drilling Activity

The number of wells we drill will vary depending on, among other things, the amount of money we have available and the money raised by ARP’s Drilling Partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table sets forth information with respect to the number of wells we drilled, both gross and net during the periods indicated:

 

 

 

Years Ended December 31,

 

 

 

2016(6)

 

 

2015

 

 

2014

 

Atlas Resource Partners: (4) (6)

 

 

 

 

 

 

 

 

 

 

 

 

Gross wells drilled

 

 

 

 

 

28

 

 

 

129

 

Net wells drilled(1)

 

 

 

 

 

17

 

 

 

67

 

Gross wells turned in line(3)

 

 

 

 

 

36

 

 

 

119

 

Net wells turned in line(1) (3)

 

 

 

 

 

15

 

 

 

64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Atlas Growth Partners: (4)

 

 

 

 

 

 

 

 

 

 

 

 

Gross wells drilled

 

 

 

 

 

 

 

 

13

 

Net wells drilled(2)

 

 

 

 

 

 

 

 

11

 

Gross wells turned in line(3) (5)

 

 

2

 

 

 

6

 

 

 

15

 

Net wells turned in line(2) (3) (5)

 

 

2

 

 

 

6

 

 

 

13

 

 

(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)

There were no exploratory wells drilled during any of the periods presented. There were no gross or net dry wells within our operating areas during any of the periods presented.  

14


 

(5)

The drilling activity related to AGP’s Eagle Ford operating area was included effective November 5, 2014, the date of acquisition. Ten wells were drilled by the prior owner but not yet turned in line, at the date of acquisition

(6)

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.  

 

We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We perform regular inspection, testing and monitoring functions on each of our operated wells.

 

As of December 31, 2016, we did not have any ongoing drilling activities.  

 

Contractual Revenue Arrangements

Natural Gas and Oil Production

Natural Gas. We market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The pricing index for our Eagle Ford production is primarily Houston Ship Channel, primarily Waha for our Marble Falls production and primarily Southern Star for our Mississippi Lime production.

We  sell the majority of natural gas produced at monthly, fixed index first of the month prices and a smaller portion at index daily prices. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of natural gas in any future periods under existing contracts or agreements.

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

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

For the year ended December 31, 2016, Tenaska Marketing Ventures, Interconn Resources LLC and Chevron accounted for approximately 29%, 15% and 14%, respectively, of ARP’s natural gas, oil and NGL production revenues with no other single customer accounting for more than 10% for this period. For the year ended December 31, 2016, Shell Trading Company and Enterprise Crude Oil LLC individually accounted for approximately 64% and 29%, respectively, of AGP’s natural gas, oil and NGL production revenues with no other single customer accounting for more than 10% for this period.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from independent oil and gas companies, MLPs and from major oil and gas companies in acquiring properties, contracting for drilling equipment and arranging for the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or other resources will permit.

Competition is strong for attractive oil and natural gas properties and there can be no assurances that we will be able to compete satisfactorily when attempting to make acquisitions. In general, sellers of producing properties are influenced primarily by the price offered for the property, although a seller also may be influenced by the financial ability of the purchaser to satisfy post-closing indemnifications, plugging and abandoning operations and similar factors.

15


 

We also may be affected by competition for drilling rigs, human resources and the availability of related oilfield services and equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas where we may acquire producing properties. In addition, it is possible that we will acquire oil and gas properties that are subject to flooding, drought or tornados. These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off-peak months. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

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

 

restricting the way waste disposal is handled;

 

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

 

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

 

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

 

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

 

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

 

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

 

imposing substantial liabilities for pollution resulting from operations; and

 

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

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

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

16


 

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

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

Hydraulic Fracturing.  In recent years, federal, state, and local scrutiny of hydraulic fracturing has increased.  Regulation of the practice remains largely the province of state governments, except for a Bureau of Land Management rule that would have imposed conditions on fracturing operations on federal lands, which was enjoined by a federal court holding BLM lacked the authority to adopt the rule.  Common elements of state regulations governing hydraulic fracturing may include, but not be limited to, the following: requirement that logs and pressure test results are included in disclosures to state authorities; disclosure of hydraulic fracturing fluids and chemicals, 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.  In December 2016, EPA released the final report of its study of the impacts of hydraulic fracturing on drinking water in the U.S. finding that the hydraulic fracturing water cycle can impact drinking water resources under some circumstances.  Those circumstances included where (1) there are water withdrawals for hydraulic fracturing in times or areas of low water availability, (2) hydraulic fracturing fluids and chemicals or produced water are spilled, (3) hydraulic fracturing fluids are injected into wells with inadequate mechanical integrity, and (4) hydraulic fracturing wastewater is stored or disposed in unlined pits.  If new federal regulations were adopted as a result of these findings, they could increase our cost to operate.

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

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 a number of different types of requirements on our operations.  First, these 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 the EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Second, 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 precise definition of waters and wetland subject to the dredge-and-fill permit requirement has been enormously complicated and is subject to on-going litigation.  A broader definition could result in more water and wetlands being subject to protection creating the possibility of additional permitting requirements for some of our existing or future facilities.  Third, the Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills.   Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that our operations are in substantial compliance with the requirements of the Clean Water Act.

