Quarterly Report (10-q)

Date : 11/08/2017 @ 4:26PM
Source : Edgar (US Regulatory)
Stock : Gastar Exploration Inc. (GSTC)
Quote : 0.053  -0.00515 (-8.86%) @ 4:01PM

Quarterly Report (10-q)

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

FOR THE QUARTERLY PERIOD ENDED September 30, 2017

OR

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

FOR THE TRANSITION PERIOD FROM           TO             

Commission File Number: 001-35211

 

GASTAR EXPLORATION INC.

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

38-3531640

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

1331 Lamar Street, Suite 650

 

 

Houston, Texas

 

77010

(Address of principal executive offices)

 

(Zip Code)

(713) 739-1800

(Registrant’s telephone number, including area code)

 

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes      No  

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

Large accelerated filer

 

  

Accelerated filer

 

 

 

 

 

 

 

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

 

 

 

 

 

 

 

Emerging growth company

 

 

 

 

 

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

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

The total number of outstanding shares of common stock, $0.001 par value per share, as of November 6, 2017 was 218,941,521.

 

 


GASTAR EXPLORATION INC.

QUARTERLY REPORT ON FORM 10-Q

For the three and nine months ended September 30, 2017

TABLE OF CONTENTS

 

 

 

 

 

Page

PART I – FINANCIAL INFORMATION

 

 

 

Item 1.

 

Financial Statements

 

 

6

 

 

Gastar Exploration Inc. Condensed Consolidated Balance Sheets as of September 30, 2017 (unaudited) and December 31, 2016

 

 

7

 

 

Gastar Exploration Inc. Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016 (unaudited)

 

 

8

 

 

Gastar Exploration Inc. Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016 (unaudited)

 

 

9

 

 

Notes to the Condensed Consolidated Financial Statements (unaudited)

 

 

10

Item 2.

 

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

 

 

33

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

 

44

Item 4.

 

Controls and Procedures

 

 

45

PART II – OTHER INFORMATION

 

 

 

Item 1.

 

Legal Proceedings

 

 

46

Item 1A.

 

Risk Factors

 

 

46

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

 

46

Item 3.

 

Defaults Upon Senior Securities

 

 

46

Item 4.

 

Mine Safety Disclosure

 

 

46

Item 5.

 

Other Information

 

 

46

Item 6.

 

Exhibits

 

 

46

SIGNATURES

 

 

48

 

 

2


 

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

 

 

 

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

 

One million British thermal units

 

 

 

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

 

 

 

PUD

 

Proved undeveloped reserves

 

 

 

STACK Play

 

An acronymic name for a predominantly oil producing play referring to the exploration and development of the Sooner Trend of the Anadarko Basin in Canadian and Kingfisher Counties, Oklahoma.  References to the STACK Play is extended to adjacent counties.  

 

 

 

U.S.

 

United States of America

 

 

 

 

4


U.S. GAAP

 

Accounting principles generally accepted in the United States of America

 

 

 

WTI

 

West Texas Intermediate

 

 

5


PART I. FINANCI AL INFORMATION

 

Item 1. Financial Statements


 

6


GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED BALANCE SHEETS  

 

 

September 30,

 

 

December 31,

 

 

 

2017

 

 

2016

 

 

 

(Unaudited)

 

 

 

 

 

 

 

(in thousands, except share and per share data)

 

ASSETS

 

 

 

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

29,229

 

 

$

71,529

 

Accounts receivable, net of allowance for doubtful accounts of $1,953, respectively

 

 

40,353

 

 

 

26,883

 

Commodity derivative contracts

 

 

4,400

 

 

 

6,212

 

Prepaid expenses

 

 

1,167

 

 

 

755

 

Total current assets

 

 

75,149

 

 

 

105,379

 

PROPERTY, PLANT AND EQUIPMENT:

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

Unproved properties, excluded from amortization

 

 

135,945

 

 

 

67,333

 

Proved properties

 

 

1,303,165

 

 

 

1,253,061

 

Total oil and natural gas properties

 

 

1,439,110

 

 

 

1,320,394

 

Furniture and equipment

 

 

3,031

 

 

 

2,622

 

Total property, plant and equipment

 

 

1,442,141

 

 

 

1,323,016

 

Accumulated depreciation, depletion and amortization

 

 

(1,147,774

)

 

 

(1,131,012

)

Total property, plant and equipment, net

 

 

294,367

 

 

 

192,004

 

OTHER ASSETS:

 

 

 

 

 

 

 

 

Restricted cash

 

 

370

 

 

 

 

Commodity derivative contracts

 

 

416

 

 

 

1,638

 

Deferred charges, net

 

 

 

 

 

676

 

Advances to operators and other assets

 

 

100

 

 

 

102

 

Other

 

 

405

 

 

 

405

 

Total other assets

 

 

1,291

 

 

 

2,821

 

TOTAL ASSETS

 

$

370,807

 

 

$

300,204

 

LIABILITIES AND STOCKHOLDERS' DEFICIT

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

 

 

Accounts payable

 

$

11,411

 

 

$

8,867

 

Revenue payable

 

