Gastar Exploration Inc.
Gastar Exploration Inc. (Form: 10-Q, Received: 08/06/2015 16:41:37)
Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________
FORM 10-Q
____________________________________________________
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED June 30, 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)
____________________________________________________
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
ý
No
o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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
ý
No
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See 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
ý
Non-accelerated filer
o   (Do not check if a smaller reporting company)
Smaller reporting company
o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   
 
Yes
o
No
ý
The total number of outstanding common shares, $0.001 par value per share, as of August 3, 2015 was 80,142,118 .


Table of Contents


GASTAR EXPLORATION INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2015
TABLE OF CONTENTS
 
 
 
Page
 
Item 1.
 
 
 
 
Item 2.
Item 3.
Item 4.
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.


2

Table of Contents

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. 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 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-Q are stated in United States dollars (“U.S. dollars”) unless otherwise noted and (v) all financial data included in this Form 10-Q have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).
General information about us can be found on our website at www.gastar.com . The information available on or through our website, or about us on any other website, is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings that we make with the U.S. Securities and Exchange Commission (“SEC”), as well as any amendments and exhibits to those reports, will be available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. Information is also available on the SEC website at www.sec.gov for our U.S. filings.



3

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
 
 
 
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
 
 
 
U.S.
 
United States of America
 
 
 
U.S. GAAP
 
Accounting principles generally accepted in the United States of America


4

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements
GASTAR EXPLORATION INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30,
2015
 
December 31,
2014
 
(Unaudited)
 
 
 
(in thousands, except share data)
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
9,378

 
$
11,008

Accounts receivable, net of allowance for doubtful accounts of $0, respectively
16,431

 
30,841

Commodity derivative contracts
13,159

 
19,687

Prepaid expenses
686

 
2,083

Total current assets
39,654

 
63,619

PROPERTY, PLANT AND EQUIPMENT:
 
 
 
Oil and natural gas properties, full cost method of accounting:
 
 
 
Unproved properties, excluded from amortization
123,162

 
128,274

Proved properties
1,208,229

 
1,124,367

Total oil and natural gas properties
1,331,391

 
1,252,641

Furniture and equipment
3,055

 
3,010

Total property, plant and equipment
1,334,446

 
1,255,651

Accumulated depreciation, depletion and amortization
(694,054
)
 
(563,351
)
Total property, plant and equipment, net
640,392

 
692,300

OTHER ASSETS:
 
 
 
Commodity derivative contracts
9,996

 
7,815

Deferred charges, net
2,889

 
2,586

Advances to operators and other assets
795

 
9,474

Total other assets
13,680

 
19,875

TOTAL ASSETS
$
693,726

 
$
775,794

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
13,333

 
$
28,843

Revenue payable
6,770

 
9,122

Accrued interest
3,553

 
3,528

Accrued drilling and operating costs
6,351

 
5,977

Advances from non-operators

 
1,820

Commodity derivative contracts
166

 

Commodity derivative premium payable
1,515

 
2,481

Asset retirement obligation
86

 
82

Other accrued liabilities
9,251

 
3,175

Total current liabilities
41,025

 
55,028

LONG-TERM LIABILITIES:
 
 
 
Long-term debt
411,545

 
360,303

Commodity derivative contracts
616

 

Commodity derivative premium payable
4,051

 
4,702

Asset retirement obligation
5,873

 
5,475

Total long-term liabilities
422,085

 
370,480

Commitments and contingencies (Note 11)

 

STOCKHOLDERS’ EQUITY:
 
 
 
Preferred stock, 40,000,000 shares authorized
 
 
 
Series A Preferred stock, par value $0.01 per share; 10,000,000 shares designated; 4,045,000 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share
41

 
41

Series B Preferred stock, par value $0.01 per share; 10,000,000 shares designated; 2,140,000 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share
21

 
21

Common stock, par value $0.001 per share; 275,000,000 shares authorized; 80,144,934 and 78,632,810 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively
78

 
78

Additional paid-in capital
569,788

 
568,440

Accumulated deficit
(339,312
)
 
(218,294
)
Total stockholders’ equity
230,616

 
350,286

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
693,726

 
$
775,794


5

Table of Contents

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

Table of Contents

GASTAR EXPLORATION INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except share and per share data)
REVENUES:
 
 
 
 
 
 
 
Oil and condensate
$
17,584

 
$
22,342

 
$
32,937

 
$
39,120

Natural gas
3,950

 
17,559

 
10,650

 
32,978

NGLs
2,184

 
4,906

 
4,280

 
11,550

Total oil, condensate, natural gas and NGLs revenues
23,718

 
44,807

 
47,867

 
83,648

(Loss) gain on commodity derivatives contracts
(1,790
)
 
(8,910
)
 
8,433

 
(15,424
)
Total revenues
21,928

 
35,897

 
56,300

 
68,224

EXPENSES:
 
 
 
 
 
 
 
Production taxes
822

 
2,037

 
1,662

 
3,931

Lease operating expenses
7,242

 
4,877

 
13,261

 
8,921

Transportation, treating and gathering
542

 
2,146

 
1,039

 
2,771

Depreciation, depletion and amortization
16,080

 
10,280

 
30,551

 
22,662

Impairment of oil and natural gas properties
100,152

 

 
100,152

 

Accretion of asset retirement obligation
131

 
125

 
256

 
247

General and administrative expense
4,421

 
3,893

 
8,669

 
8,656

Total expenses
129,390

 
23,358

 
155,590

 
47,188

(LOSS) INCOME FROM OPERATIONS
(107,462
)
 
12,539

 
(99,290
)
 
21,036

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense
(6,936
)
 
(6,912
)
 
(14,497
)
 
(13,803
)
Investment income and other
3

 
4

 
6

 
11

Foreign transaction loss

 
(4
)
 

 
(6
)
(LOSS) INCOME BEFORE PROVISION FOR INCOME TAXES
(114,395
)
 
5,627

 
(113,781
)
 
7,238

Provision for income taxes

 

 

 

NET (LOSS) INCOME
(114,395
)
 
5,627

 
(113,781
)
 
7,238

Dividends on preferred stock
(3,619
)
 