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

17


 

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

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.  Under the past eight years during the Obama Administration several Clean Air Act regulations were adopted to reduce greenhouse gas emissions, and a couple foundational regulations were upheld by the courts.  President Trump pledged during the election campaign to suspend or reverse many if not all of the Obama Administration’s initiatives to reduce the nation’s emissions of greenhouse gases.  Some of the foundational regulations, however, appear unyielding.  It would be a significant departure from the principle of stare decisis for the Supreme Court to reverse its decision in Massachusetts v. EPA, 549 U.S. 497 (2007) holding that greenhouse gases are “air pollutants” covered by the Clean Air Act.  Similarly, reversing EPA’s final determination that greenhouse gases “endanger” public health and welfare, 74 Fed. Reg. 66,496 (Dec. 15, 2009), upheld in Coalition for Responsible Regulation, Inc. v. EPA, 684 F.3d 102 (D.C. Cir. 2012), would seem to require development of new scientific evidence that runs counter to general discoveries since that determination.  

On March 28, 2017, President Trump issued an Executive Order on Promoting Energy Independence and Economic Growth explaining how his Administration would withdraw, rescind, revisit, or revise virtually every element the Obama Administration’s program for reducing greenhouse gas emissions. Under the Executive Order, some actions had immediate effect.  Other actions, including those most directly affecting our operations and the overall consumption of fossil fuels, will be the subject of potentially lengthy notice-and-comment rule-making.  With respect to rules more directly applicable to the types of operations AGP conducts, the Executive Order directed EPA to undertake new rule-making to revise or rescind 2015 methane emissions standards for new or modified wells.  Similarly, the Order directed the Department of Interior to re-write a 2015 rule imposing restrictions on fracturing operations conducted on federal land and a 2016 rule restricting flaring of methane emissions from oil and gas extraction on federal land. With respect to rules of greater applicability affecting overall consumption of fossil fuels, the Order instructed EPA to rewrite (1) the 2015 Clean Power Plan – the rule aimed at reducing greenhouse gas emissions from existing power plants by one-third (compared to 2005 levels), and (2) the 2015 New Source Rule setting greenhouse gas emission requirements for construction of new power plants.  

While we generally foresee a less stringent approach to the regulation of greenhouse gases, undoing the Obama Administrations regulations of greenhouse gas emissions will necessarily involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by those opposed to rolling back existing regulations.  Thus, it could be several years before existing regulations are off the books.  Opponents of the rollbacks, including states and environmental groups, may then decide to sue large sources of greenhouse gas emissions for the alleged nuisance created by such emissions.  In 2011, the Supreme Court held that federal common law nuisance claims were displaced by the EPA’s authority to regulate greenhouse gas emissions from large sources of emissions. If the Administration fails to pursue regulation of emissions from such sources or takes the position that it has no authority to do regulate their emissions, then it is possible that a court would find common law nuisance claims are no longer displaced.    

Although further regulation of greenhouse gas emissions from our operations may stall at the federal level, it is possible that, in the absence of additional federal regulatory action, states may pursue additional regulation of our operations, including restrictions on new and existing wells and fracturing operations, as many states already have done.

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. With authority granted by federal EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as “solid waste.” The transportation of natural gas in pipelines may also generate some “hazardous wastes” that are subject to RCRA or comparable state law requirements.  We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations.  More stringent regulation of natural gas and oil exploration 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” (but excluding petroleum) 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

18


 

damage allegedly caused by the hazardous substances released into the environment.  Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances 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.  We are not presently aware the need for us to respond to releases of hazardous substances that would impose costs that would be material to our financial condition.

OSHA and Chemical Reporting Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes.  On March 25, 2016, OSHA published its final Occupational Exposure to Respirable Crystalline Silica final rule, which imposes specific requirements to protect workers engaged in hydraulic fracturing.  81 Fed. Reg. 16,285.  The requirements of that final rule as it applies to hydraulic fracturing become effective June 23, 2018, except for the engineering controls component of the final rule, which has a compliance date of June 23, 2021.  We expect implementation of the rule to result in significant costs.  The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.  If the sectors to which community-right-to-know or similar chemical inventory reporting are expanded, our regulatory burden could increase.  We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

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

Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our or its 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 our 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 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 upon our unitholders.

19


 

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 our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

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

Employees

We employed approximately 389 persons as of December 31, 2016. Some of our officers may spend a substantial amount of time managing the business and affairs of AGP, Titan 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 SEC’s website at www.sec.gov. Any of our filings is also available at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

ITEM 1A:

RISK FACTORS

Limited liability company interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider those risk factors included herein, together with all the other information included in this report, including the matters addressed under “Forward-Looking Statements,” in evaluating an investment in our common units. If any of the following risks were to occur, our business or financial condition or results of operations could be materially adversely affected. In such case, the trading price of our common units could decline and you could lose all or part of your investment.

