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s

 

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, 2019

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: 001-36511

 

Montage Resources Corporation

(Exact name of registrant as specified in its charter)

 

 

Delaware

46-4812998

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

 

 

122 West John Carpenter Freeway, Suite 300

Irving, TX

75039

(Address of principal executive offices)

(Zip code)

(469) 444-1647

(Registrant’s telephone number, including area code)

 

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

 

Title of each class

 

Trading Symbol(s)

 

Name of each exchange on which registered

Common Stock, Par Value $0.01 Per Share

 

MR

 

New York Stock Exchange

 

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 every Interactive Data File required to be submitted 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 such files).    ☒  Yes    ☐ No

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

 

Large accelerated filer

 

☐

  

Accelerated filer

 

☒

 

 

 

 

Non-accelerated filer

 

☐  

  

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

Number of shares of the registrant’s common stock outstanding at November 4, 2019: 35,809,858 shares

 

 

 

 

 

 

MONTAGE RESOURCES CORPORATION

QUARTERLY REPORT ON FORM 10-Q

TABLE OF CONTENTS

 

 

 

 

2

 

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Quarterly Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and income or losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “will,” “plan,” “would,” “could,” “endeavor,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are or were, when made, based on our current expectations and assumptions about future events and are or were, when made, based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described in “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the Securities and Exchange Commission (the “SEC”) on March 15, 2019.

Forward-looking statements may include statements about, among other things:

 

•

realized prices for natural gas, natural gas liquids (“NGLs”) and oil and the volatility of those prices;

 

•

write-downs of our natural gas and oil asset values due to declines in commodity prices;

 

•

our business strategy;

 

•

our reserves, including the impact of current commodity prices on our estimated year end reserves;

 

•

general economic conditions;

 

•

our financial strategy, liquidity and capital required for developing our properties and the timing related thereto;

 

•

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

 

•

our hedging strategy and results;

 

•

future drilling plans;

 

•

competition and government regulations, including those related to hydraulic fracturing;

 

•

the anticipated benefits under our commercial agreements;

 

•

marketing of natural gas, NGLs and oil;

 

•

leasehold and business acquisitions, including our acquisition of Blue Ridge Mountain Resources, Inc., and joint ventures;

 

•

leasehold terms expiring before production can be established and our costs to extend such terms;

 

•

the costs, terms and availability of gathering, processing, fractionation and other midstream services;

 

•

credit markets;

 

•

uncertainty regarding our future operating results, including initial production rates and liquid yields in our type curve areas; and

 

•

plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, legal and environmental risks, drilling and other operating risks, regulatory changes, commodity price volatility and the significant decline of the price of natural gas, NGLs and oil from historic highs, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, risks associated with our level of indebtedness, the timing of development expenditures, and the other risks described in “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the SEC on March 15, 2019.

3

 

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect new information obtained or events or circumstances that occur after the date of this Quarterly Report.

 

 

4

 

PART I - FINANCIAL INFORMATION

Item 1.

Financial Statements

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

 

 

 

September 30,

2019

 

 

December 31,

2018

 

ASSETS

 

 

 

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

11,531

 

 

$

5,959

 

Accounts receivable

 

 

77,154

 

 

 

119,332

 

Assets held for sale

 

 

1,485

 

 

 

—

 

Other current assets

 

 

35,239

 

 

 

8,639

 

Total current assets

 

 

125,409

 

 

 

133,930

 

 

 

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT

 

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method:

 

 

 

 

 

 

 

 

Unproved properties

 

 

520,941

 

 

 

482,475

 

Proved oil and gas properties, net

 

 

1,210,876

 

 

 

807,583

 

Other property and equipment, net

 

 

12,349

 

 

 

6,300

 

Total property and equipment, net

 

 

1,744,166

 

 

 

1,296,358

 

 

 

 

 

 

 

 

 

 

OTHER NONCURRENT ASSETS

 

 

 

 

 

 

 

 

Other assets

 

 

9,278

 

 

 

3,481

 

Operating lease right-of-use assets

 

 

42,936

 

 

 

—

 

Assets held for sale

 

 

8,724

 

 

 

—

 

TOTAL ASSETS

 

$

1,930,513

 

 

$

1,433,769

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

 

 

 

Accounts payable

 

$

122,141

 

 

$

116,735

 

Accrued capital expenditures

 

 

51,785

 

 

 

12,979

 

Accrued liabilities

 

 

52,081

 

 

 

56,909

 

Accrued interest payable

 

 

11,137

 

 

 

21,661

 

Liabilities associated with assets held for sale

 

 

4,568

 

 

 

—

 

Operating lease liability

 

 

12,889

 

 

 

—

 

Total current liabilities

 

 

254,601

 

 

 

208,284

 

 

 

 

 

 

 

 

 

 

NONCURRENT LIABILITIES

 

 

 

 

 

 

 

 

Debt, net of unamortized discount and debt issuance costs

 

 

499,848

 

 

 

497,778

 

Revolving credit facility

 

 

127,500

 

 

 

32,500

 

Asset retirement obligations

 

 

27,169

 

 

 

7,110

 

Other liabilities

 

 

2,296

 

 

 

611

 

Operating lease liability

 

 

30,185

 

 

 

—

 

Liabilities associated with assets held for sale

 

 

6,900

 

 

 

—

 

Total liabilities

 

 

948,499

 

 

 

746,283

 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

 

 

 

STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

 

Preferred stock, 50,000,000 authorized, no shares issued and outstanding

 

 

—

 

 

 

—

 

Common stock, $0.01 par value, 1,000,000,000 authorized, 35,756,088

   and 20,169,063 shares issued and outstanding, respectively

 

 

382

 

 

 

3,043

 

Additional paid in capital

 

 

2,350,072

 

 

 

2,065,119

 

Treasury stock, shares at cost; 2,488,525 and 1,747,624 shares, respectively

 

 

(8,819

)

 

 

(3,357

)

Accumulated deficit

 

 

(1,359,621

)

 

 

(1,377,319

)

Total stockholders’ equity

 

 

982,014

 

 

 

687,486

 

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

 

$

1,930,513

 

 

$

1,433,769

 

 

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

5

 

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(In thousands, except per share data)

(Unaudited)

 

 

 

For the Three Months Ended

September 30,

 

 

For the Nine Months Ended

September 30,

 

 

 

2019

 

 

2018

 

 

2019

 

 

2018

 

REVENUES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, oil and natural gas liquids sales

 

$

153,021

 

 

$

127,179

 

 

$

428,278

 

 

$

340,620

 

Brokered natural gas and marketing revenue

 

 

10,228

 

 

 

2,944

 

 

 

31,747

 

 

 

3,318

 

Other revenue

 

 

46

 

 

 

—

 

 

 

307

 

 

 

—

 

Total revenues

 

 

163,295

 

 

 

130,123

 

 

 

460,332

 

 

 

343,938

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

11,986

 

 

 

5,312

 

 

 

29,651

 

 

 

22,026

 

Transportation, gathering and compression

 

 

57,027

 

 

 

39,066

 

 

 

150,065

 

 

 

98,126

 

Production and ad valorem taxes

 

 

1,660

 

 

 

2,604

 

 

 

8,519

 

 

 

7,226

 

Brokered natural gas and marketing expense

 

 

10,574

 

 

 

3,237

 

 

 

32,017

 

 

 

3,715

 

Depreciation, depletion, amortization and accretion

 

 

45,456

 

 

 

34,439

 

 

 

113,950

 

 

 

98,672

 

Exploration

 

 

16,621

 

 

 

11,328

 

 

 

48,602

 

 

 

36,227

 

General and administrative

 

 

14,580

 

 

 

12,937

 

 

 

57,074

 

 

 

33,391

 

Rig termination and standby

 

 

1,221

 

 

 

—

 

 

 

1,221

 

 

 

—

 

(Gain) loss on sale of assets

 

 

(733

)

 

 

6

 

 

 

(731

)

 

 

(1,814

)

Other expense

 

 

2

 

 

 

—

 

 

 

40

 

 

 

—

 

Total operating expenses

 

 

158,394

 

 

 

108,929

 

 

 

440,408

 

 

 

297,569

 

OPERATING INCOME

 

 

4,901

 

 

 

21,194

 

 

 

19,924

 

 

 

46,369

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivative instruments

 

 

15,812

 

 

 

(3,263

)

 

 

40,620

 

 

 

(24,055

)

Interest expense, net

 

 

(15,192

)

 

 

(13,932

)

 

 

(44,140

)

 

 

(39,975

)

Other income (expense)

 

 

—

 

 

 

(1

)

 

 

8

 

 

 

(1

)

Total other income (expense), net

 

 

620

 

 

 

(17,196

)

 

 

(3,512

)

 

 

(64,031

)

INCOME (LOSS) FROM CONTINUING OPERATIONS

   BEFORE INCOME TAXES

 

 

5,521

 

 

 

3,998

 

 

 

16,412

 

 

 

(17,662

)

Income tax benefit (expense)

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

INCOME (LOSS) FROM CONTINUING OPERATIONS

 

 

5,521

 

 

 

3,998

 

 

 

16,412

 

 

 

(17,662

)

Income (loss) from discontinued operations, net of income tax

 

 

(1,237

)

 

 

—

 

 

 

1,286

 

 

 

—

 

NET INCOME (LOSS)

 

$

4,284

 

 

$

3,998

 

 

$

17,698

 

 

$

(17,662

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EARNINGS (LOSS) PER SHARE OF COMMON STOCK

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common stock outstanding

 

 

35,684

 

 

 

20,144

 

 

 

32,343

 

 

 

19,947

 

Income (loss) from continuing operations

 

$

0.15

 

 

$

0.20

 

 

$

0.51

 

 

$

(0.89

)

Income (loss) from discontinued operations

 

 

(0.03

)

 

 

—

 

 

 

0.04

 

 

 

—

 

Net income (loss)

 

$

0.12

 

 

$

0.20

 

 

$

0.55

 

 

$

(0.89

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common stock outstanding

 

 

35,697

 

 

 

20,170

 

 

 

32,471

 

 

 

19,947

 

Income (loss) from continuing operations

 

$

0.15

 

 

$

0.20

 

 

$

0.51

 

 

$

(0.89

)

Income (loss) from discontinued operations

 

 

(0.03

)

 

 

—

 

 

 

0.04

 

 

 

—

 

Net income (loss)

 

$

0.12

 

 

$

0.20

 

 

$

0.55

 

 

$

(0.89

)

 

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

 

6

 

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

 

 

 

Number of

Shares

 

 

Common

Stock

($0.01 Par)

 

 

Additional

Paid-in-

Capital

 

 

Treasury

Stock

 

 

Accumulated

Deficit

 

 

Total

 

Balances, December 31, 2017

 

 

17,516,024

 

 

$

2,637

 

 

$

1,967,958

 

 

$

(2,096

)

 

$

(1,396,145

)

 

$

572,354

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

1,981

 

 

 

—

 

 

 

—

 

 

 

1,981

 

Equity issuance costs

 

 

—

 

 

 

—

 

 

 

(145

)

 

 

—

 

 

 

—

 

 

 

(145

)

Shares of common stock

   issued in asset acquisition,

   net of equity issuance costs

 

 

2,521,573

 

 

 

378

 

 

 

89,642

 

 

 

—

 

 

 

—

 

 

 

90,020

 

Issuance of common stock upon vesting of equity-

   based compensation awards, net of shares

   withheld for income tax withholdings

 

 

80,477

 

 

 

18

 

 

 

(18

)

 

 

(935

)

 

 

—

 

 

 

(935

)

Net loss

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

(2,624

)

 

 

(2,624

)

Balances, March 31, 2018

 

 

20,118,074

 

 

$

3,033

 

 

$

2,059,418

 

 

$

(3,031

)

 

$

(1,398,769

)

 

$

660,651

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

1,979

 

 

—

 

 

—

 

 

 

1,979

 

Equity issuance costs

 

 

—

 

 

 

—

 

 

 

(25

)

 

—

 

 

—

 

 

 

(25

)

Issuance of restricted stock

 

 

15,476

 

 

 

2

 

 

 

(2

)

 

—

 

 

—

 

 

 

—

 

Issuance of common stock upon vesting of equity-

   based compensation awards, net of shares

   withheld for income tax withholdings

 

 

21,452

 

 

 

5

 

 

 

(5

)

 

 

(205

)

 

—

 

 

 

(205

)

Net loss

 

 

—

 

 

—

 

 

—

 

 

—

 

 

 

(19,036

)

 

 

(19,036

)

Balances, June 30, 2018

 

 

20,155,002

 

 

$

3,040

 

 

$

2,061,365

 

 

$

(3,236

)

 

$

(1,417,805

)

 

$

643,364

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

2,171

 

 

 

—

 

 

 

—

 

 

 

2,171

 

Equity issuance costs

 

 

—

 

 

 

—

 

 

 

(137

)

 

 

—

 

 

 

—

 

 

 

(137

)

Issuance of common stock upon vesting of equity-

   based compensation awards, net of shares

   withheld for income tax withholdings

 

 

14,061

 

 

 

3

 

 

 

(3

)

 

 

(121

)

 

 

—

 

 

 

(121

)

Net income

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

3,998

 

 

 

3,998

 

Balances, September 30, 2018

 

 

20,169,063

 

 

$

3,043

 

 

$

2,063,396

 

 

$

(3,357

)

 

$

(1,413,807

)

 

$

649,275

 

7

 

 

 

 

Number of

Shares

 

 

Common

Stock

($0.01 Par)

 

 

Additional

Paid-in-

Capital

 

 

Treasury

Stock

 

 

Accumulated

Deficit

 

 

Total

 

Balances, December 31, 2018

 

 

20,169,063

 

 

$

3,043

 

 

$

2,065,119

 

 

$

(3,357

)

 

$

(1,377,319

)

 

$

687,486

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

6,001

 

 

 

—

 

 

 

—

 

 

 

6,001

 

Equity issuance costs

 

 

—

 

 

 

—

 

 

 

(30

)

 

 

—

 

 

 

—

 

 

 

(30

)

Shares of common stock issued in merger,

   net of equity issuance costs

 

 

15,013,520

 

 

 

150

 

 

 

275,609

 

 

 

—

 

 

 

—

 

 

 

275,759

 

Reverse split 1:15

 

 

—

 

 

 

(2,833

)

 

 

2,833

 

 

 

—

 

 

 

—

 

 

 

—

 

Issuance of common stock upon vesting of equity-

   based compensation awards, net of shares

   withheld for income tax withholdings

 

 

499,897

 

 

 

22

 

 

 

(5

)

 

 

(5,411

)

 

 

—

 

 

 

(5,394

)

Net loss

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

(14,098

)

 

 

(14,098

)

Balances, March 31, 2019

 

 

35,682,480

 

 

$

382

 

 

$

2,349,527

 

 

$

(8,768

)

 

$

(1,391,417

)

 

$

949,724

 

Stock-based compensation

 

—

 

 

—

 

 

 

552

 

 

—

 

 

—

 

 

 

552

 

Equity issuance costs

 