 

16,428

 

 

 

6,690

 

Accrued interest

 

 

7,271

 

 

 

3,515

 

Accrued drilling and operating costs

 

 

12,100

 

 

 

2,615

 

Advances from non-operators

 

 

1,589

 

 

 

3,504

 

Commodity derivative contracts

 

 

326

 

 

 

338

 

Commodity derivative premium payable

 

 

1,337

 

 

 

1,654

 

Asset retirement obligation

 

 

 

 

 

89

 

Other accrued liabilities

 

 

2,791

 

 

 

2,462

 

Total current liabilities

 

 

53,253

 

 

 

29,734

 

LONG-TERM LIABILITIES:

 

 

 

 

 

 

 

 

Long-term debt

 

 

333,593

 

 

 

404,493

 

Commodity derivative contracts

 

 

129

 

 

 

 

Commodity derivative premium payable

 

 

34

 

 

 

969

 

Asset retirement obligation

 

 

4,574

 

 

 

5,443

 

Total long-term liabilities

 

 

338,330

 

 

 

410,905

 

Commitments and contingencies (Note 11)

 

 

 

 

 

 

 

 

STOCKHOLDERS’ DEFICIT:

 

 

 

 

 

 

 

 

Preferred stock, par value $0.01 per share, 40,000,000 shares authorized

 

 

 

 

 

 

 

 

8.625% Series A Cumulative Preferred Stock, 10,000,000 shares designated;

   4,045,000 shares issued and outstanding at September 30, 2017 and December 31, 2016,

   respectively, with liquidation preference of $25.00 per share

 

 

41

 

 

 

41

 

10.75% Series B Cumulative Preferred Stock, 10,000,000 shares designated;

   2,140,000 shares issued and outstanding at September 30, 2017 and December 31, 2016,

   respectively, with liquidation preference of $25.00 per share

 

 

21

 

 

 

21

 

Common stock, par value $0.001 per share; 800,000,000 and 550,000,000 shares authorized at

         September 30, 2017 and December 31, 2016, respectively; 218,946,763 and

         150,377,870 shares issued and outstanding at September 30, 2017 and December 31, 2016,

         respectively

 

 

219

 

 

 

150

 

Additional paid-in capital

 

 

817,627

 

 

 

644,306

 

Accumulated deficit

 

 

(838,684

)

 

 

(784,953

)

Total stockholders’ deficit

 

 

(20,776

)

 

 

(140,435

)

TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT

 

$

370,807

 

 

$

300,204

 

 

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

 

7


GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

For the Three Months Ended

September 30,

 

 

For the Nine Months Ended September 30,

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

(in thousands, except share

and per share data)

 

REVENUES:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate

 

$

12,952

 

 

$

10,306

 

 

$

37,886

 

 

$

30,464

 

Natural gas

 

 

2,519

 

 

 

2,500

 

 

 

7,452

 

 

 

8,394

 

NGLs

 

 

2,757

 

 

 

1,695

 

 

 

7,527

 

 

 

5,100

 

Total oil, condensate, natural gas and NGLs revenues

 

 

18,228

 

 

 

14,501

 

 

 

52,865

 

 

 

43,958

 

(Loss) gain on commodity derivatives contracts

 

 

(2,896

)

 

 

(1,498

)

 

 

3,782

 

 

 

(3,991

)

Total revenues

 

 

15,332

 

 

 

13,003

 

 

 

56,647

 

 

 

39,967

 

EXPENSES (BENEFIT):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production taxes

 

 

721

 

 

 

400

 

 

 

1,675

 

 

 

1,469

 

Lease operating expenses

 

 

6,178

 

 

 

5,166

 

 

 

16,396

 

 

 

15,829

 

Transportation, treating and gathering

 

 

436

 

 

 

338

 

 

 

1,187

 

 

 

1,346

 

Depreciation, depletion and amortization

 

 

6,059

 

 

 

5,223

 

 

 

16,762

 

 

 

24,543

 

Impairment of oil and natural gas properties

 

 

 

 

 

 

 

 

 

 

 

48,497

 

Accretion of asset retirement obligation

 

 

62

 

 

 

92

 

 

 

171

 

 

 

286

 

General and administrative expense

 

 

4,067

 

 

 

3,925

 

 

 

12,482

 

 

 

15,872

 

Litigation settlement benefit

 

 

 

 

 

(10,100

)

 

 

 

 

 

(10,100

)

Total expenses

 

 

17,523

 

 

 

5,044

 

 

 

48,673

 

 

 

97,742

 

(LOSS) INCOME FROM OPERATIONS

 

 

(2,191

)

 

 

7,959

 

 

 

7,974

 

 

 

(57,775

)

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(10,159

)

 

 

(8,178

)

 

 

(29,744

)

 

 

(26,739

)

Loss on early extinguishment of debt

 

 

 

 

 

 

 

 

(12,172

)

 

 

 

Investment income and other (expense)

 

 

51

 

 

 

41

 

 

 

166

 

 

 

(2

)

LOSS BEFORE PROVISION FOR INCOME TAXES

 

 

(12,299

)