20


 

Risks Relating to Our Business

Our long term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time, and we are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. AGP recently suspended its quarterly distributions, and we do not expect that Titan will pay distributions for the foreseeable future. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP), for financial reporting purposes, those distributions, along with distributions from Lightfoot and AGP’s annual management fees, are our primary sources of liquidity to satisfy our obligations under our credit agreements. In addition, the obligations under our first lien credit agreement mature in September 2017.  Our cash on hand and cash flow from operations are not sufficient to continue to fund our operations and allow us to satisfy our obligations.

We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet and meeting our debt service obligations. We could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We are evaluating various options with our lenders, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. We expect that any changes to our capital structure we undertake has the potential to result in cancellation of indebtedness income that would be allocable to our unitholders, which may be significant. Please see “—Tax Risks to Unitholders—We expect to engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.”

We cannot assure you that we 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 our debt instruments or in a manner that does not negatively impact the price of our securities.  Additionally, there can be no assurance that the above actions would allow us to meet our debt obligations and capital requirements.

Please see “Management’s Discussion and Results of Operations— Liquidity, Capital Resources and Ability to Continue as a Going Concern.”

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.

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. 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.

21


 

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

 

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; 

 

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, 2016, the NYMEX Henry Hub natural gas index price ranged from a high of $3.93 per MMBtu to a low of $1.64 per MMBtu, and West Texas Intermediate (“WTI”) oil prices ranged from a high of $54.06 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 and results of operations. 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.

22


 

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

Our 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, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

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

 

unexpected operational events and drilling conditions;

 

adverse weather conditions;

 

facility or equipment malfunctions;

 

title problems;

 

pipeline ruptures or spills;

 

compliance with environmental and other governmental requirements;

 

unusual or unexpected geological formations;

 

formations with abnormal pressures;

 

injury or loss of life 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 our receipt of drilling and production revenues, thereby reducing our earnings. 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 cash flow.

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

Economic conditions and instability in the financial markets could negatively impact our businesses.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, and the Chinese economy 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 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 impact our and AGP’s access to liquidity needed for our businesses and impact 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 impact our businesses.

23


 

A continuing or weakening of the current economic situation could have an adverse impact on producers, key suppliers or other customers, or on our lenders, causing them to fail to meet their obligations. Market conditions could also impact our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and AGP’s cash flow could be impacted. 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 credit agreements limit could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Our credit agreements limit 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 credit agreements also contain 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. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP), for financial reporting purposes, distributions from AGP and Titan along with distributions from Lightfoot and AGP’s annual management fee, are our primary sources of liquidity to satisfy our obligations under our credit agreements. However, neither AGP nor Titan is currently paying distributions. In addition, the obligations under our first lien credit agreement mature in September 2017.

We are evaluating various options with our lenders, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. A breach of any of the covenants in our credit facilities, 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 agreements, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness, if any.

Our borrowings under our credit agreements are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk.  If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same. The provisions of our credit agreements 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 debt obligations could have a negative impact on our financing options and liquidity position.

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

 

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

 

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

 

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

 

increasing our vulnerability to general adverse economic and industry conditions;

 

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

 

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

 

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

24


 

 

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

 

limiting our 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 may use financial hedges and physical hedges for our production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and oil and are considered normal sales of natural gas and oil. We generally limit these arrangements to smaller quantities than those we project to be available at any delivery point.

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

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on our cash flow from operations for the periods covered by these arrangements. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

 

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.

However, it is not always possible for us to engage in a derivative transaction that completely mitigates our 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.

 

25


 

Regulations adopted by the Commodities 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 Commodities Futures Trading Commission (the “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. Certain bona fide hedging transactions would be exempt from these position limits. The CFTC 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. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

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 also intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our and 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.

Any acquisitions we or our subsidiaries complete are subject to substantial risks that could adversely affect our and our subsidiaries’ financial condition and results of operations.

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

 

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

 

an inability to successfully integrate the businesses we or our subsidiaries acquire;

 

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

 

a significant increase in interest expense or financial leverage if we or our subsidiaries additional debt to finance acquisitions;

 

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 our 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;

 

the loss of key purchasers of our production; 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 the above risks may be materially greater than estimated at the time of the acquisition.  Further, our and our subsidiaries’ 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.

26


 

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

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

 

operating a significantly larger combined entity;

 

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

 

integrating personnel with diverse business backgrounds and organizational cultures;

 

consolidating operational and administrative functions;

 

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

 

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

 

customer or key employee loss from the acquired businesses;

 

a significant increase in our or our subsidiaries’ 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 our or our subsidiaries’ operations could harm our business or future prospects, and result in significant decreases in our or our subsidiaries’ gross margin and cash flows.

If in the future we cease to manage Titan or control AGP, we may be deemed to be an investment company.

If we cease to manage Titan or control 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.

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

27


 

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 Exploration and Production Operations

Our operations require substantial capital expenditures to increase our asset bases. If we 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 LLC Agreement, we expect we 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 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 revenues to decline and diminish its and our ability to service any debt that any of us may have at such time. If we 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 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 revenues and available cash could decline.

We 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 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, 2016, Shell Trading Company and Enterprise Crude Oil LLC accounted for approximately 64% and 29% 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 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 receive for our production could significantly reduce our available cash and adversely affect our financial condition.

