10-K 1 gst-10k_20151231.htm 10-K gst-10k_20151231.htm

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

x

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

For the fiscal year ended December 31, 2015

or

o

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

For the transition period from                    to                    

Commission file number: 001-35211

 

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

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  o    No  x

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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  x    No  o

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.  x

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

 

Large accelerated filer

o

 

Accelerated filer

x

 

 

 

 

 

Non-accelerated filer

o

 

Smaller reporting company

o

 

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  o    No  x

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, 2015 (the last business day of Gastar Exploration Inc.’s most recently completed second fiscal quarter) was approximately $233.9 million based on the closing price of $3.09 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 7, 2016 was 81,837,275.

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, 2015

TABLE OF CONTENTS

 

 

 

Page

PART I

 

 

 

 

Item 1.

 

Business

 

9

 

 

 

 

Overview

 

9

 

 

 

 

Our Strategy

 

9

 

 

 

 

Oil and Natural Gas Activities

 

11

 

 

 

 

Markets and Customers

 

17

 

 

 

 

Competition

 

18

 

 

 

 

Seasonal Nature of Business

 

18

 

 

 

 

U.S. Governmental Regulation

 

18

 

 

 

 

Regulation of Exploration and Production

 

19

 

 

 

 

U.S. Environmental and Occupational Safety and Health Regulation

 

21

 

 

 

 

Industry Segment and Geographic Information

 

26

 

 

 

 

Insurance Matters

 

26

 

 

 

 

Filings of Reserve Estimates with Other Agencies

 

26

 

 

 

 

Employees

 

27

 

 

 

 

Corporate Offices

 

27

 

 

 

 

Available Information

 

27

 

 

Item 1A.

 

Risk Factors

 

27

 

 

Item 1B.

 

Unresolved Staff Comments

 

43

 

 

Item 2.

 

Properties

 

43

 

 

 

 

Production, Prices and Operating Expenses

 

44

 

 

 

 

Drilling Activity

 

45

 

 

 

 

Exploration and Development Acreage

 

46

 

 

 

 

Undeveloped Acreage Expirations

 

46

 

 

 

 

Productive Wells

 

47

 

 

 

 

Oil and Natural Gas Reserves

 

47

 

 

Item 3.

 

Legal Proceedings

 

50

 

 

Item 4.

 

Mine Safety Disclosure

 

50

PART II

 

 

 

 

Item 5.

 

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

 

50

 

 

 

 

Market Information

 

50

 

 

 

 

Stockholders

 

51

 

 

 

 

Dividends

 

51

 

 

 

 

Issuer Purchases of Equity Securities

 

51

 

 

 

 

Recent Sales of Unregistered Securities

 

51

 

 

Item 6.

 

Selected Financial Data

 

51

 

 

Item 7.

 

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

 

52

 

 

 

 

Overview

 

52

 

 

 

 

Financial Highlights

 

54

 

 

 

 

Results of Operations

 

54

 

 

 

 

Liquidity and Capital Resources

 

62

 

 

 

 

Off-Balance Sheet Arrangements

 

66

 

 

 

 

Contractual Obligations

 

66

 

 

 

 

Commitments

 

66

 

 

 

 

Critical Accounting Policies and Estimates

 

67

 

 

 

 

Recent Accounting Developments

 

70

 

 

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

 

70

 

 

 

 

Commodity Price Risk

 

71

 

 

 

 

Interest Rate Risk

 

71

 

 

Item 8.

 

Financial Statements and Supplementary Data

 

72

 

 

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

120

 

2


Table of Contents

 

 

 

Item 9A.

 

Controls and Procedures

 

120

 

 

 

 

Evaluation of Disclosure Controls and Procedures

 

120

 

 

 

 

Management’s Report on Internal Control over Financial Reporting

 

120

 

 

 

 

Changes in Internal Control over Financial Reporting

 

120

 

 

 

 

Report of Independent Registered Public Accounting Firm

 

121

 

 

Item 9B.

 

Other Information

 

122

PART III

 

 

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

 

123

 

 

Item 11.

 

Executive Compensation

 

126

 

 

Item 12.

 

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

 

144

 

 

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

 

146

 

 

Item 14.

 

Principal Accountant Fees and Services

 

147

PART IV

 

 

 

 

Item 15.

 

Exhibits, Financial Statements and Schedules

 

148

 

 

 

 

Exhibit Index

 

149

 

 

 

 

Signatures

 

154

 

 

 

3


Table of Contents

 

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;

 

·

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

 

·

the potential need to sell certain assets, restructure our debt or raise additional capital;

 

·

the need to take ceiling test impairments due to lower 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;

 

·

our ability to monetize certain assets;

 

4


Table of Contents

 

 

·

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

 

·

our ability to successfully complete the sale of certain of our Appalachian Basin assets;

 

·

our ability to meet financial covenants under our indenture or credit agreements or the ability to obtain amendments or waivers to effect such compliance;

 

·

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 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.

 

5


Table of Contents

 

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 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”).