—

 

 

—

 

 

 

(925

)

 

—

 

 

—

 

 

 

(925

)

Issuance of common stock upon vesting of equity-

   based compensation awards, net of shares

   withheld for income tax withholdings

 

 

4,727

 

 

—

 

 

—

 

 

$

(26

)

 

  —

 

 

 

(26

)

Net income

 

—

 

 

—

 

 

—

 

 

—

 

 

 

27,512

 

 

 

27,512

 

Balances, June 30, 2019

 

 

35,687,207

 

 

$

382

 

 

$

2,349,154

 

 

$

(8,794

)

 

$

(1,363,905

)

 

$

976,837

 

Stock-based compensation

 

 

—

 

 

 

—

 

 

 

1,061

 

 

 

—

 

 

 

—

 

 

 

1,061

 

Issuance of restricted stock

 

 

50,568

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Issuance of common stock upon vesting of equity-

   based compensation awards, net of shares

   withheld for income tax withholdings

 

 

18,313

 

 

 

—

 

 

 

(143

)

 

 

(25

)

 

 

—

 

 

 

(168

)

Net income

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

4,284

 

 

 

4,284

 

Balances, September 30, 2019

 

 

35,756,088

 

 

$

382

 

 

$

2,350,072

 

 

$

(8,819

)

 

$

(1,359,621

)

 

$

982,014

 

 

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

 

8

 

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

 

For the Nine Months Ended

September 30,

 

 

 

2019

 

 

2018

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

Net income (loss)

 

$

17,698

 

 

$

(17,662

)

Adjustments to reconcile net loss to net cash provided by operating activities

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

 

114,331

 

 

 

98,672

 

Exploration expense

 

 

36,193

 

 

 

20,827

 

Stock-based compensation

 

 

7,614

 

 

 

6,131

 

Net cash for plugging wells

 

 

(444

)

 

 

—

 

(Gain) loss on derivative instruments

 

 

(40,620

)

 

 

24,055

 

Net cash receipts (payments) on settled derivatives

 

 

11,072

 

 

 

(7,724

)

Gain on sale of assets

 

 

(734

)

 

 

(1,814

)

Amortization of deferred financing costs

 

 

2,160

 

 

 

1,677

 

Amortization of debt discount

 

 

998

 

 

 

995

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

68,056

 

 

 

(48,601

)

Other assets

 

 

619

 

 

 

(2,144

)

Accounts payable and accrued liabilities

 

 

(40,634

)

 

 

18,989

 

Net cash provided by operating activities

 

 

176,309

 

 

 

93,401

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

Capital expenditures for oil and gas properties

 

 

(268,768

)

 

 

(210,612

)

Capital expenditures for other property and equipment

 

 

(576

)

 

 

(892

)

Proceeds from sale of assets

 

 

1,810

 

 

 

10,348

 

Cash proceeds from merger

 

 

12,894

 

 

 

—

 

Change in deposits and other long-term assets

 

 

(53

)

 

 

—

 

Net cash used in investing activities

 

 

(254,693

)

 

 

(201,156

)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

 

Debt issuance costs

 

 

(4,242

)

 

 

(108

)

Repayments of long-term debt

 

 

(260

)

 

 

(381

)

Proceeds from revolving credit facility

 

 

95,000

 

 

 

99,000

 

Equity issuance costs

 

 

(31

)

 

 

(307

)

Employee tax withholding for settlement of equity

   compensation awards

 

 

(6,511

)

 

 

(1,261

)

Net cash provided by financing activities

 

 

83,956

 

 

 

96,943

 

Net increase (decrease) in cash and cash equivalents

 

 

5,572

 

 

 

(10,812

)

Cash and cash equivalents at beginning of period

 

 

5,959

 

 

 

17,224

 

Cash and cash equivalents at end of period

 

$

11,531

 

 

$

6,412

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW

   INFORMATION

 

 

 

 

 

 

 

 

Cash paid for interest

 

$

51,280

 

 

$

49,280

 

SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES

 

 

 

 

 

 

 

 

Asset retirement obligations incurred, including changes in

   estimate

 

$

1,006

 

 

$

388

 

Additions of other property through debt financing

 

$

—

 

 

$

174

 

Additions to oil and natural gas properties - changes in

   accounts payable, accrued liabilities,

   and accrued capital expenditures

 

$

16,583

 

 

$

3,988

 

Asset acquisition through stock issuance

 

$

—

 

 

$

90,020

 

BRMR Merger consideration

 

$

275,759

 

 

$

—

 

 

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

 

9

 

MONTAGE RESOURCES CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

Note 1—Organization and Nature of Operations

Montage Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale, Indian Castle/Flat Creek Shales and Marcellus Shale prospective areas.

 

 

Note 2—Basis of Presentation

The accompanying Condensed Consolidated Financial Statements are unaudited except the Condensed Consolidated Balance Sheet at December 31, 2018, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. All such adjustments are of a normal recurring nature. These interim Condensed Consolidated Financial Statements should be read in conjunction with the audited Consolidated Financial Statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 15, 2019.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2019 or any other future periods.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the Condensed Consolidated Financial Statements are the following:

 

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion and impairment of capitalized costs of oil and natural gas properties;

 

•

estimates of asset retirement obligations;

 

•

estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;

 

•

impairment of undeveloped properties and other assets; and

 

•

depreciation and depletion of property and equipment.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

 

 

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of September 30, 2019 or December 31, 2018.

10

 

The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales prices and transportation and compression fees.

(c) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion, amortization and accretion expense (see “Depreciation, Depletion, Amortization and Accretion” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s Condensed Consolidated Statements of Operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s Condensed Consolidated Balance Sheets. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s Condensed Consolidated Statements of Operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

 

 

 

September 30, 2019

 

 

December 31, 2018

 

Oil and natural gas properties:

 

 

 

 

 

 

 

 

Unproved

 

$

520,941

 

 

$

482,475

 

Proved

 

 

2,702,202

 

 

 

2,188,233

 

Gross oil and natural gas properties

 

 

3,223,143

 

 

 

2,670,708

 

Less accumulated depreciation, depletion and

   amortization

 

 

(1,491,326

)

 

 

(1,380,650

)

Oil and natural gas properties, net

 

 

1,731,817

 

 

 

1,290,058

 

Other property and equipment

 

 

21,935

 

 

 

14,460

 

Less accumulated depreciation

 

 

(9,586

)

 

 

(8,160

)

Other property and equipment, net

 

 

12,349

 

 

 

6,300

 

Property and equipment, net

 

$

1,744,166

 

 

$

1,296,358

 

 

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, and not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

Other Property and Equipment

Other property and equipment includes land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

11

 

(d) Revenue Recognition

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas.  The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials and certain downstream costs incurred by third parties.  The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to process and transport NGLs prior to the delivery point are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials and certain costs incurred by third parties. The Company transfers control of the product from the central stabilization facilities and well pads to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third-party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs.  The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

The following table illustrates the revenue disaggregated by type for the three and nine months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended

September 30,

 

 

Nine Months Ended

September 30,

 

 

 

2019

 

 

2018

 

 

2019

 

 

2018

 

Revenues (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

87,841

 

 

$

65,756

 

 

$

264,030

 

 

$

178,648

 

NGL sales

 

 

20,200

 

 

 

25,074

 

 

 

60,841

 

 

 

63,520

 

Oil sales

 

 

44,980

 

 

 

36,349

 

 

 

103,407

 

 

 

98,452

 

Brokered natural gas and marketing revenue

 

 

10,228

 

 

 

2,944

 

 

 

31,747

 

 

 

3,318

 

Other revenue

 

 

46

 

 

 

—

 

 

 

307

 

 

 

—

 

Total revenues

 

$

163,295

 

 

$

130,123

 

 

$

460,332

 

 

$

343,938

 

 

12

 

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations are part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.  Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.  Accounts receivable attributable to the Company’s revenue contracts with customers was $57.2 million and $94.1 million at September 30, 2019 and December 31, 2018, respectively.

(e) Concentration of Credit Risk

The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances (if any), by product or service as of September 30, 2019 and December 31, 2018 (in thousands):

 

 

 

September 30, 2019

 

 

December 31, 2018

 

Receivables by product or service:

 

 

 

 

 

 

 

 

Sale of oil and natural gas and related products

   and services

 

$

57,245

 

 

$

94,107

 

Joint interest owners

 

 

16,305

 

 

 

24,830

 

Derivatives

 

 

366

 

 

 

372

 

Other

 

 

3,238

 

 

 

23

 

Total

 

$

77,154

 

 

$

119,332

 

 

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the States of Ohio, Pennsylvania and West Virginia. As a general policy, collateral is not required for receivables, but customers’ financial condition and creditworthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of the counterparties to these derivative instruments. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. Such counterparties are not required to provide credit support to the Company. The fair value of the Company’s unsettled commodity derivative contracts was a net asset position of $28.1 million and $5.7 million at September 30, 2019 and December 31, 2018, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s derivative contracts. As of September 30, 2019 and December 31, 2018, the Company did not have past-due receivables from or payables to any of such counterparties.

 

13

 

(f) Depreciation, Depletion, Amortization and Accretion

Oil and Natural Gas Properties

Depreciation, depletion, amortization and accretion (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties, including accretion expense, totaled approximately $44.9 million and $34.0 million for the three months ended September 30, 2019 and 2018, respectively, and $112.4 million and $97.3 million for the nine months ended September 30, 2019 and 2018, respectively, and is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from five to 40 years. Depreciation totaled approximately $0.6 million and $0.4 million for the three months ended September 30, 2019 and 2018, respectively, and $1.6 million and $1.4 million for the nine months ended September 30, 2019 and 2018, respectively. This amount is included in depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations.

(g) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review for impairment of the Company’s oil and gas properties is performed by determining whether the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.  There were no impairments of proved properties for the three or nine months ended September 30, 2019 or the three or nine months ended September 30, 2018.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $14.1 million and $7.0 million for the three months ended September 30, 2019 and 2018, respectively, and $36.2 million and $20.6 million for the nine months ended September 30, 2019 and 2018, respectively. These costs are included in exploration expense in the Condensed Consolidated Statements of Operations.

14

 

(h) Income Taxes

The Company accounts for income taxes under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not (i.e. a likelihood greater than 50 percent) that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

The Company applies Topic 740’s intra-period income tax allocation rules using the with and without approach, to allocate income tax expense (benefit) among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital as required.

(i) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.  The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

(j) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the Condensed Consolidated Balance Sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying Condensed Consolidated Balance Sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the Condensed Consolidated Statements of Operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

15

 

(k) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate.

Estimating the future ARO requires management to make estimates and judgments based on historical information regarding timing and existence of a liability, as well as what constitutes adequate restoration.  Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the nine months ended September 30, 2019 (in thousands):

 

 

 

Nine Months Ended September 30, 2019

 

Asset retirement obligations, beginning of period

 

$

7,110

 

Accretion

 

 

1,688

 

Additional liabilities incurred

 

 

267

 

Obligation for wells acquired

 

 

20,188

 

Obligation for wells drilled

 

 

445

 

Liabilities settled via plugging

 

 

(387

)

Less: current ARO portion (accrued liabilities)

 

 

(2,142

)

Asset retirement obligations, end of period

 

$

27,169

 

 

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(l) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(m) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(n) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

16

 

(o) Recent Accounting Pronouncements

Recently Adopted

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Entities are required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases’ classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements.” The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements,” which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.

The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third-party-sponsored lease accounting information system to facilitate the accounting and financial reporting requirements, and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment.  See Note 7 – Leases for the disclosures required by the standards.

 

Note 4—Acquisitions

Eclipse Resources-PA, LP Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania, from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 2.5 million shares of the Company’s common stock (the “Flat Castle Acquisition”).  The transaction was accounted for as an asset acquisition.  Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired.  In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.  

During the year ended December 31, 2018, the Company assigned its option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC, which owns midstream infrastructure with associated gathering rights on acreage in the Indian Castle and Flat Creek Shales, to a third party.  The third party exercised its option to purchase all of the outstanding equity interests of Cardinal in July 2018.

Merger with Blue Ridge Mountain Resources

On February 28, 2019, the Company completed its business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc. (“Merger Sub”), a Delaware corporation and a wholly owned subsidiary of the Company, and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock split (See Note 13— Net Income (Loss) Per Share). Former stockholders of BRMR received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement. 

17

 

The following table summarizes the preliminary purchase price allocation and the values of assets acquired and liabilities assumed (in thousands):

 

Purchase Price

 

February 28, 2019

 

Fair value of the Company's common stock issued

 

$

263,487

 

Fair value of BRMR share-based and other compensation

 

 

12,272

 

Total Fair Value of Consideration

 

$

275,759

 

 

 

 

 

 

Cash and cash equivalents

 

 

12,894

 

Accounts receivable

 

 

25,884

 

Assets held for sale - current

 

 

2,296

 

Other current assets

 

 

1,702

 

Unproved properties

 

 

84,742

 

Proved oil and gas properties

 

 

218,866

 

Other property and equipment

 

 

7,059

 

Other assets

 

 

2,461

 

Operating lease right-of-use asset

 

 

7,900

 

Assets held for sale - long-term

 

 

8,505

 

Total assets acquired

 

$

372,309

 

Accounts payable

 

 

(16,571

)

Accrued capital expenditures

 

 

(5,807

)

Accrued liabilities

 

 

(31,619

)

Operating lease liability - current

 

 

(1,977

)

Liabilities associated with assets held for sale - current

 

 

(7,683

)

Asset retirement obligations

 

 

(20,188

)

Operating lease liability - noncurrent

 

 

(5,923

)

Liabilities associated with assets held for sale - long-term

 

 

(6,782

)

Total liabilities assumed

 

$

(96,550

)

 

 

 

 

 

Net identifiable assets

 

$

275,759

 

 

The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs.  The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighed average cost of capital rate.  The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin.  These inputs required significant judgements and estimates by management at the time of the valuation and are the most sensitive to possible future changes.

The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018.  The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.

 

 

 

For the Three Months Ended

September 30,

 

 

For the Nine Months Ended

September 30,

 

(in thousands, except per share data) (unaudited)

 

2019

 

 

2018

 

 

2019

 

 

2018

 

Pro forma total revenues

 

$

163,294

 

 

$

176,925

 

 

$

502,989

 

 

$

451,761

 

Pro forma net income (loss)

 

$

8,220

 

 

$

10,127

 

 

$

26,638

 

 

$

(30,160

)

Pro forma net income (loss) per share (basic and diluted)

 

$

0.23

 

 

$

0.28

 

 

$

0.75

 

 

$

(0.85

)

 

18

 

 

Note 5—Sale of Oil and Natural Gas Property Interests

During the nine months ended September 30, 2018, the Company received approximately $6.0 million from a completed asset sale of approximately 1,000 acres to a third party.  As a result of this sale, the Company recognized a gain of approximately $1.5 million.

During the nine months ended September 30, 2018, the Company received approximately $3.8 million from a completed asset sale of approximately 400 acres to a third party.  No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the nine months ended September 30, 2018, the Company received approximately $0.3 million from an additional completed asset sale of approximately 50 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $0.3 million.