The prices that we 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 receive could significantly reduce our 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 will be exposed to any increase in such differentials, which could adversely affect our results of operations.

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

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, contracting for drilling equipment and securing trained personnel. Our 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 have. All of these challenges could make it more difficult for us to execute our growth strategies. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

28


 

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 competitors possess greater financial and other resources than we do or they have, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we can.

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

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our 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. Our 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 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 test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our economic interests and our plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published future prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates.

 

Prolonged depressed prices of natural gas and oil may cause the carrying value of our 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, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to AGP’s proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties.

 

Our acquisitions may prove to be worth less than we 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 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 our proved reserves estimates may thus exceed actual acquired proved reserves. In connection with our assessments, we perform a review of the acquired properties that we believe is generally consistent with industry practices.  However, such a review will not reveal all existing problems. In addition, our 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.

Also, our reviews of acquired properties 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 would it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.

29


 

We 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 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 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 financial condition and results of operations.

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

Good and clear title to our 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 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 business, financial condition and results of operations.

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

Our 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 are subject to the regulations regarding conservation practices and protection of correlative rights.  These regulations affect our operations and limit the quantity of natural gas, NGLs and oil we may produce and sell.  A major risk inherent in a drilling plan is the need to obtain drilling permits (which can include financial responsibility requirements) 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, NGLs 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.  We may be put at a competitive disadvantage to larger companies in the industry that can spread these additional costs over a greater number of wells and these increased regulatory hurdles over a larger operating staff.

Because we handle natural gas, NGLs and oil, we may incur significant costs and liabilities in the future in order to comply with, or as a result of failing to comply with, new or existing environmental regulations or from an accidental release of substances into the environment.

How we plan, design, drill, install, operate and abandon natural gas and oil 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;

30


 

 

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

 

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

 

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

 

Wildlife protection laws and regulations such as the Migratory Bird Treaty Act and the Endangered Species Act, which require operators to cover reserve pits during the cleanup phase of the pit, if the pit is open more than 90 days, and impose restrictions regarding the extent and timing of development, including, for example, prohibitions for tree clearing.

Complying with these environmental requirements may increase costs and prompt delays in natural gas, NGLs and oil production.  It is possible that the costs and delays associated with compliance with such requirements could cause us 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.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle.  For example, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and remediation costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations.  Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary.  We may not be able to recover remediation costs, or other losses/damages, under our respective insurance policies.

We may incur costs or delays and encounter operational restrictions in connection with complying with stringent environmental regulations that apply specifically to hydraulic fracturing.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations.  The process involves the injection of water, sand, and chemical additives under pressure into formations to fracture the surrounding rock and stimulate production.  Some of the potential effects of Federal, state, and local environmental regulation of hydraulic fracturing, including future changes in such regulation, could include the following:

 

additional permitting requirements and permitting delays;

 

increased costs;

 

changes in the way operations, drilling and/or completion must be conducted;

 

increased recordkeeping and reporting; and

 

restrictions on the types of additives that can be used and locations in which we can operate.

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

State regulation of hydraulic fracturing and related development operations could result in increased costs and additional operating restrictions or delays.

The hydraulic fracturing and related development operations processes are 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 and related development operations in certain circumstances.  State regulation of hydraulic fracturing can take many forms.  Among the forms of regulation that do, and in the future could, affect our operations or increase our costs are the following:

 

Typically, states impose, by means of permits, well casing, cementing, drilling, mechanical integrity, completion, well control, and plugging and abandonment requirements to ensuring hydraulic fracturing and related development operations do not contaminate groundwater and nearby surface water.

 

Most states require the disclosure of chemicals used in hydraulic fracturing fluids.

31


 

 

Many states have imposed controls on the management, reuse, recycling, and disposal of hydraulic fracturing flowback fluid and production fluids.

 

States limit when venting/flaring of casing head gas and gas well gas may occur.

 

States may limit where fracturing can be performed and/or impose operating restrictions in certain geographic regions (i.e., location standards).  For example, in areas in which there are concerns regarding induced seismicity, a state could curtail fracturing operations in the area or allow its continuance only under certain operational limitations.

 

States may impose performance standards for surface activities at oil and natural gas well sites (including containment and spill response and remediation practices) and requiring operators to identify and monitor abandoned, orphaned and inactive wells prior to hydraulic fracturing.

 

States may impose conditions on the disposal of drilling wastes containing naturally occurring radioactive material, as well as regulations applying to facilities that receive such wastes.

 

States could even take the step of a total ban on hydraulic fracturing, as New York has done, blocking our business from that state.

Local and municipal laws could also result in increased costs and additional operating restrictions or delays.

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 and related operations in particular.  In some jurisdictions, the authority of localities to regulate hydraulic fracturing has become contentious.  Courts have been asked to determine whether state regulatory schemes “pre-empt” local regulation.  The outcome of legal challenges to local efforts to regulate hydraulic fracturing depends in large part on the intent of the State legislature and the comprehensiveness of its statutory scheme.  If the right of municipalities to impose additional requirements is upheld, and municipalities elect to do so, local rules could impose additional constraints – such as siting and setback restrictions – and costs on our operations.

