Gastar Exploration Inc.
Gastar Exploration Inc. (Form: 10-K, Received: 03/09/2017 16:40:53)

Table of Contents

 

 

 

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: 001-35211

 

GASTAR EXPLORATION INC.

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

38-3531640

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

1331 Lamar Street, Suite 650 Houston, Texas

 

77010

(Address of principal executive offices)

 

(Zip Code)

 

(713) 739-1800

(Registrant’s telephone number, including area code)

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

 

Title of each class

 

Name of exchange on which registered

Common Stock, par value $0.001 per share

8.625% Series A Cumulative Preferred Stock, par value $0.01 per share

10.75% Series B Cumulative Preferred Stock, par value $0.01 per share

 

 

 

 

NYSE MKT LLC

NYSE MKT LLC

 

 

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

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by 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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) 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 (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  

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

 

Large accelerated filer

 

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

Smaller reporting company

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).    Yes       No  

The aggregate market value of the voting and non-voting common equity of Gastar Exploration Inc. held by non-affiliates of Gastar Exploration Inc. as of June 30, 2016 (the last business day of Gastar Exploration Inc.’s most recently completed second fiscal quarter) was approximately $129.3 million based on the closing price of $1.10 per share on the NYSE MKT LLC.

The total number of shares of common stock, par value $0.001 per share, outstanding as of March 6, 2017 was 186,124,138.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

 

 


Table of Contents

 

GASTAR EXPLORATION INC. AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2016

TABLE OF CONTENTS

 

 

 

Page

PART I

 

 

 

 

Item 1.

 

Business

 

8

 

 

 

 

Overview

 

8

 

 

 

 

Our Strategy

 

8

 

 

 

 

Oil and Natural Gas Activities

 

10

 

 

 

 

Markets and Customers

 

14

 

 

 

 

Competition

 

15

 

 

 

 

Seasonal Nature of Business

 

15

 

 

 

 

U.S. Governmental Regulation

 

15

 

 

 

 

Regulation of Exploration and Production

 

15

 

 

 

 

U.S. Environmental and Occupational Safety and Health Regulation

 

18

 

 

 

 

Industry Segment and Geographic Information

 

23

 

 

 

 

Insurance Matters

 

23

 

 

 

 

Filings of Reserve Estimates with Other Agencies

 

23

 

 

 

 

Employees

 

23

 

 

 

 

Corporate Offices

 

24

 

 

 

 

Available Information

 

24

 

 

Item 1A.

 

Risk Factors

 

24

 

 

Item 1B.

 

Unresolved Staff Comments

 

40

 

 

Item 2.

 

Properties

 

40

 

 

 

 

Production, Prices and Operating Expenses

 

40

 

 

 

 

Drilling Activity

 

41

 

 

 

 

Exploration and Development Acreage

 

42

 

 

 

 

Undeveloped Acreage Expirations

 

42

 

 

 

 

Productive Wells

 

43

 

 

 

 

Oil and Natural Gas Reserves

 

43

 

 

Item 3.

 

Legal Proceedings

 

46

 

 

Item 4.

 

Mine Safety Disclosure

 

47

PART II

 

 

 

 

Item 5.

 

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

 

47

 

 

 

 

Market Information

 

47

 

 

 

 

Stockholders

 

47

 

 

 

 

Dividends

 

47

 

 

 

 

Issuer Purchases of Equity Securities

 

48

 

 

 

 

Recent Sales of Unregistered Securities

 

48

 

 

Item 6.

 

Selected Financial Data

 

48

 

 

Item 7.

 

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

 

49

 

 

 

 

Overview

 

49

 

 

 

 

Financial Highlights

 

50

 

 

 

 

Results of Operations

 

50

 

 

 

 

Liquidity and Capital Resources

 

57

 

 

 

 

Off-Balance Sheet Arrangements

 

61

 

 

 

 

Contractual Obligations

 

61

 

 

 

 

Commitments

 

62

 

 

 

 

Critical Accounting Policies and Estimates

 

62

 

 

 

 

Recent Accounting Developments

 

66

 

 

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

 

66

 

 

 

 

Commodity Price Risk

 

67

 

 

 

 

Interest Rate Risk

 

67

 

 

Item 8.

 

Financial Statements and Supplementary Data

 

68

 

 

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

115

 

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Item 9A.

 

Controls and Procedures

 

115

 

 

 

 

Evaluation of Disclosure Controls and Procedures

 

115

 

 

 

 

Management’s Report on Internal Control over Financial Reporting

 

115

 

 

 

 

Changes in Internal Control over Financial Reporting

 

115

 

 

 

 

Report of Independent Registered Public Accounting Firm

 

116

 

 

Item 9B.

 

Other Information

 

117

PART III

 

 

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

 

118

 

 

Item 11.

 

Executive Compensation

 

121

 

 

Item 12.

 

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

 

137

 

 

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

 

139

 

 

Item 14.

 

Principal Accountant Fees and Services

 

140

PART IV

 

 

 

 

Item 15.

 

Exhibits, Financial Statements and Schedules

 

141

 

 

Item 16.

 

Form 10-K Summary

 

141

 

 

 

 

Exhibit Index

 

142

 

 

 

 

Signatures

 

148

 

 

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Form 10-K”) contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included or incorporated by reference in this Form 10-K are forward-looking statements, including, without limitation, all statements regarding future plans, business objectives, strategies, expected future financial position or performance, future covenant compliance, expected future operational position or performance, budgets and projected costs, future competitive position or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology.

The forward-looking statements contained in this Form 10-K are largely based on our expectations and beliefs concerning future developments and their potential effect on us, which reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends and other factors. Forward-looking statements may include statements that relate to, among other things, our:

 

financial condition;

 

cash flow and liquidity;

 

timing and results of property divestitures;

 

compliance with covenants under our indenture and credit agreements;

 

business strategy and budgets;

 

capital expenditures;

 

drilling of wells, including the scheduling and results of such operations;

 

oil, natural gas and natural gas liquids (“NGLs”) reserves;

 

timing and amount of future production of oil, condensate, natural gas and NGLs;

 

operating costs and other expenses;

 

availability of capital; and

 

prospect development.

Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the known material factors that could cause actual results to differ from those in the forward-looking statements, see Item 1A. “Risk Factors” in Part I of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

 

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

 

continued low or further declining prices for oil, condensate, natural gas and NGLs including risks of low commodity prices affecting the benefits of the Development Agreement (as defined below);

 

our financial condition, results of operations, revenues, cash flows and expenses;

 

the potential need to sell certain assets or raise additional capital;

 

the need to take ceiling test impairments due to low commodity prices;

 

worldwide political and economic conditions and conditions in the energy market;

 

the extent to which we are able to realize the anticipated benefits from acquired assets;

 

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our ability to monetize certain assets;

 

our ability to raise capital to fund capital expenditures, service our indebtedness or repay or refinance debt upon maturity;

 

the ability and willingness of our current or potential counterparties, third-party operators or vendors to enter into transactions with us and/or to fulfill their obligations to us;

 

failure of our co-participants to fund any or all of their portion of any capital program;

 

the ability to find, acquire, market, develop and produce new oil and natural gas properties;

 

uncertainties about the estimated quantities of oil and natural gas reserves and in the projection of future rates of production and timing of development expenditures of proved reserves;

 

strength and financial resources of competitors;

 

availability and cost of material and equipment, such as drilling rigs, service costs and transportation pipelines;

 

availability and cost of processing and transportation;

 

changes or advances in technology;

 

the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry wells, operating hazards inherent to the oil and natural gas business and down hole drilling and completion risks that are generally not recoverable from third parties or insurance;

 

potential mechanical failure or under-performance of significant wells or pipeline mishaps;

 

environmental risks;

 

possible new legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not limited to, national healthcare, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax regimes, changes in environmental regulations, environmental risks and liability under federal, state and local environmental laws and regulations;

 

effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;

 

potential losses from pending or possible future claims, litigation or enforcement actions;

 

potential defects in title to our properties or lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;

 

the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

 

our ability to find and retain skilled personnel; and

 

any other factors that impact or could impact the exploration of oil or natural gas resources, including, but not limited to, the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.

