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GULFPORT ENERGY CORP - Quarter Report: 2019 June (Form 10-Q)

Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM 10-Q
 
(Mark One)
☒
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2019
OR
☐
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                      to                     
Commission File Number 000-19514
 
Gulfport Energy Corporation
(Exact Name of Registrant As Specified in Its Charter)
 
Delaware
73-1521290
(State or Other Jurisdiction of Incorporation or Organization)
(IRS Employer Identification Number)
3001 Quail Springs Parkway

Oklahoma City,
Oklahoma
73134
(Address of Principal Executive Offices)
(Zip Code)
(405) 252-4600
(Registrant 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
 
GPOR
 
Nasdaq Global Select Market
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý    No  ¨
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 (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit such files).     Yes  ý    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 definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filer  ý     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  ý
As of July 26, 2019, 159,396,017 shares of the registrant’s common stock were outstanding.


Table of Contents


GULFPORT ENERGY CORPORATION
TABLE OF CONTENTS
 
 
 
Page
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
Item 5.
 
 
 
Item 6.
 
 
 
 

 



1
Table of Contents


GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
June 30, 2019
 
December 31, 2018
 
(In thousands, except share data)
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
20,777

 
$
52,297

Accounts receivable—oil and natural gas sales
131,675

 
210,200

Accounts receivable—joint interest and other
46,645

 
22,497

Prepaid expenses and other current assets
9,474

 
10,607

Short-term derivative instruments
134,920

 
21,352

Total current assets
343,491

 
316,953

Property and equipment:
 
 
 
Oil and natural gas properties, full-cost accounting, $2,836,441 and $2,873,037 excluded from amortization in 2019 and 2018, respectively
10,510,427

 
10,026,836

Other property and equipment
96,413

 
92,667

Accumulated depletion, depreciation, amortization and impairment
(4,882,729
)
 
(4,640,098
)
Property and equipment, net
5,724,111

 
5,479,405

Other assets:
 
 
 
Equity investments
119,307

 
236,121

Long-term derivative instruments
5,036

 
—

Deferred tax asset
179,331

 
—

Inventories
9,001

 
4,754

Operating lease assets
19,334

 
—

Operating lease assets - related parties
53,579

 
—

Other assets
12,280

 
13,803

Total other assets
397,868

 
254,678

Total assets
$
6,465,470

 
$
6,051,036

Liabilities and Stockholders’ Equity
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
493,830

 
$
518,380

Short-term derivative instruments
198

 
20,401

Current portion of operating lease liabilities
17,999

 
—

Current portion of operating lease liabilities - related parties
20,817

 
—

Current maturities of long-term debt
615

 
651

Total current liabilities
533,459

 
539,432

Long-term derivative instruments
210

 
13,992

Asset retirement obligation—long-term
88,491

 
79,952

Deferred tax liability
3,127

 
3,127

Non-current operating lease liabilities
1,335

 
—

Non-current operating lease liabilities - related parties
32,762

 
—

Long-term debt, net of current maturities
2,198,678

 
2,086,765

Total liabilities
2,858,062

 
2,723,268

Commitments and contingencies (Note 7)

 

Preferred stock, $0.01 par value; 5,000,000 shares authorized (30,000 authorized as redeemable 12% cumulative preferred stock, Series A), and none issued and outstanding
—

 
—

Stockholders’ equity:
 
 
 
Common stock - $0.01 par value, 200,000,000 shares authorized, 159,396,017 issued and outstanding at June 30, 2019 and 162,986,045 at December 31, 2018
1,594

 
1,630

Paid-in capital
4,202,599

 
4,227,532

Accumulated other comprehensive loss
(48,615
)
 
(56,026
)
Accumulated deficit
(548,170
)
 
(845,368
)
Total stockholders’ equity
3,607,408

 
3,327,768

Total liabilities and stockholders’ equity
$
6,465,470

 
$
6,051,036


See accompanying notes to consolidated financial statements.

2
Table of Contents


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(In thousands, except share data)
Revenues:
 
 
 
 
 
 
 
Natural gas sales
$
225,257

 
$
232,695

 
$
501,273

 
$
482,094

Oil and condensate sales
36,910

 
49,319

 
69,392

 
95,005

Natural gas liquid sales
25,687

 
41,271

 
57,812

 
88,107

Net gain (loss) on natural gas, oil and NGLs derivatives
171,140

 
(70,545
)
 
151,095

 
(87,074
)
 
458,994

 
252,740

 
779,572

 
578,132

Costs and expenses:

 
 
 
 
 
 
Lease operating expenses
22,388

 
22,912

 
42,195

 
41,818

Production taxes
8,098

 
7,659

 
16,019

 
14,513

Midstream gathering and processing expenses
72,015

 
71,440

 
142,297

 
135,633

Depreciation, depletion and amortization
124,951

 
121,915

 
243,384

 
232,933

General and administrative expenses
13,265

 
14,008

 
24,823

 
27,107

Accretion expense
1,359

 
1,015

 
2,426

 
2,019

 
242,076

 
238,949

 
471,144

 
454,023

INCOME FROM OPERATIONS
216,918

 
13,791

 
308,428

 
124,109

OTHER EXPENSE (INCOME):

 
 
 
 
 
 
Interest expense
34,880

 
33,704

 
69,000

 
67,669

Interest income
(159
)
 
(33
)
 
(311
)
 
(70
)
Insurance proceeds
(83
)
 
(231
)
 
(83
)
 
(231
)
Gain on sale of equity method investments
—

 
(122,035
)
 
—

 
(122,035
)
Loss (income) from equity method investments, net
125,582

 
(8,888
)
 
121,309

 
(22,424
)
Other expense (income)
1,073

 
(45
)
 
646

 
(140
)
 
161,293

 
(97,528
)
 
190,561

 
(77,231
)
INCOME BEFORE INCOME TAXES
55,625

 
111,319

 
117,867

 
201,340

INCOME TAX BENEFIT
(179,331
)
 
—

 
(179,331
)
 
(69
)
NET INCOME
$
234,956

 
$
111,319

 
$
297,198

 
$
201,409

NET INCOME PER COMMON SHARE:
 
 
 
 
 
 
 
Basic
$
1.47

 
$
0.64

 
$
1.85

 
$
1.14

Diluted
$
1.47

 
$
0.64

 
$
1.84

 
$
1.13

Weighted average common shares outstanding—Basic
159,324,909

 
173,623,630

 
161,064,787

 
177,158,230

Weighted average common shares outstanding—Diluted
159,506,826

 
174,140,627

 
161,590,087

 
177,737,282


See accompanying notes to consolidated financial statements.


3
Table of Contents


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(In thousands)
Net income
$
234,956

 
$
111,319

 
$
297,198

 
$
201,409

Foreign currency translation adjustment
3,610

 
(3,364
)
 
7,411

 
(8,867
)
Other comprehensive income (loss)
3,610

 
(3,364
)
 
7,411

 
(8,867
)
Comprehensive income
$
238,566

 
$
107,955

 
$
304,609

 
$
192,542



See accompanying notes to consolidated financial statements.