If the federal government were to comprehensively regulate hydraulic fracturing, it could impose greater costs or additional restrictions on our operations.

To date, hydraulic fracturing has not generally been subject to comprehensive regulation at the federal level.  Instead, there has been limited federal regulation.  For example, U.S. EPA released guidance, under its Safe Drinking Water Act underground injection control authority, regarding the use of diesel fuels in hydraulic fracturing.   Implementation of the guidance will largely occur through State permitting programs.  As another example, the Department of Interior’s Bureau of Land Management had issued regulations governing the conduct of hydraulic fracturing federal and Indian lands, but, on June 21, 2016, a Wyoming federal district judge invalidated the rules on the basis that Congress had not given the Department authority to regulate in this manner.  The Federal government appealed the decision to the 10th Circuit Court of Appeals on June 24, 2016, and the litigation is ongoing.  On-going federal agency environmental reviews of hydraulic fracturing could, however, result in additional regulation.  Or Congress could adopt new laws affecting our operations or directing a federal agency to regulate our operations in new or additional ways.  Any such development on the federal level could make it more difficult or costly for us to perform hydraulic fracturing to stimulate production from dense subsurface rock formations.

Our drilling and production operations require both adequate sources of water to facilitate the fracturing process and the disposal of flowback and produced fluids.  If we are unable to dispose of the flowback and produced fluids at a reasonable cost and in compliance with applicable environmental rules, our ability to produce gas economically and in commercial quantities could be impaired.

A significant portion of our natural gas, NGLs and oil extraction activities utilize hydraulic fracturing, which results in water that must be treated and disposed of in accordance with applicable regulatory requirements.  Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance.  Our ability to collect and dispose of flowback and produced fluids will affect our production, and potential increases in the cost of wastewater treatment, handling, and disposal may affect our profitability.  The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of wastewater, drilling fluids and other substances associated with the exploration, development and production of natural gas, NGLs and oil.

 

32


 

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.

Future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with its operations.

With the issuance, on March 28, 2017, of President Trump’s Executive Order on Promoting Energy Independence and Economic Growth, we believe it may take many years for new comprehensive federal policy aimed at greenhouse gas emissions to gel (see “Item 1. Business- Environmental Matters and Regulation - Greenhouse Gas Regulation and Climate Change”).  Given 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) and scientific hurdles to overturning EPA’s endangerment finding, we believe the new Administration will have to pursue some form of regulation.  Regulations with the most direct impact on our operations concern controlling methane emissions from wells.  Rules that affect overall consumption of fossil fuels, and the mix of fossil fuels consumed, could also affect the demand for our products.  We believe, however, that federal agency implementation of the President’s Executive Order is some years away.  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.  Reports of greater Congressional activity with respect to greenhouse gas emissions are scare.

In the absence of comprehensive federal climate change policy, 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.  States may also pursue additional regulation of our operations, including restrictions on methane emissions from new and existing wells and fracturing operations.  State and regional initiatives could result in significant costs, including increased capital expenditures and operating costs, affect the demand for our products, and could affect the results of their business.

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

Rules regulating air emissions from oil and natural gas operations could cause us 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.   President Trump’s March 28, 2017, Executive Order on Promoting Energy Independence and Economic Growth ordered federal agencies to revisit federal rules aimed at limiting methane emissions from oil and gas wells.  We believe it will be several years before those new rules are fully implemented

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.

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

 

If fully implemented, environmental policies the new President supported during his campaign could increase supply in the overall markets for fuels, thereby potentially reducing prices for the Company’s output.

33


 

During the election campaign, President Trump pledged to implement policies that would reinvigorate coal’s use for energy production and ease restrictions on production and transportation of petroleum.  If fully implemented, these policies could have the effect of increasing the overall fuel supply, thereby reducing prices for the Company’s output.  For example, President Trump pledged to reverse the prior Administration’s policies that disadvantaged coal as a fuel for energy production.  President Trump promised to take several actions to encourage burning coal for energy production and lessen the financial burden of environmental regulations on coal-fired plants’ operations.  The President pledged to withdraw from the Paris Climate Agreement, withdraw or re-write the Clean Power Plan, withdraw mercury limits on coal plants’ air emissions, lift the prior Administration’s ban on new coal leases on federal lands and end the review of the program’s greenhouse gas impacts, and withdraw the “Waters of the United States” stream protection rule.  The new Administration has taken this final action.  President Trump also indicated his Administration would open more federal lands for oil and gas production, approve the construction of the Keystone Pipeline to facilitate refining of Alberta oil shale in the U.S., license the Dakota Access Pipeline, and open areas in the Arctic and Atlantic Ocean to drilling.  If fully implemented, these policies would increase the overall fuel supply and could have the effect of diminishing demand for the Company’s natural gas output.  Diminished demand could put additional downward pressure on the price of the natural gas the Company produces.

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

How we 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;

 

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 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 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 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 AGP’s wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs

34


 

and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under their insurance policies.