 

6


Table of Contents

 

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

 

 

 

Bbl/d

 

Barrels of oil, condensate or NGLs per day

 

 

 

Bcf

 

One billion cubic feet of natural gas

 

 

 

Bcfe

 

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

 

 

 

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

 

 

 

Btu

 

British thermal unit, typically used in measuring natural gas energy content

 

 

 

CRP

 

Central receipt point

 

 

 

FASB

 

Financial Accounting Standards Board

 

 

 

GAAP

 

Accounting principles generally accepted in the United States of America

 

 

 

Gross acres

 

Refers to acres in which we own a working interest

 

 

 

Gross wells

 

Refers to wells in which we have 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

 

 

 

Mcf/d

 

One thousand cubic feet of natural gas per day

 

 

 

Mcfe

 

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

 

 

 

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

 

 

 

MMcfe

 

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

 

 

 

MMcfe/d

 

One million cubic feet of natural gas equivalent 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

 

 

 

psi

 

Pounds per square inch

 

 

 

PUD

 

Proved undeveloped reserves

 

 

 

 

7


Table of Contents

 

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

 

 

 

WTI

 

West Texas Intermediate

 

 

 

8


Table of Contents

 

PART I

Item 1. Business

Overview

We are an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. 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. In Oklahoma, we have developed the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and are drilling other prospective formations on the same acreage, primarily the Meramec Shale (Middle Mississippi Lime), while we plan to also test the Woodford Shale, along with emerging prospective plays in the shallow Oswego formation and in the Osage formation, a deeper bench of the Mississippi Lime located below the Meramec.  These formations comprise what is commonly referred to as the STACK Play.  In West Virginia, we have developed liquids-rich natural gas in the Marcellus Shale and have drilled and completed two successful dry gas Utica Shale/Point Pleasant wells on our acreage.  On February 19, 2016, we entered into an agreement to sell substantially all of our assets and proved reserves and a significant portion of our undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions, including obtaining certain required lessor consents to assign (the “Appalachian Basin Sale”).  The transaction is expected to close on or before March 31, 2016 with an effective date of January 1, 2016.  We completed the sale of substantially all of our East Texas assets in 2013.

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 growth and improved operating results from our existing assets. We recognize that there may be periods, such as the currently 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 of our Mid-Continent assets in the STACK Play;

 

·

exploitation of the STACK Play on our Mid-Continent acreage;

 

·

the sale of certain of our properties, including our Appalachian Basin Sale and the possible sale of a portion of our undeveloped STACK Play acreage in the Mid-Continent;

 

·

active management of our drilling programs; and

 

·

effective management and utilization of technological expertise.

Development of our Mid-Continent Assets in the STACK Play

During 2012, we began acquiring leasehold in an emerging oil play located in Oklahoma. We continued to build our acreage position in this region during 2013 through 2015 with our AMI co-participant in an initial AMI prospect area and two additional adjacent prospect areas. 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 (the “Chesapeake Parties”) and affiliates of Lime Rock Resources (the “Lime Rock Parties”), respectively, during 2013. On December 16, 2015, we completed the acquisition of additional interests in the AMI from our AMI co-participant including working and net revenue interests in 103 gross (10.2 net) producing wells and approximately 15,700 net developed and undeveloped acres in Kingfisher and Garfield Counties, Oklahoma (the “Husky Acquisition”) for an adjusted purchase price of $42.1 million and the conveyance of approximately 11,000 net non-core, non-producing acres in Blaine, Major and Kingfisher Counties, Oklahoma to the sellers.  With the closing of the Husky Acquisition, our AMI participation agreements with our AMI co-participant were dissolved and we obtained operatorship of the acquired wells.  

Our Mid-Continent development program has been 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 historically using vertical wells with conventional completion techniques. Since 2012, we, along with our former AMI co-participant

 

9


Table of Contents

 

in the initial AMI and adjacent areas, until such time as we bought out our AMI co-participant, drilled and completed 38 gross (17.9 net) horizontal non-operated wells.  As a result of the Husky Acquisition, we now operate each of these wells.

Since we began our operated drilling program in the Hunton Limestone in 2013, we have drilled and completed 22 gross (21.4 net) operated wells, including 17 gross (16.7 net) wells within the West Edmond Hunton Lime Unit (“WEHLU”).    

To further test the potential of other Mid-Continent formations, during 2015 and to date in 2016, we also participated in three gross (0.1 net) non-operated Woodford Shale wells, two gross (0.1 net) non-operated wells targeting the Oswego, one gross (0.003 net) non-operated well targeting the Osage Shale and six gross (0.5 net) non-operated Meramec Shale wells.  Prior to 2015, we participated in one gross (0.1 net) non-operated Mississippian Lime well and two gross (0.1 net) non-operated Woodford Shale well.

Exploitation of the STACK Play on our Mid-Continent Acreage

In addition to Hunton Limestone potential, we believe that our acreage is also prospective in the STACK Play, an area of central Oklahoma that includes oil and natural gas-rich shale formations such as the proven Meramec and Woodford Shales, ranging in depth from 6,000 to 9,000 feet, and emerging prospective plays in the shallow Oswego formation and in the Osage formation, a deeper bench of the Mississippi Lime located below the Meramec.  Subsequent to the closing of the Husky Acquisition, our exposure to the STACK Play is approximately 38,100 net acres in the Meramec Shale play, 39,200 net acres in the Osage Shale play, 14,900 net acres in the Oswego formation and 39,200 net acres in the Woodford Shale play.

