Gastar Exploration Inc.
Gastar Exploration Inc. (Form: 10-Q, Received: 05/05/2016 16:38:14)

 

 

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 March 31, 2016

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   x    No   o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

¨

  

Accelerated filer

 

x

 

 

 

 

 

 

 

Non-accelerated filer

 

¨   (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   x

The total number of outstanding common shares, $0.001 par value per share, as of May 2, 2016 was 81,712,298.

 

 


GASTAR EXPLORATION INC.

QUARTERLY REPORT ON FORM 10-Q

For the three months ended March 31, 2016

TABLE OF CONTENTS

 

 

 

 

 

Page

PART I – FINANCIAL INFORMATION

 

 

 

Item 1.

 

Financial Statements

 

 

6

 

 

Gastar Exploration Inc. Condensed Consolidated Balance Sheets as of March 31, 2016 (unaudited) and December 31, 2015

 

 

6

 

 

Gastar Exploration Inc. Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015 (unaudited)

 

 

7

 

 

Gastar Exploration Inc. Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015 (unaudited)

 

 

8

 

 

Notes to the Condensed Consolidated Financial Statements (unaudited)

 

 

9

Item 2.

 

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

 

 

29

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

 

40

Item 4.

 

Controls and Procedures

 

 

40

PART II – OTHER INFORMATION

 

 

 

Item 1.

 

Legal Proceedings

 

 

41

Item 1A.

 

Risk Factors

 

 

41

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

 

44

Item 3.

 

Defaults Upon Senior Securities

 

 

44

Item 4.

 

Mine Safety Disclosure

 

 

44

Item 5.

 

Other Information

 

 

44

Item 6.

 

Exhibits

 

 

44

SIGNATURES

 

 

45

 

 

2


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 commo n 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 and (ii) all dollar amounts appearing in this Form 10-Q are stated in United States dollars (“U.S. dollars”) unless otherwise noted and (iii) 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


Glossary of Terms

 

AMI

 

Area of mutual interest, an agreed designated geographic area where co-participants or other industry participants 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

 

 

 

 

4


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 of America

 

 

 

WTI

 

West Texas Intermediate

 

 

5


PART I. FINANCI AL INFORMATION

 

 

Item 1. Financial Statements

GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

March 31,

 

 

December 31,

 

 

 

2016

 

 

2015

 

 

 

(Unaudited)

 

 

 

 

 

 

 

(in thousands, except share data)

 

ASSETS

 

 

 

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

26,950

 

 

$

50,074

 

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

 

 

11,905

 

 

 

14,302

 

Commodity derivative contracts

 

 

7,767

 

 

 

15,534

 

Prepaid expenses

 

 

4,956

 

 

 

5,056

 

Total current assets

 

 

51,578

 

 

 

84,966

 

PROPERTY, PLANT AND EQUIPMENT:

 

 

 

 

 

 

 

 

Oil and natural gas properties, full cost method of accounting:

 

 

 

 

 

 

 

 

Unproved properties, excluded from amortization

 

 

103,221

 

 

 

92,609

 

Proved properties

 

 

1,292,089

 

 

 

1,286,373

 

Total oil and natural gas properties

 

 

1,395,310

 

 

 

1,378,982

 

Furniture and equipment

 

 

3,072

 

 

 

3,068

 

Total property, plant and equipment

 

 

1,398,382

 

 

 

1,382,050

 

Accumulated depreciation, depletion and amortization

 

 

(1,115,342

)

 

 

(1,053,116

)

Total property, plant and equipment, net

 

 

283,040

 

 

 

328,934

 

OTHER ASSETS:

 

 

 

 

 

 

 

 

Commodity derivative contracts

 

 

8,309

 

 

 

9,335

 

Deferred charges, net

 

 

1,667

 

 

 

985

 

Advances to operators and other assets

 

 

629

 

 

 

331

 

Other

 

 

4,944

 

 

 

4,944

 

Total other assets

 

 

15,549

 

 

 

15,595

 

TOTAL ASSETS

 

$

350,167

 

 

$

429,495

 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

 

 

Accounts payable

 

$

6,942

 

 

$

2,029

 

Revenue payable

 

 

9,812

 

 

 

5,985

 

Accrued interest

 

 

10,660

 

 

 

3,730

 

Accrued drilling and operating costs

 

 

2,102

 

 

 

2,010

 

Advances from non-operators

 

 

147

 

 

 

167

 