4
Table of Contents


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)

 
 
 
 
 

Paid-in
Capital
 
Accumulated
Other
Comprehensive (Loss) Income
 
Accumulated
Deficit
 
Total
Stockholders’
Equity
 
Common Stock
 
 
 
 
 
Shares
 
Amount
 
 
 
 
 
(In thousands, except share data)
Balance at January 1, 2019
162,986,045

 
$
1,630

 
$
4,227,532

 
$
(56,026
)
 
$
(845,368
)
 
$
3,327,768

Net Income
—

 
—

 
—

 
—

 
62,242

 
62,242

Other Comprehensive Income
—

 
—

 
—

 
3,801

 
—

 
3,801

Stock Compensation
—

 
—

 
2,785

 
—

 
—

 
2,785

Shares Repurchased
(3,618,634
)
 
(37
)
 
(28,293
)
 
—

 
—

 
(28,330
)
Issuance of Restricted Stock
54,554

 
1

 
(1
)
 
—

 
—

 
—

Balance at March 31, 2019
159,421,965

 
$
1,594

 
$
4,202,023

 
$
(52,225
)
 
$
(783,126
)
 
$
3,368,266

Net Income
—

 
—

 
—

 
—

 
234,956

 
234,956

Other Comprehensive Income
—

 
—

 
—

 
3,610

 
—

 
3,610

Stock Compensation
—

 
—

 
2,846

 
—

 
—

 
2,846

Shares Repurchased
(296,587
)
 
(3
)
 
(2,267
)
 
—

 
—

 
(2,270
)
Issuance of Restricted Stock
270,639

 
3

 
(3
)
 
—

 
—

 
—

Balance at June 30, 2019
159,396,017

 
$
1,594

 
$
4,202,599

 
$
(48,615
)
 
$
(548,170
)
 
$
3,607,408

(Continued on next page)

5
Table of Contents


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)
(Unaudited)

 
 
 
 
 

Paid-in
Capital
 
Accumulated
Other
Comprehensive (Loss) Income
 
Accumulated
Deficit
 
Total
Stockholders’
Equity
 
Common Stock
 
 
 
 
 
Shares
 
Amount
 
 
 
 
 
(In thousands, except share data)
Balance at January 1, 2018
183,105,910

 
$
1,831

 
$
4,416,250

 
$
(40,539
)
 
$
(1,275,928
)
 
$
3,101,614

Net Income
—

 
—

 
—

 
—

 
90,090

 
90,090

Other Comprehensive Loss
—

 
—

 
—

 
(5,503
)
 
—

 
(5,503
)
Stock Compensation
—

 
—

 
2,685

 
—

 
—

 
2,685

Shares Repurchased
(9,692,356
)
 
(97
)
 
(99,900
)
 
—

 
—

 
(99,997
)
Issuance of Restricted Stock
109,933

 
1

 
(1
)
 
—

 
—

 
—

Balance at March 31, 2018
173,523,487

 
$
1,735

 
$
4,319,034

 
$
(46,042
)
 
$
(1,185,838
)
 
$
3,088,889

Net Income
—

 
—

 
—

 
—

 
111,319

 
111,319

Other Comprehensive Loss
—

 
—

 
—

 
(3,364
)
 
—

 
(3,364
)
Stock Compensation
—

 
—

 
3,355

 
—

 
—

 
3,355

Shares Repurchased
(412,516
)
 
(4
)
 
(4,996
)
 
—

 
—

 
(5,000
)
Issuance of Restricted Stock
191,084

 
2

 
(2
)
 
—

 
—

 
—

Balance at June 30, 2018
173,302,055

 
$
1,733

 
$
4,317,391

 
$
(49,406
)
 
$
(1,074,519
)
 
$
3,195,199


See accompanying notes to consolidated financial statements.

6
Table of Contents


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six months ended June 30,
 
2019
 
2018
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net income
$
297,198

 
$
201,409

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Accretion expense
2,426

 
2,019

Depletion, depreciation and amortization
243,384

 
232,933

Stock-based compensation expense
3,379

 
3,624

Loss (income) from equity investments
121,449

 
(22,322
)
Change in fair value of derivative instruments
(152,589
)
 
102,248

Deferred income tax benefit
(179,331
)
 
(69
)
Amortization of loan costs
3,191

 
3,006

Gain on sale of equity investments and other assets
(112
)
 
(122,035
)
Distributions from equity method investments
2,457

 
—

Changes in operating assets and liabilities:
 
 
 
Decrease in accounts receivable—oil and natural gas sales
78,525

 
6,564

Increase in accounts receivable—joint interest and other
(24,148
)
 
(16,385
)
Increase in accounts receivable—related parties
—

 
(110
)
Decrease (increase) in prepaid expenses and other current assets
1,133

 
(5,786
)
Increase in other assets
(296
)
 
(1,517
)
(Decrease) increase in accounts payable, accrued liabilities and other
(87,560
)
 
28,184

Settlement of asset retirement obligation
(117
)
 
(719
)
Net cash provided by operating activities
308,989

 
411,044

Cash flows from investing activities:
 
 
 
Additions to other property and equipment
(4,298
)
 
(6,252
)
Additions to oil and natural gas properties
(417,535
)
 
(579,734
)
Proceeds from sale of oil and natural gas properties
745

 
3,762

Proceeds from sale of other property and equipment
130

 
167

Proceeds from sale of equity method investments
—

 
221,965

Contributions to equity method investments
(432
)
 
(1,569
)
Distributions from equity method investments
1,945

 
1,196

Net cash used in investing activities
(419,445
)
 
(360,465
)
Cash flows from financing activities:
 
 
 
Principal payments on borrowings
(345,350
)
 
(150,285
)
Borrowings on line of credit
455,000

 
225,000

Debt issuance costs and loan commitment fees
(114
)
 
(624
)
Payments for repurchase of stock
(30,600
)
 
(104,997
)
Net cash provided by (used in) financing activities
78,936

 
(30,906
)
Net (decrease) increase in cash, cash equivalents and restricted cash
(31,520
)
 
19,673

Cash, cash equivalents and restricted cash at beginning of period
52,297

 
99,557

Cash, cash equivalents and restricted cash at end of period
$
20,777

 
$
119,230

Supplemental disclosure of cash flow information:
 
 
 
Interest payments
$
67,472

 
$
59,915

Income tax receipts
$
(1,794
)
 
$
—

Supplemental disclosure of non-cash transactions:
 
 
 
Capitalized stock-based compensation
$
2,252

 
$
2,416

Asset retirement obligation capitalized
$
6,230

 
$
535

Interest capitalized
$
1,771

 
$
2,351

Foreign currency translation gain (loss) on equity method investments
$
7,411

 
$
(8,867
)
 See accompanying notes to consolidated financial statements.