(3,611
)
 
(7,237
)
 
(7,187
)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(118,014
)
 
$
2,016

 
$
(121,018
)
 
$
51

NET (LOSS) INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
 
 
 
 
 
 
 
Basic
$
(1.52
)
 
$
0.03

 
$
(1.56
)
 
$

Diluted
$
(1.52
)
 
$
0.03

 
$
(1.56
)
 
$

WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
 
 
 
 
 
 
 
Basic
77,611,167

 
58,702,982

 
77,364,368

 
58,462,124

Diluted
77,611,167

 
61,922,874

 
77,364,368

 
61,674,267

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

Table of Contents

GASTAR EXPLORATION INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 
For the Six Months Ended June 30,
 
2015
 
2014
 
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net (loss) income
$
(113,781
)
 
$
7,238

Adjustments to reconcile net (loss) income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
30,551

 
22,662

Impairment of oil and natural gas properties
100,152

 

Stock-based compensation
2,773

 
2,532

Mark to market of commodity derivatives contracts:
 
 
 
Total (gain) loss on commodity derivatives contracts
(8,433
)
 
15,424

Cash settlements of matured commodity derivatives contracts, net
11,408

 
(6,061
)
Cash premiums paid for commodity derivatives contracts
(45
)
 
(155
)
Amortization of deferred financing costs
1,736

 
1,491

Accretion of asset retirement obligation
256

 
247

Settlement of asset retirement obligation
(80
)
 
(546
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
15,887

 
(2,827
)
Prepaid expenses
1,397

 
112

Accounts payable and accrued liabilities
(4,806
)
 
9,649

Net cash provided by operating activities
37,015

 
49,766

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Development and purchase of oil and natural gas properties
(84,724
)
 
(55,295
)
Advances to operators
(1,225
)
 
(20,657
)
Acquisition of oil and natural gas properties - refund

 
4,209

Proceeds from sale of oil and natural gas properties
2,008

 
3,077

Deposit for sale of oil and natural gas properties
6,620

 

(Payments to) proceeds from non-operators
(1,820
)
 
526

Purchase of furniture and equipment
(45
)
 
(158
)
Net cash used in investing activities
(79,186
)
 
(68,298
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds from revolving credit facility
55,000

 
35,000

Repayment of revolving credit facility
(5,000
)
 
(15,000
)
Proceeds from issuance of preferred stock, net of issuance costs

 
2,064

Dividends on preferred stock
(7,237
)
 
(7,187
)
Deferred financing charges
(797
)
 
(319
)
Tax withholding related to restricted stock and performance based unit award vestings
(1,425
)
 
(3,656
)
Net cash provided by financing activities
40,541

 
10,902

NET DECREASE IN CASH AND CASH EQUIVALENTS
(1,630
)
 
(7,630
)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
11,008

 
32,393

CASH AND CASH EQUIVALENTS, END OF PERIOD
$
9,378

 
$
24,763


The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8

Table of Contents

GASTAR EXPLORATION INC.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.
Description of Business
Gastar Exploration Inc. (the “Company” or “Gastar,” and before January 31, 2014, “Gastar USA”) is an independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs in the U.S. Gastar’s 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, Gastar is developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and expects to test other prospective formations on the same acreage, including the Meramec Shale (middle Mississippi Lime) and the Woodford Shale, which Gastar refers to as the STACK Play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus Shale and has drilled and completed its first two successful dry gas Utica Shale/Point Pleasant wells on its acreage.
All references to “Gastar,” the “Company” and similar terms refer collectively to Gastar Exploration Inc. Unless otherwise stated or the context requires otherwise, all references in these notes to “Gastar USA” refer collectively to Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) and its wholly-owned subsidiaries and all references to “Parent” refer solely to Gastar Exploration, Inc. (formerly known as Gastar Exploration Ltd.).

2.
Summary of Significant Accounting Policies
The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2014 (the “ 2014 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2014 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material item included in those notes has changed except as a result of normal transactions in the interim or as disclosed within this report.
The unaudited interim condensed consolidated financial statements of the Company included herein are stated in U.S. dollars and were prepared from the records of the Company by management in accordance with U.S. GAAP applicable to interim financial statements and reflect all normal and recurring adjustments, which are, in the opinion of management, necessary to provide a fair presentation of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the 2014 Form 10-K. The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies,” included in the 2014 Form 10-K.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows.
The unaudited interim condensed consolidated financial statements of the Company include the consolidated accounts of all of its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Certain reclassifications of prior year balances have been made to conform to the current year presentation; these reclassifications have no impact on net income (loss).
The results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 . In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these condensed consolidated financial statements, as appropriate.
Recent Accounting Developments
The following recently issued accounting pronouncement may impact the Company in future periods:
Debt Issuance Costs. In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.

9


Going Concern. In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continu e as a going concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the ability to continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions or events leading to substantial doubt. The updated guidance is effective for annual reporting periods and interim periods within those annual periods beginning after December 15, 2016. Earlier adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.
Revenue Recognition. In May 2014, the FASB issued an amendment to previously issued guidance regarding the recognition of revenue. The FASB and the International Accounting Standards Board initiated a joint project to clarify the principles for recognizing revenue and to develop a common standard that would (i) remove inconsistencies and weaknesses in revenue requirements, (ii) provide a more robust framework for addressing revenue issues, (iii) improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets, (iv) provide more useful information to users of financial statements through improved disclosure requirements and (v) simplify the preparation of financial statements by reducing the number of requirements to which an entity must refer. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This guidance supersedes prior revenue recognition requirements and most industry-specific guidance throughout the FASB Accounting Standards Codification. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018. The proposal will be subject to the FASB's due process requirement, which includes a period for public comments. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows and does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flows.