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

Our 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. We may be put at a competitive disadvantage to larger companies in the industry that can spread these additional costs over a greater number of wells and these increased regulatory hurdles over a larger operating staff.

Estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our 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 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 PV-10 and standardized measure are calculated using natural gas prices that do not include financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from the reserve estimates.

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

 

actual prices received for natural gas and oil;

 

the amount and timing of actual production;

 

the amount and timing of capital expenditures;

 

supply of and demand for natural gas and oil; and

 

changes in governmental regulations or taxation.

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

35


 

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 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 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 prices of our common units decline, our common unitholders could lose a significant part of their investment.

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

 

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

 

the public’s reaction to our 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;

 

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 cash distributions;

 

future issuances and sales of our securities; 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.

The trading price of our common units may be volatile, with the result that an investor may not be able to sell any shares acquired at a price equal to or greater than the price paid by the investor.

Our Common Shares are quoted on the OTCQX Market under the symbol “ATLS.” These markets are relatively unorganized, inter-dealer, over-the-counter markets that provide significantly less liquidity than the NASDAQ or the NYSE.  Although we will use our commercially reasonable efforts to list our common units on the NYSE (or other national securities exchange approved by our board of directors as soon as practicable after the applicable listing standards are satisfied or have been waived, no assurances can be

36


 

given that our common units can be listed on the NYSE (or other national securities exchange).  In this event, there would be a highly illiquid market for our common units and you may be unable to dispose of your common units at desirable prices or at all.

Sales of our common units may cause our share price to decline.

Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our shares to decline.  In addition, the sale of these common units could impair our ability to raise capital through the sale of additional shares.

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

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

 

a board of directors that is divided into three classes with staggered terms, and this classified board provision could have the effect of making the replacement of incumbent directors more time consuming and difficult;

 

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

 

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

 

the inability of our common unitholders to remove directors; and

 

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

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

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

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

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

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

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

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

37


 

can be charged to customers by our subsidiaries or who fails to comply with the procedures instituted by our board of directors to obtain proof of the U.S. federal income tax status.

Tax Risks to Unitholders

We expect to engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.

We continually monitor the respective capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. As such, we are actively evaluating potential transactions to deleverage our balance sheet and manage our liquidity, which could include reducing existing debt through debt exchanges, debt repurchases and other modifications and extinguishment of existing debt. If, as expected, we execute such a strategic transaction, we expect that we would recognize cancellation of indebtedness income (“CODI”), which will be allocated to our unitholders at the time of such transaction. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of liquidity and capital resources.

The amount of CODI generally will be equal to the excess of the adjusted issue price of the restructured debt over the value of the consideration received by debtholders in exchange for the debt. In certain cases, CODI can be realized even when existing debt is modified with no reduction in such debt’s stated principal amount. We will not make a corresponding cash distribution with respect to such allocation of CODI. Therefore, any CODI will cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to such unitholder. Such CODI, like other items of our income, gain, loss, and deduction that are allocated to our unitholders, will be taken into account in the taxable income of the holders of our units as appropriate. CODI is not itself an additional tax due but is an amount that must be reported as ordinary income by the unitholder, potentially increasing such unitholder’s tax liabilities.

Our unitholders may not have sufficient tax attributes available to offset such allocated CODI. Moreover, CODI that is allocated to our unitholders will be ordinary income, and, as a result, it may not be possible for our unitholders to offset such CODI by claiming capital losses with respect to their units, even if such units are cancelled for no consideration in connection with such a restructuring. Importantly, certain exclusions that are available with respect to CODI generally do not apply at the partnership level, and any solvent unitholder that is not in a Chapter 11 proceeding will be unable to rely on such exclusions.

CODI with respect to any future transaction undertaken by us will be allocated to our unitholders of record (as applicable) on the date on which such a strategic transaction closes (the “CODI Allocation Date”). No CODI should be allocated to a unitholder with respect to units which are sold prior to the CODI Allocation Date.

Each unitholder’s tax situation is different. The ultimate effect to each unitholder will depend on the unitholder’s individual tax position with respect to its units. Additionally, certain of our unitholders may have more losses available than other of our unitholders, and such losses may be available to offset some or all of the CODI that could be generated in a strategic transaction involving our debt. Accordingly, unitholders are highly encouraged to consult, and depend on, their own tax advisors in making such evaluation.

Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us or cancellation of our debt, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

 

We expect to engage in transactions in the future that would result in CODI that will be allocated to our unitholders. Some or all of our unitholders may be allocated substantial amounts of such taxable income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder would depend on the unitholder’s individual tax position with respect to the units; however, taxable income allocations from us, including CODI, increase a unitholder’s tax basis in their units.

38


 

 

In addition, we and our subsidiaries may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.

A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange. Cash distributions from us decrease a unitholder’s tax basis in its units, and the amount, if any, of excess distributions over a unitholder’s tax basis in its units will, in effect, become taxable income to the unitholder, above and beyond the unitholder’s share of our taxable income and gain (or specific items thereof).