7
Table of Contents


GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
These consolidated financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods in all material respects, on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal, recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s most recent annual report on Form 10-K. Results for the three and six months ended June 30, 2019 are not necessarily indicative of the results expected for the full year.
1.
PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of June 30, 2019 and December 31, 2018 are as follows:
 
June 30, 2019
 
December 31, 2018
 
(In thousands)
Oil and natural gas properties
$
10,510,427

 
$
10,026,836

Office furniture and fixtures
46,327

 
42,581

Building
44,565

 
44,565

Land
5,521

 
5,521

Total property and equipment
10,606,840

 
10,119,503

Accumulated depletion, depreciation, amortization and impairment
(4,882,729
)
 
(4,640,098
)
Property and equipment, net
$
5,724,111

 
$
5,479,405



Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At June 30, 2019, the calculated ceiling was greater than the net book value of the Company’s oil and natural gas properties, and no ceiling test impairment was required for the three and six months ended June 30, 2019. No impairment was required for oil and natural gas properties for the three and six months ended June 30, 2018.
Included in oil and natural gas properties at June 30, 2019 is the cumulative capitalization of $219.8 million in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $8.8 million and $16.5 million for the three and six months ended June 30, 2019, respectively, and $9.4 million and $18.2 million for the three and six months ended June 30, 2018, respectively.
The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $1.00 and $0.96 per Mcfe for the six months ended June 30, 2019 and 2018, respectively.

8
Table of Contents


The following table summarizes the Company’s non-producing properties excluded from amortization by area at June 30, 2019:
 
June 30, 2019
 
(In thousands)
Utica
$
1,475,997

MidContinent
1,359,279

Niobrara
454

Southern Louisiana
611

Bakken
100

 
$
2,836,441


At December 31, 2018, approximately $2.9 billion of non-producing leasehold costs was not subject to amortization.
The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three to five years. However, the majority of the Company’s non-producing leases in the Utica Shale have five-year extension terms which could extend this time frame beyond five years.
A reconciliation of the Company’s asset retirement obligation for the six months ended June 30, 2019 and 2018 is as follows:
 
June 30, 2019
 
June 30, 2018
 
(In thousands)
Asset retirement obligation, beginning of period
$
79,952

 
$
75,100

Liabilities incurred
5,153

 
909

Liabilities settled
(117
)
 
(719
)
Accretion expense
2,426

 
2,019

Revisions in estimated cash flows
1,077

 
(374
)
Asset retirement obligation as of end of period
88,491

 
76,935

Less current portion
—

 
120

Asset retirement obligation, long-term
$
88,491

 
$
76,815



9
Table of Contents


2.
EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of June 30, 2019 and December 31, 2018:
 
 
 
Carrying value
 
Loss (income) from equity method investments

 
Approximate ownership %
 
June 30, 2019
 
December 31, 2018
 
Three months ended June 30,
 
Six months ended June 30,
 
 
 
 
2019
 
2018
 
2019
 
2018
 
 
 
(In thousands)
Investment in Tatex Thailand II, LLC
23.5
%
 
$
—

 
$
—

 
$
(1,945
)
 
$
(63
)
 
$
(2,085
)
 
$
(104
)
Investment in Grizzly Oil Sands ULC
24.9999
%
 
51,607

 
44,259

 
(54
)
 
228

 
339

 
558

Investment in Timber Wolf Terminals LLC(1)
—
%
 
—

 
—

 
—

 
534

 
—

 
536

Investment in Windsor Midstream LLC
22.5
%
 
39

 
39

 
—

 
(9
)
 
—

 
(9
)
Investment in Mammoth Energy Services, Inc.
21.8
%
 
67,661

 
191,823

 
127,581

 
(9,242
)
 
123,055

 
(22,712
)
Investment in Strike Force Midstream LLC(2)
—
%
 
—

 
—

 
—

 
(336
)
 
—

 
(693
)
 
 
 
$
119,307


$
236,121


$
125,582

 
$
(8,888
)
 
$
121,309

 
$
(22,424
)

(1)
On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"). See below under Timber Wolf Terminals LLC for information regarding the subsequent dissolution of Timber Wolf.
(2)
On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream LLC ("Strike Force") to EQT Midstream Partners, LP. See below under Strike Force Midstream LLC for information regarding this transaction.

The tables below summarize financial information for the Company’s equity investments as of June 30, 2019 and December 31, 2018.
Summarized balance sheet information:
 
June 30, 2019
 
December 31, 2018
 
 
 
(In thousands)
Current assets
$
477,559

 
$
471,733

Noncurrent assets
$
1,353,113

 
$
1,302,488

Current liabilities
$
167,901

 
$
239,975

Noncurrent liabilities
$
190,200

 
$
94,575


Summarized results of operations:    
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(In thousands)
Gross revenue
$
179,114

 
$
566,404

 
$
443,958

 
$
1,067,537

Net (loss) income
$
(4,072
)
 
$
49,018

 
$
20,684

 
$
113,470


Tatex Thailand II, LLC
The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex II"). Tatex II held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field. The Company received $2.1 million in distributions from Tatex II during the six months ended June 30, 2019, of which $1.9 million related to proceeds from the sale of its interest in APICO.

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Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.9999% interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. (“Oil Sands”). As of June 30, 2019, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company reviewed its investment in Grizzly for impairment at June 30, 2019 and 2018 and determined no impairment was required. If commodity prices decline in the future however, impairment of the Company's investment in Grizzly may be necessary. During the six months ended June 30, 2019, Gulfport paid $0.4 million in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was increased by $3.5 million and $7.3 million for the three and six months ended June 30, 2019, respectively, as a result of a foreign currency translation gain. The Company's investment in Grizzly was decreased by $3.4 million and $8.7 million for the three and six months ended June 30, 2018, respectively, as a result of a foreign currency translation loss.
Timber Wolf Terminals LLC
During 2012, the Company invested in Timber Wolf. Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. Timber Wolf was dissolved in 2018.
Windsor Midstream LLC
At June 30, 2019, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received no distributions from Midstream during the six months ended June 30, 2019.
As of June 30, 2019, the Company determined that Midstream was a variable interest entity ("VIE") but was not the primary beneficiary because it does not have a controlling financial interest in Midstream. This entity is considered a VIE because the limited partners lack substantive kick-out or participating rights over the general partner. The general partner has power to direct the activities that most significantly impact Midstream's economic performance. The Company accounts for its investment in VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations
Mammoth Energy Services, Inc.
At June 30, 2019, the Company owned 9,829,548 shares, or approximately 21.8%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The Company reviewed its investment in Mammoth Energy as of June 30, 2019 for impairment based on certain qualitative and quantitative factors. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was indicated. This resulted in recording an aggregate impairment loss of $125.4 million for the six months ended June 30, 2019, which is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. If Mammoth Energy's common stock continues to trade below the Company's carrying value for a prolonged period of time, further impairment of the Company's investment in Mammoth Energy may be necessary. The Company’s investment in Mammoth Energy was increased by $0.1 million and $0.2 million foreign currency gains resulting from Mammoth Energy's foreign subsidiary for the three and six months ended June 30, 2019, respectively. The Company’s investment in Mammoth Energy was decreased by a $0.1 million and $0.3 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the three and six months ended June 30, 2018, respectively. During the six months ended June 30, 2019, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of $0.125 per share dividends in February 2019 and May 2019. The approximate fair value of the Company's investment in Mammoth Energy's common stock at June 30, 2019 was $67.7 million based on the quoted market price of Mammoth Energy's common stock. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.
Strike Force Midstream LLC
In February 2016, the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), then a subsidiary of Rice Energy Inc., to

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develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through Strike Force. In 2017, Rice was acquired by EQT Corporation ("EQT"). The Company owned a 25% interest in Strike Force, which was sold to EQT Midstream Partners, LP in May 2018. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.
3.
LONG-TERM DEBT
Long-term debt consisted of the following items as of June 30, 2019 and December 31, 2018:
 