 

 

(178

)

 

 

(33,776

)

 

 

(84,516

)

Provision for income taxes

 

 

 

 

 

 

 

 

 

 

 

 

NET LOSS

 

 

(12,299

)

 

 

(178

)

 

 

(33,776

)

 

 

(84,516

)

Dividends on preferred stock

 

 

(1,206

)

 

 

 

 

 

(8,443

)

 

 

(3,618

)

Undeclared cumulative dividends on preferred stock

 

 

(2,412

)

 

 

(3,618

)

 

 

(2,412

)

 

 

(7,237

)

NET LOSS ATTRIBUTABLE TO COMMON

   STOCKHOLDERS

 

$

(15,917

)

 

$

(3,796

)

 

$

(44,631

)

 

$

(95,371

)

NET LOSS PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.08

)

 

$

(0.03

)

 

$

(0.23

)

 

$

(0.92

)

Diluted

 

$

(0.08

)

 

$

(0.03

)

 

$

(0.23

)

 

$

(0.92

)

WEIGHTED AVERAGE SHARES OF COMMON STOCK

   OUTSTANDING:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

209,072,232

 

 

 

129,301,817

 

 

 

190,745,688

 

 

 

104,125,317

 

Diluted

 

 

209,072,232

 

 

 

129,301,817

 

 

 

190,745,688

 

 

 

104,125,317

 

 

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

 

 

 

8


GASTAR EXPLORATION INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

For the Nine Months Ended

September 30,

 

 

 

2017

 

 

2016

 

 

 

(in thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

Net loss

 

$

(33,776

)

 

$

(84,516

)

Adjustments to reconcile net loss to net cash provided by

   operating activities:

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

16,762

 

 

 

24,543

 

Impairment of oil and natural gas properties

 

 

 

 

 

48,497

 

Stock-based compensation

 

 

3,990

 

 

 

3,145

 

Mark to market of commodity derivatives contracts:

 

 

 

 

 

 

 

 

Total (gain) loss on commodity derivatives contracts

 

 

(3,782

)

 

 

3,991

 

Cash settlements of matured commodity derivatives contracts, net

 

 

5,602

 

 

 

10,690

 

Cash premiums paid for commodity derivatives contracts

 

 

 

 

 

(565

)

Amortization of deferred financing costs and debt discount

 

 

8,218

 

 

 

3,812

 

Accretion of asset retirement obligation

 

 

171

 

 

 

286

 

Settlement of asset retirement obligation

 

 

 

 

 

(87

)

Loss on sale of furniture and equipment

 

 

 

 

 

97

 

Loss on early extinguishment of debt

 

 

12,172

 

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

(13,466

)

 

 

3,861

 

Prepaid expenses

 

 

(412

)

 

 

362

 

Accounts payable and accrued liabilities

 

 

13,657

 

 

 

7,656

 

Net cash provided by operating activities

 

 

9,136

 

 

 

21,772

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

Development and purchase of oil and natural gas properties

 

 

(81,906

)

 

 

(43,175

)

(Acquisition of) refund for oil and natural gas properties

 

 

(54,462

)

 

 

1,149

 

Proceeds from sale of oil and natural gas properties

 

 

28,798

 

 

 

77,499

 

Application of proceeds from non-operators

 

 

(1,915

)

 

 

(57

)

(Advances to) reimbursements from operators

 

 

(22

)

 

 

211

 

(Purchase) sale of furniture and equipment

 

 

(409

)

 

 

80

 

Net cash (used in) provided by investing activities

 

 

(109,916

)

 

 

35,707

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

Proceeds from term loan

 

 

250,000

 

 

 

 

Proceeds from convertible notes

 

 

200,000

 

 

 

 

Repayment of senior secured notes

 

 

(325,000

)

 

 

 

Repayment of revolving credit facility

 

 

(84,630

)

 

 

(100,370

)

Loss on early extinguishment of debt

 

 

(7,011

)

 

 

 

Proceeds from issuance of common stock, net of issuance costs

 

 

56,366

 

 

 

44,815

 

Dividends on preferred stock

 

 

(19,298

)

 

 

(3,618

)

Deferred financing charges

 

 

(10,991

)

 

 

(930

)

Increase in restricted cash

 

 

(370

)

 

 

 

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

 

 

(586

)

 

 

(711

)

Net cash provided by (used in) financing activities

 

 

58,480

 

 

 

(60,814

)

NET DECREASE IN CASH AND CASH EQUIVALENTS

 

 

(42,300

)

 

 

(3,335

)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

 

71,529

 

 

 

50,074

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

29,229

 

 

$

46,739

 

 

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

 

 

 

9


GASTAR EXPLORATION INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

1.

Description of Business

Gastar Exploration Inc. (the “Company” or “Gastar”) is a pure play Mid-Continent independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and NGLs. 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. Gastar holds a concentrated acreage position in the normally pressured oil window of the STACK Play, an area of central Oklahoma which is home to multiple oil and natural gas-rich reservoirs including the Oswego limestone, Meramec and Osage bench formations within the Mississippi Lime, the Woodford shale and Hunton limestone formations.    