3.
Property, Plant and Equipment
The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., located in the states of Oklahoma, Pennsylvania and West Virginia.
The following table summarizes the components of unproved properties excluded from amortization at the dates indicated:
 
June 30, 2015
 
December 31, 2014
 
(in thousands)
Unproved properties, excluded from amortization:
 
 
 
Drilling in progress costs
$
14,895

 
$
29,193

Acreage acquisition costs
98,278

 
91,362

Capitalized interest
9,989

 
7,719

Total unproved properties excluded from amortization
$
123,162

 
$
128,274



The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value (discounted at 10% per annum) of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that the Company's capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling at the end of the reported period, the excess must be written off to expense for such period. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation is determined using a mandatory trailing 12-month unweighted arithmetic average of the first-day-of-the-month commodities pricing and costs in effect at the end of the period, each of which are held constant indefinitely (absent specific contracts with respect to future prices and costs) with respect to valuing future net cash flows from proved reserves for this purpose. The 12-month unweighted arithmetic average of the first-day-of-the-month commodities prices are adjusted for basis and quality differentials in determining the present value of the proved reserves. The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials:

10


 
2015
 
Total Impairment
 
June 30
 
March 31
Henry Hub natural gas price (per MMBtu) (1)
 
 
$
3.39

 
$
3.88

West Texas Intermediate oil price (per Bbl) (1)
 
 
$
71.68

 
$
82.72

Impairment recorded (pre-tax) (in thousands)
$
100,152

 
$
100,152

 
$


 
2014
 
Total Impairment
 
June 30
 
March 31
Henry Hub natural gas price (per MMBtu) (1)
 
 
$
4.10

 
$
3.99

West Texas Intermediate oil price (per Bbl) (1)
 
 
$
100.11

 
$
98.30

Impairment recorded (pre-tax) (in thousands)
$

 
$

 
$

 _________________________________
(1)
For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub spot natural gas prices and West Texas Intermediate spot oil prices.
Future declines in the trailing 12-month average of oil, condensate, natural gas and NGLs prices will likely result in the recognition of significant additional ceiling impairments in 2015.
Mid-Continent Divestiture
On July 6, 2015 , the Company sold to an undisclosed private third party 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 approximately $46.1 million , reflecting an effective date of April 1, 2015 and customary closing adjustments. Of the total purchase price, $6.6 million was deposited during the second quarter of 2015 and accounted for in other liabilities at June 30, 2015. The sale will be reflected as a reduction to the full cost pool and the Company will not record a gain or loss related to the divestiture as it is not significant to the full cost pool.
Atinum Joint Venture
In September 2010, the Company entered into a joint venture (the “Atinum Joint Venture”) pursuant to which the Company ultimately assigned to an affiliate of Atinum Partners Co., Ltd. (“Atinum”), for total consideration of $70.0 million , a 50% working interest in certain undeveloped acreage and wells. Effective June 30, 2011 , an area of mutual interest (“AMI”) was established for additional acreage acquisitions in Ohio, New York, Pennsylvania and West Virginia, excluding the counties of Pendleton, Pocahontas, Preston, Randolph and Tucker, West Virginia. Within this AMI, the Company acts as operator and is obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum will pay the Company 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 Joint Venture pursued an initial three -year development program that called for the partners to drill a minimum of 60 operated horizontal wells by year-end 2013. Due to natural gas price declines, Atinum and the Company agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 gross wells to 51 gross wells. At June 30, 2015 , 74 gross operated horizontal Marcellus Shale wells and two gross operated horizontal Utica Shale/Point Pleasant well were capable of production under the Atinum Joint Venture. The Atinum Joint Venture Agreement expires on November 1, 2015.
    
4.
Long-Term Debt
Second Amended and Restated Revolving Credit Facility
On June 7, 2013 , the Company entered into the Second Amended and Restated Credit Agreement among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). At the Company's election, borrowings bear interest at the reference rate or the Eurodollar rate plus an applicable margin. The reference rate is the greater of (i) the rate of interest publicly announced by the administrative agent, (ii) the federal funds rate plus 50 basis points and (iii) LIBOR plus 1.0% . The applicable interest rate margin varies from 1.0% to 2.0% in the case of borrowings based on the reference rate and from 2.0% to 3.0% in the case of borrowings based on the Eurodollar rate, depending on the utilization percentage in relation to the

11


borrowing base and subject to adjustments based on the Company's leverage ratio. An annual commitment fee of 0.5% is payable quarterly on the unutilized balance of the borrowing base. The Revolving Credit Facility has a scheduled maturity of November 14, 2017 .
The Revolving Credit Facility will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees are secured by a first priority lien on certain domestic oil and natural gas properties currently owned by or later acquired by the Company and its subsidiaries, excluding de minimis value properties as determined by the lender. The Revolving Credit Facility is secured by a first priority pledge of the capital stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the issuer and 65% of the stock of any foreign subsidiary of the Company.
The Revolving Credit Facility contains various covenants, including, among others:
Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments;
Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than 1.0 to 1.0 , as adjusted;
Maintenance of a maximum ratio of net indebtedness to EBITDA of not greater than 4.0 to 1.0 , subject to the modifications in Amendment No. 5 set forth below; and
Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than 2.5 to 1.0 , subject to the modifications in Amendment No. 5 set forth below.
All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including, among others:
Failure to make payments;
Non-performance of covenants and obligations continuing beyond any applicable grace period; and
The occurrence of a change in control of the Company, as defined under the Revolving Credit Facility.
On March 9, 2015 , the Company, together with the parties thereto, entered into a Master Assignment, Agreement and Amendment No. 5 (“Amendment No. 5”) to Second Amended and Restated Credit Agreement. Amendment No. 5 amended the Revolving Credit Facility to, among other things, (i) increase the borrowing base from $145.0 million to $200.0 million , (ii) adjust the total leverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to September 30, 2016 , to 5.25 to 1.00 ; for the fiscal quarter ending on September 30, 2016 , to 5.00 to 1.00 ; for the fiscal quarter ending on December 31, 2016 , to 4.75 to 1.00 ; for the fiscal quarter ending on March 31, 2017 , to 4.25 to 1.00 ; and for each fiscal quarter ending on or after June 30, 2017 , to 4.00 to 1.00 , (iii) adjust the interest coverage ratio for each fiscal quarter ending on or after March 31, 2015 but prior to March 31, 2016 , to 2.00 to 1.00 and for each fiscal quarter ending on or after March 31, 2016 , to 2.50 to 1.00 , and (iv) add the senior secured leverage ratio covenant, such ratio not to exceed, (a) for each fiscal quarter ending on or after March 31, 2015 but prior to June 30, 2016 , 2.25 to 1.00 and (b) for each fiscal quarter ending on or after June 30, 2016 , 2.00 to 1.00 provided that this senior secured leverage ratio shall cease to apply commencing with the first fiscal quarter end occurring after June 30, 2016 for which the total leverage ratio is equal to or less than 4.00 to 1.00 .
Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year. The Company and its lender group may each request one additional unscheduled redetermination during any six-month period between scheduled redeterminations. At June 30, 2015 , the Revolving Credit Facility had a borrowing base of $200.0 million , with $95.0 million borrowings outstanding and availability of $105.0 million . The next regularly scheduled redetermination is set for November 2015. Future increases in the borrowing base in excess of the original $50.0 million are limited to 17.5% of the increase in adjusted consolidated net tangible assets as defined in the indenture pursuant to which the Company's senior secured notes are issued (as discussed below in “Senior Secured Notes”).
At June 30, 2015 , the Company was in compliance with all financial covenants under the Revolving Credit Facility.
Senior Secured Notes
The Company has $325.0 million aggregate principal amount of 8 5/8 % Senior Secured Notes due May 15, 2018 (the “Notes”) outstanding under an indenture (the “Indenture”) by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent (in such capacity, the “Collateral Agent”). The Notes bear interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year. The Notes mature on May 15, 2018 .