June 30, 2019
 
December 31, 2018
 
(In thousands)
Revolving credit agreement(1) 
$
155,000

 
$
45,000

6.625% senior unsecured notes due 2023
350,000

 
350,000

6.000% senior unsecured notes due 2024
650,000

 
650,000

6.375% senior unsecured notes due 2025
600,000

 
600,000

6.375% senior unsecured notes due 2026
450,000

 
450,000

Net unamortized debt issuance costs(2)
(28,426
)
 
(30,733
)
Construction loan
22,719

 
23,149

Less: current maturities of long term debt
(615
)
 
(651
)
Debt reflected as long term
$
2,198,678

 
$
2,086,765


(1) The Company has entered into a senior secured revolving credit facility, as amended (the "revolving credit facility"), with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. On June 3, 2019, the Company further amended its revolving credit facility to, among other things, allow the Company to designate certain of its subsidiaries as unrestricted subsidiaries and to include LIBOR replacement provisions. Additionally, the borrowing base was reaffirmed at $1.4 billion, and the Company’s elected commitment amount remained at $1.0 billion.
As of June 30, 2019, $155.0 million was outstanding under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $251.5 million letters of credit, was $593.5 million. The Company’s wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.
At June 30, 2019, amounts borrowed under the revolving credit facility bore interest at a weighted average rate of 3.93%.
The Company was in compliance with its financial covenants under the revolving credit facility at June 30, 2019.
(2) Loan issuance costs related to the 6.625% Senior Notes due 2023 (the "2023 Notes"), the 6.000% Senior Notes due 2024 (the "2024 Notes"), the 6.375% Senior Notes due 2025 (the "2025 Notes") and the 6.375% Senior Notes due 2026 (the "2026 Notes") (collectively the “Notes”) have been presented as a reduction to the Notes. At June 30, 2019, total unamortized debt issuance costs were $4.0 million for the 2023 Notes, $8.1 million for the 2024 Notes, $11.7 million for the 2025 Notes and $4.7 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement were $0.1 million at June 30, 2019.
The Company capitalized approximately $1.0 million and $1.8 million in interest expense to undeveloped oil and natural gas properties during the three and six months ended June 30, 2019, respectively. The Company capitalized approximately $1.5 million and $2.4 million in interest expense to undeveloped oil and natural gas properties during the three and six months ended June 30, 2018, respectively.
4.
COMMON STOCK AND CHANGES IN CAPITALIZATION
Stock Repurchase Program
In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the Company's outstanding stock during 2018. In May 2018, the Company's board of directors authorized the expansion of its stock repurchase program, authorizing the Company to acquire up to an additional $100 million of its outstanding common stock during 2018 for a total of up to $200 million. The repurchase program did not require the Company to acquire any

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specific number of shares. This repurchase program was authorized to extend through December 31, 2018 and the Company repurchased 20.7 million shares of common stock in 2018 for $200.0 million in aggregate consideration.
In January 2019, the board of directors of the Company approved a new stock repurchase program to acquire up to $400 million of the Company's outstanding common stock within a 24 month period. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program is authorized to extend through December 31, 2020 and may be suspended, modified, extended or discontinued by the board of directors at any time. The Company repurchased approximately 0.2 million and 3.8 million shares for a cost of approximately $1.8 million and $30.0 million during the three and six months ended June 30, 2019, respectively. Additionally, during each of the three and six months ended June 30, 2019, the Company repurchased approximately 0.1 million shares for a cost of approximately $0.5 million and $0.6 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. All repurchased shares have been canceled and returned to the status of authorized but unissued shares.

5.
STOCK-BASED COMPENSATION
The Company has granted restricted stock units to employees and directors pursuant to the 2013 Restated Incentive Stock Plan ("2013 Plan"), as discussed below. During the three and six months ended June 30, 2019, the Company’s stock-based compensation cost was $2.8 million and $5.6 million, respectively, of which the Company capitalized $1.1 million and $2.3 million, respectively, relating to its exploration and development efforts. During the three and six months ended June 30, 2018, the Company's stock-based compensation cost was $3.3 million and $6.0 million, respectively, of which the Company capitalized $1.3 million and $2.4 million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.
The following table summarizes restricted stock unit activity for the six months ended June 30, 2019:
 
 
Number of
Unvested
Restricted Stock Units
 
Weighted
Average
Grant Date
Fair Value
 
Number of
Unvested
Performance Vesting Restricted Stock Units
 
Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 2019
1,535,811

 
$
11.57

 
$
—

 
$
—

Granted
770,661

 
6.96

 
228,659

 
9.66

Vested
(325,193
)
 
10.08

 
—

 
—

Forfeited
(8,776
)
 
12.44

 
—

 
—

Unvested shares as of June 30, 2019
1,972,503

 
$
10.01

 
228,659

 
$
9.66


Restricted Stock Units
Restricted stock units awarded under the 2013 Plan generally vest over a period of one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of June 30, 2019 related to restricted stock units was $13.8 million. The expense is expected to be recognized over a weighted average period of 1.90 years.
Performance Vesting Restricted Stock Units
During the six months ended June 30, 2019, the Company awarded performance vesting units to its Chief Executive Officer under the 2013 Plan. The number of shares of common stock that will ultimately be issued will be determined by comparing the Company's total stockholder return relative to the total stockholder return of a predetermined group of peer companies at the end of the 36-month performance period. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a risk-free interest rate of 2.42% and a range of expected volatilities of 30.5% to 72.6% to estimate the fair

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value of performance vesting units granted during the six months ended June 30, 2019. Unrecognized compensation expense as of June 30, 2019 related to performance vesting restricted shares was $1.9 million. The expense is expected to be recognized over a weighted average period of 2.51 years.

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6.
EARNINGS PER SHARE
Reconciliations of the components of basic and diluted net income per common share are presented in the tables below:
 
Three months ended June 30,
 
2019
 
2018
 
Income
 
Shares
 
Per
Share
 
Income
 
Shares
 
Per
Share
 
(In thousands, except share data)
Basic:
 
 
 
 
 
 
 
 
 
 
 
Net income
$
234,956

 
159,324,909

 
$
1.47

 
$
111,319

 
173,623,630

 
$
0.64

Effect of dilutive securities:

 

 

 

 

 

Stock options and awards
—

 
181,917

 

 
—

 
516,997

 

Diluted:

 

 

 

 

 

Net income
$
234,956

 
159,506,826

 
$
1.47

 
$
111,319

 
174,140,627

 
$
0.64


 
Six months ended June 30,
 
2019
 
2018
 
Income
 
Shares
 
Per
Share
 
Income
 
Shares
 
Per
Share
 
(In thousands, except share data)
Basic:
 
 
 
 
 
 
 
 
 
 
 
Net income
$
297,198

 
161,064,787

 
$
1.85

 
$
201,409

 
177,158,230

 
$
1.14

Effect of dilutive securities:

 

 

 
 
 

 

Stock options and awards
—

 
525,300

 

 
—

 
579,052

 

Diluted:

 

 

 
 
 

 