You should not unduly rely on these forward-looking statements in this Form 10-K, as they speak only as of the date of this Form 10-K. Except as required by law, we undertake no obligation to publicly update, revise or release any revisions to these forward-looking statements after the date on which they are made to reflect new information, events or circumstances occurring after the date of this Form 10-K or to reflect the occurrence of unanticipated events.

On November 14, 2013, Gastar Exploration Ltd., an Alberta, Canada corporation, changed its jurisdiction of incorporation to the State of Delaware and changed its name to “Gastar Exploration, Inc.” On January 31, 2014, Gastar Exploration, Inc. merged with and into Gastar Exploration USA, Inc., its direct subsidiary, as part of a reorganization to eliminate Gastar Exploration, Inc.’s holding company corporate structure. Pursuant to the merger agreement, shares of Gastar Exploration, Inc.’s common stock were converted into an equal number of shares of common stock of Gastar Exploration USA, Inc., and Gastar Exploration USA, Inc. changed its name to “Gastar Exploration Inc.” Gastar Exploration Inc., together with its subsidiary, owns and continues to conduct Gastar Exploration, Inc.’s business in substantially the same manner as was being conducted prior to the merger.

Unless otherwise indicated or required by the context, (i) for any date or period prior to the January 31, 2014 merger described above, “Gastar,” the “Company,” “we,” “us,” “our” and similar terms refer collectively to Gastar Exploration, Inc. (formerly known

 

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as Gastar Exploration Ltd.) and its subsidiaries, including Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.), and for any date or period after January 31, 2014, such terms refer collectively to Gastar Exploration Inc. and its subsidiaries, (ii) “Gastar USA” refers to Gastar Exploration USA, Inc., which, until January 31, 2014 was a first-tier subsidiary of Gastar Exploration, Inc. and its primary operating company, (iii) “Parent” refers to Gastar Exploration, Inc., (iv) all dollar amounts appearing in this Form 10-K are stated in United States dollars (“U.S. dollars”) unless otherwise noted and (v) all financial data included in this Form 10-K have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).


 

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Glossary of Terms

 

AMI

 

Area of mutual interest, an agreed designated geographic area where joint venturers or other industry partners have a right of participation in acquisitions and operations

 

 

 

Bbl

 

Barrel of oil, condensate or NGLs

 

 

 

Bcf

 

One billion cubic feet of natural gas

 

 

 

Boe

 

One barrel of oil equivalent determined using the ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs

 

 

 

Boe/d

 

Barrels of oil equivalent per day

 

 

 

FASB

 

Financial Accounting Standards Board

 

 

 

Gross acres

 

Refers to acres in which we own a working interest

 

 

 

MBbl

 

One thousand barrels of oil, condensate or NGLs

 

 

 

MBbl/d

 

One thousand barrels of oil, condensate or NGLs per day

 

 

 

MBoe

 

One thousand barrels of oil equivalent, calculated by converting natural gas volumes on the basis of 6 Mcf of natural gas per barrel

 

 

 

MBoe/d

 

One thousand barrels of oil equivalent per day

 

 

 

Mcf

 

One thousand cubic feet of natural gas

 

 

 

Mcfe

 

One thousand cubic feet of natural gas equivalent, calculated by converting liquids volumes on the basis of 1/6 th of a barrel of oil, condensate or NGLs per Mcf

 

 

 

MMBoe

 

One million barrels of oil equivalent, calculated by converting natural gas volumes on the basis of 6 Mcf of natural gas per barrel

 

 

 

MMBtu/d

 

One million British thermal units per day

 

 

 

MMcf

 

One million cubic feet of natural gas

 

 

 

MMcf/d

 

One million cubic feet of natural gas per day

 

 

 

Net acres

 

Refers to our proportionate interest in acreage resulting from our ownership in gross acreage

 

 

 

Net wells

 

Refers to gross wells multiplied by our working interest in such wells

 

 

 

NGLs

 

Natural gas liquids

 

 

 

NYMEX

 

New York Mercantile Exchange

 

 

 

PBU

 

Performance based unit comprising one of our compensation plan awards

 

 

 

PUD

 

Proved undeveloped reserves

 

 

 

STACK Play

 

An acronymic name for a predominantly oil producing play referring to the exploration and development of the Sooner Trend of the Anadarko Basin in Canadian and Kingfisher Counties, Oklahoma.

 

 

 

U.S.

 

United States

 

 

 

U.S. GAAP

 

Accounting principles generally accepted in the United States of America

 

 

 

WTI

 

West Texas Intermediate

 

 

 

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PAR T I

Item 1. Business

Overview

We are a pure-play Mid-Continent independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs.  Our principal business activities include the identification, acquisition, and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. We hold a concentrated acreage position in what is believed to be the core of the STACK Play, an area of central Oklahoma which is home to multiple oil and natural gas-rich reservoirs, including the Meramec and Osage formations within the Mississippi Lime, the Oswego limestone, the Woodford shale and Hunton limestone formations.   On April 8, 2016, we sold substantially all of our producing assets and proved reserves and a significant portion of our undeveloped acreage in the Appalachian Basin for an adjusted sales price of $75.7 million, net of $3.5 million of suspense liability transferred to buyer, with an effective date of January 1, 2016 (the “Appalachian Basin Sale”).  As of December 31, 2016, our remaining acreage position in the Appalachian Basin was approximately 15,400 gross (14,500 net) acres, of which 83% was undeveloped.  We sold our remaining Appalachian Basin interests on January 20, 2017 (effective January 1, 2017) for approximately $200,000, before fees and expenses.  

Shares of our common stock are listed on the NYSE MKT LLC under the symbol “GST,” shares of our 8.625% Series A Cumulative Preferred Stock are listed on the NYSE MKT LLC under the symbol “GST.PRA” and shares of our 10.75% Series B Cumulative Preferred Stock are listed on the NYSE MKT LLC under the symbol “GST.PRB”. Our principal office is located at 1331 Lamar Street, Suite 650, Houston, Texas 77010, and our telephone number is (713) 739-1800. Our website address is http://www.gastar.com. Information on our website or about us on any other website is not incorporated by reference into and does not constitute part of this Form 10-K.

Our Strategy

Our strategy is to increase stockholder value by delivering sustainable reserves and production growth and improved operating results from our existing assets. We recognize that there may be periods, such as the recently depressed commodity price environment, which make it difficult to fully execute this strategy on a short-term basis. We intend to implement our strategy by focusing on:

 

development and exploitation of our Mid-Continent assets in the STACK Play;

 

the successful execution of our Drilling Program (as defined below) on certain of our STACK Play acreage in the Mid-Continent;

 

active management of our drilling programs; and

 

effective management, adoption and utilization of technological advancement.

Development and Exploitation of our Mid-Continent Assets in the STACK Play

After we sold a substantial portion of our Appalachian Basin assets in April 2016, we focused our activities in the STACK Play.  Our leasing activities primarily located in northwest Kingfisher County, Oklahoma, began in 2012 initially with an AMI co-participant and were expanded to include two additional adjacent prospect areas.  We continued to build our acreage position in this region during 2013 through 2015 with our AMI co-participant, who prior to the closing of the Husky Acquisition (as defined below), handled all drilling, completion and production activities while we handled leasing and permitting activities in certain areas of the AMI.  We also increased our exposure within the play through acquisitions of acreage and producing wells from subsidiaries of Chesapeake Energy Corporation and certain entities affiliated with its former chief executive officer and affiliates of Lime Rock Resources, respectively, during 2013. On December 16, 2015, we completed the acquisition of additional working and net revenue interests in 103 gross (10.2 net) producing wells and certain undeveloped acreage in the STACK Play and Hunton limestone formations in our existing AMI from our AMI co-participant Husky Ventures, Inc., Silverstar of Nevada, Inc., Maximus Exploration, LLC and Atwood Acquisitions, LLC for an adjusted purchase price of approximately $42.7 million, net of $358,000 of revenue suspense liability assumed by us, reflecting adjustment for an acquisition effective date of July 1, 2015, and the conveyance of approximately 11,000 net non-core, non-producing acres in Blaine, Major and Kingfisher Counties, Oklahoma to the sellers, subject to certain adjustments and customary closing conditions (the “Husky Acquisition”) and; as a result of the Husky Acquisition, we assumed operatorship of a majority of the acquired wells.  With the closing of the Husky Acquisition, our AMI participation agreements with our AMI co-participant were dissolved.  