12


In the event of a change of control, as defined in the Indenture, each holder of the Notes will have the right to require the Company to repurchase all or any part of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase.
The Notes will be guaranteed, jointly and severally, on a senior secured basis by certain future domestic subsidiaries (the “Guarantees”). The Notes and Guarantees will rank senior in right of payment to all of the Company's and the Guarantors' future subordinated indebtedness and equal in right of payment to all of the Company's and the Guarantors' existing and future senior indebtedness. The Notes and Guarantees also will be effectively senior to the Company's unsecured indebtedness and effectively subordinated to the Company's and Guarantors' under the Revolving Credit Facility, any other indebtedness secured by a first-priority lien on the same collateral and any other indebtedness secured by assets other than the collateral, in each case to the extent of the value of the assets securing such obligation.
The Indenture contains covenants that, among other things, limit the Company's ability and the ability of its subsidiaries to:
Transfer or sell assets or use asset sale proceeds;
Pay dividends or make distributions, redeem subordinated debt or make other restricted payments;
Make certain investments; incur or guarantee additional debt or issue preferred equity securities;
Create or incur certain liens on the Company's assets;
Incur dividend or other payment restrictions affecting future restricted subsidiaries;
Merge, consolidate or transfer all or substantially all of the Company's assets;
Enter into certain transactions with affiliates; and
Enter into certain sale and leaseback transactions.
These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture.
At June 30, 2015 , the Notes reflected a balance of $316.5 million , net of unamortized discounts of $8.5 million , on the condensed consolidated balance sheets.

5.
Fair Value Measurements
The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties or estimated market data based on area transactions, which are Level 3 inputs. For the three and six months ended June 30, 2015 , management's evaluation of unproved properties resulted in an impairment. Due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, the Company reclassified $26,000 and $60,000 , respectively, of unproved properties to proved properties for the three and six months ended June 30, 2015 related to acreage in Marcellus East. For the three and six months ended June 30, 2014 , management's evaluation of unproved properties resulted in an impairment of $234,000 and $428,000 , respectively, related to Marcellus East. As no other fair value measurements are required to be recognized on a non-recurring basis at June 30, 2015 , no additional disclosures are provided at June 30, 2015 .
As defined in the guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows:

13


Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds.
Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.
Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.
As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets.
Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods.

14


The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2015 and December 31, 2014 :
 
Fair value as of June 30, 2015
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
9,378

 
$

 
$

 
$
9,378

Commodity derivative contracts

 

 
23,155

 
23,155

Liabilities:
 
 
 
 
 
 
 
Commodity derivative contracts

 

 
(782
)
 
(782
)
Total
$
9,378

 
$

 
$
22,373

 
$
31,751

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value as of December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
11,008

 
$

 
$

 
$
11,008

Commodity derivative contracts

 

 
27,502

 
27,502

Liabilities:
 
 
 
 
 
 
 
Commodity derivative contracts

 

 

 

Total
$
11,008

 
$

 
$
27,502

 
$
38,510


The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2015 and 2014 . Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at June 30, 2015 and 2014 .
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Balance at beginning of period
$
31,823

 
$
620

 
$
27,502

 
$
3,764

Total (losses) gains included in earnings
(1,790
)
 
(8,910
)
 
8,433

 
(15,424
)
Purchases
45

 
268

 
911

 
339

Issuances
(1,127
)
 

 
(1,313
)
 

Settlements (1)
(6,578
)
 
3,394

 
(13,160
)
 
6,693

Balance at end of period
$
22,373

 
$
(4,628
)
 
$
22,373

 
$
(4,628
)
The amount of total losses for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at June 30, 2015 and 2014
$
(7,777
)
 
$
(5,418
)
 
$
(3,525
)
 
$
(8,573
)
 _________________________________
(1)
Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.
At June 30, 2015 , the estimated fair value of accounts receivable, prepaid expenses, accounts and revenue payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s long-term debt at June 30, 2015 was $399.8 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximates the current market rate (Level 2).
The Company has consistently applied the valuation techniques discussed above in all periods presented.
The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 6, “Derivative Instruments and Hedging Activity.”


15


6.
Derivative Instruments and Hedging Activity
The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk.
All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the condensed consolidated statements of operations in (loss) gain on commodity derivatives contracts. For the three months ended June 30, 2015 and 2014 , the Company reported losses of $7.8 million and $5.4 million , respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts still held at June 30, 2015 and 2014 . For the six months ended June 30, 2015 and 2014 , the Company reported losses of $3.5 million and $8.6 million , respectively, in the condensed consolidated statements of operations related to the change in the fair value of its commodity derivative contracts still held at June 30, 2015 and 2014 .