 

 

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, 2016 (the “2016 Form 10-K”) filed with the SEC. Please refer to the notes to the consolidated financial statements included in the 2016 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 2016 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 2016 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 valuation of convertible debt, 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.

The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.

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.

 

Accounts Receivable

Accounts receivable are reported net of the allowance for doubtful accounts.  The allowance for doubtful accounts is determined based on a review of the Company’s receivables.  Receivable accounts are charged off when collection efforts have failed or the account is deemed uncollectible.  During 2016, the Company determined that a receivable account from a third-party natural gas and NGLs purchaser would no longer be collectible as a result of the third-party purchaser filing for bankruptcy.  A summary of the activity related to the allowance for doubtful accounts is as follows:

 

 

10


 

 

September 30,

2017

 

 

December 31,

2016

 

 

 

(in thousands)

 

Allowance for doubtful accounts, beginning of period

 

$

1,953

 

 

$

 

Expense

 

 

 

 

 

1,953

 

Reductions/write-offs

 

 

 

 

 

 

Allowance for doubtful accounts, end of period

 

$

1,953

 

 

$

1,953

 

Recent Accounting Developments

Business Combinations.   In January 2017, the FASB issued updated guidance to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.  The amendments in this update provide a screen to determine when a set is not a business.  The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business.  This screen reduces the number of transactions that need to be further evaluated.  If the screen is not met, the amendments in this update (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements.  The amendments in this update affect all reporting entities that must determine whether they have acquired or sold a business and are effective for public business entities for annual reporting periods beginning after December 15, 2017, including interim periods within those periods.  The amendments should be applied prospectively on or after the effective date and no disclosures are required at transition.  Early application is allowed as follows (1) for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance and (2) for transactions in which a subsidiary is deconsolidated or a group of assets is derecognized that occur before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance.  The application of this guidance to future acquisitions and disposals could have an effect on the Company’s financial position or results of operations.

Statement of Cash Flows. In August 2016, the FASB issued updated guidance associated with the classification of certain cash receipts and cash payments on the statement of cash flows. The amended guidance addresses specific cash flow issues with the objective of reducing existing diversity in practice.  The amendment provides guidance on the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle.  The amendments in this update apply to all entities required to present a statement of cash flows.  The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.  Early adoption is permitted, including adoption in an interim 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 should be applied using a retrospective transition method to each period presented.  If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable.  The Company is currently evaluating the effect that adopting this guidance will have on its presentation of cash flows and does not believe the effects of adopting this updated guidance will have a material effect on its statement of cash flows nor that it will affect the Company’s financial position or results of operations.    

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.  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 adopted this updated guidance for the fiscal year beginning January 1, 2017 and recorded a cumulative adjustment of approximately $657,000 to retained earnings to properly reflect the adjustment to stock compensation expense to reduce the forfeiture rate to 0%.

 

11


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 req uired 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 amendme nts 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 financ ial statements.  Early adoption is permitted.  The Company has begun analyzing its lease contracts but 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 U.S. 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. International Accounting Standard 1, Presentation of Financial Statements .  This updated 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.  The Company has adopted this guidance prospectively and such adoption did not have an 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 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.   In 2015, the FASB delayed the effective date one year, beginning in fiscal year 2018.  

The Company has substantially completed its scoping and assessment of impact of the new revenue recognition standard.

The Company has evaluated a representative sample of revenue contracts related to its oil, natural gas and NGLs revenues.  For these contracts, the Company has reviewed the contract provisions and evaluated the contracts under the new standard to assess the impact on the quantum and timing of revenue recognition and presentation of revenues on adoption of the new guidance.  The Company believes that it has identified all material contract types and contractual features that represent the Company’s revenue.  Based upon work completed to date, the Company does not currently expect that the adoption of this standard will have a material impact on net profit, although the Company does believe that certain reclassifications between revenue and expenses may be required based upon its assessment of i) where control passes to the customer and ii) whether the Company represents the principal or agent in certain arrangements.  In addition, the Company’s disclosures surrounding revenue recognition will be more substantial upon adoption.   These conclusions are subject to change and the Company is continuing to evaluate the requirements of this standard as it works towards finalizing its assessment, and as it continues to perform other implementation activities such as establishing new policies, procedures and controls, quantifying the adoption date adjustments and drafting disclosures.  The Company is required to apply this new standard beginning January 1, 2018.  Two methods of transition are permitted under this standard: the full retrospective method, in which the standard would be applied retrospectively to each prior reporting period presented, subject to certain allowable exceptions; or the modified retrospective method, in which the standard would be applied to all contracts existing as of the date of initial application, with the cumulative effect of applying the standard recognized in retained earnings (the adoption date adjustments).  The Company anticipates adopting this standard using the modified retrospective method.

 

 

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., specifically the states of Oklahoma, Pennsylvania and West Virginia.  On April 8, 2016, the Company sold substantially all

 

12


of its producing assets and proved reserves and a significant portion of its undeveloped acreage in Pennsylvania and West Virginia comprising the Company’s assets in the Appalachian Basin.  On January 20, 2017, the Compan y sold its remaining interest in producing wells and undeveloped acreage in West Virginia, effective January 1, 2017, for $200,000 before fees and expenses.