 

In addition, we have issued and outstanding as of December 31, 2016 approximately 1.8 million Series A convertible preferred units with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”) to certain members of our management, two management members of the Board, and outside investors.  All of the Series A Preferred Units are convertible into approximately 5.7 million common units at the option of the holder at any time.  If the Series A Preferred Units are converted into common units, net income that otherwise would have first been allocated to the Series A Preferred Units will instead be allocated to all common unitholders, including the holders of common units received in the conversion.  Such net income allocations could include types of income, including CODI, for which our unitholders may not receive cash distributions from us equal to their share of such taxable income or even equal to the actual tax liability that results from their share of such taxable income.

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

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

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

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

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

39


 

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

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

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

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

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

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

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

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

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

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

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

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

40


 

Unitholders may be subject to state and local taxes and return filing requirements, including in states where they do not live, as a result of investing in our common units.

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Recently, the U.S. Treasury Department issued Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. The regulations do not, however, specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

Risks Relating to Our Conflicts of Interest

Although we control AGP and exercise significant control over Titan, certain duties are owed to each such entity and its unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including between us (as holder of the Series A Preferred Share of Titan), on the one hand, and Titan and its common shareholders, on the other hand, as well as between the general partner of AGP, on the one hand, and AGP and its limited partners, on the other hand. Our AGP’s general partner has a duty to manage AGP in a manner beneficial to us, its owner. At the same time, these directors and officers have a duty to manage AGP in a manner they believe is beneficial to the partnership’s interests. In addition, our officers and directors who serve as officers and directors of Titan owe certain duties. Titan’s board of directors and the board of directors of AGP’s general partner, or Titan’s or AGP’s respective conflicts committees, will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

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

 

the allocation of shared overhead expenses;

 

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Titan or AGP, on the other hand;

 

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

 

the decision as to whether Titan or AGP should make acquisitions, and on what terms; and

41


 

 

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

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

Our LLC Agreement, Titan’s limited liability company agreement and the partnership agreements of AGP do not prohibit Titan, AGP or our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, our affiliates, Titan or AGP. In addition, Titan, AGP and their affiliates may acquire, develop or dispose of additional assets related to the production and development of oil, natural gas and NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. As a result, competition among these entities could adversely affect our results of operations and cash available for paying required debt service on our credit facilities or making distributions.

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

Our LLC Agreement eliminates our directors’ and officers’ fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our directors and officers.

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

 

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

 

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

 

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

It will be presumed that, in making decisions and taking, or declining to take, actions, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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

 

 

42


 

ITEM 1B:

UNRESOLVED STAFF COMMENTS

None.

ITEM 2:

PROPERTIES

Natural Gas, Oil and NGL Reserves

The following tables summarize information regarding our estimated proved natural gas, oil and NGL reserves as of December 31, 2016 and 2015. Proved reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties as well as the reserves attributable to ARP’s percentage interests in the oil and gas properties owned by Drilling Partnerships in which ARP owned partnership interests. All of the reserves are located in the United States. We base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared independent third-party engineers. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 reserves will not be comparable to our 2015 reserves.  Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 31, 2016 and 2015, and are listed below as of the dates indicated: 

 

 

 

December 31,

 

Unadjusted Prices

 

2016

 

 

2015

 

Natural gas (per MMBtu)

 

$

2.48

 

 

$

2.59

 

Oil (per Bbl)

 

$

42.75

 

 

$

50.28

 

NGLs (per Bbl)

 

$

19.57

 

 

$

11.02

 

 

 

 

 

 

 

 

 

 

Average Realized Prices, Before Hedge(1)

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

2.32

 

 

$

2.21

 

Oil (per Bbl)

 

$

38.00

 

 

$

44.28

 

NGLs (per Bbl)

 

$

13.87

 

 

$

12.77

 

  

(1)

Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for year ended December 31, 2015. Including the effect of this subordination, the average realized sales price was $2.19 per Mcf before the effects of financial hedging for year ended December 31, 2015.

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

The preparation of our natural gas, oil and NGL reserve estimates were completed in accordance with prescribed internal control procedures by reserve engineers. Other than for ARP’s Rangely assets, for the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 40 years of experience in the estimation and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. For ARP’s Rangely assets, Cawley, Gillespie and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 34 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our President.

43


 

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

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

 

 

 

Proved Reserves at

December 31,

 

 

 

2016 (2)

 

 

2015 (1)

 

Proved reserves: (2)

 

 

 

 

 

 

 

 

Natural gas reserves (MMcf):

 

 

 

 

 

 

 

 

Proved developed reserves

 

652

 

 

 

568,794

 

Proved undeveloped reserves

 

780

 

 

 

38,892

 

Total proved reserves of natural gas

 

1,432

 

 

 

607,686

 

Oil reserves (MBbl):

 

 

 

 

 

 

 

 

Proved developed reserves

 

925

 

 

 

27,130

 

Proved undeveloped reserves

 

2,462

 

 

 

25,453

 

Total proved reserves of oil

 

3,387

 

 

 

52,583

 

NGL reserves (MBbl):

 

 

 

 

 

 

 

 

Proved developed reserves

 

100

 

 

 

6,489

 

Proved undeveloped reserves

 

167

 

 

 

1,987

 

Total proved reserves of NGL

 

267

 

 

 

8,476

 

Total proved reserves (MMcfe)

 

23,356

 

 

 

974,042

 

Standardized measure of discounted future cash flows (in thousands)(2)

 

$

17,381

 

 

$

575,231

 

 

(1)

At December 31, 2015, ARP’s ownership in these reserves was subject to reduction as ARP generally makes capital contributions, which includes leasehold acreage associated with ARP’s proved undeveloped reserves, to its Drilling Partnerships in exchange for an equity interest in these partnerships, which was approximately 30%, which would reduce ARP’s ownership interest in these reserves from 100% to its respective ownership interest as ARP makes these contributions.