On September 6, 2015, we spudded our first operated Meramec well, the Deep River 30-1H, with a vertical depth of approximately 7,300 feet and drilled an approximate 5,100-foot lateral and completed it with a 34-stage fracture stimulation.  The Deep River 30-1H was placed on flowback on October 28, 2015.  The Deep River produced a peak 24-hour rate of 1,094 Boe per day (71% oil) and at a post-peak 60-day average daily production rate of 803 Boe per day (63% oil).  Our working interest in the Deep River 30-1H is 100% (NRI 80%).  The estimated cost to drill and complete the Deep River 30-1H is approximately $6.5 million.

We spud one gross (1.0 net) well, our second Meramec well, the Holiday Road 2-1H, February 10, 2016 and the well is scheduled to begin completion operations in mid-March 2016.  The well was drilled to a total depth of 12,000 feet in approximately 12 days and has a horizontal lateral of approximately 4,300 feet.  Our working interest in the Holiday Road 2-1H will not be less than 72% (approximate NRI 57%).

Sale of Certain of our Properties

Due to continued declines in natural gas and NGLs prices in the Appalachian Basin, we suspended our drilling operations in the Appalachian Basin during the second quarter of 2015.  On February 19, 2016, we entered into an agreement to sell substantially all of our assets and proved reserves and a significant portion of our undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions, including obtaining certain required lessor consents to assign.  The transaction is expected to close on or before March 31, 2016, with an effective date of January 1, 2016.  The proceeds from the Appalachian Basin Sale will be utilized to reduce outstanding borrowings under our revolving credit facility (the “Revolving Credit Facility”).

We are currently marketing approximately 26,000 net acres of primarily undeveloped leasehold in Canadian and southeast Kingfisher Counties, Oklahoma.  If the sale of such acreage is successful, the proceeds from the sale may be utilized to partially reduce the borrowings outstanding under our Revolving Credit Facility, for lease renewals and for the expansion of our 2016 capital program.

Actively Manage Our Drilling Program

We believe that operating the majority of our capital budget for 2016 will enable us to control the timing and cost of our drilling as well as control operating costs and the marketing of our production. Given the currently depressed commodity price environment and market conditions, control over our costs and expenditures is increasingly important.  Due to uncertainty concerning current and future commodity prices and our 2016 capital resources, we have not established our full-year 2016 capital plan.  Our preliminary capital budget for 2016 is approximately $37.0 million, excluding other capitalized costs, which contemplates the drilling and completion of a second operated Meramec well for approximately $5.5 million (gross), $3.5 million net for recompletion projects on producing operated wells in Oklahoma, $8.0 million for our participation in non-operated STACK Play drilling and $20.0 million for maintaining our current Oklahoma leasehold 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 Hunton Limestone and the STACK Play wells.

 

10


Table of Contents

 

 

Manage and Utilize Technological Expertise

We believe that micro-seismic data acquisition and interpretation, 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 2015. 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 Operation.”

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 and Woodford Shale, ranging in depth from 6,000 to 9,000 feet, and emerging prospective plays in the shallow Oswego formation and in the Osage formation, a deeper bench of the Mississippi Lime located below the Meramec as well as the proven Hunton Limestone horizontal oil play.  As of December 31, 2015, we held leases covering approximately 184,900 gross (110,700 net) acres in Garfield, Canadian, Kingfisher, Logan, Blaine and Oklahoma Counties, Oklahoma within 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. Prior to the closing of the Husky Acquisition, our AMI co-participant handled all drilling, completion and production activities, and we handled leasing and permitting activities in certain areas of the AMI.  On December 16, 2015, we completed the Husky Acquisition of additional interests in the AMI from our AMI co-participant including working and net revenue interests in 103 gross (10.2 net) producing wells and approximately 15,700 net developed and undeveloped acres in Kingfisher and Garfield Counties, Oklahoma and assumed operatorship of the acquired wells.  With the closing of the Husky Acquisition, our AMI participation agreements with our AMI co-participant were dissolved.    

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 November 15, 2013, we acquired a 98.3% working interest (80.5% net revenue interest) in 24,000 net acres of oil and natural gas leasehold interests in the WEHLU located in Kingfisher, Logan and Oklahoma Counties, Oklahoma, including production from interests in 56 gross (55.0 net) producing wells, for an adjusted cash purchase price of approximately $177.8 million.

On June 7, 2013, we acquired approximately 157,000 net acres of oil and natural gas leasehold interests in Canadian and Kingfisher Counties, Oklahoma from the Chesapeake Parties, including production interests in 206 gross producing wells for an adjusted cash purchase price of approximately $69.4 million. Effective July 1, 2013, our working interest partner in the original AMI in Oklahoma exercised its rights to acquire approximately 12,800 net acres and certain proved properties that we acquired from the Chesapeake Parties for a total payment of $11.6 million. In addition, on August 6, 2013, we sold approximately 76,000 net acres in Kingfisher and Canadian Counties, Oklahoma to Newfield Exploration Mid-Continent Inc. (“Newfield”) for an adjusted purchase price of approximately $57.0 million cash net of our purchase of approximately 1,850 net acres of Oklahoma oil and gas leasehold interests from Newfield for $1.5 million.