Net income
$
297,198

 
161,590,087

 
$
1.84

 
$
201,409

 
177,737,282

 
$
1.13





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7.
COMMITMENTS AND CONTINGENCIES
Firm Transportation and Sales Commitments
The table below presents the firm sales commitments by year:
 
 
(MMBtu per day)
Remaining 2019
 
493,000

2020
 
276,000

2021
 
179,000

2022
 
70,000

2023
 
42,000

Thereafter
 
25,000

Total
 
1,085,000


The table below presents the firm transportation commitments by year:
 
 
(In thousands)
Remaining 2019
 
$
122,128

2020
 
273,973

2021
 
273,011

2022
 
273,011

2023
 
268,209

Thereafter
 
2,283,229

Total
 
$
3,493,561


Other Commitments
Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective August 3, 2018, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses through 2021. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company did not incur any non-utilization fees under this agreement during the three months ended June 30, 2019 and incurred $0.3 million of such fees during the six months ended June 30, 2019. The Company did not incur any non-utilization fees during the three months ended June 30, 2018 and incurred $0.9 million of such fees during the six months ended June 30, 2018.
Future minimum commitments under this agreement at June 30, 2019 are:
 
(In thousands)
Remaining 2019
$
12,000

2020
24,000

2021
24,000

Total
$
60,000



Litigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is

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indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.
The Company, along with a number of other oil and gas companies, has been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The cases have been removed to the United States District Court for the Western District of Louisiana, and motions to remand are pending.
The cases are still in their early stages and the parties have conducted very little discovery. As a result, the Company has not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to the Company's operations and management cannot determine the amount of loss, if any, that may result.
SEC Investigation
The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. The Company has fully cooperated and intends to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, the Company believes that the outcome of this matter will not have a material effect on the Company’s business, financial condition or results of operations.
Business Operations
The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.
The Company received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 12 locations in Ohio. The first FOV for one site was dated December 11, 2013.  Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019.  The Company has exchanged information with the USEPA and is engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000. 
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position,

17
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results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
8.
DERIVATIVE INSTRUMENTS
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments
The Company seeks to reduce its exposure to unfavorable changes in natural gas, oil and natural gas liquids ("NGLs") prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective natural gas, oil and NGLs prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production.
Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural gas, the NYMEX West Texas Intermediate for oil and Mont Belvieu for propane, pentane and ethane. Below is a summary of the Company’s open fixed price swap positions as of June 30, 2019. 
 
Location
Daily Volume (MMBtu/day)
 
Weighted
Average Price
Remaining 2019
NYMEX Henry Hub
1,380,000

 
$
2.81

2020
NYMEX Henry Hub
204,000

 
$
2.77


 
Location
Daily Volume
(Bbls/day)
 
Weighted
Average Price
Remaining 2019
NYMEX WTI
6,000

 
$
60.81

2020
NYMEX WTI
6,000

 
$
59.82

 
Location
Daily Volume
(Bbls/day)
 
Weighted
Average Price
Remaining 2019
Mont Belvieu C2
1,000

 
$
18.48

Remaining 2019
Mont Belvieu C3
4,000

 
$
29.02

Remaining 2019
Mont Belvieu C5
1,000

 
$
53.71


The Company sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.
 
Location
Daily Volume (MMBtu/day)
 
Weighted Average Price
Remaining 2019
NYMEX Henry Hub
30,000

 
$
3.10


For a portion of the natural gas fixed price swaps listed above, the counterparty had the option to extend the original terms for an additional twelve months for the period of January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is included in the natural gas fixed price swaps listed above.

18

In addition, the Company entered into natural gas basis swap positions. As of June 30, 2019, the Company had the following natural gas basis swap positions open:
 
Gulfport Pays
Gulfport Receives
Daily Volume (MMBtu/day)
 
Weighted Average Fixed Spread
Remaining 2019
Transco Zone 4
NYMEX Plus Fixed Spread
60,000

 
$
(0.05
)
2020
Transco Zone 4
NYMEX Plus Fixed Spread
60,000

 
$
(0.05
)
2020
Fixed Spread
ONEOK Minus NYMEX
10,000

 
$
(0.54
)

Balance Sheet Presentation
The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at June 30, 2019 and December 31, 2018:
 
June 30, 2019
 
December 31, 2018
 
(In thousands)
Short-term derivative instruments - asset
$
134,920

 
$
21,352

Long-term derivative instruments - asset
$
5,036

 
$
—

Short-term derivative instruments - liability
$
198

 
$
20,401

Long-term derivative instruments - liability
$
210

 
$
13,992


Gains and Losses
The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and six months ended June 30, 2019 and 2018.
 
Net gain (loss) on derivative instruments
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(In thousands)
Natural gas derivatives
$
152,475

 
$
(31,194
)
 
$
136,044

 
$
(40,890
)
Oil derivatives
11,871

 
(24,419
)
 
11,417

 
(33,566
)
NGL derivatives
6,794

 
(14,932
)
 
3,634

 
(12,618
)
Total
$
171,140

 
$
(70,545
)
 
$
151,095

 
$
(87,074
)

Offsetting of Derivative Assets and Liabilities
As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value.
 
As of June 30, 2019
 
Gross Assets (Liabilities)
 
Gross Amounts
 
 
 
Presented in the
 
Subject to Master
 
Net
 
Consolidated Balance Sheets
 
Netting Agreements
 
Amount
 
(In thousands)
Derivative assets
$
139,956

 
$
(408
)
 
$
139,548

Derivative liabilities
$
(408
)
 
$
408

 
$
—


19

 
As of December 31, 2018
 
Gross Assets (Liabilities)
 
Gross Amounts
 
 
 
Presented in the
 
Subject to Master
 
Net
 
Consolidated Balance Sheets
 
Netting Agreements
 
Amount
 
(In thousands)
Derivative assets
$
21,352

 
$
(19,289
)
 
$
2,063

Derivative liabilities
$
(34,393
)
 
$
19,289

 
$
(15,104
)

Concentration of Credit Risk
By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company’s derivative contracts are with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.
9.
FAIR VALUE MEASUREMENTS
The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories:
Level 1 – Quoted prices in active markets for identical assets and liabilities.
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 – Significant inputs to the valuation model are unobservable.
Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The 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. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of June 30, 2019 and December 31, 2018:
 
June 30, 2019
 
Level 1
 
Level 2
 
Level 3
 
(In thousands)
Assets:
 
 
 
 
 
Derivative Instruments
$
—

 
$
139,956

 
$
—

Liabilities:
 
 
 
 
 
Derivative Instruments
$
—

 
$
408

 
$
—



20
Table of Contents


 
December 31, 2018
 
Level 1
 
Level 2
 
Level 3
 
(In thousands)
Assets:
 
 
 
 
 
Derivative Instruments
$
—

 
$
21,352

 
$
—

Liabilities:
 
 
 
 
 
Derivative Instruments
$
—

 
$
34,393

 
$
—


The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
The estimated fair values of proved oil and natural gas properties assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. The estimated fair values of unevaluated oil and natural gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of the business combination were estimated using the same assumptions and methodology as described below.
The fair value of the Company's investment in Mammoth Energy as of June 30, 2019 was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares.
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 1 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the six months ended June 30, 2019 were approximately $5.2 million.
10.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's construction loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.
At June 30, 2019, the carrying value of the outstanding debt represented by the Notes was approximately $2.0 billion, including the unamortized debt issuance cost of approximately $4.0 million related to the 2023 Notes, approximately $8.1 million related to the 2024 Notes, approximately $11.7 million related to the 2025 Notes and approximately $4.7 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $1.6 billion at June 30, 2019.
11.
REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGLs. Sales of natural gas, oil and condensate and NGLs are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at the time control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The