Commodity derivative premium payable

 

 

1,723

 

 

 

3,194

 

Asset retirement obligation

 

 

89

 

 

 

89

 

Other accrued liabilities

 

 

6,053

 

 

 

6,764

 

Total current liabilities

 

 

37,528

 

 

 

23,968

 

LONG-TERM LIABILITIES:

 

 

 

 

 

 

 

 

Long-term debt

 

 

496,927

 

 

 

516,476

 

Commodity derivative contracts

 

 

 

 

 

451

 

Commodity derivative premium payable

 

 

2,339

 

 

 

2,788

 

Asset retirement obligation

 

 

6,111

 

 

 

5,997

 

Total long-term liabilities

 

 

505,377

 

 

 

525,712

 

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 March 31, 2016 and December 31, 2015,

   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 March 31, 2016 and December 31, 2015,

   respectively, with liquidation preference of $25.00 per share

 

 

21

 

 

 

21

 

Common stock, par value $0.001 per share; 275,000,000 shares authorized;

   81,837,274 and 80,024,218 shares issued and outstanding at March 31, 2016

   and December 31, 2015, respectively

 

 

82

 

 

 

80

 

Additional paid-in capital

 

 

572,867

 

 

 

571,947

 

Accumulated deficit

 

 

(765,749

)

 

 

(692,274

)

Total stockholders’ equity

 

 

(192,738

)

 

 

(120,185

)

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

350,167

 

 

$

429,495

 

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

 

6


GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

For the Three Months Ended March 31,

 

 

 

2016

 

 

2015

 

 

 

(in thousands, except share and per share data)

 

REVENUES:

 

 

 

 

 

 

 

 

Oil and condensate

 

$

8,813

 

 

$

15,353

 

Natural gas

 

 

4,018

 

 

 

6,700

 

NGLs

 

 

1,695

 

 

 

2,096

 

Total oil, condensate, natural gas and NGLs revenues

 

 

14,526

 

 

 

24,149

 

Gain on commodity derivatives contracts

 

 

285

 

 

 

10,223

 

Total revenues

 

 

14,811

 

 

 

34,372

 

EXPENSES:

 

 

 

 

 

 

 

 

Production taxes

 

 

705

 

 

 

840

 

Lease operating expenses

 

 

6,079

 

 

 

6,019

 

Transportation, treating and gathering

 

 

613

 

 

 

497

 

Depreciation, depletion and amortization

 

 

13,729

 

 

 

14,471

 

Impairment of oil and natural gas properties

 

 

48,497

 

 

 

 

Accretion of asset retirement obligation

 

 

105

 

 

 

125

 

General and administrative expense

 

 

5,675

 

 

 

4,248

 

Total expenses

 

 

75,403

 

 

 

26,200

 

(LOSS) INCOME FROM OPERATIONS

 

 

(60,592

)

 

 

8,172

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

Interest expense

 

 

(9,298

)

 

 

(7,561

)

Investment income and other

 

 

33

 

 

 

3

 

(LOSS) INCOME BEFORE PROVISION FOR INCOME TAXES

 

 

(69,857

)

 

 

614

 

Provision for income taxes

 

 

 

 

 

 

NET (LOSS) INCOME

 

 

(69,857

)

 

 

614

 

Dividends on preferred stock

 

 

(3,618

)

 

 

(3,618

)

NET LOSS ATTRIBUTABLE TO COMMON

   STOCKHOLDERS

 

$

(73,475

)

 

$

(3,004

)

NET LOSS PER SHARE OF COMMON STOCK

   ATTRIBUTABLE TO COMMON STOCKHOLDERS:

 

 

 

 

 

 

 

 

Basic

 

$

(0.93

)

 

$

(0.04

)

Diluted

 

$

(0.93

)

 

$

(0.04

)

WEIGHTED AVERAGE SHARES OF COMMON STOCK

   OUTSTANDING:

 

 

 

 

 

 

 

 

Basic

 

 

78,788,133

 

 

 

77,114,826

 

Diluted

 

 

78,788,133

 

 

 

77,114,826

 

 

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

 

 

 

7


GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

For the Three Months Ended March 31,

 

 

 

2016

 

 

2015

 

 

 

(in thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(69,857

)

 

$

614

 

Adjustments to reconcile net (loss) income to net cash provided by

   operating activities:

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

13,729

 

 

 

14,471

 

Impairment of oil and natural gas properties

 

 

48,497

 

 