    

 

11


Table of Contents

 

As of December 31, 2015 and currently as of the date of this report, we had production operations on the following wells completed during 2015 in our original AMI in the Hunton Limestone formation:

 

Well Name

 

Current

Working

Interest

 

 

Approximate Lateral Length

(in feet)

 

 

Peak Production Rates(1)

(Boe/d)

 

 

Boe/d(2)

 

 

% Oil

 

 

Date of First

Production

 

Approximate

Gross Costs to

Drill & Complete

($ millions)

 

LB 1-1H

 

 

60.9%

 

 

 

4,300

 

 

 

791

 

 

 

147

 

 

 

61%

 

 

January 23, 2015

 

$

4.4

 

Hubbard 1-23H

 

 

87.9%

 

 

 

4,500

 

 

 

63

 

 

 

16

 

 

 

97%

 

 

February 19, 2015

 

$

6.1

 

Boss Hogg 1-14H

 

 

75.5%

 

 

 

4,300

 

 

 

129

 

 

 

45

 

 

 

70%

 

 

February 21, 2015

 

$

7.4

 

Bo 1-23H

 

 

64.3%

 

 

 

4,300

 

 

 

547

 

 

 

213

 

 

 

42%

 

 

February 28, 2015

 

$

5.0

 

The River 1-22H

 

 

39.7%

 

 

 

3,800

 

 

 

1,250

 

 

 

639

 

 

 

26%

 

 

March 14, 2015

 

$

4.6

 

Bigfoot 1-9H

 

 

72.4%

 

 

 

4,200

 

 

 

161

 

 

 

77

 

 

 

51%

 

 

March 17, 2015

 

$

5.1

 

Falcon 1-5H

 

 

61.7%

 

 

 

4,100

 

 

 

1,202

 

 

 

496

 

 

 

64%

 

 

April 1, 2015

 

$

4.4

 

Dorothy 1-12H

 

 

68.2%

 

 

 

3,900

 

 

 

41

 

 

 

13

 

 

 

77%

 

 

April 10, 2015

 

$

4.5

 

Polar Bear 1-20H

 

 

56.2%

 

 

 

4,300

 

 

 

403

 

 

 

99

 

 

 

88%

 

 

May 5, 2015

 

$

5.2

 

Unruh 1-34H

 

 

75.9%

 

 

 

4,400

 

 

 

371

 

 

 

242

 

 

 

45%

 

 

October 28, 2015

 

$

7.3

 

 

(1)

Represents highest daily gross Boe rate.

(2)

Represents gross cumulative production divided by actual producing days through February 29, 2016.

As of December 31, 2015 and currently as of the date of this report, we had production operations on the following operated wells on our WEHLU acreage in the Hunton Limestone formation:

 

Well Name

 

Current

Working

Interest

 

 

Approximate Lateral Length

(in feet)

 

 

Peak

Production

Rates(1) (Boe/d)

 

 

Boe/d(2)

 

 

% Oil

 

 

Date of First

Production

 

Approximate

Gross Costs to

Drill & Complete ($ millions)

 

Upper Hunton Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Warsaw 33-2H

 

 

98.3%

 

 

 

4,900

 

 

 

615

 

 

 

183

 

 

 

50%

 

 

February 13, 2015

 

$

4.4

 

Blair Farms 31-1H

 

 

98.3%

 

 

 

7,500

 

 

 

509

 

 

 

339

 

 

 

75%

 

 

May 7, 2015

 

$

5.1

 

Easton 22-4H

 

 

98.3%

 

 

 

5,800

 

 

 

604

 

 

 

285

 

 

 

87%

 

 

May 20, 2015

 

$

2.9

 

Jetson 8-2H

 

 

98.3%

 

 

 

6,100

 

 

 

353

 

 

 

138

 

 

 

88%

 

 

August 19, 2015

 

$

4.6

 

Arcadia Farms 15-2H

 

 

98.3%

 

 

 

7,700

 

 

 

444

 

 

 

178

 

 

 

81%

 

 

September 13, 2015

 

$

3.1

 

O' Donnell 5-1H

 

 

98.3%

 

 

 

4,400

 

 

 

462

 

 

 

223

 

 

 

74%

 

 

October 8, 2015

 

$

3.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lower Hunton Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Warsaw 33-3H

 

 

98.3%

 

 

 

6,100

 

 

 

663

 

 

 

173

 

 

 

56%

 

 

February 14, 2015

 

$

6.9

 

Easton 22-3H

 

 

98.3%

 

 

 

6,700

 

 

 

548

 

 

 

354

 

 

 

76%

 

 

May 24, 2015

 

$

4.6

 

Davis 9-2H

 

 

98.3%

 

 

 

6,600

 

 

 

280

 

 

 

206

 

 

 

81%

 

 

August 6, 2015

 

$

6.2

 

Jetson 8-1H

 

 

98.3%

 

 

 

5,800

 

 

 

316

 

 

 

156

 

 

 

59%

 

 

August 19, 2015

 

$

5.5

 

Davis 9-4H

 

 

98.3%

 

 

 

7,700

 

 

 

177

 

 

 

102

 

 

 

98%

 

 

October 3, 2015

 

$

5.5

 

Arcadia Farms 15-1CH

 

 

98.3%

 

 

 

6,800

 

 

 

251

 

 

 

181

 

 

 

69%

 

 

October 9, 2015

 

$

5.9

 

O'Donnell 5-2CH

 

 

98.3%

 

 

 

5,600

 

 

 

521

 

 

 

287

 

 

 

58%

 

 

October 9, 2015

 

$

4.3

 

 

(1)

Represents highest daily gross Boe rate.