Our Mid-Continent development program was originally focused on using modern horizontal drilling and multi-stage fracture stimulation technologies to exploit the Hunton Limestone, a predominantly crude oil-bearing reservoir, which has been produced

 

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historically using vertical wells with conventional completion techniques.  Since 2012, we, along with our former AMI co-participant acting as operator in the initial AMI and adjacent areas, drilled and completed 38 gross (17.9 net to Gastar) horizontal Hunton Limestone wells, representing the lowest known productive horizon of the STACK Play.  As a result of the Husky Acquisition in late 2015, we operate each of these wells previously operated by our AMI co-participant.  Commencing in 2013, we also drilled and completed 22 gross (21.4 net) Hunton Limestone wells as operator, including 17 gross (16.7 net) wells within the West Edmond Hunton Lime Unit (“WEHLU”).  

During 2015, we began testing the potential of the Meramec formation within our Mid-Continent STACK Play acreage.  

We believe that our acreage is prospective in the STACK Play, an area of central Oklahoma that includes oil and natural gas-rich formations such as the Meramec, the Osage, a deeper bench of the Mississippi Lime located below the Meramec, the Woodford Shale, all ranging in depth from 6,000 to 9,000 feet, prospective plays in the shallower Oswego formation and the proven deeper Hunton limestone horizontal oil play.  We believe that the STACK Play is one of the most economic plays in North America under current commodities prices and costs.  It is a horizontal drilling play in an area of previously drilled vertical wells with multiple productive reservoirs that are predominantly oil producing.  The STACK Play encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. STACK is an acronym for Sooner Trend Anadarko Canadian Kingfisher.  At December 31, 2016, we held leases covering approximately 107,000 gross (83,800 net) acres in Garfield, Canadian, Kingfisher, Logan, Blaine and Oklahoma Counties, Oklahoma,  all of which we believe is prospective for one or several of the horizons comprising the STACK Play.

On October 14, 2016, we executed a definitive agreement with STACK Exploration LLC (the “Investor”) to jointly develop up to 60 Gastar operated wells in the STACK Play within a defined area of Kingfisher County, Oklahoma (the “Development Agreement”).  The drilling program under the Development Agreement (the “Drilling Program”) will target the Meramec and Osage formations within the Mississippi Lime in a contract area within three townships covering approximately 32,900 gross (19,100 net) undeveloped mineral acres under leases held by us. We will serve as operator of all wells jointly developed under the Development Agreement.

Under the Development Agreement, the Investor will fund 90% of our working interest portion of drilling and completion costs to initially earn 80% of our working interest in each new well (in each case, proportionately reduced by other participating working interests in the well).  As a result, we will pay 10% of our working interest portion of such costs for 20% of our original working interest in the well.  

The Drilling Program wells will be mutually developed in three tranches of 20 wells each.  The locations of the first 20 wells, comprised of 18 Meramec formation wells and two Osage formation wells, have been mutually agreed upon by us and the Investor. Participation in the second tranche of 20 Drilling Program wells will be at the election of the Investor and the third tranche of 20 wells will require mutual consent.  With respect to each 20 well tranche, when the Investor has achieved an aggregate 15% internal rate of return (“IRR”) for its investment in the tranche, its interest will be reduced from 80% to 40% of our original working interest and our working interest increases from 20% to 60% of our original working interest.  When a tranche IRR of 20% is achieved by the Investor, its working interest decreases to 10% and our working interest increases to 90% of the working interest originally owned by us.  The parties to the Development Agreement can mutually agree to expand the contract area and formation focus.

After final reversion of each tranche (the “WI Tail”), the Investor has the right, but not the obligation, for a period of six months after final reversion to cause us to purchase the Investor’s WI Tail in the Drilling Program for such tranche (the “Investor Put Right”) for fair market value by applying the methodology to determine a 15% discounted present value as defined by the Development Agreement.  If the Investor fails to exercise the Investor Put Right within the six-month period after achieving final reversion, then for a period of six months thereafter, we shall have the right, but not the obligation, to purchase the WI Tail from the Investor on the same fair market value approach of the Investor Put Right.  If final reversion has not been achieved by the eighth anniversary of the spud date of the first well in a given tranche, Investor will, for a period of six months thereafter, have the right to cause us to buy Investor’s then-current interest in such tranche at an agreed upon valuation.  

We spudded our first operated STACK Play well, the Deep River 30-1H in the Meramec, in September 2015.  To date, we have drilled and completed 11 gross (2.8 net) operated horizontal Meramec wells, of which nine gross (1.0 net) wells were drilled and completed under the Development Agreement, one gross (0.8 net) operated Osage well and one gross (0.8 net) operated Oswego well.  In addition, we are currently drilling or completing nine gross (1.5 net) horizontal STACK Play wells, of which seven gross (0.5 net) wells are under the Development Agreement.

 

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To further test the potential of the STACK Play, to date, we have participated in the completion of seven gross (0.2 net) non-operated Meramec Shale wells, one gross (0.3 net) non-operated well targeting the Osage Shale, four gross (0.4 net) non-operated wells targeting the Oswego Limestone formation and three gross (0.1 net) non-operated Woodford Shale wells.

Actively Manage Our Drilling Program

We believe that dedicating the majority of our capital budget for 2017 to drilling and completing wells that we operate will enable us to control the timing and cost of our drilling and completion activities, as well as control operating costs and the marketing of our production.  After the significant reduction in commodities prices experienced since mid-2014, control over our costs and expenditures has become increasingly important in achieving acceptable returns on capital investment.  Our preliminary capital budget for 2017, which is dedicated exclusively to our STACK Play activities, is approximately $84.0 million, which includes $34.1 million for the planned drilling and completion of 14 gross (9.1 net) operated Osage wells, $5.1 million for our share of costs on 23 gross (2.3 net) operated Drilling Program wells, $3.3 million net costs for recompletion projects on producing operated wells in Oklahoma, $3.5 million for our participation in nine gross (0.9 net) non-operated STACK Play drilling, $30.8 million for maintaining our current Oklahoma leasehold position and $7.2 million for capitalized interest and administration costs.  We may also seek opportunistic acquisitions of acreage positions in the STACK Play, with or without existing production, depending on the availability of capital and the quality and strategic importance of such acreage to our position.    

We believe that we have assembled an experienced team of operating professionals with the specialized skills needed to plan and execute the drilling and completion of horizontal STACK Play wells.

Management, Adoption and Utilization of Technological Advancements

We believe that enhanced natural gas recovery processes, horizontal drilling and other advanced drilling, formation evaluation and production techniques are valuable tools that improve drilling results and ultimately enhance production and returns. We believe that utilizing these technologies and production techniques in exploring for, developing and exploiting natural gas and oil properties has helped us reduce drilling risks, lower finding costs and provide for more efficient production of natural gas and oil from our properties.

Oil and Natural Gas Activities

The following provides an overview of our major oil and natural gas projects during 2016. There is no assurance that new drilling opportunities will be identified or that any new drilling opportunities will be successful if drilled. For additional information regarding our sources of revenue and historical expenditures, please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Mid-Continent Horizontal Oil Plays

We believe that our acreage is prospective in the STACK Play, an area of central Oklahoma that includes oil and natural gas-rich shale formations such as the proven Meramec formation, the Osage formation, a deeper bench of the Mississippi Lime located below the Meramec, and the Woodford Shale, ranging in depth from 6,000 to 9,000 feet, and emerging prospective play in the shallow Oswego formation as well as the proven Hunton Limestone horizontal oil play.  As of December 31, 2016, we held leases covering approximately 107,000 gross (83,800 net) acres in Garfield, Canadian, Kingfisher, Logan, Blaine and Oklahoma Counties, Oklahoma within the STACK Play, all of which we believe is prospective for one or several of the horizons comprising the STACK Play.