 

 

Stock-based compensation

 

 

1,633

 

 

 

1,526

 

Mark to market of commodity derivatives contracts:

 

 

 

 

 

 

 

 

Total gain on commodity derivatives contracts

 

 

(285

)

 

 

(10,223

)

Cash settlements of matured commodity derivatives contracts, net

 

 

8,158

 

 

 

5,277

 

Amortization of deferred financing costs

 

 

990

 

 

 

822

 

Accretion of asset retirement obligation

 

 

105

 

 

 

125

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

636

 

 

 

14,279

 

Prepaid expenses

 

 

100

 

 

 

275

 

Accounts payable and accrued liabilities

 

 

11,475

 

 

 

5,957

 

Net cash provided by operating activities

 

 

15,181

 

 

 

33,123

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

Development and purchase of oil and natural gas properties

 

 

(12,825

)

 

 

(46,121

)

Advances to operators

 

 

(69

)

 

 

(1,753

)

Acquisition of oil and natural gas properties

 

 

127

 

 

 

 

Proceeds from sale of oil and natural gas properties

 

 

 

 

 

2,008

 

Payments to non-operators

 

 

(20

)

 

 

(795

)

Purchase of furniture and equipment

 

 

(4

)

 

 

(3

)

Net cash used in investing activities

 

 

(12,791

)

 

 

(46,664

)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

Proceeds from revolving credit facility

 

 

 

 

 

25,000

 

Repayment of revolving credit facility

 

 

(20,370

)

 

 

(5,000

)

Dividends on preferred stock

 

 

(3,618

)

 

 

(3,618

)

Deferred financing charges

 

 

(815

)

 

 

(281

)

Tax withholding related to restricted stock and performance based unit award vestings

 

 

(711

)

 

 

(1,425

)

Net cash (used in) provided by financing activities

 

 

(25,514

)

 

 

14,676

 

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

 

 

(23,124

)

 

 

1,135

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

 

50,074

 

 

 

11,008

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

26,950

 

 

$

12,143

 

 

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

 

 

 

8


GASTAR EXPLORATION INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

1.

Description of Business

Gastar Exploration Inc. (the “Company” or “Gastar”) 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 has developed and is drilling other prospective formations on the same acreage, primarily the Meramec Shale (Middle Mississippi Lime), while Gastar plans 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 as well as the proven Hunton Limestone horizontal oil play.  These formations comprise what is commonly referred to as the STACK Play. In West Virginia, Gastar developed liquids-rich natural gas in the Marcellus Shale and drilled and completed two successful dry gas Utica Shale/Point Pleasant wells on its acreage.  On April 8, 2016, Gastar sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for an adjusted sales price of $76.6 million, subject to certain additional adjustments, with an effective date of January 1, 2016 (the “Appalachian Basin Sale”).  The Appalachian Basin Sale will be considered a significant disposition, thus resulting in changes to the Company’s financial position, statement of operations and cash flows on a go-forward basis.  

 

 

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, 2015 (the “2015 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2015 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 2015 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 2015 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 months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

Subsequent Events

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.

 

9


On April 8, 2016, the Company completed the Appalach ian Basin Sale.  After certain adjustments (including an adjustment for the assumption by the buyer of approximately $2.8 million in revenue suspense liabilities), cash proceeds from the Appalachian Basin Sale were approximately $76.6 million, subject to c ertain additional adjustments.  In connection with the completion of the Appalachian Basin Sale, the Company used the cash proceeds and other funds to reduce the outstanding borrowings under its revolving credit facility by $80.0 million .

Recent Accounting Developments

The following recently issued accounting pronouncements may impact the Company in future periods:

 

Compensation – Stock Compensation.   In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows.  For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period.  Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted.  Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively.  Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively.  An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements.  

Leases.   In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements.  Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements.  Early adoption is permitted.  The Company has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements.

Income Taxes.   In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes.  Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled.  To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards (IFRS). IAS 1, Presentation of Financial Statements .  This guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  Earlier application is permitted as of the beginning of an interim or annual reporting period and can be applied either prospectively or retrospectively to all periods presented.  The Company does not expect the adoption of this guidance to materially impact its consolidated financial statements.

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, other than those costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, similar to the presentation for debt discounts and premiums, instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate.  This guidance was effective for the Company on January 1, 2016.  The Company’s adoption of this guidance was applied retrospectively and did not have a material impact on the Company’s consolidated financial statements.  