(2)

Represents gross cumulative production divided by actual producing days through February 29, 2016.

On September 6, 2015, we spudded our first Meramec well, the Deep River 30-1H, with a vertical depth of approximately 7,300 feet and drilled an approximate 5,100-foot lateral and completed it with a 34-stage fracture stimulation.  The Deep River 30-1H commenced flow back on October 28, 2015 and in December 2015, produced at a peak 24-hour rate of 1,094 Boe per day (71% oil) and at a post-peak 60-day average daily production rate of 803 Boe per day (63% oil).  Our working interest in the Deep River 30-1H is 100% (NRI 80%).  The estimated cost to drill and complete the Deep River 30-1H is approximately $6.5 million.  On February 10, 2016, we spudded our second Meramec well, the Holiday Road 2-1H, and the well is scheduled to begin completion operations in mid-March 2016.  The well was drilled to a total depth of 12,000 feet in approximately 12 days and has a horizontal lateral of approximately 4,300 feet.  Our working interest in the Holiday Road 2-1H will not be less than 72% (approximate NRI 57%).

In 2015 and to date in 2016, we have also elected to participate in eight gross (0.6 net) non-operated Meramec Shale wells, three gross (0.1 net) non-operated Woodford Shale wells, three gross (0.4 net) non-operated wells targeting the Oswego and one gross (0.003 net) non-operated well targeting the Osage Shale.  Prior to 2015, we participated in one gross (0.1 net) non-operated

 

12


Table of Contents

 

Mississippian Lime well and two gross (0.1 net) non-operated Woodford Shale wells.  We are currently planning to participate in an additional non-operated well targeting the Oswego in Kingfisher County, Oklahoma during the second quarter of 2016.

At December 31, 2015, proved reserves attributable to the Mid-Continent were approximately 41.0 MMBoe, a 21% increase from year-end 2014 reserves of 34.0 MMBoe. As of December 31, 2015, Mid-Continent proved reserves represented approximately 73% of our total proved reserves and 94% of our SEC total proved PV-10 value. Total Mid-Continent proved reserves at year-end 2015 were comprised of approximately 78% of oil, condensate and NGLs reserves compared to 79% at year-end 2014. Approximately 33% of the Mid-Continent year-end 2015 and year-end 2014 reserves were proved developed.

For 2016, our focus is to drill in areas that we believe will result in de-risking of additional acreage within the STACK Play and the renewal of acreage in areas that our past drilling has proven to provide attractive returns and production rates and substantial reserve additions. We may elect to sell in the future certain acreage that is outside of our drilling focus to reduce net capital expenditures.  We are currently marketing approximately 26,000 net acres of primarily undeveloped leasehold in Canadian and southeast Kingfisher Counties, Oklahoma.  If the sale of such acreage is successful, the proceeds from the sale may be utilized to partially reduce the borrowings outstanding under our Revolving Credit Facility, for lease renewals and for the expansion of our 2016 capital program.  

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

 

 

 

For the Years Ended December 31,

 

Mid-Continent

 

2015

 

 

2014

 

 

2013

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (MBbl)

 

 

1,182

 

 

 

792

 

 

 

189

 

Natural gas (MMcf)

 

 

3,370

 

 

 

2,822

 

 

 

1,095

 

NGLs (MBbl)

 

 

433

 

 

 

332

 

 

 

23

 

Total Production (MBoe)

 

 

2,177

 

 

 

1,594

 

 

 

395

 

Oil and condensate (MBbl/d)

 

 

3.2

 

 

 

2.2

 

 

 

0.5

 

Natural gas (MMcf/d)

 

 

9.2

 

 

 

7.7

 

 

 

3.0

 

NGLs (MBbl/d)

 

 

1.2

 

 

 

0.9

 

 

 

0.1

 

Total daily production (MBoe/d)

 

 

6.0

 

 

 

4.4

 

 

 

1.1

 

Average sales price per unit(1):

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (per Bbl)

 

$

46.18

 

 

$

88.84

 

 

$

94.80

 

Natural gas (per Mcf)

 

$

2.57

 

 

$

4.24

 

 

$

4.75

 

NGLs (per Bbl)

 

$

13.15

 

 

$

31.79

 

 

$

33.06

 

Average sales price per Boe(1)

 

$

31.67

 

 

$

58.27

 

 

$

60.53

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

$

1,444

 

 

$

2,940

 

 

$

820

 

Lease operating expenses

 

$

19,270

 

 

$

15,112

 

 

$

4,019

 

Transportation, treating and gathering

 

$

14

 

 

$

40

 

 

$

3

 

Selected operating expenses per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

$

0.66

 

 

$

1.84

 

 

$

2.08

 

Lease operating expenses

 

$

8.85

 

 

$

9.48

 

 

$

10.17

 

Transportation, treating and gathering

 

$

0.01

 

 

$

0.02

 

 

$

0.01

 

Production costs(2)

 

$

8.86

 

 

$

9.50

 

 

$

10.17

 

 

(1)

Excludes the impact of hedging activities.