During the nine months ended September 30, 2019, the Company received $1.8 million from acreage trades from various working interest owners which resulted in a gain of approximately $0.7 million.

 

Note 6—Assets Held for Sale and Discontinued Operations

Assets Held for Sale

As a result of the BRMR Merger, the Company acquired certain assets that met the criteria for assets held for sale at the acquisition date, comprised of the net assets of Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of BRMR.  These assets are located primarily in Kentucky and Tennessee.

The following summarizes assets and liabilities held for sale at September 30, 2019:

 

(in thousands)

 

September 30, 2019

 

Accounts receivable

 

$

605

 

Other current assets

 

 

880

 

Total current assets held for sale

 

$

1,485

 

 

 

 

 

 

Proved oil and gas properties, net

 

$

8,552

 

Other noncurrent assets

 

 

172

 

Total noncurrent assets held for sale

 

$

8,724

 

 

 

 

 

 

Accounts payable

 

$

3,489

 

Accrued liabilities

 

 

525

 

Other current liabilities

 

 

554

 

Total current liabilities associated with assets held for sale

 

$

4,568

 

 

 

 

 

 

Asset retirement obligations

 

$

6,346

 

Other liabilities

 

 

554

 

Total noncurrent liabilities associated with assets held for sale

 

$

6,900

 

 

19

 

Discontinued Operations

The Company determined that the planned divestiture of MHP met the assets held for sale criteria and the criteria for classification as discontinued operations as of September 30, 2019.  The Company included the results of operations for MHP for the three and nine months ended September 30, 2019 in discontinued operations as follows:

 

(in thousands)

 

For the Three

Months Ended

September 30, 2019

 

 

For the Nine Months Ended

September 30, 2019

 

Revenues

 

$

1,874

 

 

$

5,402

 

Depreciation, depletion, amortization and accretion

 

 

(168

)

 

 

(380

)

Other operating expenses

 

 

(2,943

)

 

 

(3,738

)

Other income

 

 

—

 

 

 

2

 

Income (loss) from discontinued operations, net of tax

 

 

(1,237

)

 

 

1,286

 

Gain on disposal of discontinued operations, net of tax

 

 

—

 

 

 

—

 

Income (loss) from discontinued operations, net of tax

 

$

(1,237

)

 

$

1,286

 

 

The Company had maintained an accrued liability of $3.5 million related to litigation involving MHP and a third-party regarding certain royalty and overriding royalty deductions and related payments under several farm-out agreements.  The litigation concluded in April 2019 and, as a result, the Company removed the accrued liability and recognized corresponding income from discontinued operations for the nine months ended September 30, 2019.

Total operating and investing cash flows of discontinued operations for the nine months ended September 30, 2019 were as follows:

 

(in thousands)

 

For the Nine Months Ended

September 30, 2019

 

Net cash provided by operating activities

 

$

1,189

 

Net cash provided by investing activities

 

$

14

 

 

Note 7—Leases

The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036.  Certain lease agreements may include options to renew the lease, terminate the lease early, or purchase the underlying asset(s).  The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including the options to extend or terminate the lease when such an option is reasonably certain to be exercised.

As discussed in Note 3—Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using the optional transition method of adoption.  The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification, and (iii) initial direct costs.  In addition, the Company elected the following practical expedients for all asset classes: (i) to not reassess certain land easements, (ii) to not apply the recognition requirements under the standard to short-term leases, and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense.

On January 1, 2019, the Company recorded a total of $10.4 million in right-of-use assets and corresponding new lease liabilities on its Condensed Consolidated Balance Sheets representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of 12 months or less, taking into account extensions if reasonably certain to be exercised, are considered short-term leases and are not recorded on the balance sheet.

20

 

The Company incurred $4.3 million and $12.2 million in operating lease cost during the three and nine months ended September 30, 2019, respectively.  The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in current liabilities and noncurrent liabilities, respectively, on the Condensed Consolidated Balance Sheets. As of September 30, 2019, the operating right-of-use assets were $42.9 million and operating lease liabilities were $43.1 million, of which $12.9 million was classified as current. As of September 30, 2019, the weighted average remaining lease term was 4.0 years and the weighted average discount rate was 5.4%.

Supplemental cash flow information related to the Company’s operating leases is included in the table below (in thousands):

 

 

 

For the Nine Months Ended

September 30, 2019

 

Cash paid for amounts included in the measurement of lease

   liabilities:

 

 

 

 

Operating cash flows for operating leases

 

$

3,851

 

Investing cash flows for operating leases

 

$

8,394

 

ROU assets added in exchange for lease obligations

   (upon adoption)

 

$

10,434

 

ROU assets and lease obligations acquired in BRMR Merger

 

$

7,900

 

ROU assets added in exchange for lease obligations,

   net of terminations (since adoption)

 

$

34,331

 

 

The Company’s lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):

 

 

 

Operating Leases

 

Remainder of 2019

 

$

3,653

 

2020

 

 

15,034

 

2021

 

 

13,616

 

2022

 

 

6,158

 

2023

 

 

4,259

 

Thereafter

 

 

5,424

 

Total lease payments

 

$

48,144

 

Less imputed interest

 

 

(5,070

)

Total lease liability

 

$

43,074

 

 

Note 8—Derivative Instruments

Commodity Derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps, options and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

21

 

The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of September 30, 2019, the Company’s derivative instruments were with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, EDF Energy, J Aron, KeyBank N.A., Morgan Stanley, NextEra Energy, Inc., Royal Bank of Canada, and Wells Fargo. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of September 30, 2019, for future production periods:

Natural Gas Derivatives:

 

Description

 

Volume

(MMBtu/d)

 

 

Production Period

 

Weighted Average

Price ($/MMBtu)

 

Natural Gas Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

120,000

 

 

October 2019 – December 2019

 

$

2.80

 

 

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.67

 

 

 

 

20,000

 

 

January 2020 – March 2020

 

$

2.80

 

 

 

 

50,000

 

 

January 2020 – June 2020

 

$

2.70

 

 

 

 

20,000

 

 

April 2020 – June 2020

 

$

2.75

 

 

 

 

30,000

 

 

July 2020 – December 2020

 

$

2.60

 

Natural Gas Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

95,000

 

 

October 2019 – December 2019

 

$

2.60

 

Ceiling sold price (call)

 

 

95,000

 

 

October 2019 – December 2019

 

$

2.91

 

Floor purchase price (put)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.49

 

Ceiling sold price (call)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.88

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.65

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.98

 

Floor purchase price (put)

 

 

15,000

 

 

April 2020 – June 2020

 

$

2.50

 

Ceiling sold price (call)

 

 

15,000

 

 

April 2020 – June 2020

 

$

2.80

 

Natural Gas Three-way Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

77,500

 

 

October 2019 – December 2019

 

$

2.72

 

Floor sold price (put)

 

 

77,500

 

 

October 2019 – December 2019

 

$

2.30

 

Ceiling sold price (call)

 

 

77,500

 

 

October 2019 – December 2019

 

$

3.04

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – December 2020

 

$

2.70

 

Floor sold price (put)

 

 

30,000

 

 

January 2020 – December 2020

 

$

2.40

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – December 2020

 

$

3.05

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.72

 

Floor sold price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.25

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – March 2020

 

$

3.15

 

Floor purchase price (put)

 

 

20,000

 

 

January 2020 – June 2020

 

$

2.70

 

Floor sold price (put)

 

 

20,000

 

 

January 2020 – June 2020

 

$

2.25

 

Ceiling sold price (call)

 

 

20,000

 

 

January 2020 – June 2020

 

$

3.05

 

Floor purchase price (put)

 

 

30,000

 

 

October 2019 – June 2020

 

$

2.90

 

Floor sold price (put)

 

 

30,000

 

 

October 2019 – June 2020

 

$

2.50

 

Ceiling sold price (call)

 

 

30,000

 

 

October 2019 – June 2020

 

$

3.15

 

Natural Gas Call/Put Options:

 

 

 

 

 

 

 

 

 

 

Ceiling sold price (call)

 

 

40,000

 

 

October 2019 – December 2019

 

$

3.44

 

Floor sold price (put)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.30

 

Floor sold price (put)

 

 

50,000

 

 

January 2020 – June 2020

 

$

2.25

 

Swaption sold price (call)

 

 

50,000

 

 

January 2021 – December 2021

 

$

2.75

 

Swaption sold price (call)

 

 

50,000

 

 

January 2022 – December 2022

 

$

3.00

 

Basis Swaps:

 

 

 

 

 

 

 

 

 

 

Appalachia - Dominion

 

 

12,500

 

 

October 2019

 

$

(0.52

)

Appalachia - Dominion

 

 

12,500

 

 

April 2020 – October 2020

 

$

(0.52

)

Appalachia - Dominion

 

 

20,000

 

 

January 2020 – December 2020

 

$

(0.59

)

Appalachia - Dominion

 

 

20,000

 

 

October 2019 – March 2020

 

$

(0.39

)

Appalachia - Dominion

 

 

17,500

 

 

October 2019 – December 2019

 

$

(0.50

)

22

 

 

Oil Derivatives:

 

Description

 

Volume

(Bbls/d)

 

 

Production Period

 

Weighted Average

Price ($/Bbl)

 

Oil Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

1,500

 

 

October 2019 – December 2019

 

$

59.18

 

 

 

 

1,000

 

 

January 2020 – December 2020

 

$

58.60

 

 

 

 

1,000

 

 

July 2020 – December 2020

 

$

56.53

 

Oil Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

1,500

 

 

October 2019 – December 2019

 

$

51.67

 

Ceiling sold price (call)

 

 

1,500

 

 

October 2019 – December 2019

 

$

65.92

 

Floor purchase price (put)

 

 

1,000

 

 

January 2020 – December 2020

 

$

51.50

 

Ceiling sold price (call)

 

 

1,000

 

 

January 2020 – December 2020

 

$

64.25

 

Floor purchase price (put)

 

 

500

 

 

July 2020 – December 2020

 

$

52.00

 

Ceiling sold price (call)

 

 

500

 

 

July 2020 – December 2020

 

$

60.00

 

Floor purchase price (put)

 

 

500

 

 

October 2019 – March 2020

 

$

60.00

 

Ceiling sold price (call)

 

 

500

 

 

October 2019 – March 2020

 

$

67.00

 

Oil Three-way Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

2,000

 

 

October 2019 – December 2019

 

$

50.00

 

Floor sold price (put)

 

 

2,000

 

 

October 2019 – December 2019

 

$

40.00

 

Ceiling sold price (call)

 

 

2,000

 

 

October 2019 – December 2019

 

$

60.56

 

Floor purchase price (put)

 

 

2,000

 

 

January 2020 – June 2020

 

$

62.50

 

Floor sold price (put)

 

 

2,000

 

 

January 2020 – June 2020

 

$

55.00

 

Ceiling sold price (call)

 

 

2,000

 

 

January 2020 – June 2020

 

$

74.00

 

Oil Call/Put Options:

 

 

 

 

 

 

 

 

 

 

Swaption sold price (call)

 

 

500

 

 

January 2021 – December 2021

 

$

56.80

 

 

NGL Derivatives:

 

Description

 

Volume

(Bbls/d)

 

 

Production Period

 

Weighted Average

Price ($/Bbl)

 

Propane Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

350

 

 

October 2019 – December 2019

 

$

39.90

 

 

Fair Values and Gains (Losses)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the Condensed Consolidated Balance Sheets (in thousands). None of the derivative instruments are designated as a hedge for accounting purposes.

 

As of September 30, 2019

 

Gross

Amount

 

 

Netting

Adjustments(a)

 

 

Net Amount

Presented in

Balance Sheets

 

 

Balance

Sheet

Location

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

32,344

 

 

$

(3,279

)

 

 

29,065

 

 

Other

current assets

Commodity derivatives - noncurrent

 

 

2,816

 

 

 

(699

)

 

 

2,117

 

 

Other assets

Total assets

 

$

35,160

 

 

$

(3,978

)

 

$

31,182

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

(4,232

)

 

$

3,279

 

 

$

(953

)

 

Accrued

liabilities

Commodity derivatives - noncurrent

 

 

(2,804

)

 

 

699

 

 

 

(2,105

)

 

Other liabilities

Total liabilities

 

$

(7,036

)

 

$

3,978

 

 

$

(3,058

)

 

 

23

 

 

As of December 31, 2018

 

Gross

Amount

 

 

Netting

Adjustments(a)

 

 

Net Amount

Presented in

Balance Sheets

 

 

Balance

Sheet

Location

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

4,960

 

 

$

(845

)

 

$

4,115

 

 

Other

current assets

Commodity derivatives - noncurrent

 

 

1,910

 

 

 

—

 

 

 

1,910

 

 

Other assets

Total assets

 

$

6,870

 

 

$

(845

)

 

$

6,025

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives - current

 

$

(845

)

 

$

845

 

 

$

—

 

 

Accrued

liabilities

Commodity derivatives - noncurrent

 

 

(326

)

 

 

—

 

 

 

(326

)

 

Other liabilities

Total liabilities

 

$

(1,171

)

 

$

845

 

 

$

(326

)

 

 

 

(a)

The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the Condensed Consolidated Statements of Operations for the periods presented (in thousands):

 

 

 

 

 

Amount of Gain (Loss)

Recognized in Income

 

Derivatives not designated as hedging

instruments under ASC 815

 

Location of Gain (Loss)

Recognized in Income

 

Three Months Ended

September 30,

 

 

Nine Months Ended

September 30,

 

 

 

 

 

2019

 

 

2018

 

 

2019

 

 

2018

 

Commodity derivatives

 

Gain (loss) on derivative instruments

 

$

15,812

 

 

$

(3,263

)

 

$

40,620

 

 

$

(24,055

)

 

 

Note 9—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the Condensed Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality, and therefore, generally have no unobservable inputs, they are classified as Level 2.

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total Fair Value

 

As of September 30, 2019: (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

—

 

 

$

28,124

 

 

$

—

 

 

$

28,124

 

Total

 

$

—

 

 

$

28,124

 

 

$

—

 

 

$

28,124

 

As of December 31, 2018: (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

—

 

 

$

5,699

 

 

$

—

 

 

$

5,699

 

Total

 

$

—

 

 

$

5,699

 

 

$

—

 

 

$

5,699

 

 

24

 

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 10—Debt).

 

 

Note 10—Debt

8.875% Senior Unsecured Notes Due 2023

On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding senior PIK notes. The Company used the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes.

During the three and nine months ended September 30, 2019, the Company amortized $0.9 million and $3.2 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.  The Company amortized $0.9 million and $2.7 million of deferred financing costs and debt discount to interest expense using the effective interest method for the three and nine months ended September 30, 2018, respectively. 

The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture at September 30, 2019.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at September 30, 2019 was $390.7 million.

25

 

Revolving Credit Facility

During the first quarter of 2014, Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”) entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).