As of June 30, 2015 , the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
Settlement Period
 
Derivative Instrument
 
Average
Daily
Volume (1)
 
Total of
Notional
Volume
 
Floor
(Long)
 
Short
Put
 
Ceiling
(Short)
 
 
 
 
(in Bbls)
 
 
 
 
 
 
2015
 
Costless three-way collar
 
400

 
73,600

 
$
85.00

 
$
70.00

 
$
96.50

2015
 
Costless three-way collar
 
325

 
59,800

 
$
85.00

 
$
65.00

 
$
97.80

2015
 
Costless three-way collar
 
50

 
9,200

 
$
85.00

 
$
65.00

 
$
96.25

2015
 
Costless collar
 
750

 
130,000

 
$
52.50

 
$

 
$
62.05

2015
 
Costless collar
 
300

 
55,200

 
$
52.50

 
$

 
$
68.10

2015
 
Fixed price swap
 
600

 
110,400

 
$
72.54

 
$

 
$

2015
 
Fixed price swap
 
250

 
46,000

 
$
74.20

 
$

 
$

2016
 
Costless three-way collar
 
275

 
100,600

 
$
85.00

 
$
65.00

 
$
95.10

2016
 
Costless three-way collar
 
330

 
120,780

 
$
80.00

 
$
65.00

 
$
97.35

2016
 
Costless three-way collar
 
450

 
164,700

 
$
57.50

 
$
42.50

 
$
80.00

2016
 
Put spread
 
550

 
201,300

 
$
85.00

 
$
65.00

 
$

2016
 
Put spread
 
300

 
109,800

 
$
85.50

 
$
65.50

 
$

2017
 
Costless three-way collar
 
280

 
102,200

 
$
80.00

 
$
65.00

 
$
97.25

2017
 
Costless three-way collar
 
242

 
88,150

 
$
80.00

 
$
60.00

 
$
98.70

2017
 
Costless three-way collar
 
200

 
73,000

 
$
60.00

 
$
42.50

 
$
85.00

2017
 
Put spread
 
500

 
182,500

 
$
82.00

 
$
62.00

 
$

2017
 
Costless three-way collar
 
200

 
73,000

 
$
57.50

 
$
42.50

 
$
76.13

2018 (2)
 
Put spread
 
425

 
103,275

 
$
80.00

 
$
60.00

 
$

 _______________________________
(1)
Crude volumes hedged include oil, condensate and certain components of our NGLs production.
(2)
For the period January to August 2018.
As of June 30, 2015 , the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
 

16


Settlement Period
 
Derivative Instrument
 
Average
Daily
Volume
 
Total of
Notional
Volume
 
Base
Fixed
Price
 
Floor
(Long)
 
Short
Put
 
Call
(Long)
 
Ceiling
(Short)
 
 
 
 
(in MMBtus)
 
 
 
 
 
 
 
 
 
 
2015
 
Fixed price swap
 
400

 
73,600

 
$
4.00

 
$

 
$

 
$

 
$

2015
 
Fixed price swap
 
2,500

 
460,000

 
$
4.06

 
$

 
$

 
$

 
$

2015
 
Protective spread
 
2,600

 
478,400

 
$
4.00

 
$

 
$
3.25

 
$

 
$

2015
 
Fixed price swap
 
5,000

 
920,000

 
$
3.49

 
$

 
$

 
$

 
$

2015
 
Fixed price swap
 
2,000

 
368,000

 
$
3.53

 
$

 
$
3.25

 
$

 
$

2015
 
Producer three-way collar
 
2,500

 
460,000

 
$

 
$
3.70

 
$
3.00

 
$

 
$
4.09

2015
 
Producer three-way collar
 
5,000

 
920,000

 
$

 
$
3.77

 
$
3.00

 
$

 
$
4.11

2015 (1)
 
Producer three-way collar
 
2,000

 
246,000

 
$

 
$
3.00

 
$
2.25

 
$

 
$
3.34

2015 (1)
 
Fixed price swap
 
10,000

 
1,230,000

 
$
2.94

 
$

 
$

 
$

 
$

2015 (2)
 
Producer three-way collar
 
2,500

 
152,500

 
$

 
$
3.00

 
$
2.25

 
$

 
$
3.65

2015
 
Basis swap(3)
 
2,500

 
460,000

 
$
(1.12
)
 
$

 
$

 
$

 
$

2015
 
Basis swap(3)
 
2,500

 
460,000

 
$
(1.11
)
 
$

 
$

 
$

 
$

2015
 
Basis swap(3)
 
2,500

 
460,000

 
$
(1.14
)
 
$

 
$

 
$

 
$

2016 (4)
 
Producer three-way collar
 
2,500

 
762,500

 
$

 
$
3.00

 
$
2.25

 
$

 
$
3.65

2016
 
Protective spread
 
2,000

 
732,000

 
$
4.11

 
$

 
$
3.25

 
$

 
$

2016
 
Producer three-way collar
 
2,000

 
732,000

 
$

 
$
4.00

 
$
3.25

 
$

 
$
4.58

2016
 
Producer three-way collar
 
5,000

 
1,830,000

 
$

 
$
3.40

 
$
2.65

 
$

 
$
4.10

2016
 
Basis swap(5)
 
2,500

 
915,000

 
$
(1.10
)
 
$

 
$

 
$

 
$

2017
 
Short call
 
10,000

 
3,650,000

 
$

 
$

 
$

 
$

 
$
4.75

 _______________________________
(1)
For the period July to October 2015.
(2)
For the period November to December 2015.
(3)
Represents basis swaps at the sales point of Dominion South.
(4)
For the period January to October 2016.
(5)
Represents basis swaps at the sales point of TetcoM2.