Going Concern.   In August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue 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 the date of

 

10


issuance of annual and interim financial statements, and requires specific disclosure s regarding the conditions or events leading to substantial doubt.  The updated guidance is effective for annual reporting periods ending after December 15, 2016 and for annual periods and interim periods thereafter .  Earlier adoption is permitted , but the Company has not elected to adopt the updated guidance early .  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, which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, “Revenue Recognition,” and most industry-specific guidance.  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 and such proposal was subsequently adopted by the FASB in August 2015.  The Company is evaluating the new guidance and has not yet determined the impact this new standard may have on its consolidated financial statements or decided upon its method of adoption.

 

 

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.  On April 8, 2016, the Company sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin.

The following table summarizes the components of unproved properties excluded from amortization at the dates indicated:

 

 

 

March 31, 2016

 

 

December 31, 2015

 

 

 

(in thousands)

 

Unproved properties, excluded from amortization:

 

 

 

 

 

 

 

 

Drilling in progress costs

 

$

3,155

 

 

$

1,533

 

Acreage acquisition costs

 

 

90,965

 

 

 

82,560

 

Capitalized interest

 

 

9,101

 

 

 

8,516

 

Total unproved properties excluded from amortization

 

$

103,221

 

 

$

92,609

 

 

 

11


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 pursu ant 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 o ff 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 unweigh ted 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 reserv es.  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:

 

 

 

2016

 

 

 

Total Year to Date

Impairment

 

 

March 31

 

Henry Hub natural gas price (per MMBtu) (1)

 

 

 

 

 

$

2.40

 

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

 

 

 

 

 

$

46.26

 

Impairment recorded (pre-tax) (in thousands)

 

$

48,497

 

 

$

48,497

 

 

 

 

2015

 

 

 

Total Year to Date

Impairment

 

 

March 31

 

Henry Hub natural gas price (per MMBtu) (1)

 

 

 

 

 

$

3.88

 

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

 

 

 

 

 

$

82.72

 

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.

 

The Company could potentially incur further ceiling test impairments in 2016 assuming commodities prices do not increase. While it is difficult to project future impairment charges in light of numerous variables involved, the following analysis using basic assumptions is provided to illustrate the impact of lower commodities pricing on impairment charges and proved reserves volumes.  The historical 12-month unweighted average first-day-of-the-month benchmark price applicable to proved reserves reported under SEC rules on April 1, 2016 decreased to $2.34 per MMbtu for natural gas and $45.16 per barrel for crude oil.  

 

The Company’s estimated proved reserve volumes were 55.9 MMBoe at December 31, 2015 using the SEC-mandated 12-month average benchmark pricing at such date.  If such  reserves estimates were made using the further reduced 12-month average benchmark prices as of April 1, 2016 as described in the foregoing paragraph and without regard to cost savings, reserve additions or other further revisions to reserves other than as a result of such pricing changes, the Company’s internally estimated proved reserves as of December 31, 2015, excluding the impact of recent sales, would decrease primarily as a result of the loss of proved undeveloped locations and tail-end estimated future production volumes which would not be economically producible at such lower prices.  The Company’s proved reserves estimates and their estimated discounted value and standardized measure will also be impacted by changes in lease operating costs, future development costs, production, exploration and development activities.

  

 

12


Appalachian Basin Sale

          On February 19, 2016, the Company entered into an agreement to sell substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for $80.0 million, subject to customary closing adjustments.  Pursuant to the agreement, on April 8, 2016, the Company completed the Appalachian Basin Sale for an adjusted sales price of $76.6 million, subject to certain additional adjustments.

 

Appalachian Basin Sale Pro Forma Operating Results

 

The following unaudited pro forma results for the three months ended March 31, 2016 and 2015 show the effect on the Company's consolidated results of operations as if the Appalachian Basin Sale had occurred at the beginning of the periods presented. The pro forma results are the result of excluding from the statement of operations of the Company the revenues and direct operating expenses for the properties divested adjusted for (1) the reduction in ARO liabilities and accretion expense for the properties divested,  (2) the reduction in depreciation, depletion and amortization expense as a result of the divestiture and (3) the reduction in interest expense as a result of the pay down of debt under the Revolving Credit Facility in conjunction with the closing of the Appalachian Basin Sale. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.