The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was amended and restated on January 12, 2015. The primary change effected by such amendment was to add the Company as a party to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Montage Resources Corporation (f/k/a Eclipse Resources Corporation) rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended the Credit Agreement to, among other things, adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense (as such terms are defined in the Credit Agreement), and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5%.

On February 24, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020.  In addition, this amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Consolidated Total Funded Net Debt (as defined in the Credit Agreement) to EBITDAX.  On August 1, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $175 million to $225 million.  

On February 28, 2019, the Company amended and restated the Credit Agreement to increase its revolving credit facility from $500 million to $1 billion.  Further, the amended and restated Credit Agreement, among other things, increased the borrowing base from $225 million to $375 million (subject to scheduled and interim redeterminations based on the Company’s oil and natural gas reserves and other adjustments described therein) and extended the maturity date thereof to February 2024 (subject to earlier maturity in certain circumstances specified therein).  The amended and restated Credit Agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX to provide that the Company will not, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2019), permit its ratio of Consolidated Total Funded Net Debt to EBITDAX for the four previous fiscal quarters to be greater than 4.00 to 1.00.  

On May 6, 2019, the borrowing base under the Credit Agreement was redetermined, which increased the borrowing base from $375 million to $400 million.

On September 19, 2019, the Company entered into an additional amendment to the Credit Agreement to, among other things, confirm the redetermination of the borrowing base under the Credit Agreement, which increased the borrowing base from $400 million to $500 million.

At September 30, 2019, the borrowing base was $500 million and the Company had $127.5 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $29.2 million and the outstanding borrowings of $127.5 million, the Company had available borrowing capacity under the revolving credit facility of $343.3 million at September 30, 2019.  

The revolving credit facility is secured by mortgages on 85% of the value of the Company’s proved reserves and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of September 30, 2019. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization.

 

26

 

Note 11—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, as amended (“the Code”), under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(k) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.3 million for each of the three months ended September 30, 2019 and 2018, and $0.8 million and $0.7 million for the nine months ended September 30, 2019 and 2018, respectively.

 

Note 12—Stock-Based Compensation

At the Company’s 2019 Annual Meeting of Stockholders held on June 14, 2019, the Company’s stockholders approved the Company’s 2019 Long-Term Incentive Plan (the “2019 Plan”), which was previously approved by the Company’s Board of Directors.  The 2019 Plan replaces the Company’s 2014 Long-Term Incentive Plan, as amended (the “Prior Plan”).  Upon stockholder approval, (i) the 2019 Plan became effective, and (ii) the Prior Plan terminated and no additional awards will be granted under the Prior Plan; provided that awards outstanding under the Prior Plan as of the date the 2019 Plan became effective will remain in full force and effect under the Prior Plan according to their respective terms.

The Company is authorized to grant up to 2,650,000 shares of common stock under the 2019 Plan.  The 2019 Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 1,778,895 shares were available for future grants under the Plan as of September 30, 2019.

Stock-based compensation expense was as follows for the three and nine months ended September 30, 2019 and 2018 (in thousands):

 

 

 

Three Months Ended September 30,

 

 

Nine Months Ended September 30,

 

 

 

2019

 

 

2018

 

 

2019

 

 

2018

 

Restricted stock units

 

$

445

 

 

$

1,026

 

 

$

3,773

 

 

$

3,164

 

Performance units

 

 

374

 

 

 

1,047

 

 

 

3,364

 

 

 

2,685

 

Restricted and unrestricted stock

 

 

242

 

 

 

98

 

 

 

477

 

 

 

282

 

Total expense

 

$

1,061

 

 

$

2,171

 

 

$

7,614

 

 

$

6,131

 

 

Restricted Stock Units

Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of September 30, 2019, there was $2.8 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the shares to vest is approximately two years. A summary of employee restricted stock unit awards activity during the nine months ended September 30, 2019 is as follows:

 

 

 

Number of

shares

 

 

Weighted

average grant

date fair value

 

 

Aggregate

intrinsic

value (in

thousands)

 

Total awarded and unvested, December 31, 2018

 

 

233,960

 

 

$

29.27

 

 

$

3,685

 

Granted

 

 

407,714

 

 

 

6.46

 

 

 

 

 

Vested

 

 

(212,140

)

 

 

28.71

 

 

 

 

 

Forfeited

 

 

(485

)

 

 

31.78

 

 

 

 

 

Total awarded and unvested, September 30, 2019

 

 

429,049

 

 

$

7.86

 

 

$

1,622

 

 

27

 

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (as defined in the award agreements), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of September 30, 2019, there was $2.0 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the shares to vest is approximately two years. A summary of performance stock unit awards activity during the nine months ended September 30, 2019 is as follows:

 

 

 

Number of

shares

 

 

Weighted

average grant

date fair value

 

 

Aggregate

intrinsic

value (in

thousands)

 

Total awarded and unvested, December 31, 2018

 

 

346,589

 

 

$

27.68

 

 

$

716

 

Granted

 

 

255,419

 

 

 

7.25

 

 

 

 

 

Vested

 

 

(270,068

)

 

 

27.57

 

 

 

 

 

Forfeited

 

 

(16,483

)

 

 

24.60

 

 

 

 

 

Total awarded and unvested, September 30, 2019

 

 

315,457

 

 

$

11.39

 

 

$

—

 

 

The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s stock price.  Prior to 2018, the volatility estimate was tied to the Company’s public peer group.  The following table presents the assumptions used to determine the fair value for performance stock units granted during the nine months ended September 30, 2019 and 2018:

 

 

 

Nine Months Ended September 30,

 

 

 

2019

 

 

2018

 

Volatility

 

 

65.10

%

 

 

89.70

%

Risk-free interest rate

 

 

1.83

%

 

 

2.37

%

 

Restricted and Unrestricted Stock

On May 17, 2017, the Company issued an aggregate of 10,212 restricted shares of common stock to its three non-employee members of its Board of Directors who were not affiliated with the Company’s then controlling stockholder, which shares became fully vested on May 17, 2018.

On May 16, 2018, the Company issued an aggregate of 15,476 restricted shares of common stock to its three non-employee members of its Board of Directors who were not affiliated with the Company’s then controlling stockholder, which shares became fully vested on  May 16, 2019.  

Effective February 28, 2019, the Company issued an aggregate of 70,409 restricted shares of common stock to two of its officers in connection with retention bonus arrangements entered into between the Company and each of these officers.  Twenty-five percent of the restricted shares vested on August 28, 2019, and the remaining 75% of the restricted shares vest in substantially equal installments on February 28, 2020, August 28, 2020 and February 28, 2021.

Pursuant to the Company’s Non-Employee Director Compensation Policy, on June 18, 2019, the Company awarded an aggregate of 53,328 restricted shares of common stock to eight of the non-employee members of its Board of Directors, which shares are scheduled to fully vest on June 18, 2020.  The other non-employee member of the Company’s Board of Directors declined to receive any compensation for his service on the Company’s Board of Directors for 2019.

Pursuant to the Company’s Non-Employee Director Compensation Policy, on August 2, 2019, the Company issued an aggregate of 26,935 unrestricted shares of common stock to four of the non-employee members of its Board of Directors.

 

 

28

 

Note 13—Net Income (Loss) Per Share

Net Income (Loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though the awards are contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.  

Reverse Stock Split

Effective immediately prior to the Effective Time on February 28, 2019 (See Note 4— Acquisitions), the Company effected a 15-to-1 reverse stock split of its common stock.  Holders of shares of the Company’s common stock immediately prior to the Effective Time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the par value to reflect the reduced shares with the offset to additional paid-in-capital.  The table below retroactively reflects, in accordance with ASC 505 “Equity,” the reverse stock split that occurred on February 28, 2019 for the three and nine months ended September 30, 2018.  The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three and nine months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended September 30,

 

(in thousands, except per share data)

 

2019

 

 

2018

 

 

 

Income

 

 

Shares

 

 

Per Share

 

 

Income

 

 

Shares

 

 

Per Share

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income, shares, basic

 

$

4,284

 

 

 

35,684

 

 

$

0.12

 

 

$

3,998

 

 

 

20,144

 

 

$

0.20

 

Weighted-average number of shares of common

   stock-diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock and performance unit awards

 

 

—

 

 

 

13

 

 

 

 

 

 

 

—

 

 

 

26

 

 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income, shares, diluted

 

$

4,284

 

 

 

35,697

 

 

$

0.12

 

 

$

3,998

 

 

 

20,170

 

 

$

0.20

 

 

 

 

Nine Months Ended September 30,

 

(in thousands, except per share data)

 

2019

 

 

2018

 

 

 

Income

 

 

Shares

 

 

Per Share

 

 

Loss

 

 

Shares

 

 

Per Share

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss), shares, basic

 

$

17,698

 

 

 

32,343

 

 

$

0.55

 

 

$

(17,662

)

 

 

19,947

 

 

$

(0.89

)

Weighted-average number of shares of common

   stock-diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock and performance unit awards

 

 

—

 

 

 

127

 

 

 

 

 

 

 

—

 

 

 

—

 

 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss), shares, diluted

 

$

17,698

 

 

 

32,471

 

 

$

0.55

 

 

$

(17,662

)

 

 

19,947

 

 

$

(0.89

)

 

 

Note 14—Related Party Transactions

During the three and nine months ended September 30, 2018, the Company incurred approximately $0.2 million and $0.5 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer.  The Company incurred less than $0.1 million during the nine months ended September 30, 2019, and during the three months ended September 30, 2019, the Company did not incur any expense related to such flight charter services.  The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms.  The Company no longer utilizes any flight charter services under this arrangement.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”).  EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own approximately 40% of the outstanding shares of the Company’s common stock (See Note 4—Acquisitions).

 

 

29

 

Note 15—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

During the nine months ended September 30, 2019, the Company removed an accrued liability related to certain litigation involving MHP (See Note 6— Assets Held for Sale and Discontinued Operations).

(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

(c) Other Commitments

As a result of the BRMR Merger, effective as of February 28, 2019, the Company assumed commitments related to certain firm transportation and gas processing, gathering and compression service agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR, as shown below (in thousands):

 

 

 

Firm

transportation(i)

 

 

Gas processing,

gathering, and

compression

services(ii)

 

 

Total

 

Year Ending December 31:

 

 

 

 

 

 

 

 

 

 

 

 

2019

 

$

14,562

 

 

$

12,873

 

 

$

27,435

 

2020

 

 

19,416

 

 

 

17,133

 

 

 

36,549

 

2021

 

 

19,416

 

 

 

17,087

 

 

 

36,503

 

2022

 

 

19,416

 

 

 

17,087

 

 

 

36,503

 

2023

 

 

18,047

 

 

 

16,561

 

 

 

34,608

 

Thereafter

 

 

92,395

 

 

 

139,545

 

 

 

231,940

 

Total

 

$

183,252

 

 

$

220,286

 

 

$

403,538

 

 

(i)

Firm transportation - Firm transportation agreements with various pipelines to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements its proportionate share of costs based on its working interest.  

(ii)

Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing and gathering agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its Consolidated Financial Statements its proportionate share of costs based on its working interest.

 

 

Note 16—Income Tax

For the year ending December 31, 2019, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items.  The Company expects to incur book income but a tax loss in fiscal year 2019, and thus, no current federal income taxes are anticipated to be paid.  The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss.  On December 22, 2017, the Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, resulted in the reduction in the U.S. statutory rate from 35% to 21%.  The Company’s interest expense deduction has the potential to be limited as a result of the enactment of the Tax Cuts and Jobs Act; however, the impact is anticipated to be minimal as a result of its full valuation allowance.

30

 

In forecasting the 2019 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book income such that no net deferred tax asset is recorded in 2019. Management reached this conclusion considering several factors such as: (i) the lack of carryback potential resulting in a tax refund, and (ii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s balance sheet.

The Company is forecasting positive pre-tax book income for the year ending December 31, 2019.  Management expects that income tax expense attributable to current year operations will be offset by a release of the valuation allowance on hand at the beginning of the year.  As a result, no net income tax expense or benefit is allocable to either income from continuing operations or to discontinued operations.

As a result of the BRMR Merger, BRMR’s pre-acquisition tax loss carryforward (“NOL”) and other tax attributes will be subject to limitation in accordance with ownership change rules under Code section 382, and the Company will have an ownership change which would similarly limit its ability to use pre-acquisition NOLs and other tax attributes.  The Company is still evaluating the impact that Code section 382 will have on both the acquired BRMR tax attributes as well as the Company’s pre-acquisition tax attributes.

 

Note 17—Subsidiary Guarantors

Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, jointly and severally, guarantee the Company’s 8.875% senior unsecured notes.  Each such subsidiary of the Company in existence immediately prior to the BRMR Merger guaranteed the Company’s 8.875% senior unsecured notes.  As a result of the BRMR Merger, and within the timeframe required by the indenture governing the Company’s 8.875% senior unsecured notes, the Company caused BRMR and each of its subsidiaries that guaranteed the Company’s revolving credit facility to guarantee the Company’s 8.875% senior unsecured notes (See Note 10—Debt). Montage Resources Corporation, standing alone, has no independent operations or (other than its equity interests in its subsidiaries) material assets. The Company’s wholly owned subsidiary guarantors are not restricted from transferring funds to Montage Resources Corporation or other wholly owned subsidiary guarantors. The Company’s wholly owned subsidiaries do not have any restricted net assets.

A subsidiary guarantor may be released from its obligations under the senior unsecured notes guarantee:

 

•

in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or

 

•

if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes.

 

 

Note 18—Subsequent Events

Management has evaluated subsequent events and believes there are no events that would have a material impact on the aforementioned financial statements and related disclosures in the accompanying notes to the Condensed Consolidated Financial Statements.

 

 

31

 

Item 2.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018 and our Condensed Consolidated Financial Statements and related notes appearing elsewhere in this Quarterly Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview of Our Business

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin.  On February 28, 2019, we completed a business combination (the “BRMR Merger”) with Blue Ridge Mountain Resources, Inc. (“BRMR”), and immediately thereafter, we changed our legal name from “Eclipse Resources Corporation” to “Montage Resources Corporation.”  Except where the context indicates otherwise, the terms “we,” “us,” “our” or the “Company” as used herein refer, for periods prior to the completion of the BRMR Merger, to Eclipse Resources Corporation and its subsidiaries and, for periods following the completion of the BRMR Merger, to Montage Resources Corporation (“Montage”) and its subsidiaries.

As of September 30, 2019, we had assembled an acreage position approximating 236,700 net acres in Eastern Ohio, 44,600 net acres in Pennsylvania, and 49,700 net acres in West Virginia, which excludes any acreage currently pending title.

Approximately 224,300 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 92,500 net acres of stacked pay opportunity are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio and West Virginia within what we refer to as our Marcellus Area. We are the operator of approximately 98% of our net acreage within the Utica Core Area and our Marcellus Area. We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.

As of September 30, 2019, we were operating one horizontal rig. We had average daily production for the three months ended September 30, 2019 of approximately 621.7 MMcfe comprised of approximately 76% natural gas, 14% NGLs and 10% oil.