As of June 30, 2015 , the following NGLs derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:
Settlement Period
 
Derivative Instrument
 
Average
Daily
Volume
 
Total of
Notional
Volume
 
Base
Fixed
Price
 
 
 
 
(in Bbls)
 
 
2015
 
Fixed price swap
 
250
 
46,000

 
$
45.61

2015
 
Fixed price swap
 
500
 
92,000

 
$
20.79

2016
 
Fixed price swap
 
500
 
183,000

 
$
20.79

As of June 30, 2015 , all of the Company’s economic derivative hedge positions were with a multinational energy company or large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features.
In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period July 2015 through August 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. The following table provides information regarding the deferred put premium liabilities for the periods indicated:

17


 
June 30, 2015
 
December 31, 2014
 
(in thousands)
Current commodity derivative put premium payable
$
1,515

 
$
2,481

Long-term commodity derivative put premium payable
4,051

 
4,702

Total unamortized put premium liabilities
$
5,566

 
$
7,183

 
For the Three Months Ended June 30, 2015
 
For the Six Months Ended June 30, 2015
 
(in thousands)
Put premium liabilities, beginning balance
$
7,281

 
$
7,183

Amortization of put premium liabilities
(1,715
)
 
(2,297
)
Additional put premium liabilities

 
680

Put premium liabilities, ending balance
$
5,566

 
$
5,566

The following table provides information regarding the amortization of the deferred put premium liabilities by year as of June 30, 2015 :
 
Amortization
 
(in thousands)
January to December 2016
$
3,050

January to December 2017
1,684

January to August 2018
832

Total unamortized put premium liabilities
$
5,566


Additional Disclosures about Derivative Instruments and Hedging Activities
The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated statement of financial position and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:
 
 
Fair Values of Derivative Instruments
Derivative Assets (Liabilities)
 
 
 
Fair Value
 
Balance Sheet Location
 
June 30, 2015
 
December 31, 2014
 
 
 
(in thousands)
Derivatives not designated as hedging instruments
 
 
 
 
 
Commodity derivative contracts
Current assets
 
$
13,159

 
$
19,687

Commodity derivative contracts
Other assets
 
9,996

 
7,815

Commodity derivative contracts
Current liabilities
 
(166
)
 

Commodity derivative contracts
Long-term liabilities
 
(616
)
 

Total derivatives not designated as hedging instruments
 
 
$
22,373

 
$
27,502


18


 
 
 
Amount of Gain (Loss)
Recognized in Income on
Derivatives For the Three
Months Ended June 30,
 
Location of Gain (Loss) Recognized in Income on Derivatives
 
2015
 
2014
 
 
 
(in thousands)
Derivatives not designated as hedging instruments
 
 
 
 
 
Commodity derivative contracts
Loss on commodity derivatives contracts
 
$
(1,790
)
 
$
(8,910
)
Total
 
 
$
(1,790
)
 
$
(8,910
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of Loss
Recognized in Income on
Derivatives For the Six Months Ended June 30,
 
Location of (Gain) Loss Recognized in Income on Derivatives
 
2015
 
2014
 
 
 
(in thousands)
Derivatives not designated as hedging instruments
 
 
 
 
 
Commodity derivative contracts
Gain (loss) on commodity derivatives contracts
 
$
8,433

 
$
(15,424
)
Total
 
 
$
8,433

 
$
(15,424
)
 
 
 
 
 
 



7.
Capital Stock
Common Stock
On May 7, 2015 , the Company entered into an at-the-market issuance sales agreement with MLV & Co. LLC (the “Sales Agent”) to sell, from time to time through the Sales Agent, shares of the Company's common stock (the “ATM Program”). The shares will be issued pursuant to the Company's existing effective shelf registration statement on Form S-3, as amended (Registration No. 333-193832). The Company registered shares having an aggregate offering price of up to $50.0 million . During the three months ended June 30, 2015, no shares were sold through the ATM program.
Preferred Stock
The Company currently has 40,000,000 shares of preferred stock authorized for issuance under its certificate of incorporation. The Company has designated 10,000,000 shares to constitute its 8.625% Series A Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 shares to constitute its 10.75% Series B Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a par value of $0.01 per share and a liquidation preference of $25.00 per share.
Series A Preferred Stock
At June 30, 2015 , there were 4,045,000 shares of the Series A Preferred Stock issued and outstanding with a $25.00 per share liquidation preference.
The Series A Preferred Stock ranks senior to the Company's common stock and on parity with the Series B Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series A Preferred Stock is subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock.
The Series A Preferred Stock cannot be converted into common stock, but may be redeemed, at the Company’s option for $25.00 per share plus any accrued and unpaid dividends.
There is no mandatory redemption of the Series A Preferred Stock.
The Company pays cumulative dividends on the Series A Preferred Stock at a fixed rate of 8.625%  per annum of the $25.00 per share liquidation preference. For the three and six months ended June 30, 2015 , the Company recognized dividend expense of $2.2 million and $4.4 million , respectively, for the Series A Preferred Stock.

19


Series B Preferred Stock
At June 30, 2015 , there were 2,140,000 shares of the Series B Preferred Stock issued and outstanding with a $25.00 per share liquidation preference.
The Series B Preferred Stock ranks senior to the Company’s common stock and on parity with the Series A Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock.
Except upon a change in ownership or control, as defined in the Series B Preferred Stock certificate of designations of rights and preferences, the Series B Preferred Stock may not be redeemed before November 15, 2018 , at or after which time it may be redeemed at the Company’s option for $25.00 per share in cash. Following a change in ownership or control, the Company will have the option to redeem the Series B Preferred Stock within 90 days of the occurrence of the change in control, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If the Company does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into the Company's common stock based upon on an average common stock trading price then in effect but limited to an aggregate of 11.5207 shares of the Company’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If the Company exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption.
There is no mandatory redemption of the Series B Preferred Stock.
The Company pays cumulative dividends on the Series B Preferred Stock at a fixed rate of 10.75%  per annum of the $25.00 per share liquidation preference. For the three and six months ended June 30, 2015 , the Company recognized dividend expense of $1.4 million and $2.9 million , respectively, for the Series B Preferred Stock.
Other Share Issuances
The following table provides information regarding the issuances and forfeitures of common stock pursuant to the Company's long-term incentive plan for the periods indicated:  
 
For the Three Months Ended June 30, 2015
 
For the Six Months Ended June 30, 2015
Other share issuances:
 
 
 
Shares of restricted common stock granted

 
1,421,224

Shares of restricted common stock vested

 
1,274,872

Shares of common stock issued pursuant to PBUs vested, net of forfeitures

 
497,636

Shares of restricted common stock surrendered upon vesting/exercise (1)

 
382,238

Shares of restricted common stock forfeited
841

 
24,498

 __________________
(1)
Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.

On June 12, 2014 , the Company's stockholders approved an amendment and restatement to the Gastar Exploration Inc. Long-Term Incentive Plan (the “LTIP”), effective April 24, 2014 , to, among other things, increase the number of shares of common stock reserved for issuance under the LTIP by 3,000,000 shares of common stock. There were 2,850,275 shares of common stock available for issuance under the LTIP at June 30, 2015 .
Shares Reserved
At June 30, 2015 , the Company had 866,600 common shares reserved for the exercise of stock options.