(2)

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 reserves will not be comparable to our 2015 reserves.

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

Proved Undeveloped Reserves (“PUDs”)

PUD Locations. As of December 31, 2016, we had 10 PUD locations totaling approximately 17 net Bcfe’s of natural gas, oil and NGLs. These PUDS are based on the definition of PUD’s in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

Material changes in PUDs. As of January 1, 2016, we had 128 PUD locations totaling approximately 204 net Bcfe’s of natural gas, oil, and NGLs.  Material changes in PUDS that occurred during the year ended December 31, 2016 were due to negative revisions

44


 

of approximately 24 Bcfe in PUDs due to the reduction of our five year drilling plans and unfavorable pricing environment and a decrease of 179 Bcfe due to the deconsolidation of ARP for financial reporting purposes.

Development Costs. There were no costs incurred related to the development of PUDs that remained after the deconsolidation of ARP for financial reporting purposes for the year ended December 31, 2016. As of December 31, 2016, there were no PUDs that had remained undeveloped for five years or more. The proved undeveloped reserves disclosed at December 31, 2016 are included within our five-year development plan and will be developed within five years of the initial disclosure.

Productive Wells

The following table sets forth information regarding productive natural gas and oil wells in which AGP has a working interest as of December 31, 2016. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which AGP has an interest directly and net wells are the sum of our fractional working interests in gross wells:

 

 

 

 

Number of productive

wells(1)

 

Atlas Growth Partners:

 

 

Gross

 

 

 

Net

 

Marble Falls:

 

 

 

 

 

 

 

 

Gas wells

 

 

11

 

 

 

11

 

Oil wells

 

 

2

 

 

 

2

 

Total

 

 

13

 

 

 

13

 

Mississippi Lime:

 

 

 

 

 

 

 

 

Gas wells

 

 

2

 

 

 

 

Oil wells

 

 

 

 

 

 

Total

 

 

2

 

 

 

 

Eagle Ford:

 

 

 

 

 

 

 

 

Gas wells

 

 

 

 

 

 

Oil wells(2)

 

 

10

 

 

 

10

 

Total

 

 

10

 

 

 

10

 

Total:

 

 

 

 

 

 

 

 

Gas wells

 

 

13

 

 

 

11

 

Oil wells

 

 

12

 

 

 

12

 

Total

 

 

25

 

 

 

23

 

 

 

(1)

There were no exploratory wells drilled by AGP during the year ended December 31, 2016. There were no gross or net dry wells within AGP’s operating areas during the year ended December 31, 2016.

 

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2016:

 

 

 

Developed acreage(1)

 

 

 

Undeveloped acreage(2)

 

Atlas Growth Partners:

 

Gross(3)

 

 

 

Net(4)

 

 

 

Gross(3)

 

 

 

Net(4)

 

Texas

 

4,289

 

 

 

4,270

 

 

 

816

 

 

 

770

 

Oklahoma

 

76

 

 

 

9

 

 

 

 

 

 

 

Total

 

4,365

 

 

 

4,279

 

 

 

816

 

 

 

770

 

  

(1)

Developed acres are acres spaced or assigned to productive wells.

(2)

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

(3)

A gross acre is an acre in which AGP owns a working interest. The number of gross acres is the total number of acres in which we own a working interest.

45


 

(4)

Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. There are no concessions for undeveloped acreage as of December 31, 2016. As of December 31, 2016, there are no leases set to expire on or before December 31, 2017 and 2018.

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

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

ITEM 3:

LEGAL PROCEEDINGS

We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See “Item 8: Financial Statements and Supplementary Data – Note 11”.

ITEM 4:

MINE SAFETY DISCLOSURES

Not applicable.

46


 

PART II

ITEM 5:

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

 Our common units began trading on March 2, 2015 on the New York Stock Exchange (“NYSE”). On March 18, 2016, we were notified by the NYSE that it had determined to commence proceedings to delist our common units. Our common units commenced quotation on the OTCQX under the symbol “ATLS” on March 21, 2016. On April 12, 2017, the closing price of our common units was $0.19, and there were 160 holders of record of our common units. The following table sets forth the high and low sales price per unit of our common units as reported by the OTCQX and the NYSE for the year ended December 31, 2016 and the NYSE for the year ended December 31, 2015 and the cash distributions declared by quarter per unit on our common units:

 

 

 

 

 

 

 

 

 

 

 

Cash Distribution

per Common

Unit

 

 

 

High

 

 

Low