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

 

 

 

September 30,

2017

 

 

December 31,

2016

 

 

 

(in thousands)

 

Unproved properties, excluded from amortization:

 

 

 

 

 

 

 

 

Drilling in progress costs

 

$

10,881

 

 

$

1,100

 

Acreage acquisition costs

 

 

113,110

 

 

 

58,857

 

Capitalized interest

 

 

11,954

 

 

 

7,376

 

Total unproved properties excluded from amortization

 

$

135,945

 

 

$

67,333

 

 

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 each reporting 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:

 

 

 

2017

 

 

 

Total Year to Date

Impairment

 

 

September 30

 

 

June 30

 

 

March 31

 

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

 

 

 

 

 

$

3.00

 

 

$

3.01

 

 

$

2.73

 

WTI oil price (per Bbl) (1)

 

 

 

 

 

$

49.81

 

 

$

48.95

 

 

$

47.61

 

Impairment recorded (pre-tax) (in thousands)

 

$

 

 

$

 

 

$

 

 

$

 

 

 

 

2016

 

 

 

Total Year to Date

Impairment

 

 

September 30

 

 

June 30

 

 

March 31

 

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

 

 

 

 

 

$

2.28

 

 

$

2.24

 

 

$

2.40

 

WTI oil price (per Bbl) (1)

 

 

 

 

 

$

41.68

 

 

$

43.12

 

 

$

46.26

 

Impairment recorded (pre-tax) (in thousands)

 

$

48,497

 

 

$

 

 

$

 

 

$

48,497

 

 

(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 WTI spot oil prices.

The Company could potentially incur ceiling test impairments in the future should commodities prices decline. However, it is difficult to project future impairment charges in light of numerous variables involved.

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 and estimated future income taxes.  The ceiling limitation calculation is not intended to be indicative of the fair market value of the Company’s proved reserves or future results.

STACK Leasehold Acquisition

On March 22, 2017, the Company completed the acquisition of additional working and net revenue interests in approximately 66 gross (9.5 net) producing wells and 5,670 net acres of additional undeveloped STACK Play leasehold in Kingfisher County,

 

13


Oklahoma, effective March 1, 2017, for $51.4 million (the “STACK Leasehold Acquisition”).  Prior to the completion of the STACK Leasehold Acquisition, the Company held an interest in the majority of acquired producing wells and acreage.  The Company accounted for th e STACK Leasehold Acquisition as an asset acquisition.  

Development Agreement

On October 14, 2016, the Company executed an agreement with STACK Exploration LLC (the “Investor”) (the “Development Agreement”) to jointly develop up to 60 Gastar operated wells in the STACK Play in Kingfisher County, Oklahoma (the “Drilling Program”).  The Drilling Program targeted the Meramec and Osage formations within the Mississippi Lime in a contract area within three townships covering approximately 32,900 gross (21,200 net) undeveloped mineral acres under leases held by the Company. The Company is the operator of all wells jointly developed under the Development Agreement.      

Under the Development Agreement, the Investor funded 90% of the Company’s working interest portion of drilling and completion costs to initially earn 80% of the Company’s working interest in each new well (in each case, proportionately reduced by other participating working interests in the well).  As a result, the Company paid 10% of its working interest portion of such costs for 20% of its original working interest.  

The proposed Drilling Program wells were to be mutually developed in three tranches of 20 wells each.  The locations of the first 20 wells, comprised of 18 Meramec formation wells and two Osage formation wells, were mutually agreed upon by the Company and the Investor.   Participation in the second tranche of 20 Drilling Program wells was to be at the election of the Investor and the third tranche of 20 wells would require mutual consent.  On July 31, 2017, the Investor elected not to participate in the second tranche of wells.  With respect to each 20-well tranche, when the Investor has achieved an aggregate 15% internal rate of return for its investment in the tranche, Investor’s interest will be reduced from 80% to 40% of the Company’s original working interest and the Company’s working interest increases from 20% to 60% of its original working interest.  When a tranche internal rate of return of 20% is achieved by the Investor, Investor’s working interest decreases to 10% and the Company’s working interest increases to 90% of the working interest originally owned by the Company.  

Upon completion of a tranche, the Investor has the right, but not the obligation, for a period of six months to cause the Company to purchase the Investor’s interest in the Drilling Program that is not subject to final reversion (the “WI Tail”) for such tranche (the “Investor Put Right”) for fair market value by applying the methodology to determine a 15% discounted present value as defined by the Development Agreement.  If the Investor fails to exercise the Investor Put Right within the six-month period after achieving final reversion, then for a period of six months thereafter, the Company shall have the right, but not the obligation, to purchase the WI Tail from the Investor on the same fair market value approach of the Investor Put Right.  If final reversion has not been achieved by the eighth anniversary of the spud date of the first well in a given tranche, Investor will, for a period of six months thereafter, have the right to cause us to buy Investor’s then-current interest in such tranche at an agreed upon valuation.  Based on current commodity prices, well cost and production performance of the completed wells in the first tranche, the 15% of internal rate of return is not anticipated to be achieved.  