21
Table of Contents


payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less, and the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.
Contract Balances
Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $131.7 million and $210.2 million as of June 30, 2019 and December 31, 2018, respectively, and are reported in accounts receivable - oil and natural gas sales on the consolidated balance sheet. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.
Prior-Period Performance Obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For the six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
12.
LEASES
Effective January 1, 2019, the Company adopted Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842). The new standard supersedes the previous lease guidance by requiring lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The Company adopted the new standard on a prospective basis using the simplified transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting right-of-use assets and corresponding lease liabilities recognized by the Company on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations exceeding one year. No cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The Company elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications.
Nature of Leases
The Company has operating leases associated with drilling rig commitments, pressure pumping services, field offices and other equipment with remaining lease terms with contractual durations in excess of one year. Short-term leases that have an initial term of one year or less are not capitalized.
The Company has entered into contracts for drilling rigs with third parties to ensure rig availability in its key operating areas. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the evaluation that the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of one to two years and expire at various dates through 2021. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.

22
Table of Contents


Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective July 1, 2018, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company through 2021 and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided. The Company has the right to suspend services of one crew and only one crew at any point in time without payment, fee or other obligation associated with the suspended crew, given appropriate notification of suspension. The Company has determined that the agreement with Stingray Pressure is an operating lease due to the implicit identification of assets and the evaluation that the Company has the right to control the identified assets. The operating lease liability associated with this agreement is based on the minimum contractual obligations, which is the monthly service fee for one crew, and does not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.
The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. These agreements are typically structured with non-cancelable terms of one to five years. The Company has determined these agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. The Company has included any renewal options that it has determined are reasonably certain of exercise in the determination of the lease terms.
Discount Rate
As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
Maturities of operating lease liabilities as of June 30, 2019 were as follows:
 
 
(In thousands)
Remaining 2019
 
$
25,243

2020
 
27,481

2021
 
22,731

2022
 
115

2023
 
90

Thereafter
 
30

Total lease payments
 
$
75,690

Less: Imputed interest
 
(2,777
)
Total
 
$
72,913


Lease cost for the six months ended June 30, 2019 consisted of the following:
 
(In thousands)
Operating lease cost
$
16,284

Operating lease cost - related party
11,220

Variable lease cost
960

Variable lease cost - related party
59,611

Short-term lease cost
183

Total lease cost(1)
$
88,258

(1)
The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statement of operations.

23
Table of Contents


Supplemental cash flow information for the six months ended June 30, 2019 related to leases was as follows:
Cash paid for amounts included in the measurement of lease liabilities
 
(In thousands)
     Operating cash flows from operating leases
 
$
120

     Investing cash flow from operating leases
 
$
12,288

     Investing cash flow from operating leases - related party
 
$
43,925


The weighted-average remaining lease term as of June 30, 2019 was 1.86 years. The weighted-average discount rate used to determine the operating lease liability as of June 30, 2019 was 3.78%.
13.    INCOME TAXES
The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.

The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to potential limitations under Internal Revenue Code Section 382 (“Section 382”) and its related tax regulations. The utilization of these attributes may be limited if certain ownership changes by 5% stockholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change of more than 50% in the beneficial ownership of Gulfport. The Company updates its Section 382 analysis to determine if an ownership change has occurred at each reporting period. If it is determined that an ownership change has occurred under these rules, the Company would generally be subject to an annual limitation on the use of pre-ownership change NOL carryforwards and certain other losses and/or credits. In addition, certain future transactions regarding the Company's equity, including the cumulative effects of small transactions as well as transactions beyond the Company’s control, could cause an ownership change and therefore a potential limitation on the annual utilization of its deferred tax assets.
For the three and six months ended June 30, 2019, the Company's estimated annual effective tax rates were approximately (322.5)% and (152.2)%, respectively. The change is primarily due to the release of the valuation allowance that was previously recorded against deferred tax assets of $179.3 million as a discrete adjustment in the quarter. The Company considered the release of the valuation allowance resulting from current period earnings in the estimated annual effective tax rate and recognized the tax benefit associated with future earnings as a discrete item.

For the three month period ended March 31, 2019, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. As of June 30, 2019, in part because in the current year the Company achieved more than three years of cumulative pretax income in the U.S. federal tax jurisdiction and the Company determined that an ownership change under Internal Revenue Code Section 382 did not occur that would further limit its ability to utilize net operating loss carryforwards, management determined that there was sufficient positive evidence to conclude that it is more likely than not that additional deferred taxes of $207.2 million are realizable. The Company will recognize $27.7 million of valuation allowance release as part of its estimated annualized effective tax rate and $179.3 million as a discrete adjustment during the six month period ending June 30, 2019. It therefore reduced the valuation allowance accordingly. The Company maintained a valuation allowance of $4.8 million related to foreign tax credits, general business credits and net operating losses in jurisdictions for which it has determined that it is more likely than not that deferred tax assets would not be realized.

14.     CONDENSED CONSOLIDATING FINANCIAL INFORMATION

24
Table of Contents


The 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company’s secured revolving credit facility or certain other debt (the “Guarantors”). The Notes are not guaranteed by Grizzly Holdings or Mule Sky LLC ("Mule Sky") (the “Non-Guarantors”). The Guarantors are 100% owned by Gulfport (the “Parent”), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.
The following condensed consolidating balance sheets, statements of operations, statements of comprehensive income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantors and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The information has been presented using the equity method of accounting for the Parent’s ownership of the Guarantors and the Non-Guarantors.


25
Table of Contents


CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
 
June 30, 2019
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
10,940

 
$
9,799

 
$
38

 
$
—

 
$
20,777

Accounts receivable - oil and natural gas sales
4,116

 
127,559

 
—

 
—

 
131,675

Accounts receivable - joint interest and other
9,043

 
37,602

 
—

 
—

 
46,645

Accounts receivable - intercompany
819,584

 
433,776

 
—

 
(1,253,360
)
 
—

Prepaid expenses and other current assets
5,948

 
3,451

 
75

 
—

 
9,474

Short-term derivative instruments
134,920

 
—

 
—

 
—

 
134,920

Total current assets
984,551

 
612,187

 
113

 
(1,253,360
)
 
343,491

 
 
 
 
 
 
 
 
 
 
Property and equipment:
 
 
 
 
 
 
 
 
 
Oil and natural gas properties, full-cost accounting
1,352,894

 
9,158,193

 
69

 
(729
)
 
10,510,427

Other property and equipment
92,343

 
751

 
3,319

 
—

 
96,413

Accumulated depletion, depreciation, amortization and impairment
(1,414,011
)
 
(3,468,663
)
 
(55
)
 
—

 
(4,882,729
)
Property and equipment, net
31,226

 
5,690,281

 
3,333

 
(729
)
 
5,724,111

Other assets:
 
 
 
 
 
 
 
 
 