The net assets of our subsidiary, Magnum Hunter Production, Inc. (“MHP”), are classified as assets held for sale and liabilities associated with assets held for sale as of September 30, 2019.  All operations of MHP are reflected as discontinued operations for all periods presented.

How We Evaluate Our Operations

In evaluating our current and future financial results, we focus on production and revenue growth, lease operating expense, general and administrative expense (both before and after non-cash stock compensation expense and other unusual or infrequent items) and operating margin per unit of production. In addition to these metrics, we use Adjusted EBITDAX, a non-GAAP measure, to evaluate our financial results. We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion, amortization and accretion (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX is not a measure of net income as determined by generally accepted accounting principles in United States, or “U.S. GAAP.”  See —Non-GAAP Financial Measure for more information.

In addition to the operating metrics above, as we grow our reserve base, we will assess our capital spending by calculating our operated proved developed reserves and our operated proved developed finding costs and development costs. We believe that operated proved developed finding and development costs are one of the key measurements of the performance of an oil and gas exploration and production company. We will focus on our operated properties as we control the location, spending and operations associated with drilling these properties. In determining our proved developed finding and development costs, only cash costs incurred in connection with exploration and development will be used in the calculation, while the costs of acquisitions will be excluded because our board approves each material acquisition. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years will be excluded from the assessment, but any performance related reserve revisions are included.

32

 

We also continually evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our acreage in the Utica Core Area and our Marcellus Area. We review changes in drilling and completion costs, lease operating costs, natural gas, NGLs and oil prices, well productivity, and other factors in order to focus our drilling on the highest rate of return areas within our acreage on a per well basis.

As a result of the closing of the BRMR Merger on February 28, 2019, BRMR’s assets and liabilities are included in the Unaudited Condensed Consolidated Balance Sheet as of September 30, 2019 and BRMR’s revenues and expenses are included in the Unaudited Condensed Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to September 30, 2019 (See Note 4— Acquisitions).

Overview of Results for the Three and Nine Months Ended September 30, 2019

During the three months ended September 30, 2019, we achieved the following financial and operating results:

 

•

our average daily net production for the three months ended September 30, 2019 was 621.7 MMcfe per day representing an increase of 79% over the comparable period of the prior year;

 

•

commenced drilling 4 gross (3.3 net) operated wells, commenced completions of 7 gross (5.2 net) operated wells and turned-to-sales 16 gross (13.9 net) operated wells;

 

•

recognized net income of $4.3 million for the three months ended September 30, 2019 compared to $4.0 million for the three months ended September 30, 2018; and

 

•

realized Adjusted EBITDAX of $83.6 million for the three months ended September 30, 2019 compared to $66.8 million for three months ended September 30, 2018. Adjusted EBITDAX is a non-GAAP financial measure. See —Non-GAAP Financial Measure for more information.

During the nine months ended September 30, 2019, we achieved the following financial and operating results:

 

•

our average daily net production for the nine months ended September 30, 2019 was 522.4 MMcfe per day representing an increase of 62% over the comparable period of the prior year;

 

•

commenced drilling 26 gross (23.1 net) operated wells, commenced completions of 31 gross (25.5 net) operated wells and turned-to-sales 35 gross (27.4 net) operated wells;

 

•

recognized net income (loss) of $17.7 million for the nine months ended September 30, 2019 compared to ($17.7) million for the nine months ended September 30, 2018; and

 

•

realized Adjusted EBITDAX of $223.5 million for the nine months ended September 30, 2019 compared to $180.9 million for the nine months ended September 30, 2018.  Adjusted EBITDAX is a non-GAAP financial measure. See —Non-GAAP Financial Measure for more information.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists the high, low and average daily and monthly settled NYMEX Henry Hub prices for natural gas and the high, low and average daily NYMEX WTI prices for oil for the three and nine months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended

September 30,

 

 

Nine Months Ended

September 30,

 

 

 

2019

 

 

2018

 

 

2019

 

 

2018

 

NYMEX Henry Hub High ($/MMBtu)

 

$

2.75

 

 

$

3.12

 

 

$

4.25

 

 

$

6.24

 

NYMEX Henry Hub Low ($/MMBtu)

 

 

2.02

 

 

 

2.73

 

 

 

2.02

 

 

 

2.49

 

Average Daily NYMEX Henry Hub ($/MMBtu)

 

 

2.38

 

 

 

2.93

 

 

 

2.62

 

 

 

2.95

 

Average Monthly Settled NYMEX Henry Hub ($/MMBtu)

 

 

2.23

 

 

 

2.90

 

 

 

2.67

 

 

 

2.90

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NYMEX WTI High ($/Bbl)

 

$

63.10

 

 

$

74.19

 

 

$

66.24

 

 

$

77.41

 

NYMEX WTI Low ($/Bbl)

 

 

51.14

 

 

 

65.07

 

 

 

46.31

 

 

 

59.20

 

Average Daily NYMEX WTI ($/Bbl)

 

 

56.34

 

 

 

69.69

 

 

 

57.04

 

 

 

66.93

 

 

33

 

Historically, commodity prices have been extremely volatile, and we expect this volatility to continue for the foreseeable future. A decline in commodity prices could materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

The Company is committed to profitably developing its natural gas, NGLs and oil reserves through an environmentally-responsible and cost-effective operational plan.  The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop, its reserves.  Despite the continued low price commodity environment, the Company believes the long-term outlook for its business is favorable due to the Company’s resource base, low cost structure, risk management strategies, and disciplined investment of capital.

It is difficult to quantify the impact of changes in future commodity prices on our reported estimated net proved reserves with any degree of certainty because of the various components and assumptions used in the process.  However, to demonstrate the sensitivity of our estimates of natural gas, NGLs and oil reserves to changes in commodity prices, we provided an analysis in our Annual Report on Form 10-K for the year ended December 31, 2018.  Further, if we recalculated our reserves using the unweighted arithmetic average first-day-of-the-month price for each of the 12 months in the period ended September 30, 2019 and held all other factors constant, then our estimated net proved reserves at December 31, 2018 would have decreased by approximately 3.3% from our previously reported estimated net proved reserves at such time, including a 1.4% reduction of proved developed reserves and a 4.4% reduction of proved undeveloped reserves.  The foregoing estimate is based upon an average SEC price of $2.87 per MMBtu for natural gas and $57.69 per Bbl for oil. This calculation only isolates the potential impact of commodity prices on our estimated proved reserves and does not account for other factors impacting our estimated proved reserves, such as anticipated drilling and completion costs and our production results since December 31, 2018. There are also numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods. As such, this calculation is provided for illustrative purposes only and should not be construed as indicative of our final year-end reserve estimation process.

We consider future commodity prices when determining our development plan, but many other factors are also considered.  To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan. We plan to fund our development budget with a portion of the cash on hand at September 30, 2019, cash flows from operations, borrowings under our revolving credit facility, and proceeds from asset sales.

Results of Operations

The following discussion pertains to our results of operations, including analysis of our continuing operations regarding natural gas, NGLs and oil revenues, production, average product prices and average production costs and expenses for the three months ended September 30, 2019 and 2018.  The results of operations of MHP are reflected as discontinued operations for all periods presented.  

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the three months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Revenues (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

87,841

 

 

$

65,756

 

 

$

22,085

 

NGL sales

 

 

20,200

 

 

 

25,074

 

 

 

(4,874

)

Oil sales

 

 

44,980

 

 

 

36,349

 

 

 

8,631

 

Brokered natural gas and marketing revenue

 

 

10,228

 

 

 

2,944

 

 

 

7,284

 

Other revenue

 

 

46

 

 

 

—

 

 

 

46

 

Total revenues

 

$

163,295

 

 

$

130,123

 

 

$

33,172

 

 

34

 

Our production grew by approximately 25.3 Bcfe for the three months ended September 30, 2019 over the same period in 2018 due to increased drilling activity and from wells acquired as part of the BRMR Merger. Our production for the three months ended September 30, 2019 and 2018 is set forth in the following table:

 

 

 

Three Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

43,289.9

 

 

 

22,979.7

 

 

 

20,310.2

 

NGLs (Mbbls)

 

 

1,401.1

 

 

 

906.4

 

 

 

494.7

 

Oil (Mbbls)

 

 

916.2

 

 

 

574.8

 

 

 

341.4

 

Total (MMcfe)

 

 

57,193.7

 

 

 

31,866.9

 

 

 

25,326.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volume:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

470,542

 

 

 

249,779

 

 

 

220,763

 

NGLs (Bbls/d)

 

 

15,229

 

 

 

9,852

 

 

 

5,377

 

Oil (Bbls/d)

 

 

9,959

 

 

 

6,248

 

 

 

3,711

 

Total (Mcfe/d)

 

 

621,670

 

 

 

346,379

 

 

 

275,291

 

 

35

 

Our average realized price (including cash settled derivatives and firm transportation) received during the three months ended September 30, 2019 was $2.56 per Mcfe compared to $3.34 per Mcfe during the three months ended September 30, 2018. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled derivatives and firm transportation) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled derivatives and firm transportation) does not include derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Condensed Consolidated Statements of Operations. Average sales price (including firm transportation and excluding cash settled derivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the three months ended September 30, 2019 and 2018 are shown below:

 

 

 

Three Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Average realized price (excluding cash settled derivatives

   and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.03

 

 

$

2.86

 

 

$

(0.83

)

NGLs ($/Bbl)

 

 

14.42

 

 

 

27.66

 

 

 

(13.24

)

Oil ($/Bbl)

 

 

49.09

 

 

 

63.24

 

 

 

(14.15

)

Total average prices ($/Mcfe)

 

 

2.68

 

 

 

3.99

 

 

 

(1.31

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled derivatives,

   excluding firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.28

 

 

$

2.89

 

 

$

(0.61

)

NGLs ($/Bbl)

 

 

14.92

 

 

 

27.66

 

 

 

(12.74

)

Oil ($/Bbl)

 

 

49.53

 

 

 

52.67

 

 

 

(3.14

)

Total average prices ($/Mcfe)

 

 

2.88

 

 

 

3.82

 

 

 

(0.94

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including firm transportation,

   excluding cash settled derivatives)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

1.60

 

 

$

2.19

 

 

$

(0.59

)

NGLs ($/Bbl)

 

 

14.42

 

 

 

27.66

 

 

 

(13.24

)

Oil ($/Bbl)

 

 

49.09

 

 

 

63.24

 

 

 

(14.15

)

Total average prices ($/Mcfe)

 

 

2.35

 

 

 

3.51

 

 

 

(1.16

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled derivatives

   and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

1.85

 

 

$

2.22

 

 

$

(0.37

)

NGLs ($/Bbl)

 

 

14.92

 

 

 

27.66

 

 

 

(12.74

)

Oil ($/Bbl)

 

 

49.53

 

 

 

52.67

 

 

 

(3.14

)

Total average prices ($/Mcfe)

 

 

2.56

 

 

 

3.34

 

 

 

(0.78

)

 

Brokered natural gas and marketing revenue was $10.2 million for the three months ended September 30, 2019 compared to $2.9 million for the three months ended September 30, 2018.  Brokered natural gas and marketing revenue includes revenue received from selling natural gas not related to production and from the release of firm transportation capacity.  The increase for the three months ended September 30, 2019 was due to an increase in the amount of firm transportation that was available for brokered gas transactions or release to third parties.  

36

 

Costs and Expenses

We believe some of our expense fluctuations are most accurately analyzed on a unit-of-production, or per Mcfe, basis. The following table presents these expenses for the three months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

11,986

 

 

$

5,312

 

 

$

6,674

 

Transportation, gathering and compression

 

 

57,027

 

 

 

39,066

 

 

 

17,961

 

Production and ad valorem taxes

 

 

1,660

 

 

 

2,604

 

 

 

(944

)

Depreciation, depletion, amortization and accretion

 

 

45,456

 

 

 

34,439

 

 

 

11,017

 

General and administrative

 

 

14,580

 

 

 

12,937

 

 

 

1,643

 

Operating expenses per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

0.21

 

 

$

0.17

 

 

$

0.04

 

Transportation, gathering and compression

 

 

0.99

 

 

 

1.21

 

 

 

(0.22

)

Production and ad valorem taxes

 

 

0.03

 

 

 

0.08

 

 

 

(0.05

)

Depreciation, depletion, amortization and accretion

 

 

0.79

 

 

 

1.08

 

 

 

(0.29

)

General and administrative

 

 

0.25

 

 

 

0.41

 

 

 

(0.16

)

 

Lease operating expense was $12.0 million in the three months ended September 30, 2019 compared to $5.3 million in the three months ended September 30, 2018.  Lease operating expense per Mcfe was $0.21 in the three months ended September 30, 2019 compared to $0.17 in the three months ended September 30, 2018.  The increase of $6.7 million was primarily attributable to an increase in the number of producing wells.  The increase of $0.04 per Mcfe was primarily due to increased water disposal costs for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018.  Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.  

Transportation, gathering and compression expense was $57.0 million during the three months ended September 30, 2019 compared to $39.1 million during the three months ended September 30, 2018.  Transportation, gathering and compression expense per Mcfe was $0.99 in the three months ended September 30, 2019 compared to $1.21 in the three months ended September 30, 2018.  The following table details our transportation, gathering and compression expenses for the three months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Transportation, gathering and compression (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

18,346

 

 

$

10,732

 

 

$

7,614

 

Processing and fractionation

 

 

17,894

 

 

 

10,588

 

 

 

7,306

 

Liquids transportation and stabilization

 

 

2,320

 

 

 

2,326

 

 

 

(6

)

Marketing

 

 

—

 

 

 

12

 

 

 

(12

)

Firm transportation

 

 

18,467

 

 

 

15,408

 

 

 

3,059

 

 

 

$

57,027

 

 

$

39,066

 

 

$

17,961

 

Transportation, gathering and compression per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

0.32

 

 

$

0.33

 

 

$

(0.01

)

Processing and fractionation

 

 

0.31

 

 

 

0.33

 

 

 

(0.02

)

Liquids transportation and stabilization

 

 

0.04

 

 

 

0.07

 

 

 

(0.03

)

Marketing

 

 

—

 

 

 

—

 

 

 

—

 

Firm transportation

 

 

0.32

 

 

 

0.48

 

 

 

(0.16

)

 

 

$

0.99

 

 

$

1.21

 

 

$

(0.22

)

 

The increase of $18.0 million to transportation, gathering and compression expenses during the three months ended September 30, 2019 was primarily due to increased firm transportation capacity and increased production during the three months ended September 30, 2019.  The decrease of $0.22 per Mcfe was primarily due to a higher percentage of production attributable to natural gas and fixed firm transportation costs spread across increased production during the three months ended September 30, 2019.

 

37

 

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $1.7 million in the three months ended September 30, 2019 compared to $2.6 million in the three months ended September 30, 2018. Production and ad valorem taxes per Mcfe was $0.03 for the three months ended September 30, 2019 compared to $0.08 per Mcfe for the three months ended September 30, 2018.  The decrease of $0.9 million and $0.05 per Mcfe was primarily due to the recognition of a refund of production taxes from a state taxing authority partially offset by increased well count for the three months ended September 30, 2019.