(2)

Production costs include lease operating expense, insurance, transportation, treating and gathering and workover expense and excludes ad valorem and severance taxes.

Our preliminary 2016 Mid-Continent capital budget includes plans  for drilling and completion of a second operated Meramec well for approximately $5.5 million, $3.5 million for recompletion projects on producing operated Oklahoma wells, $8.0 million for our participation in non-operated STACK Play drilling and $20.0 million for maintaining our current Oklahoma leasehold position.

 

13


Table of Contents

 

Appalachian Basin

Due to the continued depressed price environment in the Appalachian Basin, we suspended our drilling operations in the Appalachian Basin in the second quarter of 2015.  As of December 31, 2015, we had no drilling operations in progress on our Marcellus Shale and Utica/Point Pleasant acreage in Marshall County, West Virginia.   On February 19, 2016, we entered into an agreement to sell substantially all of our assets and proved reserves and a significant portion of our undeveloped acreage in the Appalachian Basin for $80.0 million, subject to certain adjustments and customary closing conditions.  The transaction is expected to close on or before March 31, 2016 with an effective date of January 1, 2016.

Marcellus Shale

The Marcellus Shale is Devonian aged shale that underlies much of the Appalachian region of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The depth of the Marcellus Shale and its low permeability make the Marcellus Shale an unconventional exploration target in the Appalachian Basin. Advancements in horizontal drilling and hydraulic fracture stimulation have produced promising results in the Marcellus Shale. As of December 31, 2015, our acreage position in the play was approximately 56,300 gross (36,900 net) acres. We refer to the approximately 27,500 gross (11,500 net) acres reflecting our interest in our Marcellus Shale assets in West Virginia and Pennsylvania subject to our participation agreement (the “Atinum Participation Agreement”) with an affiliate of Atinum Partners Co. Ltd. (“Atinum”) as our “Marcellus West acreage.” We refer to the approximately 28,800 gross (25,400 net) acres in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West Virginia as our “Marcellus East acreage.” The entirety of our acreage is believed to be in the core, over-pressured area of the Marcellus Shale play.

On September 21, 2010, we entered into the Atinum Participation Agreement pursuant to which we ultimately assigned to Atinum, for $70.0 million in total consideration, a 50% working interest in certain undeveloped acreage and shallow producing wells. Atinum has the right to participate in any future leasehold acquisitions made by us within Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to those governing the then-existing Atinum Participation Agreement. We are the operator and are obligated to offer any future lease acquisitions to Atinum on a 50/50 basis. Atinum will pay us on an annual basis an amount equal to 10% of lease bonuses and third party leasing costs, up to $20.0 million, and 5% of such costs on activities above $20.0 million.

The Atinum co-participants pursued an initial three-year development program that called for the drilling of a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, we and Atinum agreed to reduce the minimum wells to be drilled requirements from 60 gross wells to 51 gross wells. At December 31, 2015, 74 gross (37.0 net) operated Marcellus Shale horizontal wells were capable of production. All of our Marcellus Shale well operations to date were drilled under the Atinum Participation Agreement. The Atinum Participation Agreement expired on November 1, 2015.

From the inception of our operations in the Marcellus Shale in 2011 to late 2013, our operated production and sales in West Virginia were temporarily curtailed by issues with condensate handling, dehydration limitations, high line pressures and excessive unscheduled system down-time on a third-party-operated gathering system. The gathering system operator continually attempted to resolve these issues with operational improvements. Subsequent to October 1, 2013, we have not experienced significant curtailment or high line pressure issues on our Marcellus West production on the third-party gathering system. In July 2013, we initiated an arbitration proceeding requesting damages against the gathering system operator for, among other claims, failure to timely construct certain gathering and processing facilities, maximize the net value of produced condensation, and fractionate and purchase NGLs, which claims were settled in June 2014.

At December 31, 2015, proved reserves attributable to the Marcellus Shale were approximately 13.6 MMBoe, a 78% decrease from year-end 2014 reserves of 61.0 MMBoe.  The decrease was the result of all Marcellus Shale PUD locations being uneconomic at year-end SEC prices.  As of December 31, 2015, Marcellus Shale proved reserves represented approximately 24% of our total proved reserves and 6% of PV-10 value. Total Marcellus Shale proved reserves at year-end 2015 were comprised of approximately 43% of oil and condensate and NGLs reserves compared to 45% at year-end 2014. All of the Marcellus Shale year-end 2015 reserves are proved developed compared to 41% at December 31, 2014.