Our leasing activities primarily located in northwest Kingfisher County, Oklahoma, began in 2012 initially with an AMI co-participant whom we bought out in the Husky Acquisition and assumed operatorship of the acquired wells in December 2015.      

On October 14, 2016, we entered into the Development Agreement with the Investor to jointly develop up to 60 Gastar operated wells in the STACK Play in Kingfisher County, Oklahoma.  See “—Development and Exploitation of our Mid-Continent Assets in the STACK Play” above for more information on the terms of the Development Agreement.

On July 6, 2015, we sold certain non-core assets comprised of 38 gross (16.7 net) wells producing approximately net 170 Boe/d (41% oil) for the three months ended March 31, 2015 and approximately 29,500 gross (19,200 net) acres in Kingfisher County, Oklahoma for an adjusted purchase price of $46.5 million.  The sale is reflected as a reduction to the full cost pool and we did not record a gain or loss related to the divestiture as it was not significant to the full cost pool.

On October 19, 2016, we entered into a purchase and sale agreement to sell certain non-core leasehold interests in approximately 25,300 net acres of which only 19,100 net acres was ascribed allocated value and interests in 25 gross (11.2 net) wells

 

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primarily in northeast Canadian County and also in southeast Kingfisher County, Oklahoma to Red Bluff Resources Operating, LLC, a Delaware limited liability company, (“Red Bluff”) for approximately $71.0 million (of which up to $10.0 million is contingent upon the satisfaction of certain conditions), subject to certain adjustments and with a property sale effective date of August 1, 2016 (“South STACK Play Acreage Sale”).  On November 18, 2016, we and Red Bluff executed and delivered two amendments to the sale agreement and entered into a relating closing agreement, which, among other things, allocated $1.4 million of the purchase price to producing properties with the remainder of the purchase price to non-producing properties.   As of December 31, 2016, we had received approximately $48.6 million of the South STACK Play Acreage Sale proceeds.  Since December 31, 2016, we have received an additional $9.5 million of the South STACK Play Acreage Sales proceeds, bringing the total net sales proceeds received to date to $58.1 million.  We anticipate receiving an additional $12.7 million of South STACK Play Acreage Sale proceeds  by July 2017, subject to certain adjustments.  

As of the date of this report, we had production and drilling operations at various stages on the following operated STACK Play wells on our acreage:

 

Well Name

 

Current

Working

Interest (1)

 

 

Approximate Lateral Length

(in feet)

 

 

Peak Production Rates (2)

(Boe/d)

 

 

Boe/d (3)

 

 

% Oil (4)

 

 

Date of First

Production or Status

 

Approximate Gross Costs to Drill & Complete

($ millions)

 

Meramec Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Holiday Road 2-1H (6)

 

 

78.3%

 

 

 

4,300

 

 

 

654

 

 

 

230

 

 

 

74%

 

 

April 11, 2016

 

$

4.0

 

Ingle 29-1H (5)

 

 

16.5%

 

 

 

4,900

 

 

 

1,037

 

 

 

612

 

 

 

75%

 

 

October 22, 2016

 

$

5.2

 

Geis 31-1H (5)

 

 

11.6%

 

 

 

4,900

 

 

 

877

 

 

 

490

 

 

 

76%

 

 

October 31, 2016

 

$

3.8

 

Katy 21-1H (5)

 

 

13.6%

 

 

 

4,900

 

 

N/A

 

 

 

327

 

 

 

69%

 

 

November 17, 2016

 

$

4.0

 

Lilly 28-1H (5)(6)

 

 

12.7%

 

 

 

4,400

 

 

N/A

 

 

 

581

 

 

 

89%

 

 

December 2, 2016

 

$

4.5

 

Mott 19-1H (5)

 

 

8.9%

 

 

 

4,500

 

 

N/A

 

 

 

68

 

 

 

84%

 

 

January 8, 2017

 

$

4.5

 

Mott 20-2H (5)

 

 

13.8%

 

 

 

5,000

 

 

N/A

 

 

 

734

 

 

 

80%

 

 

January 10, 2017

 

$

4.4

 

Victoria 25-1H (5)

 

 

12.0%

 

 

 

4,600

 

 

N/A

 

 

 

490

 

 

 

71%

 

 

January 11, 2017

 

$

4.4

 

Kramer 29-1H (5)

 

 

9.3%

 

 

 

4,400

 

 

N/A

 

 

 

624

 

 

 

89%

 

 

January 23, 2017

 

$

5.0

 

Ma Stucki 30-1H (5)

 

 

2.9%

 

 

 

4,800

 

 

N/A

 

 

N/A

 

 

N/A

 

 

March 2, 2017

 

$

4.2

 

Best 20-1H (5)

 

 

3.9%

 

 

 

4,900

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Completing

 

$

4.5

 

Eldon 34-1H (5)

 

 

7.7%

 

 

 

4,800

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Waiting on Completion

 

$

4.5

 

Snowden 27-1H (5)

 

 

11.8%

 

 

 

5,100

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Waiting on Completion

 

$

5.5

 

Bradbury 28-1H (5)

 

 

7.5%

 

 

 

7,300

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Drilling

 

$

6.6

 

Pickle 33-1H (5)

 

 

6.2%

 

 

 

5,100

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Waiting on Completion

 

$

4.5

 

Johnny 32-1H (5)

 

 

5.0%

 

 

 

4,900

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Waiting on Completion

 

$

4.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Osage Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

McGee 29-1H (6)

 

 

81.0%

 

 

 

4,200

 

 

 

414

 

 

 

211

 

 

 

72%

 

 

September 25, 2016

 

$

4.3

 

Great Divide 1-12H (5)

 

 

7.5%

 

 

 

5,000

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Completing

 

$

3.5

 

Hane 14-1H

 

 

35.0%

 

 

 

4,900

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Drilling

 

$

3.5

 

Pedlik 10-1H

 

 

65.0%

 

 

 

4,900

 

 

N/A

 

 

N/A

 

 

N/A

 

 

Drilling

 

$

3.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oswego Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tomahawk 7-1H

 

 

79.3%

 

 

 

4,200

 

 

 

418

 

 

 

87

 

 

 

90%

 

 

September 24, 2016

 

$

2.7

 

 

(1)

Current estimated working interest.  Working interest subject to change based on final force pooling orders.  

(2)

Represents highest daily gross Boe rate.  N/A indicates that the well has not yet reached its peak initial production rate.

(3)

Represents average gross production for the most current five days through February 28, 2017.

(4)

Represents percent oil produced inception to date.

(5)

Drilling Program well.  Working interest reflected is our total current working interest after Development Agreement impact.  

(6)

Excludes one-time fishing or coring costs.  

To further test the potential of other Mid-Continent STACK Play formations, to date, we have participated in the completion of seven gross (0.2 net) non-operated Meramec Shale wells, one gross (0.3 net) non-operated well targeting the Osage Shale, four gross (0.4 net) non-operated wells targeting the Oswego Limestone formation and three gross (0.1 net) non-operated Woodford Shale wells.

At December 31, 2016, proved reserves attributable to the Mid-Continent were approximately 25.6 MMBoe, a 38% decrease from year-end 2015 reserves of 41.0 MMBoe.  The 30.3 MMBoe decline in proved reserves from year-end 2015 is primarily the result of the sale of 14.9 MMBoe of proved reserves, the majority of which related to the sale of our assets in the Appalachian Basin and

 

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16.2 MMBoe related to negative reserve revisions partially offset by extensions and discoveries exceeding production.  The reserve revisions primarily resulted from the removal of Hunton PUD locations as we now focus our capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate our STACK Play position.  As of December 31, 2016, Mid-Continent proved reserves represented 100% of our total proved reserves and SEC total proved PV-10 value. Total Mid-Continent proved reserves at year-end 2016 were comprised of approximately 75% of oil, condensate and NGLs reserves compared to 78% at year-end 2015. Approximately 51% and 33% of the Mid-Continent year-end 2016 and year-end 2015 reserves were proved developed, respectively.

For 2017, our focus is to drill in areas that we believe will result in de-risking of additional acreage within the STACK Play and hold by production near-term expiring acreage.    