Depreciation, depletion, amortization and accretion was approximately $45.5 million in the three months ended September 30, 2019 compared to $34.4 million in the three months ended September 30, 2018. DD&A per Mcfe was $0.79 for the three months ended September 30, 2019 compared to $1.08 for the three months ended September 30, 2018. DD&A increased on an aggregate basis due to increased production in the three months ended September 30, 2019.  DD&A decreased on a per Mcfe basis due to a lower depletion rate resulting from reserves increasing at a higher rate than capital costs for the three months ended September 30, 2019.

General and administrative expense was $14.6 million for the three months ended September 30, 2019 compared to $12.9 million for the three months ended September 30, 2018.  General and administrative expense per Mcfe was $0.25 in the three months ended September 30, 2019 compared to $0.41 in the three months ended September 30, 2018.  The increase of $1.6 million was primarily related to an increase in professional fees.  General and administrative expense included $1.1 million and $2.2 million of stock-based compensation expense as well as $3.3 million and $3.0 million of expenses related to the BRMR Merger for the three months ended September 30, 2019 and 2018, respectively.  The decrease of $0.16 per Mcfe was due to fixed costs spread across increased production during the three months ended September 30, 2019.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. The following table details our other operating expenses for the three months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Other operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Brokered natural gas and marketing expense

 

$

10,574

 

 

$

3,237

 

 

$

7,337

 

Exploration

 

 

16,621

 

 

 

11,328

 

 

 

5,293

 

Rig termination and standby

 

 

1,221

 

 

 

—

 

 

 

1,221

 

(Gain) loss on sale of assets

 

 

(733

)

 

 

6

 

 

 

(739

)

 

Brokered natural gas and marketing expense was $10.6 million for the three months ended September 30, 2019 compared to $3.2 million for the three months ended September 30, 2018.  Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties.  The increase for the three months ended September 30, 2019 was due to an increase in the amount of brokered gas transactions.

Exploration expense was $16.6 million for the three months ended September 30, 2019 compared to $11.3 million for the three months ended September 30, 2018. The following table details our exploration-related expenses for the three months ended September 30, 2019 and 2018:

 

 

 

Three Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Exploration expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Geological and geophysical

 

$

180

 

 

$

182

 

 

$

(2

)

Delay rentals

 

 

2,327

 

 

 

4,082

 

 

 

(1,755

)

Impairment of unproved properties

 

 

14,114

 

 

 

6,971

 

 

 

7,143

 

Dry hole and other

 

 

—

 

 

 

93

 

 

 

(93

)

 

 

$

16,621

 

 

$

11,328

 

 

$

5,293

 

 

38

 

Delay rentals were $2.3 million for the three months ended September 30, 2019 compared to $4.1 million for the three months ended September 30, 2018.  The decrease in delay rental expense related to the reduction in future drilling activity and concentrating renewals in our core acreage area during the three months ended September 30, 2019.

Impairment of unproved properties was $14.1 million for the three months ended September 30, 2019 compared to $7.0 million for the three months ended September 30, 2018. The increase in impairment charges during the three months ended September 30, 2019 was the result of an increase in expected lease expirations due to a reduction in planned future drilling activity.  As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Rig termination and standby expense was $1.2 million for the three months ended September 30, 2019 primarily related to the reduction in development activity during the three months ended September 30, 2019.  There were no rig termination and standby expenses for the three months ended September 30, 2018.

(Gain) loss on sale of assets was ($0.7) million for the three months ended September 30, 2019 compared to less than $0.1 million for the three months ended September 30, 2018.

Other Income (Expense)

Gain (loss) on derivative instruments was $15.8 million for the three months ended September 30, 2019 compared to ($3.3) million for the three months ended September 30, 2018, primarily due to changes in commodity prices during each period. Cash receipts (payments) were approximately $11.8 million and ($5.4) million for derivative instruments that settled during the three months ended September 30, 2019 and 2018, respectively.

Interest expense, net was $15.2 million for the three months ended September 30, 2019 compared to $13.9 million for three months ended September 30, 2018.  Interest expense increased primarily due to our increased borrowings under our revolving credit facility during the three months ended September 30, 2019.

Income tax benefit (expense) was not recognized for the three months ended September 30, 2019 and 2018 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income, respectively.

 

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to our operations for the nine months ended September 30, 2019 and 2018:

 

 

 

Nine Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Revenues (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

264,030

 

 

$

178,648

 

 

$

85,382

 

NGL sales

 

 

60,841

 

 

 

63,520

 

 

 

(2,679

)

Oil sales

 

 

103,407

 

 

 

98,452

 

 

 

4,955

 

Brokered natural gas and marketing revenue

 

 

31,747

 

 

 

3,318

 

 

 

28,429

 

Other revenue

 

 

307

 

 

 

—

 

 

 

307

 

Total revenues

 

$

460,332

 

 

$

343,938

 

 

$

116,394

 

39

 

 

Our production grew by approximately 54.6 Bcfe for the nine months ended September 30, 2019 over the same period in 2018 due to increased drilling activity and from wells acquired as part of the BRMR Merger.  Our production for the nine months ended September 30, 2019 and 2018 is set forth in the following table:

 

 

 

Nine Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

109,613.9

 

 

 

63,308.4

 

 

 

46,305.5

 

NGLs (Mbbls)

 

 

3,414.9

 

 

 

2,492.6

 

 

 

922.3

 

Oil (Mbbls)

 

 

2,083.3

 

 

 

1,629.4

 

 

 

453.9

 

Total (MMcfe)

 

 

142,603.1

 

 

 

88,040.4

 

 

 

54,562.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volume:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf/d)

 

 

401,516

 

 

 

231,899

 

 

 

169,617

 

NGLs (Bbls/d)

 

 

12,509

 

 

 

9,130

 

 

 

3,379

 

Oil (Bbls/d)

 

 

7,631

 

 

 

5,968

 

 

 

1,663

 

Total (Mcfe/d)

 

 

522,356

 

 

 

322,487

 

 

 

199,869

 

 

40

 

Our average realized price (including cash settled derivatives and firm transportation) received during the nine months ended September 30, 2019 was $2.72 per Mcfe compared to $3.39 per Mcfe during the nine months ended September 30, 2018. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled derivatives and firm transportation) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled derivatives and firm transportation) does not include derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying Condensed Consolidated Statements of Operations. Average sales price (including firm transportation and excluding cash settled derivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the nine months ended September 30, 2019 and 2018 are shown below:

 

 

 

Nine Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Average realized price (excluding cash settled

   derivatives and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.41

 

 

$

2.82

 

 

$

(0.41

)

NGLs ($/Bbl)

 

 

17.82

 

 

 

25.48

 

 

 

(7.66

)

Oil ($/Bbl)

 

 

49.64

 

 

 

60.42

 

 

 

(10.78

)

Total average prices ($/Mcfe)

 

 

3.00

 

 

 

3.87

 

 

 

(0.87

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled

   derivatives, excluding firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.49

 

 

$

2.92

 

 

$

(0.43

)

NGLs ($/Bbl)

 

 

18.19

 

 

 

25.11

 

 

 

(6.92

)

Oil ($/Bbl)

 

 

50.15

 

 

 

52.32

 

 

 

(2.17

)

Total average prices ($/Mcfe)

 

 

3.08

 

 

 

3.78

 

 

 

(0.70

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including firm

   transportation, excluding cash settled derivatives)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

1.94

 

 

$

2.28

 

 

$

(0.34

)

NGLs ($/Bbl)

 

 

17.82

 

 

 

25.48

 

 

 

(7.66

)

Oil ($/Bbl)

 

 

49.64

 

 

 

60.42

 

 

 

(10.78

)

Total average prices ($/Mcfe)

 

 

2.64

 

 

 

3.48

 

 

 

(0.84

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized price (including cash settled

   derivatives and firm transportation)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas ($/Mcf)

 

$

2.02

 

 

$

2.38

 

 

$

(0.36

)

NGLs ($/Bbl)

 

 

18.19

 

 

 

25.11

 

 

 

(6.92

)

Oil ($/Bbl)

 

 

50.15

 

 

 

52.32

 

 

 

(2.17

)

Total average prices ($/Mcfe)

 

 

2.72

 

 

 

3.39

 

 

 

(0.67

)

 

Brokered natural gas and marketing revenue was $31.7 million and $3.3 million for the nine months ended September 30, 2019 and 2018, respectively.  Brokered natural gas and marketing revenue includes revenue received from selling natural gas not related to production and from the release of firm transportation capacity.  The increase for the nine months ended September 30, 2019 was due to an increase in the amount of firm transportation that was available for brokered gas transactions or release to third parties.

41

 

Costs and Expenses

We believe some of our expenses are most accurately analyzed on a unit-of-production, or per Mcfe, basis.  The following table presents these expenses for the nine months ended September 30, 2019 and 2018:

 

 

 

Nine Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Operating expenses (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

29,651

 

 

$

22,026

 

 

$

7,625

 

Transportation, gathering and compression

 

 

150,065

 

 

 

98,126

 

 

 

51,939

 

Production and ad valorem taxes

 

 

8,519

 

 

 

7,226

 

 

 

1,293

 

Depreciation, depletion, amortization and accretion

 

 

113,950

 

 

 

98,672

 

 

 

15,278

 

General and administrative

 

 

57,074

 

 

 

33,391

 

 

 

23,683

 

Operating expenses per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

0.21

 

 

$

0.25

 

 

$

(0.04

)

Transportation, gathering and compression

 

 

1.04

 

 

 

1.11

 

 

 

(0.07

)

Production and ad valorem taxes

 

 

0.06

 

 

 

0.08

 

 

 

(0.02

)

Depreciation, depletion, amortization and accretion

 

 

0.80

 

 

 

1.12

 

 

 

(0.32

)

General and administrative

 

 

0.40

 

 

 

0.38

 

 

 

0.02

 

 

Lease operating expense was $29.7 million in the nine months ended September 30, 2019 compared to $22.0 million in the nine months ended September 30, 2018.  Lease operating expense per Mcfe was $0.21 in the nine months ended September 30, 2019 compared to $0.25 in the nine months ended September 30, 2018.  The increase of $7.6 million was primarily attributable to an increase in the number of producing wells.  The decrease of $0.04 per Mcfe was primarily due to a decrease in non-recurring workovers and fixed costs spread across increased production for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.  Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.

Transportation, gathering and compression expense was $150.1 million during the nine months ended September 30, 2019 compared to $98.1 million during the nine months ended September 30, 2018.  Transportation, gathering and compression expense per Mcfe was $1.04 in the nine months ended September 30, 2019 compared to $1.11 in the nine months ended September 30, 2018.  The following table details our transportation, gathering and compression expenses for the nine months ended September 30, 2019 and 2018:

 

 

 

Nine Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Transportation, gathering and compression (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

48,014

 

 

$

30,075

 

 

$

17,939

 

Processing and fractionation

 

 

44,836

 

 

 

27,910

 

 

 

16,926

 

Liquids transportation and stabilization

 

 

5,347

 

 

 

5,679

 

 

 

(332

)

Marketing

 

 

103

 

 

 

15

 

 

 

88

 

Firm transportation

 

 

51,765

 

 

 

34,447

 

 

 

17,318

 

 

 

$

150,065

 

 

$

98,126

 

 

$

51,939

 

Transportation, gathering and compression per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

Gathering, compression and fuel

 

$

0.33

 

 

$

0.34

 

 

$

(0.01

)

Processing and fractionation

 

 

0.31

 

 

 

0.32

 

 

 

(0.01

)

Liquids transportation and stabilization

 

 

0.04

 

 

 

0.06

 

 

 

(0.02

)

Marketing

 

 

—

 

 

 

—

 

 

 

—

 

Firm transportation

 

 

0.36

 

 

 

0.39

 

 

 

(0.03

)

 

 

$

1.04

 

 

$

1.11

 

 

$

(0.07

)

 

The increase of $51.9 million to transportation, gathering and compression expenses during the nine months ended September 30, 2019 was due to increased production and increased firm transportation capacity.  The decrease of $0.07 per Mcfe during the nine months ended September 30, 2019 was primarily due to a higher percentage of production attributable to natural gas and fixed firm transportation costs spread across increased production during the period.

42

 

Production and ad valorem taxes are paid based on market prices and applicable tax rates.  Production and ad valorem taxes were $8.5 million in the nine months ended September 30, 2019 compared to $7.2 million in the nine months ended September 30, 2018.  Production and ad valorem taxes per Mcfe were $0.06 in the nine months ended September 30, 2019 compared to $0.08 in the nine months ended September 30, 2018.  The increase of $1.3 million was primarily due to increased well count for the nine months ended September 30, 2019.  The decrease of $0.02 per Mcfe was primarily due to the recognition of a refund for production taxes from a state taxing authority during the nine months ended September 30, 2019.

Depreciation, depletion, amortization and accretion was approximately $114.0 million in the nine months ended September 30, 2019 compared to $98.7 million in the nine months ended September 30, 2018.  DD&A per Mcfe was $0.80 in the nine months ended September 30, 2019 compared to $1.12 in the nine months ended September 30, 2018.  DD&A increased on an aggregate basis due to increased production in the nine months ended September 30, 2019.  DD&A decreased on a per Mcfe basis due to a lower depletion rate resulting from reserves increasing at a higher rate than capital costs for the nine months ended September 30, 2019.

General and administrative expense was $57.1 million for the nine months ended September 30, 2019 compared to $33.4 million for the nine months ended September 30, 2018.  General and administrative expense per Mcfe was $0.40 in the nine months ended September 30, 2019 compared to $0.38 in the nine months ended September 30, 2018.  The increase of $23.7 million and $0.02 per Mcfe was primarily related to approximately $18.8 million of expenses related to the BRMR Merger incurred in the nine months ended September 30, 2019.  General and administrative expense included $7.6 million and $6.1 million of stock-based compensation for the nine months ended September 30, 2019 and 2018, respectively.  

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production.  The following table details our other operating expenses for the nine months ended September 30, 2019 and 2018:

 

 

 

Nine Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Other operating expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Brokered natural gas and marketing expense

 

$

32,017

 

 

$

3,715

 

 

$

28,302

 

Exploration

 

 

48,602

 

 

 

36,227

 

 

 

12,375

 

Rig termination and standby

 

 

1,221

 

 

 

—

 

 

 

1,221

 

Gain on sale of assets

 

 

(731

)

 

 

(1,814

)

 

 

1,083

 

 

Brokered natural gas and marketing expense was $32.0 million for the nine months ended September 30, 2019 compared to $3.7 million for the nine months ended September 30, 2018.  Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties.  The increase for the nine months ended September 30, 2019 was due to an increase in the amount of brokered gas transactions.