As of September 30, 2017, the Company and the Investor had completed 20 gross (15.8 net; 3.2 net to the Company) wells, all of which were on production, within the first tranche of the Drilling Program.  

Canadian County Property Sale

On October 19, 2016, the Company entered into a purchase and sale agreement (the “Red Bluff PSA”) to sell certain non-core leasehold interests in approximately 25,300 net acres of which only 19,100 net acres was ascribed allocated value and interests in 25 gross (11.2 net) wells primarily in northeast Canadian County and also in southeast Kingfisher County, Oklahoma to Red Bluff Resources Operating, LLC (“Red Bluff”) for $71.0 million (of which up to $10.0 million was contingent upon the satisfaction of certain conditions), subject to certain adjustments and with a property sale effective date of August 1, 2016 (“South STACK Play Acreage Sale”).  As of September 30, 2017, the sale was completed and the Company had received approximately $69.5 million of sales proceeds from the South STACK Play Acreage Sale.  The sale was reflected as a reduction to the full cost pool and no adjustment to the income statement was necessary as it was determined not to be significant.  

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 (the “Appalachian Basin Sale”).  Pursuant to the agreement, on April 8, 2016, the Company completed the Appalachian Basin Sale for an adjusted sales price of $75.7 million, net of $3.5 million of suspense liability transferred to buyer.  The Appalachian Basin Sale was reflected as a reduction to the full cost pool and the Company did not record a gain or loss related to the

 

14


divestiture as it was not d etermined to be significant to the full cost pool and did not result in a significant change to the depletion rate.

4.

Long-Term Debt

The table below provides a reconciliation of the Company’s long-term debt balance as presented in the condensed consolidated balance sheets for the periods presented:

 

 

September 30, 2017

 

 

December 31, 2016

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

Term Loan, principal balance (1)

 

$

250,000

 

 

$

 

Less:

 

 

 

 

 

 

 

 

Unamortized deferred financing costs (2)

 

 

(4,909

)

 

 

 

Unamortized debt discount (2)

 

 

(22,958

)

 

 

 

Term Loan, net

 

$

222,133

 

 

$

 

 

 

 

 

 

 

 

 

 

Notes, principal balance

 

$

162,500

 

 

$

 

Less:

 

 

 

 

 

 

 

 

Unamortized deferred financing costs (2)

 

 

(2,765

)

 

 

 

Unamortized debt discount (2)

 

 

(48,275

)

 

 

 

Notes, net

 

$

111,460

 

 

$

 

 

 

 

 

 

 

 

 

 

Revolving credit facility

 

$

 

 

$

84,630

 

 

 

 

 

 

 

 

 

 

Former senior secured notes

 

$

 

 

$

325,000

 

Less:

 

 

 

 

 

 

 

 

Unamortized deferred financing costs

 

 

 

 

 

(795

)

Unamortized debt discount

 

 

 

 

 

 

(4,342

)

Former senior secured notes, net

 

$

 

 

$

319,863

 

 

 

 

 

 

 

 

 

 

Total long-term debt

 

$

333,593

 

 

$

404,493

 

 

(1)

Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time.  

(2)

The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan and  Notes (as defined below), respectively, based on the effective interest method.

 

Ares Investment Transactions

On March 3, 2017, certain funds (the “Purchasers”) managed indirectly by Ares Management LLC (“Ares”) purchased from the Company for cash (i) $125.0 million aggregate principal amount of its Convertible Notes due 2022 (“Notes”) sold at par, which Notes, subject to the receipt of approval of the Company’s stockholders which was obtained on May 2, 2017, are convertible into common stock, par value $0.001 per share of the Company (the “Common Stock”) or, in certain circumstances, cash in lieu of Common Stock or a combination of cash and shares of Common Stock as described below and (ii) 29,408,305 shares of Common Stock for a purchase price of $50.0 million.  In addition, an affiliate of Ares concurrently loaned the Company $250.0 million pursuant to the Third Amended and Restated Credit Agreement among the Company (the “Term Loan”), as borrower, the guarantors party thereto, AF V Energy I Holdings, L.P., a fund managed indirectly by Ares, as lender, and Wilmington Trust, National Association, as Administrative Agent as further described below.  The proceeds from the sale of the Notes, the Common Stock and the Term Loan were used to fully repay and redeem the Company’s prior Revolving Credit Facility (as defined below) and to satisfy and discharge its $325.0 million of 8.625% senior secured notes due May 2018, which were satisfied and discharged on March 3, 2017 by irrevocably calling for redemption and depositing with the indenture trustee cash in the amount of the redemption price of 102.156% of their principal amount plus accrued and unpaid interest to the redemption date of March 24, 2017, and to pay the expenses from the Ares transactions.  

 

15


In order to provide funding for the STACK Leasehold Acquisition and a portion of the Company’s 2017 capital budget, on March 21, 2017, the Purchasers purchased from the Company for cash an additional $75.0 million aggregate principal amount of its Notes sold at par (t he “Additional Notes”).  