The following table provides production and operational information about the Mid-Continent for the periods indicated:

 

 

 

For the Years Ended December 31,

 

Mid-Continent

 

2016

 

 

2015

 

 

2014

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (MBbl)

 

 

1,058

 

 

 

1,182

 

 

 

792

 

Natural gas (MMcf)

 

 

3,818

 

 

 

3,370

 

 

 

2,822

 

NGLs (MBbl)

 

 

503

 

 

 

433

 

 

 

332

 

Total Production (MBoe)

 

 

2,198

 

 

 

2,177

 

 

 

1,594

 

Oil and condensate (MBbl/d)

 

 

2.9

 

 

 

3.2

 

 

 

2.2

 

Natural gas (MMcf/d)

 

 

10.4

 

 

 

9.2

 

 

 

7.7

 

NGLs (MBbl/d)

 

 

1.4

 

 

 

1.2

 

 

 

0.9

 

Total daily production (MBoe/d)

 

 

6.0

 

 

 

6.0

 

 

 

4.4

 

Average sales price per unit (1) :

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (per Bbl)

 

$

40.12

 

 

$

46.18

 

 

$

88.84

 

Natural gas (per Mcf)

 

$

2.21

 

 

$

2.57

 

 

$

4.24

 

NGLs (per Bbl)

 

$

13.94

 

 

$

13.15

 

 

$

31.79

 

Average sales price per Boe (1)

 

$

26.35

 

 

$

31.67

 

 

$

58.27

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

$

1,601

 

 

$

1,444

 

 

$

2,940

 

Lease operating expenses

 

$

19,703

 

 

$

19,270

 

 

$

15,112

 

Transportation, treating and gathering

 

$

1,086

 

 

$

14

 

 

$

40

 

Selected operating expenses per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

$

0.73

 

 

$

0.66

 

 

$

1.84

 

Lease operating expenses

 

$

8.96

 

 

$

8.85

 

 

$

9.48

 

Transportation, treating and gathering

 

$

0.49

 

 

$

0.01

 

 

$

0.02

 

Production costs (2)

 

$

9.46

 

 

$

8.86

 

 

$

9.50

 

 

(1)

Excludes the impact of hedging activities.

(2)

Production costs include lease operating expense (“LOE”), insurance, transportation, treating and gathering and workover expense and excludes ad valorem and severance taxes.

Appalachian Basin

Due to the continued depressed commodity price environment in the Appalachian Basin, we suspended our drilling operations in the Appalachian Basin in the second quarter of 2015.  On April 8, 2016, we sold substantially all of our producing assets and proved reserves and a significant portion of our undeveloped acreage in the Appalachian Basin for an adjusted price of $75.7 million, net of $3.5 million of suspense liability transferred to buyer.  As of December 31, 2016, our acreage position in the play was approximately 15,400 gross (14,500 net) acres, of which 83% was undeveloped.  On January 20, 2017, we sold our remaining interest in producing assets and leasehold in the Appalachian Basin, effective January 1, 2017, for $200,000, before fees and expenses.  

At December 31, 2016, there were no economic proved reserves attributable to the Appalachian Basin.  

 

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The following table provides production and operational information for the Appalachian Basin for the periods indicated:

 

 

 

For the Years Ended December 31,

 

Appalachian Basin

 

2016

 

 

2015

 

 

2014

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (MBbl)

 

 

47

 

 

 

243

 

 

 

182

 

Natural gas (MMcf)

 

 

2,327

 

 

 

10,389

 

 

 

8,776

 

NGLs (MBbl)

 

 

236

 

 

 

779

 

 

 

469

 

Total production (MBoe)

 

 

671

 

 

 

2,753

 

 

 

2,114

 

Oil and condensate (MBbl/d)

 

 

0.1

 

 

 

0.7

 

 

 

0.5

 

Natural gas (MMcf/d)

 

 

6.4

 

 

 

28.5

 

 

 

24.0

 

NGLs (MBbl/d)

 

 

0.6

 

 

 

2.1

 

 

 

1.3

 

Total daily production (MBoe/d)

 

 

1.8

 

 

 

7.5

 

 

 

5.8

 

Average sales price per unit (1)(2) :

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (per Bbl)

 

$

11.73

 

 

$

16.78

 

 

$

68.21

 

Natural gas (per Mcf)

 

$

1.04

 

 

$

0.79

 

 

$

4.06

 

NGLs (per Bbl)

 

$

1.00

 

 

$

1.85

 

 

$

23.11

 

Average sales price per Boe (1)(2)

 

$

4.76

 

 

$

4.99

 

 

$

27.89

 

Selected operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes (3)

 

$

307

 

 

$

1,433

 

 

$

3,794

 

Lease operating expenses (3)

 

$

900

 

 

$

4,457

 

 

$

4,211

 

Transportation, treating and gathering (3)

 

$

618

 

 

$

2,175

 

 

$

3,639

 

Selected operating expenses per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes (3)

 

$

0.46

 

 

$

0.52

 

 

$

1.79

 

Lease operating expenses (3)

 

$

1.34

 

 

$

1.62

 

 

$

1.99

 

Transportation, treating and gathering (3)

 

$

0.92

 

 

$

0.79

 

 

$

1.72

 

Production costs (4)

 

$

2.21

 

 

$

1.92

 

 

$

3.35

 

 

(1)

Excludes the impact of hedging activities.

(2)

The year ended December 31, 2014 includes the benefit of a non-recurring revenue adjustment related to an arbitration settlement. Excluding the arbitration settlement adjustment impact, average sales prices would have been as follows:

 

 

 

For   the   Year   Ended

December   31,   2014

 

Appalachian Basin

 

 

 

 

Average sales price per unit:

 

 

 

 

Oil and condensate (per Bbl)

 

$

50.96

 

Natural gas (per Mcf)

 

$

3.14

 

NGLs (per Bbl)

 

$

24.55

 

Average sales price per Boe

 

$

22.87

 

 

(3)

The year ended December 31, 2014 includes a non-recurring adjustment to production taxes, LOE and transportation, treating and gathering related to an arbitration settlement. Excluding the arbitration settlement adjustment impact, production taxes, LOE and transportation, treating and gathering per Boe would have been as follows:

 

 

 

For the Year Ended

December 31, 2014

 

Appalachian Basin

 

 

 

 

Selected operating expenses per Boe:

 

 

 

 

Production taxes

 

$

1.52

 

Lease operating expenses

 

$

2.08

 

Transportation, treating and gathering

 

$

0.97

 

 

 

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(4)

Production costs include LOE, insurance, transportation, treating and gathering and workover expense and excludes ad valorem and severance taxes. Excluding the arbitration settlement adjustment impact, production costs for the year ended December 31, 2014 would have been as follows:

 

 

 

For the Year Ended

December 31, 2014

 

Appalachian Basin

 

 

 

 

Selected operating expenses per Boe:

 

 

 

 

Production costs

 

$

2.69

 

Markets and Customers

The success of our operations is dependent primarily upon prevailing and future prices for oil, condensate, natural gas and NGLs. The markets for oil, condensate, natural gas and NGLs have historically been and currently continue to be volatile. Oil, condensate, natural gas and NGLs prices are beyond our control.   The prices we receive for our oil, condensate, natural gas and NGLs production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy, foreign imports, political conditions in other petroleum producing countries, the actions of the Organization of Petroleum Exporting Countries, domestic regulation, legislation and policies. Decreases in the prices we receive for our oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves, our revenue, profitability and cash flow from operations.  For additional information regarding the prices we receive for our oil, condensate, natural gas and NGLs production, see Item 1A. “Risk Factors - Oil, condensate, natural gas and NGLs prices are volatile.  Substantial declines in commodity prices have significantly and negatively affected our financial condition and results of operations.”

Our oil, condensate and NGLs production in the Mid-Continent is sold under spot sales transactions at market prices.  The availability and price responsiveness of the multiple oil and condensate purchasers provides for a highly competitive and liquid market for oil sales.