Equity investments and investments in subsidiaries
5,171,925

 
—

 
51,607

 
(5,104,225
)
 
119,307

Long-term derivative instruments
5,036

 
—

 
—

 
—

 
5,036

Deferred tax asset
179,331

 
—

 
—

 
—

 
179,331

Inventories
188

 
8,813

 
—

 
—

 
9,001

Operating lease assets
19,334

 
—

 
—

 
—

 
19,334

Operating lease assets - related parties
53,579

 
—

 
—

 
—

 
53,579

Other assets
11,682

 
598

 
—

 
—

 
12,280

Total other assets
5,441,075

 
9,411

 
51,607

 
(5,104,225
)
 
397,868

Total assets
$
6,456,852

 
$
6,311,879

 
$
55,053

 
$
(6,358,314
)
 
$
6,465,470

 
 
 
 
 
 
 
 
 
 
Liabilities and Stockholders’ Equity
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable and accrued liabilities
$
74,597

 
$
419,190

 
$
43

 
$
—

 
$
493,830

Accounts payable - intercompany
469,071

 
780,600

 
3,689

 
(1,253,360
)
 
—

Short-term derivative instruments
198

 
—

 
—

 
—

 
198

Current portion of operating lease liabilities
17,999

 
—

 
—

 
—

 
17,999

Current portion of operating lease liabilities - related parties
20,817

 
—

 
—

 
—

 
20,817

Current maturities of long-term debt
615

 
—

 
—

 
—

 
615

Total current liabilities
583,297

 
1,199,790

 
3,732

 
(1,253,360
)
 
533,459

Long-term derivative instruments
210

 
—

 
—

 
—

 
210

Asset retirement obligation - long-term
30,035

 
58,456

 
—

 
—

 
88,491

Deferred tax liability
3,127

 
—

 
—

 
—

 
3,127

Non-current operating lease liabilities
1,335

 
—

 
—

 
—

 
1,335

Non-current operating lease liabilities - related parties
32,762

 
—

 
—

 
—

 
32,762

Long-term debt, net of current maturities
2,198,678

 
—

 
—

 
—

 
2,198,678

Total liabilities
2,849,444

 
1,258,246

 
3,732

 
(1,253,360
)
 
2,858,062

 
 
 
 
 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
 
 
 
 
Common stock
1,594

 
—

 
—

 
—

 
1,594

Paid-in capital
4,202,599

 
4,170,574

 
262,059

 
(4,432,633
)
 
4,202,599

Accumulated other comprehensive loss
(48,615
)
 
—

 
(46,527
)
 
46,527

 
(48,615
)
(Accumulated deficit) retained earnings
(548,170
)
 
883,059

 
(164,211
)
 
(718,848
)
 
(548,170
)
Total stockholders’ equity
3,607,408

 
5,053,633

 
51,321

 
(5,104,954
)
 
3,607,408

Total liabilities and stockholders’ equity
$
6,456,852

 
$
6,311,879

 
$
55,053

 
$
(6,358,314
)
 
$
6,465,470



26
Table of Contents


CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
 
December 31, 2018
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
25,585

 
$
26,711

 
$
1

 
$
—

 
$
52,297

Accounts receivable - oil and natural gas sales
146,075

 
64,125

 
—

 
—

 
210,200

Accounts receivable - joint interest and other
16,212

 
6,285

 
—

 
—

 
22,497

Accounts receivable - intercompany
671,633

 
319,464

 
—

 
(991,097
)
 
—

Prepaid expenses and other current assets
8,433

 
2,174

 
—

 
—

 
10,607

Short-term derivative instruments
21,352

 
—

 
—

 
—

 
21,352

Total current assets
889,290

 
418,759

 
1

 
(991,097
)
 
316,953

 
 
 
 
 
 
 
 
 
 
Property and equipment:
 
 
 
 
 
 
 
 
 
Oil and natural gas properties, full-cost accounting,
7,044,550

 
2,983,015

 
—

 
(729
)
 
10,026,836

Other property and equipment
91,916

 
751

 
—

 
—

 
92,667

Accumulated depletion, depreciation, amortization and impairment
(4,640,059
)
 
(39
)
 
—

 
—

 
(4,640,098
)
Property and equipment, net
2,496,407

 
2,983,727

 
—

 
(729
)
 
5,479,405

Other assets:
 
 
 
 
 
 
 
 
 
Equity investments and investments in subsidiaries
2,856,988

 
—

 
44,259

 
(2,665,126
)
 
236,121

Inventories
3,620

 
1,134

 
—

 
—

 
4,754

Other assets
12,624

 
1,178

 
—

 
1

 
13,803

Total other assets
2,873,232

 
2,312

 
44,259

 
(2,665,125
)
 
254,678

  Total assets
$
6,258,929

 
$
3,404,798

 
$
44,260

 
$
(3,656,951
)
 
$
6,051,036

 
 
 
 
 
 
 
 
 
 
Liabilities and Stockholders’ Equity
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable and accrued liabilities
$
419,107

 
$
99,273

 
$
—

 
$
—

 
$
518,380

Accounts payable - intercompany
320,259

 
670,708

 
130

 
(991,097
)
 
—

Short-term derivative instruments
20,401

 
—

 
—

 
—

 
20,401

Current maturities of long-term debt
651

 
—

 
—

 
—

 
651

Total current liabilities
760,418

 
769,981

 
130

 
(991,097
)
 
539,432

Long-term derivative instruments
13,992

 
—

 
—

 
—

 
13,992

Asset retirement obligation - long-term
66,859

 
13,093

 
—

 
—

 
79,952

Deferred tax liability
3,127

 
—

 
—

 
—

 
3,127

Long-term debt, net of current maturities
2,086,765

 
—

 
—

 
—

 
2,086,765

Total liabilities
2,931,161


783,074


130


(991,097
)

2,723,268

 
 
 
 
 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
 
 
 
 
Common stock
1,630

 
—

 
—

 
—

 
1,630

Paid-in capital
4,227,532

 
1,915,598

 
261,626

 
(2,177,224
)
 
4,227,532

Accumulated other comprehensive loss
(56,026
)
 
—

 
(53,783
)
 
53,783

 
(56,026
)
(Accumulated deficit) retained earnings
(845,368
)
 
706,126

 
(163,713
)
 
(542,413
)
 
(845,368
)
Total stockholders’ equity
3,327,768

 
2,621,724

 
44,130

 
(2,665,854
)
 
3,327,768

  Total liabilities and stockholders’ equity
$
6,258,929

 
$
3,404,798

 
$
44,260

 
$
(3,656,951
)
 
$
6,051,036




27
Table of Contents


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
 
Three months ended June 30, 2019
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Total revenues
$
280,291

 
$
178,703

 
$
—

 
$
—

 
$
458,994

 
 
 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
12,256

 
10,132

 
—

 
—

 
22,388

Production taxes
2,820

 
5,278

 
—

 
—

 
8,098

Midstream gathering and processing expenses
28,121

 
43,894

 
—

 
—

 
72,015

Depreciation, depletion and amortization
80,132

 
44,764

 
55

 
—

 
124,951

General and administrative expenses
16,745

 
(3,583
)
 
103

 
—

 
13,265

Accretion expense
438

 
921

 
—

 
—

 
1,359

 
140,512


101,406


158


—


242,076

 
 