The Notes, including the Additional Notes, were issued with conversion rights that were subject to the approval of holders of issued and outstanding Common Stock (other than the Purchasers), which approval was obtained May 2, 2017 (the “Requisite Stockholder Approval”).  Pursuant to the purchase agreement for the Additional Notes, upon receipt of Requisite Stockholder Approval, Purchasers and the Company exchanged $37.5 million principal amount of the Additional Notes for (a) 25,456,521 newly issued shares of Common Stock (the “Repurchase Shares”) and (b) 2,000 shares of the Company’s Special Voting Preferred Stock, par value $0.01 per share (the “Mandatory Repurchase”).  The terms of Mandatory Repurchase, which was effected May 5, 2017, provided for one Repurchase Share issued for each $1.4731 of outstanding principal of the repurchased Notes, which was based on the 10-day volume weighted average trading price (“VWAP”) of the Common Stock for the period ended March 17, 2017.  The exchange reduced the aggregate principal amount of issued and outstanding Notes from $200.0 million to $162.5 million at June 30, 2017, which principal amount remains outstanding at September 30, 2017.

Term Loan

On March 3, 2017, the Company entered into a credit agreement for the Term Loan. The Term Loan bears interest at a per annum rate equal to 8.5%, payable on a quarterly basis on each March 31, June 30, September 30 and December 31 of each year, commencing March 31, 2017.  The Term Loan has a scheduled maturity of March 3, 2022.  In addition, the Term Loan is subject to an interest “make-whole” and repayment premium, such that any repayment or prepayment of the loans thereunder prior to the stated maturity date shall be subject to the payment of a repayment premium, and depending on the date of such repayment or prepayment, the applicable interest “make-whole” amount, with the amount of such repayment premium decreasing over the life of the Term Loan.

The Term Loan is guaranteed by the Company’s sole domestic subsidiary and will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Term Loan. The Term Loan is secured by a first-priority lien on substantially all of the assets of the Company and its subsidiaries, excluding certain assets as customary exceptions.

The Term Loan contains various customary covenants for credit facilities of this type, including, among others, restrictions on granting liens, incurrence of other indebtedness, payments of certain dividends and other restricted payments, engaging in transactions with affiliates, dispositions of assets and other, in each case subject to certain baskets and exceptions, and at September 30, 2017, the Company was in compliance with such covenants.  

All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including among others (i) failure to make payments; (ii) non-performance of covenants and obligations continuing beyond any applicable grace period; and (iii) the occurrence of a change in control of the Company, as defined in the Term Loan.

The Company accounted for the Term Loan in accordance with guidance relating to “ Debt with Conversion and Other Options ” which indicates that when multiple securities are issued in a single transaction, total proceeds should be allocated based on the relative fair values of each instrument, assuming no instrument is subsequently required to be recorded at fair value.  The fair value of the Term Loan at the date of issuance was determined to be at a discounted $224.8 million based on the fair value of similar debt instruments.  The $25.2 million debt discount related to the Term Loan and the $5.5 million on issuance costs associated with the Term Loan will be amortized over the life of the Term Loan using the effective interest method.  The effective interest rate for the Term Loan is approximately 13%.

On March 20, 2017, the Company, together with the parties thereto, entered into an Amendment No. 1 to the Term Loan which amendment permitted the issuance of the Additional Notes.  

On August 2, 2017, the Company, together with the parties thereto, entered into an Amendment No. 2 to Term Loan (“Amendment No. 2”).  Amendment No. 2 amended the Term Loan, to among other things, (i) allow for the payment of pay in kind (“PIK”) interest on the Term Loan at the applicable PIK percentage and (ii) increased the applicable rate for periods ending after June 30, 2017 from 8.5% per annum to 10.25% per annum.  Amendment No. 2 allows the Company to elect to PIK upon proper notice 100% of interest payments due after June 30, 2017 and prior to December 31, 2018 and at the Company’s election, PIK between 0% and 50% of any interest payments occurring after December 31, 2018 (other than interest due on the maturity date or the date of any repayment or prepayment).  The Term Loan interest rate increased to 10.25% for all interest periods post June 30, 2017 and the PIK interest shall be payable by capitalizing and adding such amounts to the outstanding principal amount of the Term Loan on the applicable interest payment date.

 

16


On September 18, 2017, the Company, together with the parties thereto, entered into an Amendment No. 3 to the Term Loan (“Amendment No. 3”).  Amendment No. 3 amended t he Term Loan to, among other things, expressly provide that certain assignments of oil and natural gas properties made or to be made by the Company to Red Bluff, pursuant to the Red Bluff PSA, are permitted by the Term Loan and are not subject to the manda tory prepayment provisions applicable to “Asset Sales” under the Term Loan.          

A carrying amount of the Term Loan for the period indicated is as follows:

 

 

 

September 30, 2017

 

 

 

(in thousands)

 

 

 

 

 

 

Term Loan, principal balance (1)

 

$

250,000

 

Less:

 

 

 

 

Unamortized deferred financing costs (2)

 

 

(4,909

)

Unamortized debt discount (2)

 

 

(22,958

)

Term loan, net

 

$

222,133

 

 

(1)

Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time.