20


8.
Interest Expense
The following table summarizes the components of interest expense for the periods indicated:
 
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Interest expense:
 
 
 
 
 
 
 
Cash and accrued
$
7,241

 
$
7,208

 
$
15,169

 
$
14,342

Amortization of deferred financing costs (1)
915

 
758

 
1,736

 
1,491

Capitalized interest
(1,220
)
 
(1,054
)
 
(2,408
)
 
(2,030
)
Total interest expense
$
6,936

 
$
6,912

 
$
14,497

 
$
13,803

 _________________________________
(1)
The three months ended June 30, 2015 and 2014 includes $629,000 and $570,000 , respectively, of debt discount accretion related to the Notes. The six months ended June 30, 2015 and 2014 includes $1.2 million and $1.1 million , respectively, of debt discount accretion related to the Notes.

9.
Income Taxes
For the three and six months ended June 30, 2015 and 2014 , respectively, the Company did not recognize a current income tax benefit or provision as the Company has a full valuation allowance against assets created by net operating losses generated. The Company believes it more likely than not that the assets will not be utilized.

10.
Earnings per Share
In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per share and share data)
Net (loss) income attributable to common stockholders
$
(118,014
)
 
$
2,016

 
$
(121,018
)
 
$
51

 
 
 
 
 
 
 
 
Weighted average common shares outstanding - basic
77,611,167

 
58,702,982

 
77,364,368

 
58,462,124

Incremental shares from unvested restricted shares

 
2,514,542

 

 
2,563,673

Incremental shares from outstanding stock options

 
112,232

 

 
106,499

Incremental shares from outstanding PBUs

 
593,118

 

 
541,971

Weighted average common shares outstanding - diluted
77,611,167

 
61,922,874

 
77,364,368

 
61,674,267

 
 
 
 
 
 
 
 
Net (loss) income per share of common stock attributable to common stockholders:
 
 
 
 
 
 
 
Basic
$
(1.52
)
 
$
0.03

 
$
(1.56
)
 
$

Diluted
$
(1.52
)
 
$
0.03

 
$
(1.56
)
 
$

Common shares excluded from denominator as anti-dilutive:
 
 
 
 
 
 
 
Unvested restricted shares
8,970

 

 
93,733

 

Stock options

 

 

 

Unvested PBUs
44,213

 

 
94,488

 

Total
53,183

 

 
188,221

 



21


11.
Commitments and Contingencies
Litigation
Gastar Exploration Ltd vs. U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No.2010-11236) District Court of Harris County, Texas 190th Judicial District . On February 19, 2010 , the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million . The combined coverage limits under the directors and officers liability coverage is $20.0 million . The District Court granted the underwriters' summary judgment request by a ruling dated January 4, 2012 . The Company appealed the District Court ruling and on July 15, 2013 , the Fourteenth Court of Appeals of Texas reversed the summary judgment ruling granted against the Company on the basis of the policies' prior-and-pending litigation endorsement and remanded the case for further proceedings in the District Court. The insurers filed a motion for reconsideration in the Fourteenth Court of Appeals, which that court denied. The insurers then sought discretionary review from the Texas Supreme Court, which that court denied on February 27, 2015. The insurers then filed in the Texas Supreme Court a motion for rehearing of their denied petition for review, which the court has denied. The case has now been remanded to the District Court. The District Court proceedings will include, but not be limited to, a determination of the portion of the Company's settlement of the ClassicStar Mare Lease Litigation that is covered by the insuring agreements. On July 28, 2015, the parties submitted briefs in support of their respective positions regarding the issues left to be resolved in the case and the requisite amount of time for such proceedings. The parties are currently scheduled for a hearing with the court on August 10, 2015, at which time it is anticipated the court will enter a docket control order establishing a time frame for the remainder of the issues to be litigated.
Husky Ventures, Inc. vs. J. Russell Porter, Michael A. Gerlich, Michael McCown, Keith R. Blair, Henry J. Hansen and John M. Selser Sr. (Case No. CIV-15-637-R) United States District Court for the Western District of Oklahoma. On June 9, 2015, Husky Ventures, Inc. filed this action against five of the Company’s senior officers and our non-executive chairman of the board alleging that each of the defendants committed fraud by grossly understating the costs of certain oil and gas interests the Company acquired that were outside a Mid-Continent AMI between Husky and the Company while inflating the costs of interests simultaneously acquired within the AMI.  Husky alleges this resulted in the defendants improperly shifting a disproportionate amount of acquisition costs away from the Company and to Husky.  Husky seeks to recover actual damages alleged to be in excess of $2.0 million , as well as punitive damages and attorneys’ fees. This case is currently stayed until the earlier of a settlement or a ruling on the Company’s request for a preliminary injunction in another action involving Husky filed in the same court in which the Company intervened and is seeking to replace Husky as operator of several wells within the AMI.  The Company is advancing defense costs to the defendants in this case and, depending upon the outcome, the Company may be obligated to indemnify each of the defendants in this action for any loss or damages incurred by the defendants.
The Company has been expensing legal costs on these proceedings as they are incurred.
The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.