 

 

For the Three Months Ended March 31,

 

 

2016

 

 

2015

 

 

(in thousands, except  per share data)

 

 

(Unaudited)

 

Revenues

$

11,621

 

 

$

28,152

 

Net Loss

$

(68,647

)

 

$

(6,969

)

Loss per share:

 

 

 

 

 

 

 

Basic

$

(0.87

)

 

$

(0.09

)

Diluted

$

(0.87

)

 

$

(0.09

)

The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Appalachian Basin Sale occurred as presented. In addition, future results may vary significantly from the results reflected in such pro forma information.

Husky Acquisition

On December 16, 2015, the Company completed the acquisition of additional working and net revenue interests in 103 gross (10.2 net) producing wells and certain undeveloped acreage in the STACK and Hunton Limestone formations in its existing AMI from its AMI co-participant Husky Ventures, Inc. (“Husky”), Silverstar of Nevada, Inc., Maximus Exploration, LLC and Atwood Acquisitions, LLC for an adjusted purchase price of approximately $42.1 million, reflecting adjustment for an acquisition effective date of July 1, 2015 and which includes a $4.9 million deposit into escrow pending the resolution of title defects by the seller and the purchase of overrides recorded to other assets at March 31, 2016, and the conveyance of approximately 11,000 net non-core, non-producing acres in Blaine, Major and Kingfisher Counties, Oklahoma to the sellers, subject to certain adjustments and customary closing conditions (the “Husky Acquisition”).  In connection with the acquisition, the AMI participation agreements with the Company’s AMI co-participant were dissolved.

The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values.  The Company incurred a total of $1.3 million of transaction and integration costs associated with the acquisition since closing and expensed these costs as incurred as general and administrative expenses.   The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 5, “Fair Value Measurements.” The Company's preliminary assessment of the fair value of the Husky Acquisition assets resulted in a fair market valuation of $44.6 million.  As the fair market valuation varied less than 6% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation.

Husky Acquisition Pro Forma Operating Results

The following unaudited pro forma results for the three months ended March 31, 2015 show the effect on the Company's consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the

 

13


properties acquired and (2) additional depreciation, depletion and amortization expense as a result of the Company's increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Husky Acquisitio n assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments.

 

 

For the Three Months Ended March 31, 2015

 

 

(in thousands, except  per share data)

 

 

(Unaudited)

 

Revenues

$

36,831

 

Net Loss

$

(1,882

)

Loss per share:

 

 

 

Basic

$

(0.02

)

Diluted

$

(0.02

)

The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Husky Acquisition occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information.

Atinum Participation Agreement

In September 2010, the Company entered into a participation agreement (the “Atinum Participation Agreement”) pursuant to a purchase and sale agreement with an affiliate of Atinum Partners Co., Ltd. (“Atinum” and, together with the Company, the “Atinum co-participants), a Korean investment firm.  Pursuant to which the Company ultimately assigned to an affiliate of Atinum, for total consideration of $70.0 million, a 50% working interest in certain undeveloped acreage and wells. Effective June 30, 2011, an 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. Prior to the Appalachian Basin Sale, within this AMI, the Company acted as operator and was obligated to offer any future lease acquisitions within the AMI to Atinum on a 50/50 basis, and Atinum paid 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 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, the Atinum co-participants agreed to reduce the minimum wells to be drilled requirements from the originally agreed upon 60 gross wells to 51 gross wells.  At March 31, 2016, 74 gross operated horizontal Marcellus Shale wells and two gross operated horizontal Utica Shale/Point Pleasant wells were capable of production under the Atinum Participation Agreement.  The Atinum Participation Agreement expired on November 1, 2015.  On April 8, 2016, the Company sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for an adjusted sales price of $76.6 million, subject to certain additional adjustments, reflecting an effective date of January 1, 2016.    

 

 

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 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

 

14


subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and mate rial 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 to Second Amended and Restated Credit Agreement (“Amendment No. 5”).  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.

On December 22, 2015, the Company, together with the parties thereto, entered into Amendment No. 6 to Second Amended and Restated Credit Agreement (“Amendment No. 6”).  Amendment No. 6 amended the Revolving Credit Facility to permit the Company to exchange its outstanding Notes constituting Second Lien Debt under the Revolving Credit Facility for equity interests in the Company.