We contract to sell natural gas from our properties with spot market contracts that vary with market forces on a daily basis. While overall natural gas prices at major markets, such as Henry Hub in Erath, Louisiana, may have some impact on regional prices, the regional natural gas price at our production facilities may move somewhat independently of broad industry price trends. We are directly impacted by natural gas prices in the regions in which we operate regardless of pricing at major market hubs. We do not own or operate any natural gas lines or distribution facilities and rely on third parties to construct additional interstate pipelines to increase our ability to bring our production to market. Any significant change affecting these facilities or our failure to obtain timely access to existing or future facilities on acceptable terms could restrict our ability to conduct normal operations. Delays in the commencement of operations of new pipelines, the unavailability of new pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition.

The following table provides information regarding our significant customers whom accounted for more than 10% of our oil, condensate, natural gas and NGLs revenues, excluding hedge impact, for the periods indicated:

 

 

 

For the Years Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Sunoco

 

 

67

%

 

 

62

%

 

 

37

%

Superior

 

 

12

%

 

 

6

%

 

 

5

%

SEI (1)

 

 

5

%

 

 

22

%

 

 

50

%

 

 

(1)

SEI filed for Chapter 7 bankruptcy on June 3, 2016.  

 

Sunoco Logistics Partners L.P. (“Sunoco”) purchases the majority of our Mid-Continent oil production.  Superior Pipeline Company (“Superior”) purchases the majority of our natural gas and NGLs production.  There are numerous purchase and transportation alternatives currently available in the Mid-Continent so in the event that Sunoco or Superior were to cease purchasing and transporting our oil, condensate, natural gas and NGLs production, our ability to conduct normal operations would not be significantly restricted.  Prior to its bankruptcy filing in June 2016, SEI Energy, LLC (“SEI”) purchased the majority of our Appalachian Basin production. For more information, see Item 1A. “Risk Factors-Our ability to market our oil, condensate, natural gas and NGLs may be impaired by capacity constraints and availability of the gathering systems and pipelines that transport our oil, condensate, natural gas and NGLs.”

 

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Compet ition

The oil and natural gas industry is intensely competitive in all of its phases. We encounter competition from other oil and natural gas companies in all areas of our operations. In seeking suitable oil and natural gas properties for acquisition, we compete with other companies operating in our areas of interest, including large oil and natural gas companies and other independent operators, many of whom have greater financial resources and, in many instances, have been engaged in the exploration and production business for a much longer time than we have. Many of our competitors also have substantially larger operating staffs than we do. Many of these competitors not only explore for and produce oil and natural gas but also market oil and natural gas and other products on a regional, national or worldwide basis. These competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and define, evaluate, bid for and purchase a greater number of properties and prospects than us. In addition, these competitors may have a greater ability to continue exploration activities during periods of low market prices. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. For more information, see Item 1A. “Risk Factors-Competition in the oil and natural gas industry is intense. We are smaller and have less operating history than many of our competitors, and increased competitive pressure could adversely affect our results of operations.”

Prices of our oil, condensate, natural gas and NGLs production are controlled by market forces. Competition in the oil and natural gas exploration industry, however, also exists in the form of competition to acquire leases and obtain favorable transportation prices. We are smaller and have a more limited operating history than most of our competitors and may have difficulty acquiring additional acreage and/or projects and arranging for the transportation of our production. We also face competition in obtaining oil and natural gas drilling rigs and in providing the manpower to operate them and provide related services.

Seasonal Nature of Business

Generally, the demand for oil and natural gas fluctuates seasonally. Seasonal anomalies such as mild winters or abnormally hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in certain areas. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages, increase our costs or delay our operations.

U.S. Governmental Regulation

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated in the United States. These laws and regulations, all of which are subject to change from time to time, include matters relating to land tenure; drilling and production practices, such as discharge permits and the spacing of wells; the disposal of water resulting from operations and the processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials (“NORM”); bonding requirements; ongoing obligations for licensing; reporting requirements; marketing and pricing policies; royalties; taxation; and foreign trade and investment.

Failure to comply with governmental rules and regulations can result in substantial sanctions, including administrative, civil and criminal penalties. Furthermore, we could be liable for personal injuries, property damage, spills, discharge of hazardous materials, reclamation costs, remediation, clean-up costs and other environmental damages as a consequence of acquiring an oil or natural gas prospect or acreage.

The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our financial condition. Historically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future cost or impact of complying with applicable laws and regulations because those legal requirements are frequently amended or reinterpreted. We are unable to predict what additional legislation or amendments may be proposed that will affect our operations or when any such proposals, if enacted, might become effective. We do not expect that any of these laws would affect us in a materially different manner than any other similarly sized oil and natural gas company operating in the United States.

Regulation of Exploration and Production

Regulation of Production

The production of oil and natural gas is subject to extensive regulation under a wide range of federal, state and local statutes, rules, orders and regulations. Federal, state and local statutes and regulations require, among other things, permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations

 

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governing conservation matters, including some provisions for the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from oil and natural gas wells; the spacing of wells; and the plugging and abandonment of wells and removal of related production equipment. These and other regulations can limit the amount of the oil and natural gas we can produce from our wells, limit the number of wells we can drill or limit the locations at which we can conduct drilling operations. Moreover, each state generally imposes a production or severance tax with respect to production and sale of crude oil, natural gas, condensate and NGLs within its jurisdiction.

Oklahoma Forced Pooling Laws

We rely upon the Oklahoma “forced pooling” laws and regulations to increase our working interest in drilling units, or increase the participation levels in a proposed well to render the project economic, for wells we propose to drill as operator in the STACK Play.  Any such increase in working interest would lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well.  Under Oklahoma law, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and natural gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may commence a “forced pooling” process.  Under current regulations, the proposed operator is required to demonstrate in an administrative proceeding that it has made a good faith effort to bargain with all of the respondents prior to filing its application.  The fair market value of the mineral interests in the unit is determined in the administrative proceeding by reference to market transactions involving nearby oil and natural gas rights, especially what has been paid for mineral leases in the particular drilling and spacing unit and the immediately surrounding drilling and spacing units.

Assuming the application is granted and a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair market value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair market value established and approved through the administrative hearing.  The pooling order usually also addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled.  The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

The availability of forced pooling makes it difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Exploration and production companies in Oklahoma often negotiate to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well.  Due to increased interest in the STACK Play as an economic play in the current price and cost environment, however, third party interest holders may be more likely to bear their proportionate share of the costs of the proposed future wells on our acreage.

Regulation of Sales of Natural Gas

The price at which we buy and sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the Federal Energy Regulatory Commission (“FERC”) and/or the Commodity Futures Trading Commission (“CFTC”). See the discussion below of “- Other Federal Laws and Regulations Affecting Our Industry – Energy Policy Act of 2005”. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. In addition, we would be required to annually report to FERC on May 1 of each year information regarding natural gas purchase and sale transactions if we have purchase or sale transactions that contribute or may contribute to the formation of a gas index during the prior calendar year in excess of 2.2 million MMBtu. See the discussion below of “- Other Federal Laws and Regulations Affecting Our Industry – FERC Market Transparency Rules.”

Regulation of Availability, Terms and Cost of Pipeline Transportation

The availability, terms and cost of transportation can significantly affect sales of natural gas. FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of natural gas produced by us and the revenues received by us for sales of such natural gas. FERC requires interstate pipelines to offer available firm transportation capacity on an open access, non-discriminatory basis to all natural gas shippers. FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state transportation of natural gas would be subject to state regulatory jurisdiction as well.

The ability of our facilities to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. In 2006, FERC issued a policy statement on provisions governing gas quality and

 

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interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. FERC strongly encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas tariffs modeled on the interim guidelines issued by a group of industry representatives headed by the Natural Gas Council (the “NGC+ Work Group”), or to explain how and why their tariff provisions differ. We have no way to predict, however, whether FERC will approve of gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline.

State laws and regulations generally govern the gathering and intrastate transportation of natural gas. Natural gas gathering systems in the states in which we operate are generally required to offer services on a non-discriminatory basis, and are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discrimination in favor of one producer over another producer or one source of supply over another source of supply.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005.  Under the Energy Policy Act of 2005 (the “EPAct 2005”), Congress made it unlawful for any entity, including otherwise non-jurisdictional producers of natural gas, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services regulated by the FERC that violates the FERC’s rules. FERC’s rules implementing the provision of EPAct 2005 make it unlawful for any entity in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act and the Natural Gas Policy Act up to $1,000,000 per day per violation. While EPAct 2005 reflects a significant expansion of the FERC’s enforcement authority, we do not anticipate that we will be affected by that statute any differently than other producers of natural gas.