(2)

The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan based on the effective interest method.

 

Indenture and Notes

On March 3, 2017, the Company entered into an indenture (the “Indenture”) by and among the Company, the subsidiary guarantor named therein, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral trustee, with respect to the Notes. The principal terms of the Notes are governed by the Indenture. Pursuant to the Indenture, the Notes were issued for cash at par, bear interest at 6.0% per annum and will mature on March 1, 2022, unless earlier repurchased, redeemed or converted in accordance with the terms of the Indenture. Interest is payable on the Notes on each March 1, June 1, September 1 and December 1 of each year, commencing on June 1, 2017.  

Pursuant to the Indenture, Requisite Stockholder Approval was required on or before July 3, 2017 to approve the conversion rights of the Notes (including the Additional Notes) to be convertible at the option of the holder into shares of Common Stock based on the terms of the Indenture.  Requisite Stockholder Approval was obtained on May 2, 2017 at a special meeting of stockholders.  

The interest rate on the Notes was subject to an increase in certain circumstances if the Company fails to comply with certain obligations under a Registration Rights Agreement described in “Note 7 – Capital Stock” below, and on the Notes in the case of certain issuances of Common Stock by the Company at a price below $1.7002 per share (subject to adjustment).

The Notes are secured by a second-priority lien on substantially all of the assets of the Company. If at least a majority of the Notes issued pursuant to the Securities Purchase Agreement dated February 16, 2017 (the “Purchase Agreement”) cease to be held by affiliates of Ares as provided in the Indenture, the liens securing the Notes will be released and substantially all of the restrictive covenants in the Indenture will terminate.  

The Indenture restricts the ability of the Company and certain of its subsidiaries to, among other things: (i) pay dividends or make other distributions in respect of the Company’s capital stock or make other restricted payments; (ii) incur additional indebtedness and issue preferred stock; (iii) make certain dispositions and transfers of assets; (iv) engage in transactions with affiliates; (v) create liens; (vi) engage in certain business activities that are not related to oil and gas; and (vii) impair any security interest. These covenants are subject to a number of exceptions and qualifications. 

The Indenture provides that a number of events will constitute an Event of Default (as defined in the Indenture), including, among other things: (i) a failure to pay the Notes when due at maturity, upon redemption or repurchase; (ii) failure to pay interest for 30 days; (iii) the Company’s failure to deliver certain notices; (iv) a default in the Company’s obligation to convert the Notes; (v) the Company’s failure to comply with certain covenants relating to merger, consolidation or sale of assets; (vi) the Company’s failure to comply, for 60 days following notice, with any of the other covenants or agreements in the Indenture; (vii) a default, which is not cured within 30 days, by the Company or any Restricted Subsidiaries (as defined in the Indenture) with respect to any mortgages or any indebtedness for money borrowed of at least $15 million; (viii) one or more final judgments against the Company or any of its Restricted Subsidiaries for the payment of at least $15 million; (ix) the Company’s failure to make any payments required under that certain development agreement; (x) causing any Guarantee (as defined in the Indenture) to cease to be in full force and effect; (xi) the

 

17


cessation to be in full force and effect of any of the collateral agreements entered into with respect to the Notes; and (xii) certain events of bankruptcy or in solvency. In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to the Company, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately.  At September 30, 2017, no Event of Default had occurred.    

In accordance with accounting guidance relating to “ Debt with Conversion and Other Options” which indicates that when multiple securities are issued in a single transaction, total proceeds should be allocated based on the relative fair values of each instrument, assuming no instrument is subsequently required to be recorded at fair value.  The Company accounted for the Notes based on their relative fair value to the bundled transaction and subsequently separately accounted for the liability and equity conversion components of the Notes due to the Company’s option to settle the conversion obligation in cash.  The fair value of the debt portion of the Notes, excluding the conversion feature, at the dates of issuance was estimated to be approximately $147.8 million and was calculated based on the fair value of similar non-convertible debt instruments in conjunction with the relative fair value of the Term Loan issued on the same date.  As a result of such valuation, a debt discount of $52.4 million related to the Notes was recorded.  Additionally, the value of the conversion option at the dates of issuance was calculated to be $77.6 million based on the residual fair value after application of such to the debt and was recorded as additional paid-in capital on the Company’s condensed consolidated balance sheet.  Total debt issuance costs related to the Notes were $5.4 million, of which $3.2 million was allocated to the liability component of the Notes and $2.2 million to the equity component of the Notes.  The debt discount and the liability component of the debt issuance costs will be amortized over the term of the Notes.  The weighted average effective interest rate used to amortize the debt discount and the liability component of the debt issue costs for the Notes is approximately 15% based on the Company’s estimated non-convertible borrowing rate as of the date the Notes were initially issued.  Since the Company incurred losses for all periods, the impact of the conversion option would be anti-dilutive to the earnings per share and therefore was not included in the calculation.

The carrying amount of the liability component of the Notes for the period indicated is as follows:

 

 

 

September 30, 2017