On January 29, 2016, the Company, together with the parties thereto, entered into Limited Waiver and Amendment No. 7 to Second Amended and Restated Credit Agreement (“Amendment No. 7”).  Pursuant to Amendment No. 7, the Company obtained (i) a waiver until March 10, 2016 of any potential defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility and (ii) a permanent waiver of any defaults of the restricted payment covenant under the Revolving Credit Facility resulting from (a) cash distributions paid on December 31, 2015 in respect of its Series A Preferred Stock and its Series B Preferred Stock and (b) the issuance on January 28, 2016, as a dividend on the Company’ common stock, of the right to purchase Series C Junior Participating Preferred Stock pursuant to the Company’s Rights Agreement dated as of January 18, 2016 as part of the Company’s previously disclosed tax benefits preservation plan.  The Revolving Credit Facility was also amended to permit the Company to make dividends and distributions of preferred equity interests or rights to purchase certain preferred equity interests.  The entry into Amendment No. 7 permitted the Company to pay monthly cash dividends on its Series A Preferred Stock and its Series B Preferred Stock on February 1, 2016.

On March 9, 2016, the Company, together with the parties thereto, entered into Waiver and Amendment No. 8 to Second Amended and Restated Credit Agreement (“Amendment No. 8”).  Pursuant to Amendment No. 8, the Company obtained the following relief with respect to its financial covenant compliance:

 

(i)

a permanent waiver of the defaults at December 31, 2015 of its leverage ratio and senior secured leverage ratio under the Revolving Credit Facility;

 

(ii)

relief from compliance with its leverage ratio through the fiscal quarter ending March 31, 2017, but the Company must maintain a maximum leverage ratio of not greater than 4.0 to 1.0 for each fiscal quarter ending on or after June 17, 2017;

 

15


 

(iii)

an adjustment to the interest coverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 1.10 to 1.00 and for each fiscal quarter ending on or after June 30, 2017 to 2.50 to 1.00; and

 

(iv)

an adjustment to its senior secured leverage ratio for each fiscal quarter ending on or after June 30, 2016 but prior to June 30, 2017, to 2.50 to 1.00 provided that during such period the Company may subtract all cash on hand in calculating the senior secured leverage ratio for such periods and for each fiscal quarter ending on or after June 30, 2017, to 2.00 to 1.00 provided that during such period the Company may only subtract up to $5 million of cash on hand in calculating the senior secured leverage ratio for such periods

As consideration for the financial covenant relief provided for in Amendment No. 8, the Revolving Credit Facility was also amended to, among other things:

 

(i)

set the interest margin at (a) 4.0% per annum for Eurodollar rate borrowings and (b) 3.0% per annum for borrowings based on the reference rate;

 

(ii)

reduce the borrowing base from $200.0 million to $180.0 million until the earlier of the closing of the Appalachian Basin Sale or April 10, 2016, at which point the borrowing base would automatically be reduced to $100.0 million and require borrowings in excess of such amount be repaid immediately;

 

(iii)

require additional automatic reductions of the borrowing base in connection with asset sales in excess of $5.0 million or the termination of any hedge agreements governing hedges with a settlement date on or after July 1, 2016;

 

(iv)

provide for an additional interim borrowing base redetermination in August 2016;

 

(v)

require the consent of the lenders to any asset sales in excess of $5.0 million; and

 

(vi)

restrict the Company after March 2016 from making any distributions or paying any cash dividends to the holders of its preferred equity, including its outstanding shares of Series A Preferred Stock and Series B Preferred Stock.

Borrowing base redeterminations are scheduled semi-annually in May and November of each calendar year, although an additional scheduled redetermination will occur in August 2016, as set forth in Amendment No. 8.  The Company and its lenders may each request one additional unscheduled redetermination during any six-month period between scheduled redeterminations.  At March 31, 2016, the Revolving Credit Facility had a borrowing base of $180.0 million, with $179.6 million of borrowings outstanding and $370,000 of letters of credit outstanding.  In connection with Amendment No. 8 and in conjunction with the closing of the Appalachian Basin Sale, the borrowing base was reduced from $180.0 million to $100.0 million on April 8, 2016.  As of May 2, 2016, there were $99.6 million of borrowings outstanding and $370,000 of letters of credit issued under the Revolving Credit Facility.     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 March 31, 2016, 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.

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 are 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:

 

·

Incur additional indebtedness or refinance existing indebtedness;

 

·

Transfer or sell assets or use asset sale proceeds;

 

·

Pay dividends or make distributions, redeem subordinated debt or make other restricted payments;

 

16


 

·

Make certain investments; incur or guarantee additional debt or issue preferred equity securities;

 

·

Create or incur certain liens on the Company's assets, including securing additional indebtedness or refinancing existing indebtedness;

 

·

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.