FERC Market Transparency Rules.   Under FERC regulations, wholesale buyers and sellers of physical natural gas are required to report on Form No. 552 on May 1 of each year aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year in excess of 2.2 million MMBtu to the extent such transactions utilize, contribute to or may contribute to the formation of price indices.

Additional proposals and proceedings that might affect the natural gas industry are pending or are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. We do not believe that we will be affected by any action taken in a materially different way than other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil.  The oil industry is also extensively regulated by numerous federal, state and local authorities. Prices for crude oil and condensate are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

In a number of instances, however, the ability to transport and sell such products on interstate pipelines is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”). The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rate as well as the rules and regulations governing the service. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable.” The ICA permits challenges to existing rates and authorizes FERC to investigate such rates to determine whether they are just and reasonable. If, upon completion of an investigation, FERC finds that the existing rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation and, in some cases, reparations for the two (2) year period prior to the filing of a complaint. We do not believe, however, that these regulations affect us any differently than other producers.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

 

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Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Our operations are subject to extensive and continually changing regulation affecting the natural gas and oil industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas and oil industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability. We do not believe that we are affected in a significantly different manner by these regulations than are our competitors.

U.S. Environmental and Occupational Safety and Health Regulation

Our oil and natural gas exploration, development and production operations, and similar operations that we do not operate but in which we own a working interest, are subject to stringent federal, tribal, regional, state and local environmental laws and regulations governing worker safety and health, environmental protection and the discharge of substances into the environment. Numerous governmental agencies, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, which may cause us to incur significant capital expenditures on costly actions to achieve and maintain compliance. These laws and regulations may, among other things, require the acquisition of permits, including drilling permits, before conducting regulated activities; restrict the types, quantities and concentrations of various substances that may be released into the environment as a result of natural gas and oil drilling, production and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas; restrict injection of produced water or other regulated fluids into subsurface strata that may contaminate groundwater or result in seismic incidents; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; impose specific safety and health criteria addressing workforce protection; and impose liabilities for pollution resulting from our operations. Failure to comply with these environmental and worker health and safety laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the occurrence of delays or restrictions in permitting or performance of projects, or the issuance of injunctions limiting or prohibiting operations in affected areas.

The trend in environmental legislation and regulation is toward stricter standards to place more restrictions and limitations on activities that may adversely affect the environment.  Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.  If substantial liabilities to third parties or governmental entities for environmental claims are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Moreover, a serious incident of pollution arising from our operations may result in our being liable for material remedial costs and damages to natural resources or properties as well as the suspension or cessation of our operations in the affected area. Although we maintain insurance coverage against costs of certain clean-up operations, no assurance can be given that we have insurance or are fully insured against all such potential risks. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

The following is a summary of some of the more significant existing environmental laws, as amended from time to time, to which our business operations are subject.

Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and analogous state laws impose strict, joint and several liability without regard to fault or legality of conduct on persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that transported, disposed or arranged for the transport or disposal of the hazardous substance released at the site. Under CERCLA, these “responsible parties” 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. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for

 

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neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA currently excludes, among other things, petroleum, natural gas and NGLs from the definition of hazardous substance, our operations as well as other operations in which we own a working interest generate materials that are subject to regulation as hazardous substances under CERCLA.

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and non-hazardous wastes. Our operations, and other operations in which we own a working interest, generate wastes, including hazardous wastes that are subject to RCRA and comparable state laws. Although RCRA currently excludes certain oil and natural gas exploration, development and production wastes from the definition of hazardous waste, allowing us to manage these wastes under RCRA's less stringent non-hazardous waste requirements, we cannot assure that this exclusion will be preserved in the future.  For example following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016.  Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary.  If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.  Any removal of this exclusion could increase the amount of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating costs, which could have a significant impact on us as well as the oil and natural gas industry in general.

Moreover, there have been public concerns expressed about NORM being detected in flow back water resulting from hydraulic fracturing. NORM is subject primarily to individual state radiation control regulations while NORM handling and management activities are governed by regulations promulgated by OSHA. These state and federal regulations impose certain requirements concerning worker protection with respect to NORM as well as the treatment, storage and disposal of such flow back water generated from these activities. Concern over NORM in general, or NORM in groundwater in particular,  could result in further regulation in the treatment, storage, handling and discharge of flow back water generated from oil and natural gas activities, including hydraulic fracturing, that, if implemented, could limit drilling or increase the costs of drilling in affected regions.

We currently own, lease, own a working interest in, or operate numerous properties that for many years have been used by third parties for the exploration, development and production of oil and natural gas. Although we utilized operating and disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on or under the properties owned, leased or operated by us or in which we own an interest, or on or under other locations, including off-site locations, where such substances have been taken for disposal or recycling. In addition, many of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination) or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges and Subsurface Injections

Our operations and other operations in which we own a working interest are subject to the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws. These laws and their implementing regulations impose detailed requirements and strict controls regarding the discharge of pollutants, including oil and hazardous substances, into waters of the United States and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit.  The EPA has issued final rules attempting to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In January 2017, the U.S. Supreme Court accepted review of the final rule to determine whether jurisdiction rests with the federal district or appellate courts.  Litigation surrounding this rule is on-going.  On February 28, 2017, President Trump issued an executive order directing the EPA and the U.S. Corps of Engineers to review and, consistent applicable law, initiate rulemaking to rescind or revise the rule.  With issuance of this executive order, it remains uncertain what actions, if any,

 

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the government will take in the pending litigation regarding the final rule and what the results of the review by the EPA and the U.S. Corps of Engineers will be.    

The Oil Pollution Act of 1990 (“OPA”) amends the CWA and sets standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.

Our oil and natural gas exploration, development and production operations, and other operations in which we own a working interest, generate produced water, drilling muds and other waste streams, some of which may be disposed by injection in underground wells situated in non-producing subsurface formations. The drilling and operation of these injection wells are regulated by the Safe Drinking Water Act (“SDWA”) and analogous state laws. The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or analogous state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected, and prohibits the migration of fluids containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages and personal injuries.

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, Oklahoma, where we conduct operations, issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on injection wells in proximity to faults and also, from time to time, developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend injection well operations. The Oklahoma Corporation Commission (“OCC”) has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted and, further, evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports.  The OCC also has established rules requiring operators of certain saltwater disposal wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells.  As a result of these measures, the OCC from time to time has developed and implemented plans calling for wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents.  As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents.  

Also, ongoing lawsuits allege that injection well disposal operations have caused damage to neighboring properties or otherwise violated state and federal rules governing waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for produced water disposal. Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of produced water into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where produced water injection activities occur or are proposed to be performed. Court decisions or the adoption of any new laws, regulations, or directives that restrict our ability to dispose of saltwater generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or otherwise, or by requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas

 

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commissions or similar state agencies, but several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances.  Additionally, the EPA issued Clean Air Act (“CAA”) final regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting; published in June 2016 an effluent limited guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing.  Also, the federal Bureau of Land Management (“BLM”) published a final rule in March 2015 establishing more stringent standards for performing hydraulic fracturing on federal and Indian lands but in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That decision is currently being appealed by the federal government.  

The U.S. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Oklahoma, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local government may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate or where we own a working interest, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Air Emissions

The CAA and comparable state laws and regulations govern emissions of various air pollutants through air emissions standards, construction and operating permit programs and the imposition of other compliance requirements. Air emissions from some equipment found at our operations or other operations in which we own an interest, such as gas compressors, are potentially subject to regulations under the CAA or equivalent state and local regulatory programs, although many small air emission sources are expressly exempt from such regulations. To the extent that these air emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. Any need to obtain air emissions permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards and states may be required to implement more stringent regulations that could apply to our operations and require the installation of new emissions controls, resulting in longer permitting timelines and cause significant increases in our capital or operating expenditures, any of which developments could adversely impact our business.