 

14


Table of Contents

 

The following table provides production and operational information for the Marcellus Shale for the periods indicated:

 

 

 

For the Years Ended December 31,

 

Marcellus Shale

 

2015

 

 

2014

 

 

2013

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (MBbl)

 

 

243

 

 

 

182

 

 

 

315

 

Natural gas (MMcf)

 

 

8,241

 

 

 

8,050

 

 

 

9,594

 

NGLs (MBbl)

 

 

779

 

 

 

469

 

 

 

471

 

Total production (MBoe)

 

 

2,395

 

 

 

1,993

 

 

 

2,385

 

Oil and condensate (MBbl/d)

 

 

0.7

 

 

 

0.5

 

 

 

0.9

 

Natural gas (MMcf/d)

 

 

22.6

 

 

 

22.1

 

 

 

26.3

 

NGLs (MBbl/d)

 

 

2.1

 

 

 

1.3

 

 

 

1.3

 

Total daily production (MBoe/d)

 

 

6.6

 

 

 

5.5

 

 

 

6.5

 

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

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (per Bbl)

 

$

16.78

 

 

$

68.21

 

 

$

55.61

 

Natural gas (per Mcf)

 

$

0.80

 

 

$

4.28

 

 

$

2.86

 

NGLs (per Bbl)

 

$

1.85

 

 

$

23.11

 

 

$

31.52

 

Average sales price per Boe(1)(2)

 

$

5.07

 

 

$

28.97

 

 

$

25.08

 

Selected operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes(3)

 

$

1,235

 

 

$

3,685

 

 

$

3,805

 

Lease operating expenses(3)

 

$

4,369

 

 

$

4,187

 

 

$

3,181

 

Transportation, treating and gathering(3)

 

$

1,934

 

 

$

3,552

 

 

$

1,176

 

Selected operating expenses per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes(3)

 

$

0.52

 

 

$

1.85

 

 

$

1.60

 

Lease operating expenses(3)

 

$

1.82

 

 

$

2.10

 

 

$

1.33

 

Transportation, treating and gathering(3)

 

$

0.81

 

 

$

1.78

 

 

$

0.49

 

Production costs(4)

 

$

2.06

 

 

$

3.50

 

 

$

1.76

 

 

(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

 

Marcellus Shale

 

 

 

 

Average sales price per unit:

 

 

 

 

Oil and condensate (per Bbl)

 

$

50.96

 

Natural gas (per Mcf)

 

$

3.27

 

NGLs (per Bbl)

 

$

24.55

 

Average sales price per Boe

 

$

23.65

 

 

(3)

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

 

 

 

For the Year Ended

December 31, 2014

 

Marcellus Shale

 

 

 

 

Selected operating expenses per Boe:

 

 

 

 

Production taxes

 

$

1.56

 

Lease operating expenses

 

$

2.19

 

Transportation, treating and gathering

 

$

0.99

 

 

 

15


Table of Contents

 

(4)

Production costs include lease operating expense, 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

 

Marcellus Shale

 

 

 

 

Selected operating expenses per Boe:

 

 

 

 

Production costs

 

$

2.80

 

 

Utica Shale

The Utica Shale is Ordovician aged shale that underlies much of the Appalachian region of Pennsylvania, Ohio and West Virginia. The depth of the Utica Shale and its low permeability make it an unconventional exploration target in the Appalachian Basin.  Advancements in horizontal drilling and hydraulic fracture stimulation have produced promising results in the Utica Shale, some in close proximity to our existing Marcellus West acreage.  Based on our successful completion of two Utica Shale wells, log analysis of offsetting wells and recent Utica Shale completions by other nearby operators, we believe that our Marcellus West acreage should be prospective for high-pressure, high-deliverability dry natural gas development in the Utica Shale/Point Pleasant formation.  We drilled the Simms U-5H to a total vertical depth of 11,500 feet and drilled an approximate 4,400-foot lateral and completed it with a 25-stage fracture stimulation.   Our working interest in the Simms U-5H is 50.0% (43.2% net revenue interest). We drilled the Blake U-7H to a total vertical depth of 11,100 feet and drilled an approximate 6,600-foot lateral and completed it with a 34-stage fracture stimulation.   Our working interest in the Blake U-7H is 50.0% (41.1% net revenue interest).  The estimated cost to drill and complete the Blake U-7H was approximately $15.9 million.  All of our Utica Shale/Point Pleasant well operations to date were drilled under the Atinum Participation Agreement.  The Atinum Participation Agreement expired on November 1, 2015.  

At December 31, 2015, proved reserves attributable to the Utica Shale were approximately 1.2 MMBoe, an 83% decrease from year-end 2014 reserves of 7.1 MMBoe.  The decrease was the result of all Utica Shale PUD locations being uneconomic at year-end 2015 SEC prices.  As of December 31, 2015, Utica Shale proved reserves represented approximately 2% of our total proved reserves and 1% of PV-10 value and were comprised 100% of natural gas reserves.  All of the Utica Shale year-end 2015 reserves are proved developed compared to 12% at December 31, 2014.