Covenants in the Indenture also limit the Company’s ability to borrow on a first priority lien secured basis, including its ability to refinance the full amount of currently outstanding borrowings under its Revolving Credit Facility or to reborrow on such facility in the event current borrowings thereunder are paid down.  These and other covenants that are contained in the Indenture are subject to important limitations and qualifications that are described in the Indenture.

A summary of the Notes balance for the periods indicated is as follows:

 

 

March 31, 2016

 

 

December 31, 2015

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

Notes, principal balance

 

$

325,000

 

 

$

325,000

 

Less:

 

 

 

 

 

 

 

 

Unamortized discounts

 

 

(6,474

)

 

 

(7,151

)

Deferred financing costs

 

 

(1,229

)

 

 

(1,373

)

Notes, net

 

$

317,297

 

 

$

316,476

 

 

 

 

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 months ended March 31, 2016 and 2015, due to continued lower natural gas prices for dry gas and no current plans to drill or extend leases in Marcellus East, management’s evaluation of unproved properties resulted in impairment and the Company reclassified an immaterial amount of costs from unproved to proved properties for each period.      As no other fair value measurements are required to be recognized on a non-recurring basis at March 31, 2016, no additional disclosures are provided at March 31, 2016.

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:

 

·

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.

 

17


 

·

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 meth odologies 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) curre nt 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 coll ars, 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 val uation 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 instr uments.

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 2016 and 2015 periods.

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 March 31, 2016 and December 31, 2015:

 

 

 

Fair value as of March 31, 2016

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

26,950

 

 

$

 

 

$

 

 

$

26,950

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

16,076

 

 

 

16,076

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

-

 

 

 

-

 

Total

 

$

26,950

 

 

$

 

 

$

16,076

 

 

$

43,026

 

 

 

 

Fair value as of December 31, 2015

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

50,074

 

 

$

 

 

$

 

 

$

50,074

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

24,869

 

 

 

24,869

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative contracts

 

 

 

 

 

 

 

 

(451

)

 

 

(451

)

Total

 

$

50,074

 

 

$

-

 

 

$

24,418

 

 

$

74,492

 

 

 

18


The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2016 and 2015 . Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumption s a marketplace participant would have used at March 31, 2016 and 2015 .

 

 

 

Three Months Ended March 31,

 

 

 

2016

 

 

2015

 

 

 

(in thousands)

 

Balance at beginning of period

 

$

24,418

 

 

$

27,502

 

Total gains included in earnings

 

 

285

 

 

 

10,223

 

Purchases

 

 

 

 

 

866

 

Issuances

 

 

 

 

 

(186

)

Settlements (1)

 

 

(8,627

)

 

 

(6,582

)

Balance at end of period

 

$

16,076

 

 

$

31,823

 

The amount of total (losses) gains for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at March 31, 2016 and 2015

 

$

(6,497

)

 

$

4,252

 

 

(1)

Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.

At March 31, 2016, 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 March 31, 2016 was $388.4 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.”

 

 

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 March 31, 2016 and 2015, the Company reported a loss of $6.5 million and a gain of $4.3 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 March 31, 2016 and 2015.     

As of March 31, 2016, 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)

 

 

 

 

 

 

 

 

 

 

 

 

 

2016 (2)

 

Costless three-way collar

 

 

250

 

 

 

38,250

 

 

$

85.00

 

 

$

65.00

 

 

$

95.10

 

2016 (2)

 

Costless three-way collar

 

 

330

 

 

 

50,490

 

 

$

80.00

 

 

$

65.00

 

 

$

97.35

 

2016 (2)

 

Costless three-way collar

 

 

450

 

 

 

68,850

 

 

$

57.50

 

 

$

42.50

 

 

$

80.00

 

2016 (2)

 

Put spread

 

 

550

 

 

 

84,150

 

 

$

85.00

 

 

$

65.00

 

 

$

 

2016 (2)

 

Put spread

 

 

300

 

 

 

45,900

 

 

$

85.50

 

 

$

65.50

 

 

$

 

2017

 

Costless three-way collar

 

 

280

 

 

 

102,200

 

 

$

80.00

 

 

$

65.00

 

 

$

97.25

 

2017

 

Costless three-way collar

 

 

250

 

 

 

91,250

 

 

$

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

 

 

$