Climate Change

Climate change continues to attract considerable public and scientific attention.  As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”).  These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.  At the federal level, no comprehensive climate change legislation has been implemented to date.  The EPA has , however, adopted rules under authority of the CAA that, among other things, establish permitting reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant emissions, which reviews could require meeting "best available control technology" standards for those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among other things, onshore producing facilities, which include certain of our operations.    

Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations.   In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions.  These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices.  Moreover, in November 2016, the EPA issued an Information Collection

 

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Request (“ICR”) seeking information about methane emissions from facilities and operators in the oil and natural gas industry but on March 2, 2017, the EPA announced it was withdrawing the ICR so that the agency may further assess the need for the information that it was collecting through the request.  Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020.  This “Paris agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions.  The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise limit emissions of GHGs from, our equipment and operations, or the equipment and operations of assets in which we own an interest, could require us to incur costs to reduce emissions of GHGs associated with those operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such physical effects were to occur, they could have an adverse effect on our exploration, development and production interests and operations.  At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and similar state laws and other regulatory initiatives restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our operations may be located in or near areas that are designated as habitat for endangered or threatened species and, in these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species or be prohibited from conducting operations during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, as a result of one or more settlements entered into by the U.S. Fish and Wildlife Service, the agency is required to make determinations on the listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines.  The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could impair our ability to timely complete well drilling and development and could cause us to incur additional costs arising from species protection measures or become subject to operating restrictions or bans in the affected areas, which delays, costs or restrictions may be significant.  If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.  

Worker Safety and Health

We are subject to the requirements of OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to- Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Operations on Federal Lands

Performance of oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands administered by the BLM, may be subject to the National Environmental Policy Act (“NEPA”).  The NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs, to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment.  The NEPA review process may take a significant amount of time and is subject to challenges by environmental groups, which have the potential to delay current and future projects.  Our current and proposed exploration, development and production activities upon federal lands require governmental permits that are subject to the requirements of NEPA. We are not currently planning any drilling operations on BLM leased acreage in 2017. Our future development of any project on BLM leased acreage will be subject to completion of these environmental assessments and any delays in such completion could result in delays in our exploration or production programs. Permit

 

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authorizations under NEPA are subject to protests, appeal or litigation, any or all of which may also delay or halt projects. Moreover, depending on the mitigation strategies recommended in the environmental assessments, we could incur added costs, which could be substantial.

Other Laws and Regulations

Our operations and other operations in which we own a working interest are also impacted by regulations governing the handling, storage, transportation and disposal of NORM. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived there from and are often based on negligence, trespass, nuisance, strict liability or fraud.

Industry Segment and Geographic Information

We operate in one industry segment, which is the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Our current operational activities are conducted in, and our consolidated revenues are generated from, markets exclusively in the U.S. For additional information relating to our disclosure of revenues, profits and total assets in the segment in which we operate, please see Item 6. “Selected Financial Data” and Item 8. “Financial Statements and Supplementary Data,” each included in this Form 10-K.

Filings of Reserve Estimates with Other Agencies

Previously, we filed with the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) revised forms related to our oil and natural gas reserves. The forms provided additional information to ensure compliance with Canadian National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”), as required by the Alberta Securities Commission and the Toronto Stock Exchange. The filings did not affect any of our filings with the SEC and were not considered part of our Form 10-K. 

On December 16, 2011, the applicable provincial commissions in Canada issued a decision document which granted us exemptive relief from the disclosure requirements contained in NI 51-101. As a result, we are no longer required to comply with the requirements of NI 51-101 and accordingly, are not required to file Form 51-101F1, “Statement of Reserves Data and Other Oil and Gas Information,” revised Form 51-101F2, “Report of Reserve Data by Independent Qualified Reserves Evaluator,” and revised Form 51-101F3, “Report of Management and Directors on Oil and Gas Disclosure.” In lieu of such filings, we are permitted to provide disclosure with respect to our oil and gas activities in the form permitted by, and in accordance with, the legal requirements of the Securities Act, the Exchange Act and the rules and regulations of the SEC and the NYSE MKT. We are required to file such disclosure on SEDAR as soon as practicable after such disclosure is filed with the SEC.

Insurance Matters

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance may have been unavailable, because premium costs are considered not in line with our deemed exposure or the risk was deemed acceptable to self-insure. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations or cash flows.

We maintain insurance at industry customary levels to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of certain prohibited substances into the environment. Such insurance might not cover the complete amount of such a claim and would not cover fines or penalties for a violation of an environmental law nor would it cover a gradual pollution loss.  We carry limited property insurance. Our control of well limits are based upon our assessment of the risk and consideration of the cost of the insurance. See Item 1A. “Risk Factors-The process of drilling for and producing oil and natural gas involves many operating risks that can cause substantial losses, and we may not have enough insurance to cover these risks adequately.”

Employees

As of March 6, 2017, we had 45 employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, regulatory reporting, environmental and tax services. On those properties where we are not the operator, we rely on outside operators to drill, produce and market our oil

 

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and natural gas. Our employees do not belong to a union or have a collective bargaining organization. Management considers its relationship with its employees to be good.

Corporate Offices

Our corporate office is located at 1331 Lamar Street, Suite 650, Houston, Texas 77010, where we lease 12,823 square feet. Additionally, we lease 7,002 square feet of office space in Oklahoma City, Oklahoma.

Available Information

Our website address is http://www.gastar.com . Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website as soon as reasonably practicable after we have electronically filed the material with or furnished it to the SEC.

The public may also read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website that contains our reports, proxy and information statements and our other SEC filings. The address of that site is www.sec.gov .

None of the information on our website should be considered incorporated into or a part of this Form 10-K.

We also make available free of charge on our internet website at www.gastar.com under the “corporate governance” tab our:

 

Code of Conduct and Ethics;

 

Corporate Governance Guidelines;

 

Audit Committee Charter;

 

Nominating and Governance Committee Charter:

 

Compensation Committee Charter;

 

Reserves Review Committee Charter; and

 

Whistleblower Procedure.

 

 

Item 1A. Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following material risk factors associated with our business and the oil and natural gas industry in which we operate. If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. There may be additional risks that are not presently material or known.

An investment in Gastar is subject to risks inherent in our business. The trading price of our common shares will be affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in Gastar may decrease, resulting in a loss.

Oil, condensate, natural gas and NGLs prices are volatile. Substantial declines in commodity prices have significantly and negatively affected our financial condition and results of operations.

The success of our business depends primarily on the market prices of oil, condensate, natural gas and NGLs. Oil, condensate, natural gas and NGLs prices are set by broad market forces, which have been and will likely continue to be volatile in the future. Since the second half of 2014, commodity prices have declined precipitously as a result of several factors, including increased worldwide supplies, a stronger U.S. dollar, weather factors, a strong competition among oil producing countries for market share and decreased demand in emerging markets, such as China. Specifically, WTI prices declined from a monthly average of $101.68 per barrel in June 2014 to a monthly average of $27.08 per barrel in February 2016.  Subsequent to February 2016, WTI prices have increased to a monthly average of $48.69 per barrel in December 2016.  The Henry Hub spot market price of natural gas declined from a monthly average of $5.86 per MMBtu in February 2014 to a monthly average of $1.69 per MMBtu in March 2016 and has subsequently increased to a monthly average of $3.57 per MMBtu in December 2016.  The continued depressed commodity prices adversely

 

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affected our 2016 financial condition and results of operations and contributed to a reduction in our anticipated future capital expenditures.  In addition, this decline in commodity prices adversely impacted our estimated proved reserves and resulted in an impairment to our oil and natural gas properties during the first quarter of 2016.

Lower realized prices also may reduce the amount of oil, condensate, natural gas or NGLs that we can produce economically. Prices for oil, condensate, natural gas and NGLs are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil, condensate, natural gas or NGLs, market uncertainty and a variety of additional factors that are beyond our control. These factors include, but are not limited to:

 

The domestic and foreign supply and demand of oil, condensate, natural gas and NGLs;

 

Volatile trading patterns in the commodity futures markets;

 

Overall economic conditions and market uncertainty;

 

Weather conditions;

 

The cost of exploring for, developing, producing, transporting and marketing natural gas, condensate, oil and NGLs;