22


12.
Statement of Cash Flows – Supplemental Information
The following is a summary of the supplemental cash paid and non-cash transactions for the periods indicated:
 
For the Six Months Ended June 30,
 
2015
 
2014
 
(in thousands)
Cash paid for interest, net of capitalized amounts
$
12,735

 
$
14,469

 
 
 
 
Non-cash transactions:
 
 
 
Capital expenditures excluded from accounts payable and accrued drilling costs
$
(7,477
)
 
$
655

Capital expenditures included in accounts receivable
$

 
$
4,077

Capital expenditures excluded from prepaid expenses
$

 
$
51

Asset retirement obligation included in oil and natural gas properties
$
227

 
$
45

Application of advances to operators
$
9,904

 
$
19,926

Other
$

 
$
(3
)


23


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This report 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 report 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 report 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 position;
business strategy and budgets;
capital expenditures;
drilling of wells, including the anticipated scheduling and results of such operations;
oil, natural gas and NGLs reserves;
timing and amount of future production of oil, condensate, natural gas and NGLs;
operating costs and other expenses;
cash flow and liquidity;
compliance with covenants under our indenture and credit agreements;
availability of capital;
prospect development; and
property acquisitions and sales.
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. 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 report 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;
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 raise capital to fund capital expenditures or repay or refinance debt upon maturity;
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 joint interest partners 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;

24


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 natural gas or oil 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.
For a more detailed description of the risks and uncertainties that we face and other factors that could affect our financial performance or cause our actual results to differ materially from our projected results please see (i) Part II, Item 1A. “Risk Factors” and elsewhere in this report, (ii) Part I, Item 1A. “Risk Factors” and elsewhere in our 2014 Form 10-K, (iii) our subsequent reports and registration statements filed from time to time with the SEC and (iv) other announcements we make from time to time.
You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. 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 report or to reflect the occurrence of unanticipated events.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 are developing the primarily oil-bearing reservoirs of the Hunton Limestone horizontal oil play and expect to test other prospective formations on the same acreage, including the Meramec Shale (middle Mississippi Lime) and the Woodford Shale , which we refer to as the STACK Play. In West Virginia, we are developing liquids-rich natural gas in the Marcellus Shale and have drilled and completed our first two successful dry gas Utica Shale/Point Pleasant wells on our acreage.
Our current operational activities are conducted in, and our consolidated revenues are generated from, markets exclusively in the U.S. As of June 30, 2015 , our major assets consist of approximately 234,600 gross ( 123,100 net) acres in Oklahoma and approximately 66,700 gross ( 46,700 net) acres in the Marcellus Shale in West Virginia and southwestern Pennsylvania, of which approximately 25,000 gross (10,600 net) acres have Utica Shale/Point Pleasant potential, of which approximately 4,300 gross (1,900 net) acres are pending lease finalization. Subsequent to June 30, 2015 and as a result of the July 6, 2015 sale of

25

Table of Contents

approximately 29,500 gross ( 19,200 net) acres in Kingfisher County, Oklahoma, our Mid-Continent assets consist of approximately 205,100 gross (103,900 net) acres in Oklahoma.
The following discussion addresses material changes in our results of operations for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 and material changes in our financial condition since December 31, 2014 . This discussion should be read in conjunction with our condensed consolidated financial statements and the notes thereto included in Part I, Item 1. “Financial Statements” of this report, as well as our 2014 Form 10-K, which includes important disclosures regarding our critical accounting policies as part of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Oil and Natural Gas Activities
The following provides an overview of our major oil and natural gas projects. While actively pursuing specific exploration and development activities in each of the following areas, there is no assurance that new drilling opportunities will be identified or that any new drilling opportunities will be successful if drilled. We are also concentrating our drilling activities in the Mid-Continent during 2015 in light of the substantial downturn in oil, natural gas and NGLs prices that has occurred since November 2014. The dramatic pricing downturns that we are experiencing may cause us to make further changes in our drilling plans.
Mid-Continent Horizontal Oil Play.
The Hunton Limestone is a limestone formation stretching over approximately 2.7 million acres mainly in Oklahoma, but also in the neighboring states of Texas, New Mexico and Arkansas. Hunton Limestone development has been attractive due to the high quality oil production and the associated production of high BTU content natural gas in the area. At June 30, 2015 , we held leases covering approximately 234,600 gross ( 123,100 net) acres in Major, Garfield, Canadian, Kingfisher, Logan, Blaine and Oklahoma Counties, Oklahoma within the Hunton Limestone horizontal oil play.
On July 6, 2015 , we sold to an undisclosed private third party 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 approximately $46.1 million , of which $6.6 million was deposited during the second quarter of 2015 and accounted for in other liabilities at June 30, 2015. The sale will be reflected as a reduction to the full cost pool and we will not record a gain or loss related to the divestiture as it is not significant to the full cost pool.
In our initial AMI with our Mid-Continent partner, we currently pay 50% of lease acquisition costs for a 50% working interest. We pay 54.25% of the lease acquisition costs in the two additional prospect areas for a 50% working interest. In the initial prospect area, we are currently responsible for paying only the drilling and completion costs associated with our 50% working interest (our approximate net revenue interest is 39.0%). In all subsequent prospect areas, we pay 54.25% of gross drilling and completion costs to earn a 50% working interest. Our AMI partner acts as operator and handles all drilling, completion and production activities, and we handle leasing and permitting activities in certain areas of the AMI. For 2015, our focus is to drill in areas that we believe will result in the most significant proved reserve recognition to capital dollars spent and renew 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 any acreage that is determined to provide less attractive returns, productions and reserve additions or is outside of our drilling focus to reduce net capital expenditures.


26

Table of Contents

As of June 30, 2015 and currently as of the date of this report, we had initial production and drilling operations at various stages on the following wells in our original AMI in the Hunton Limestone formation:
 
 
 
 
 
 
 
 
Cumulative Production Averages (2)
 
 
 
 
Well Name
 
Current Working Interest
 
Approximate Lateral Length (in feet)
 
Peak Production Rates (1)
(Boe/d)
 
Boe/d
 
% Oil
 
Date of First Production or Status
 
Approximate Gross Costs to Drill & Complete ($ millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LB 1-1H
 
47.6%
 
4,400
 
791
 
242
 
65%
 
January 23, 2015
 
$4.4
Hubbard 1-23H (3)
 
57.0%
 
4,600
 
N/A
 
22
 
95%
 
February 19, 2015
 
$6.1
Boss Hogg 1-14H
 
50.0%
 
4,400
 
129
 
61
 
68%
 
February 21, 2015
 
$7.4
Bo 1-23H