Exploration expense was $48.6 million for the nine months ended September 30, 2019 compared to $36.2 million for the nine months ended September 30, 2018.  The following table details our exploration-related expenses for the nine months ended September 30, 2019 and 2018:

 

 

 

Nine Months Ended

September 30,

 

 

 

 

 

 

 

2019

 

 

2018

 

 

Change

 

Exploration expenses (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Geological and geophysical

 

$

643

 

 

$

1,015

 

 

$

(372

)

Delay rentals

 

 

11,639

 

 

 

14,385

 

 

 

(2,746

)

Impairment of unproved properties

 

 

36,157

 

 

 

20,638

 

 

 

15,519

 

Dry hole and other

 

 

163

 

 

 

189

 

 

 

(26

)

 

 

$

48,602

 

 

$

36,227

 

 

$

12,375

 

 

Delay rentals were $11.6 million for the nine months ended September 30, 2019 compared to $14.4 million for the nine months ended September 30, 2018.  The decrease in delay rental expenses related to the reduction in future drilling activity and concentrating renewals in our core acreage area during the nine months ended September 30, 2019.

43

 

Impairment of unproved properties was $36.2 million for the nine months ended September 30, 2019 compared to $20.6 million for the nine months ended September 30, 2018.  The increase in impairment charges during the nine months ended September 30, 2019 was the result of an increase in expected lease expirations due to a reduction in planned future drilling activity.  As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Rig termination and standby expense was $1.2 million for the nine months ended September 30, 2019 primarily related to the reduction in development activity during the nine months ended September 30, 2019.  There were no rig termination and standby expenses for the nine months ended September 30, 2018.

Gain on sale of assets was $0.7 million for the nine months ended September 30, 2019 compared to $1.8 million for the nine months ended September 30, 2018.

Other Income (Expense)

Gain (loss) on derivative instruments was $40.6 million for the nine months ended September 30, 2019 compared to ($24.1) million for the nine months ended September 30, 2018, primarily due to changes in commodity prices during each period.  Cash receipts (payments) were approximately $11.1 million and ($7.7) million for derivative instruments that settled during the nine months ended September 30, 2019 and 2018, respectively.

Interest expense, net was $44.1 million for the nine months ended September 30, 2019 compared to $40.0 million for the nine months ended September 30, 2018.  The increase in interest expense primarily related to our increased borrowings under our revolving credit facility during the nine months ended September 30, 2019.

Income tax benefit (expense) was not recognized for the nine months ended September 30, 2019 and 2018 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income.

Cash Flows, Capital Resources and Liquidity

Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices. Our cash flows from operations also are impacted by changes in working capital. Short-term liquidity needs are satisfied by our operating cash flow, proceeds from asset sales, borrowings under our revolving credit facility, and issuances of debt and equity securities.  We sell a large portion of our production at the wellhead under floating market contracts.

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

Net cash provided by operations in the nine months ended September 30, 2019 was $176.3 million compared to $93.4 million in the nine months ended September 30, 2018. The increase in cash provided by operating activities reflects working capital changes, operating income and timing of cash receipts and disbursements during the year-over-year comparative periods.

Net cash used in investing activities in the nine months ended September 30, 2019 was $254.7 million compared to $201.2 million in the nine months ended September 30, 2018.

During the nine months ended September 30, 2019, we:

 

•

spent $268.8 million on capital expenditures for oil and natural gas properties;

 

•

received $1.8 million from asset sales; and

 

•

received $12.9 million as part of the assets acquired in the BRMR Merger.

44

 

During the nine months ended September 30, 2018, we:

 

•

spent $210.6 million on capital expenditures for oil and gas properties;

 

•

spent $0.9 million on property and equipment; and

 

•

received $10.3 million of proceeds relating to the sale of assets.

Net cash provided by financing activities in the nine months ended September 30, 2019 was $84.0 million compared to $96.9 million in the nine months ended September 30, 2018.

During the nine months ended September 30, 2019, we:

 

•

borrowed $95.0 million under our revolving credit facility;

 

•

paid $4.2 million in debt issuance costs associated with the amended and restated Credit Agreement governing our revolving credit facility; and

 

•

withheld from employees’ shares totaling $6.5 million related to the settlement of equity compensation awards.

During the nine months ended September 30, 2018, we:

 

•

borrowed $99.0 million under our revolving credit facility;

 

•

paid $0.3 million in equity issuance costs associated with the Flat Castle Acquisition; and

 

•

withheld from employees’ shares totaling $1.3 million related to the settlement of equity compensation awards.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales, borrowings under our revolving credit facility and access to the debt and equity capital markets. We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs, which require substantial capital expenditures. We periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. We believe that our existing cash on hand, operating cash flow and available borrowings under our revolving credit facility will be adequate to meet our capital and operating requirements for 2019.

Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We will continue using net cash on hand, cash flows from operations and borrowings under our revolving credit facility to satisfy near-term financial obligations and liquidity needs, and as necessary, we will seek additional sources of debt or equity to fund these requirements. Longer-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the natural gas and oil business. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

As of September 30, 2019, we were in compliance with all of our debt covenants under the Credit Agreement governing our revolving credit facility and the indenture governing our 8.875% senior unsecured notes due 2023. Further, based on our current forecast and activity levels, we expect to remain in compliance with all such debt covenants for the next 12 months. However, if oil and natural gas prices decrease to lower levels, we are likely to generate lower operating cash flows, which would make it more difficult for us to remain in compliance with all of our debt covenants, including requirements with respect to working capital and interest coverage ratios. This could negatively impact our ability to maintain sufficient liquidity and access to capital resources.

Credit Arrangements

Long-term debt at September 30, 2019 and December 31, 2018, excluding discount, totaled $638.0 million and $543.0 million, respectively.  Information related to our credit arrangements is described in Note 10—Debt to our Consolidated Financial Statements and is incorporated herein by reference.

45

 

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas, NGLs and oil production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, NGLs and oil production. Pricing for natural gas, NGLs and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in natural gas, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas and the WTI price for oil.

Our hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, zero cost collars that set a floor and ceiling price for the hedged production, and puts that require us to pay a premium either up front or at settlement and allow us to receive a fixed price at our option if the put price is above the market price. As of September 30, 2019, we had entered into the following derivative contracts:

46

 

Natural Gas Derivatives:

 

Description

 

Volume

(MMBtu/d)

 

 

Production Period

 

Weighted Average

Price ($/MMBtu)

 

Natural Gas Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

120,000

 

 

October 2019 – December 2019

 

$

2.80

 

 

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.67

 

 

 

 

20,000

 

 

January 2020 – March 2020

 

$

2.80

 

 

 

 

50,000

 

 

January 2020 – June 2020

 

$

2.70

 

 

 

 

20,000

 

 

April 2020 – June 2020

 

$

2.75

 

 

 

 

30,000

 

 

July 2020 – December 2020

 

$

2.60

 

Natural Gas Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

95,000

 

 

October 2019 – December 2019

 

$

2.60

 

Ceiling sold price (call)

 

 

95,000

 

 

October 2019 – December 2019

 

$

2.91

 

Floor purchase price (put)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.49

 

Ceiling sold price (call)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.88

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.65

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.98

 

Floor purchase price (put)

 

 

15,000

 

 

April 2020 – June 2020

 

$

2.50

 

Ceiling sold price (call)

 

 

15,000

 

 

April 2020 – June 2020

 

$

2.80

 

Natural Gas Three-way Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

77,500

 

 

October 2019 – December 2019

 

$

2.72

 

Floor sold price (put)

 

 

77,500

 

 

October 2019 – December 2019

 

$

2.30

 

Ceiling sold price (call)

 

 

77,500

 

 

October 2019 – December 2019

 

$

3.04

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – December 2020

 

$

2.70

 

Floor sold price (put)

 

 

30,000

 

 

January 2020 – December 2020

 

$

2.40

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – December 2020

 

$

3.05

 

Floor purchase price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.72

 

Floor sold price (put)

 

 

30,000

 

 

January 2020 – March 2020

 

$

2.25

 

Ceiling sold price (call)

 

 

30,000

 

 

January 2020 – March 2020

 

$

3.15

 

Floor purchase price (put)

 

 

20,000

 

 

January 2020 – June 2020

 

$

2.70

 

Floor sold price (put)

 

 

20,000

 

 

January 2020 – June 2020

 

$

2.25

 

Ceiling sold price (call)

 

 

20,000

 

 

January 2020 – June 2020

 

$

3.05

 

Floor purchase price (put)

 

 

30,000

 

 

October 2019 – June 2020

 

$

2.90

 

Floor sold price (put)

 

 

30,000

 

 

October 2019 – June 2020

 

$

2.50

 

Ceiling sold price (call)

 

 

30,000

 

 

October 2019 – June 2020

 

$

3.15

 

Natural Gas Call/Put Options:

 

 

 

 

 

 

 

 

 

 

Ceiling sold price (call)

 

 

40,000

 

 

October 2019 – December 2019

 

$

3.44

 

Floor sold price (put)

 

 

50,000

 

 

January 2020 – December 2020

 

$

2.30

 

Floor sold price (put)

 

 

50,000

 

 

January 2020 – June 2020

 

$

2.25

 

Swaption sold price (call)

 

 

50,000

 

 

January 2021 – December 2021

 

$

2.75

 

Swaption sold price (call)

 

 

50,000

 

 

January 2022 – December 2022

 

$

3.00

 

Basis Swaps:

 

 

 

 

 

 

 

 

 

 

Appalachia - Dominion

 

 

12,500

 

 

October 2019

 

$

(0.52

)

Appalachia - Dominion

 

 

12,500

 

 

April 2020 – October 2020

 

$

(0.52

)

Appalachia - Dominion

 

 

20,000

 

 

January 2020 – December 2020

 

$

(0.59

)

Appalachia - Dominion

 

 

20,000

 

 

October 2019 – March 2020

 

$

(0.39

)

Appalachia - Dominion

 

 

17,500

 

 

October 2019 – December 2019

 

$

(0.50

)

 

47

 

Oil Derivatives:

 

Description

 

Volume

(Bbls/d)

 

 

Production Period

 

Weighted Average

Price ($/Bbl)

 

Oil Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

1,500

 

 

October 2019 – December 2019

 

$

59.18

 

 

 

 

1,000

 

 

January 2020 – December 2020

 

$

58.60

 

 

 

 

1,000

 

 

July 2020 – December 2020

 

$

56.53

 

Oil Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

1,500

 

 

October 2019 – December 2019

 

$

51.67

 

Ceiling sold price (call)

 

 

1,500

 

 

October 2019 – December 2019

 

$

65.92

 

Floor purchase price (put)

 

 

1,000

 

 

January 2020 – December 2020

 

$

51.50

 

Ceiling sold price (call)

 

 

1,000

 

 

January 2020 – December 2020

 

$

64.25

 

Floor purchase price (put)

 

 

500

 

 

July 2020 – December 2020

 

$

52.00

 

Ceiling sold price (call)

 

 

500

 

 

July 2020 – December 2020

 

$

60.00

 

Floor purchase price (put)

 

 

500

 

 

October 2019 – March 2020

 

$

60.00

 

Ceiling sold price (call)

 

 

500

 

 

October 2019 – March 2020

 

$

67.00

 

Oil Three-way Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

2,000

 

 

October 2019 – December 2019

 

$

50.00

 

Floor sold price (put)

 

 

2,000

 

 

October 2019 – December 2019

 

$

40.00

 

Ceiling sold price (call)

 

 

2,000

 

 

October 2019 – December 2019

 

$

60.56

 

Floor purchase price (put)

 

 

2,000

 

 

January 2020 – June 2020

 

$

62.50

 

Floor sold price (put)

 

 

2,000

 

 

January 2020 – June 2020

 

$

55.00

 

Ceiling sold price (call)

 

 

2,000

 

 

January 2020 – June 2020

 

$

74.00

 

Oil Call/Put Options:

 

 

 

 

 

 

 

 

 

 

Swaption sold price (call)

 

 

500

 

 

January 2021 – December 2021

 

$

56.80

 

NGL Derivatives:

 

Description

 

Volume

(Bbls/d)

 

 

Production Period

 

Weighted Average

Price ($/Bbl)

 

Propane Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

350

 

 

October 2019 – December 2019

 

$

39.90

 

 

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with Bank of Montreal, BP Energy Company, Capital One N.A., Citibank, Citizens Bank N.A., EDF Energy, J Aron, KeyBank N.A., Morgan Stanley, NextEra Energy, Inc., Royal Bank of Canada, and Wells Fargo. We believe all such institutions currently are an acceptable credit risk. As of September 30, 2019, we did not have any past due receivables from such counterparties.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at September 30, 2019 as shown in the following table:

 

(in thousands)

 

Hypothetical 10%

Increase in

Future Prices

 

 

Hypothetical 10%

Decrease in

Future Prices

 

Natural Gas

 

$

(19,300

)

 

$

16,607

 

NGLs

 

 

(62

)

 

 

62

 

Oil

 

 

(7,094

)

 

 

7,061

 

 

48

 

Subsequent to September 30, 2019, we entered into the following derivative instruments to mitigate our exposure to natural gas and oil prices:

Natural Gas Derivatives:

 

Description

 

Volume

(MMBtu/d)

 

 

Production Period

 

Weighted Average

Price ($/MMBtu)

 

Natural Gas Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

30,000

 

 

January 2020 – June 2020

 

$

2.62

 

 

 

 

25,000

 

 

January 2020 – March 2021

 

$

2.60

 

 

 

 

20,000

 

 

July 2020 – March 2021

 

$

2.58

 

Natural Gas Three-way Collars:

 

 

 

 

 

 

 

 

 

 

Floor purchase price (put)

 

 

45,000

 

 

January 2021 – December 2021

 

$

2.55

 

Floor sold price (put)

 

 

45,000

 

 

January 2021 – December 2021

 

$

2.25

 

Ceiling sold price (call)

 

 

45,000

 

 

January 2021 – December 2021

 

$

2.81

 

Oil Derivatives:

 

Description

 

Volume

(Bbls/d)

 

 

Production Period

 

Weighted Average

Price ($/Bbl)

 

Oil Swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

500

 

 

January 2020 – December 2020

 

$

54.00

 

 

 

 

250

 

 

July 2020 – March 2021

 

$

53.20

 

 

 

 

250

 

 

January 2021 – March 2021

 

$

53.00

 

Oil Call/Put Options:

 

 

 

 

 

 

 

 

 

 

Floor sold price (put)

 

 

500

 

 

January 2020 – December 2020

 

$

53.00

 

Ceiling sold price (call)

 

 

500

 

 

January 2020 – December 2020

 

$

64.50

 

Floor sold price (put)

 

 

500

 

 

July 2020 – December 2020

 

$

45.00

 

 

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt. Our Board of Directors approved an initial capital budget for 2019 of between approximately $375 - $400 million, allocated approximately 90% for drilling and completions activities and approximately 10% for land activities and other capital requirements.  In July 2019, the Company reduced its planned drilling activity to one gross operating rig through the remainder of 2019 and in connection therewith reduced its 2019 capital budget by approximately $30 million.  The revised 2019 capital budget is expected to be substantially funded through internally generated cash flows, current cash balances, and borrowings under the revolving credit facility.  The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in natural gas, NGLs or oil prices from current levels may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production and our proved reserves as well as our ability to maintain compliance with our debt covenants. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities, additional borrowings under our revolving credit facility or the sale of assets.