The following table provides production and operational information for the Utica Shale for the period indicated:

 

 

 

For the Years Ended December 31,

 

Utica Shale

 

2015

 

 

2014

 

Production:

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

2,148

 

 

 

725

 

Total production (MBoe)

 

 

358

 

 

 

121

 

Natural gas (MMcf/d)

 

 

5.9

 

 

 

2.0

 

Total daily production (MBoe/d)

 

 

1.0

 

 

 

0.3

 

Average sales price per unit(1):

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

0.75

 

 

$

1.68

 

Average sales price per Boe(1)

 

$

4.49

 

 

$

10.10

 

Selected operating expenses (in thousands):

 

 

 

 

 

 

 

 

Production taxes

 

$

198

 

 

$

109

 

Lease operating expenses

 

$

89

 

 

$

24

 

Transportation, treating and gathering

 

$

241

 

 

$

87

 

Selected operating expenses per Boe:

 

 

 

 

 

 

 

 

Production taxes

 

$

0.55

 

 

$

0.90

 

Lease operating expenses

 

$

0.25

 

 

$

0.20

 

Transportation, treating and gathering

 

$

0.67

 

 

$

0.72

 

Production costs(2)

 

$

0.92

 

 

$

0.92

 

 

(1)

Excludes the impact of hedging activities.

(2)

Production costs include lease operating expense, insurance, gathering and workover expense and excludes ad valorem and severance taxes.

 

16


Table of Contents

 

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 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.  Since the second half of 2014, there has been a substantial decline in commodity prices which has significantly and negatively affected our 2015 financial condition and results of operations.  Additionally, our results are subject to commodity price fluctuations related to seasonal and market conditions and reservoir and production risks.”

Our oil, condensate and NGLs production in the Appalachian Basin and 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.

There are limited natural gas purchaser and transporter alternatives currently available near our Marcellus and Utica Shale acreage in the Appalachian Basin. Our Appalachian Basin production is sold on the spot market to regional pipeline companies. There are numerous natural gas purchasers and transport and processing options in our Mid-Continent area, and all natural gas production from this region is sold on the spot market to regional pipeline companies.

During December 2010, we, along with Atinum, entered into a gas purchase agreement with SEI Energy, LLC (“SEI”) with respect to our Marcellus West Marshall County, West Virginia production. The initial term of the gas purchase agreement is five years with the option to extend the term of the gas purchase agreement for an additional five-year period. Our Marshall County, West Virginia production is dedicated to SEI for the term of the gas purchase agreement. During December 2014, the gas purchase agreement with SEI was amended to include all of our Wetzel County, West Virginia production in addition to the previously dedicated Marshall County, West Virginia production. SEI will purchase all hydrocarbon production, including all natural gas, condensate and natural gas liquids. SEI has an agreement to utilize the Williams Ohio Valley Midstream LLC (“Williams”) midstream facilities (formerly owned by Caiman Energy Midstream, LLC), including its 520.0 MMcf/d Fort Beeler processing plant located in Marshall County, West Virginia for transporting and processing. In order to secure access to the Williams facilities, we, Atinum and SEI dedicated all hydrocarbons purchased and produced in Marshall County, West Virginia for a term of ten years. From the inception of our operations in the Marcellus Shale in 2011 to late 2013, our operated production and sales in West Virginia were temporarily curtailed by issues with condensate handling, dehydration limitations, high line pressures and excessive unscheduled system down-time on a third-party-operated gathering system. The gathering system operator continually took steps to attempt to resolve these issues with operational improvements. In July 2013, we initiated an arbitration proceeding requesting damages against the gathering system operator for, among other claims, failure to timely construct certain gathering and processing facilities, maximize the net value of produced condensation, and fractionate and purchase NGLs as provided in the agreements, which claims were settled in June 2014. In conjunction with the settlement, the SEI and Williams contracts were amended regarding certain fees and operational matters and the contracts were extended through July 1, 2023.

 

17


Table of Contents

 

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,

 

 

 

2015

 

 

2014

 

 

2013

 

SEI

 

 

22

%

 

 

50

%

 

 

56

%

Sunoco

 

 

62

%

 

 

37

%

 

 

16

%

 

SEI and Sunoco Logistics Partners L.P. (“Sunoco”) purchase the majority of the Company’s Mid-Continent production. There are numerous purchase and transportation alternatives currently available in the Mid-Continent so in the event that SEI or Sunoco 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.  SEI purchases the majority of our Appalachian Basin production. There are limited oil, condensate, natural gas and NGLs purchase and transportation alternatives currently available in Appalachia. If SEI was to cease purchasing and transporting our Appalachian Basin oil, condensate, natural gas and NGLs production and we were unable to obtain timely access to existing or future facilities on acceptable terms, or in the event of any significant change affecting these facilities, including delays in the commencement of operations of any new pipelines or the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise, our ability to conduct normal operations would be restricted.  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.”

Competition

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

 

18


Table of Contents

 

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 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 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.

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 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

 

19


Table of Contents

 

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.

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

 

20


Table of Contents

 

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 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.

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. While we have not been required to expend material capital expenditures or other resources in order to satisfy existing applicable environmental laws and regulations, there is no assurance that costs to comply with existing and any new environmental laws and regulations in the future will not be material. 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