On February 28, 2019, the Company completed its previously announced business combination transaction with BRMR pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company.

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock split (See Note 13— Net Income (Loss) Per Share). Former stockholders of BRMR received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted

49

 

stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.

In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in the Credit Agreement governing our revolving credit facility and other factors.

Capitalization

As of September 30, 2019 and December 31, 2018, our total debt, excluding debt discount and issuance costs, and capitalization were as follows (in millions):

 

 

 

September 30, 2019

 

 

December 31, 2018

 

Senior unsecured notes

 

$

510.5

 

 

$

510.5

 

Revolving credit facility

 

 

127.5

 

 

 

32.5

 

Stockholders' equity

 

 

982.0

 

 

 

687.5

 

Total capitalization

 

$

1,620.0

 

 

$

1,230.5

 

 

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering, and compressions services and asset retirement obligations. As of September 30, 2019 and December 31, 2018, we did not have any capital leases, any significant off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed any debt of any unrelated party. Our Condensed Consolidated Balance Sheet at September 30, 2019 reflects accrued interest payable of $11.1 million, compared to $21.7 million as of December 31, 2018.

Midstream Agreements

As a result of the BRMR Merger, we assumed commitments related to certain firm transportation and gas processing, gathering and compression agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR (See Note 15—Commitments and Contingencies). See our Annual Report on Form 10-K for further discussion of our Midstream Agreements and Other Commitments.

MarkWest Gas Processing Agreement

Triad Hunter is party to a gas processing agreement with MarkWest Liberty Midstream & Resources, L.L.C (“MarkWest”).  The agreement provides for minimum volume commitments of 37,500 Mcf per day and expires in October 2023.  Effective May 1, 2019, this agreement was amended to reflect an adjusted acreage dedication and reduced processing fee.

Equitrans Gas Transportation Agreement

Triad Hunter is party to a gas transportation agreement with Equitrans, L.P.  Under the gas transportation agreement, which expires on October 31, 2029, Triad Hunter’s maximum daily quantities are 50,000 MMBtu per day through December 31, 2024 and are reduced to 35,000 MMBtu per day effective as of January 1, 2025.

Eureka Midstream Gas Gathering Agreements

Triad Hunter is party to a gas gathering contract with Eureka Midstream, LLC (“Eureka Midstream”). The gas gathering contract provides for minimum volume commitments determined on a system-wide basis with volume banking, with annual commitments of 210,000 MMBtu per day for 2019 through 2033.  In addition, the contract includes a minimum volume commitment of 50,000 Mcf per day for a compression facility.

50

 

In March 2019, Eclipse Resources I, L.P., a wholly owned subsidiary of the Company (“Eclipse I”), entered into a rich gas gathering agreement (firm service – three well pads) with Eureka Midstream, under which Eclipse I committed to the payment of monthly reservation fees for certain maximum daily quantities of gas delivered from three well pads in Monroe County, Ohio.  The rich gas gathering agreement provides for minimum volume commitments with respect to production from the pads, with annual commitments as follows:

 

Term

 

Natural Gas

(Mcf/d)

 

July 2019 – June 2020

 

 

41,000

 

July 2020 – June 2021

 

 

40,000

 

July 2021 – June 2022

 

 

23,000

 

July 2022 – June 2023

 

 

16,500

 

July 2023 – June 2024

 

 

12,500

 

July 2024 – June 2025

 

 

10,400

 

July 2025 – June 2026

 

 

8,500

 

July 2026 – June 2027

 

 

7,250

 

July 2027 – June 2028

 

 

6,000

 

July 2028 – June 2029

 

 

5,250

 

July 2029 – June 2030

 

 

4,250

 

July 2030 – June 2031

 

 

3,500

 

July 2031 – June 2032

 

 

3,000

 

July 2032 – June 2033

 

 

2,500

 

July 2033 – June 2034

 

 

2,000

 

 

Amended MarkWest Processing Agreement

In June 2019, Eclipse I entered into an agreement with MarkWest for gas processing and fractionation.  This gas processing agreement contains terms and conditions substantially similar to the legacy gas processing agreement between Triad Hunter and MarkWest.  In June 2019, Triad Hunter and Eclipse I amended their gas processing agreements with MarkWest.  The amendments were effective as of May 1, 2019 and provide for reduced processing and compression charges as well as firm capacity that increases during the term of the agreements from approximately 150 MMcf to 275 MMcf per day.  These gas processing agreements include a dedication of Marcellus acreage and no minimum volume commitments.  The agreements expire in October 2023.

REX Transportation Agreement

Triad Hunter is party to certain transportation services agreements with Rockies Express Pipeline LLC (“REX”) for the delivery by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter.  Under the agreements, Triad Hunter committed to purchase 50,000 MMBtu per day of firm transportation through 2031.  In January 2018, Triad Hunter committed to purchase an additional 50,000 MMBtu per day of firm transportation capacity for the period October 1, 2018 through September 30, 2023.  In April 2019, REX and Triad Hunter agreed to extend the term of the additional 50,000 MMBtu per day of capacity through September 30, 2027.

In connection with its transportation services agreements with REX, Triad Hunter is required to provide credit support, which as of March 31, 2019 consisted of a letter of credit of $20 million and a cash prepayment to REX of $1.4 million.  Triad Hunter was also party to an Asset Management Agreement with BP Energy Company pursuant to which BP Energy Company agreed to provide the $20 million letter of credit to REX on behalf of Triad Hunter.  In April 2019, per the terms of the additional 50,000 MMBtu per day of capacity extension, REX and Triad Hunter agreed to reduce the currently held letter of credit to $14.4 million from the previously held $20 million. The $20 million letter of credit posted by BP Energy Company expired on April 28, 2019, and the Company issued the reduced $14.4 million letter of credit under its revolving credit facility (See Note 10—Debt).  Triad Hunter still maintains a $1.4 million cash prepayment with REX.  

Other

We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally five years. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to

51

 

be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Interest Rates

At September 30, 2019 and December 31, 2018, we had $510.5 million of senior unsecured notes outstanding, excluding discounts, which bore interest at a fixed cash rate of 8.875% per annum, payable semi-annually.

At September 30, 2019, we had outstanding borrowings of $127.5 million under our revolving credit facility with interest payable at a variable rate based on LIBOR or the prime rate based on our election at the time of borrowing.  We had outstanding borrowings of $32.5 million under our revolving credit facility as of December 31, 2018.

Information related to our interest rates is described in Note 10—Debt to our Consolidated Financial Statements and is incorporated herein by reference.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, which are described above under “—Cash Contractual Obligations.”

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, it does not normally have a significant effect on our business. We expect our costs in fiscal 2019 to continue to be a function of supply and demand.  Further strengthening of commodity prices could stimulate demand for ancillary services causing service costs to increase.  In the near term, the majority of our service costs are expected to remain flat in 2019 due to previously negotiated drilling, stimulation, and rentals contracts.  Along with these contracts, we have secured quality service equipment and tenured personnel to limit our exposure to increasing service costs and improve operational efficiencies.  

Non-GAAP Financial Measure

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; DD&A; amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items set forth in the table below. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

 

•

is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

 

•

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

 

•

is used by our management team for various purposes, including as a measure of operating performance, in presentations to our Board of Directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under the Credit Agreement governing the revolving credit facility and the indenture governing the senior unsecured notes.

52

 

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) from operations to Adjusted EBITDAX for the periods presented:

 

 

 

Three Months Ended

September 30,

 

 

Nine Months Ended

September 30,

 

$ thousands

 

2019

 

 

2018

 

 

 

2019

 

 

2018

 

Net income (loss)

 

$

4,284

 

 

$

3,998

 

 

$

17,698

 

 

$

(17,662

)

Depreciation, depletion, amortization and accretion

 

 

45,456

 

 

 

34,439

 

 

 

113,950

 

 

 

98,672

 

Exploration expense

 

 

16,621

 

 

 

11,328

 

 

 

48,602

 

 

 

36,227

 

Rig termination and standby

 

 

1,221

 

 

 

—

 

 

 

1,221

 

 

 

—

 

Stock-based compensation

 

 

1,061

 

 

 

2,171

 

 

 

7,614

 

 

 

6,131

 

(Gain) loss on sale of assets

 

 

(733

)

 

 

6

 

 

 

(731

)

 

 

(1,814

)

(Gain) loss on derivative instruments

 

 

(15,812

)

 

 

3,263

 

 

 

(40,620

)

 

 

24,055

 

Net cash receipts (payments) on settled derivatives

 

 

11,818

 

 

 

(5,377

)

 

 

11,072

 

 

 

(7,724

)

Interest expense, net

 

 

15,192

 

 

 

13,932

 

 

 

44,140

 

 

 

39,975

 

Other income (expense)

 

 

—

 

 

 

1

 

 

 

(8

)

 

 

1

 

Merger-related expenses

 

 

3,291

 

 

 

2,993

 

 

 

21,812

 

 

 

2,993

 

Income (loss) from discontinued operations

 

 

1,237

 

 

 

—

 

 

 

(1,286

)

 

 

—

 

Adjusted EBITDAX

 

$

83,636

 

 

$

66,754

 

 

$

223,464

 

 

$

180,854

 

 

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our Condensed Consolidated Financial Statements, which have been prepared in accordance with U.S. GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Annual Report on Form 10-K for further discussion of our critical accounting policies.

Recent Accounting Pronouncements

The Company’s critical accounting policies are described in Note 2—Summary of Significant Accounting Policies of the Consolidated Financial Statements for the year ended December 31, 2018 contained in the Company’s Annual Report on Form 10-K. Information related to recent accounting pronouncements is described in Note 3—Summary of Significant Accounting Policies to our Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 82% of our December 31, 2018 proved reserves were natural gas.

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices (See Note 8—Derivative Instruments).

53

 

Interest Rate Risk

Information related to our interest rates is described in Note 10—Debt to our Consolidated Financial Statements and is incorporated herein by reference.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts, the sale of our oil and gas production which we market to energy companies, end users and refineries, and joint interest receivables.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. These counterparties are not required to provide credit support to us.  As of September 30, 2019, we had economic hedges in place with 11 counterparties. The fair value of our commodity derivative contracts of approximately $28.1 million at September 30, 2019 includes the following values by counterparty: Bank of Montreal $6.3 million; BP Energy Company $2.6 million; Capital One N.A. $6.7 million; Citibank $0.6 million; EDF Energy $1.6 million; J Aron $7.8 million; KeyBank N.A. $1.7 million; Morgan Stanley ($1.1) million; NextEra Energy, Inc. $0.5 million; Royal Bank of Canada $1.0 million; and Wells Fargo $0.4 million. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at September 30, 2019 for each of the counterparties. We believe that all of these institutions currently are acceptable credit risks. Other than as provided by our revolving credit facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts. As of September 30, 2019, we did not have past-due receivables from, or payables to, any of our counterparties under our derivative contracts.

We are also subject to credit risk due to concentration of our receivables from several significant customers for sales of natural gas. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we drill. We can do very little to choose who participates in our wells.

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s management carried out an evaluation (as required by Rule 13a-15(b) under the Exchange Act), with the participation of the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act), as of the end of the period covered by this Quarterly Report. Based upon this evaluation, the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report, such that the information relating to the Company and its consolidated subsidiaries required to be disclosed by the Company in the reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the period covered by this Quarterly Report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

 

54

 

PART II – OTHER INFORMATION

Item 1.

Information regarding the Company’s legal proceedings is set forth in Note 15—Commitments and Contingencies, located in the Notes to the Condensed Consolidated Financial Statements included in Part I Item 1 of this Quarterly Report and is incorporated herein by reference.

Item 1A.

Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 15, 2019, which could materially affect our business, financial condition, and/or future results.  The risks described in our Annual Report on Form 10-K and in this Quarterly Report are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The following table sets forth our share purchase activity for each period presented:

Period

 

Total Number of Shares

Purchased (a)

 

 

Average Price Paid Per Share

 

 

Total Number of Shares Purchased as Part of Publicly Announced Plans

 

 

Maximum Number of Shares that May Yet be Purchased Under the Plan

July 1, 2019 - July 31, 2019

 

 

—

 

 

$

—

 

 

 

—

 

 

N/A

August 1, 2019 - August 31, 2019

 

 

3,252

 

 

$

2.81

 

 

 

—

 

 

N/A

September 1, 2019 - September 30, 2019

 

 

—

 

 

$

—

 

 

 

—

 

 

N/A

(a)

Represents shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock held by our employees.

55

 

Item 6.

Exhibits

See the list of exhibits below in the index to exhibits to this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

MONTAGE RESOURCES CORPORATION

INDEX TO EXHIBITS

Exhibit

No.

 

Description

 

 

 

    2.1+

 

Agreement and Plan of Merger, dated as of August 25, 2018, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

 

 

 

    2.2

 

Amendment No. 1 to Agreement and Plan of Merger, dated as of January 7, 2019, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the SEC on January 7, 2019).

 

 

 

    3.1

 

Second Amended and Restated Certificate of Incorporation of Montage Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

 

 

 

    3.2

 

Second Amended and Restated Bylaws of Montage Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

 

 

 

    3.3

 

Certificate of Ownership and Merger, filed with the Secretary of State of the State of Delaware with an effective date of February 28, 2019 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

 

 

 

    4.1

 

Amended and Restated Registration Rights Agreement, dated January 28, 2015, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Eclipse Management, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2015).

 

 

 

    4.2

 

Indenture, dated as of July 6, 2015, between Eclipse Resources Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2015).

 

 

 

    4.3

 

Registration Rights Agreement, dated as of January 18, 2018, by and among Eclipse Resources Corporation, Eclipse Resources-PA, LP, and Travis Peak Resources, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 22, 2018).

 

 

 

   10.1*

 

First Amendment to Third Amended and Restated Credit Agreement, dated as of September 19, 2019, by and among Montage Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and each of the lenders party thereto.

 

 

 

   31.1*

 

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

   31.2*

 

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

   32.1**

 

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

   32.2**

 

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS*

 

Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

 

 

 

101.SCH*

 

Inline XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL*

 

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

101.DEF*

 

Inline XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

56

 

101.LAB*

 

Inline XBRL Taxonomy Extension Label Linkbase Document.

 

 

 

101.PRE*

 

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

 

 

 

104*

 

Cover Page Interactive Data File (embedded within the Inline XBRL document).

 

+

Schedules have been omitted pursuant to Item 601(b)(2) or (5) of Regulation S-K. Montage Resources Corporation agrees to furnish a copy of such schedules, or any section thereof, to the SEC upon request.

*

Filed herewith.

**

These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.

 

57

 

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

November 8, 2019

 

MONTAGE RESOURCES CORPORATION

(Registrant)

 

 

 

 

 

/s/ John K. Reinhart

 

 

John K. Reinhart,

 

 

President and Chief Executive Officer

 

 

 

 

 

/s/ Michael L. Hodges

 

 

Michael L. Hodges,

 

 

Executive Vice President and Chief Financial Officer

 

58

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