 
 
 
 
 
 
 
 
INCOME (LOSS) FROM OPERATIONS
139,779


77,297


(158
)

—


216,918

 
 
 
 
 
 
 
 
 
 
OTHER EXPENSE (INCOME):
 
 
 
 
 
 
 
 
 
Interest expense
35,835

 
(955
)
 
—

 
—

 
34,880

Interest income
(120
)
 
(39
)
 
—

 
—

 
(159
)
Insurance proceeds
(83
)
 
—

 
—

 
—

 
(83
)
Loss (income) from equity method investments and investments in subsidiaries
47,449

 
—

 
(54
)
 
78,187

 
125,582

Other expense
1,073

 
—

 
—

 
—

 
1,073

 
84,154


(994
)

(54
)

78,187


161,293

 
 
 
 
 
 
 
 
 
 
INCOME (LOSS) BEFORE INCOME TAXES
55,625

 
78,291

 
(104
)
 
(78,187
)
 
55,625

INCOME TAX BENEFIT
(179,331
)
 
—

 
—

 
—

 
(179,331
)
 
 
 
 
 
 
 
 
 
 
NET INCOME (LOSS)
$
234,956


$
78,291


$
(104
)

$
(78,187
)

$
234,956




28
Table of Contents


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

 
Three months ended June 30, 2018
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Total revenues
$
146,774

 
$
105,966

 
$
—

 
$
—

 
$
252,740

 
 
 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
16,593

 
6,319

 
—

 
—

 
22,912

Production taxes
4,793

 
2,866

 
—

 
—

 
7,659

Midstream gathering and processing expenses
52,542

 
18,898

 
—

 
—

 
71,440

Depreciation, depletion and amortization
121,915

 
—

 
—

 
—

 
121,915

General and administrative expenses
14,975

 
(968
)
 
1

 
—

 
14,008

Accretion expense
795

 
220

 
—

 
—

 
1,015

 
211,613


27,335


1


—


238,949

 
 
 
 
 
 
 
 
 
 
(LOSS) INCOME FROM OPERATIONS
(64,839
)

78,631


(1
)

—


13,791

 
 
 
 
 
 
 
 
 
 
OTHER (INCOME) EXPENSE:
 
 
 
 
 
 
 
 
 
Interest expense
34,663

 
(959
)
 
—

 
—

 
33,704

Interest income
(27
)
 
(6
)
 
—

 
—

 
(33
)
Insurance proceeds
(231
)
 
—

 
—

 
—

 
(231
)
Gain on sale of equity method investments
(25,616
)
 
(96,419
)
 
—

 
—

 
(122,035
)
(Income) loss from equity method investments and investments in subsidiaries
(183,901
)
 
(336
)
 
228

 
175,121

 
(8,888
)
Other (income) expense
(1,046
)
 
1

 
—

 
1,000

 
(45
)
 
(176,158
)
 
(97,719
)
 
228

 
176,121

 
(97,528
)
 
 
 
 
 
 
 
 
 
 
INCOME (LOSS) BEFORE INCOME TAXES
111,319


176,350


(229
)

(176,121
)

111,319

INCOME TAX BENEFIT
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
NET INCOME (LOSS)
$
111,319

 
$
176,350

 
$
(229
)
 
$
(176,121
)
 
$
111,319




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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

 
Six months ended June 30, 2019
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Total revenues
$
466,537

 
$
313,035

 
$
—

 
$
—

 
$
779,572

 
 
 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
27,149

 
15,046

 
—

 
—

 
42,195

Production taxes
6,081

 
9,938

 
—

 
—

 
16,019

Midstream gathering and processing expenses
71,420

 
70,877

 
—

 
—

 
142,297

Depreciation, depletion, and amortization
198,564

 
44,765

 
55

 
—

 
243,384

General and administrative expenses
28,977

 
(4,258
)
 
104

 
—

 
24,823

Accretion expense
1,389

 
1,037

 
—

 
—

 
2,426

 
333,580

 
137,405

 
159

 
—

 
471,144

 
 
 
 
 
 
 
 
 
 
INCOME (LOSS) FROM OPERATIONS
132,957

 
175,630

 
(159
)
 
—

 
308,428

 
 
 
 
 
 
 
 
 
 
OTHER EXPENSE (INCOME):
 
 
 
 
 
 
 
 
 
Interest expense
70,259

 
(1,259
)
 
—

 
—

 
69,000

Interest income
(267
)
 
(44
)
 
—

 
—

 
(311
)
Insurance proceeds
(83
)
 
—

 
—

 
—

 
(83
)
(Income) loss from equity method investments and investments in subsidiaries
(55,465
)
 
—

 
339

 
176,435

 
121,309

Other expense
646

 
—

 
—

 
—

 
646

 
15,090

 
(1,303
)
 
339

 
176,435

 
190,561

 
 
 
 
 
 
 
 
 
 
INCOME (LOSS) BEFORE INCOME TAXES
117,867

 
176,933

 
(498
)
 
(176,435
)
 
117,867

INCOME TAX BENEFIT
(179,331
)
 
—

 
—

 
—

 
(179,331
)
 
 
 
 
 
 
 
 
 
 
NET INCOME (LOSS)
$
297,198

 
$
176,933

 
$
(498
)
 
$
(176,435
)
 
$
297,198




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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)

 
Six months ended June 30, 2018
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Total revenues
$
360,335

 
$
217,797

 
$
—

 
$
—

 
$
578,132

 
 
 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
30,424

 
11,394

 
—

 
—

 
41,818

Production taxes
8,804

 
5,709

 
—

 
—

 
14,513

Midstream gathering and processing expenses
98,208

 
37,425

 
—

 
—

 
135,633

Depreciation, depletion, and amortization
232,932

 
1

 
—

 
—

 
232,933

General and administrative expenses
28,786

 
(1,681
)
 
2

 
—

 
27,107

Accretion expense
1,585

 
434

 
—

 
—

 
2,019

 
400,739

 
53,282

 
2

 
—

 
454,023

 
 
 
 
 
 
 
 
 
 
(LOSS) INCOME FROM OPERATIONS
(40,404
)
 
164,515

 
(2
)
 
—

 
124,109

 
 
 
 
 
 
 
 
 
 
OTHER (INCOME) EXPENSE:
 
 
 
 
 
 
 
 
 
Interest expense
69,056

 
(1,387
)
 
—

 
—

 
67,669

Interest income
(58
)
 
(12
)
 
—

 
—

 
(70
)
Insurance proceeds
(231
)
 
—

 
—

 
—

 
(231
)
Gain on sale of equity method investments
(25,616
)
 
(96,419
)
 
—

 
—

 
(122,035
)
(Income) loss from equity method investments and investments in subsidiaries
(283,765
)
 
(693
)
 
558

 
261,476

 
(22,424
)
Other (income) expense
(1,130
)
 
(10
)
 
—

 
1,000

 
(140
)
 
(241,744
)
 
(98,521
)
 
558

 
262,476

 
(77,231
)
 
 
 
 
 
 
 
 
 
 
INCOME (LOSS) BEFORE INCOME TAXES
201,340

 
263,036

 
(560
)
 
(262,476
)
 
201,340

INCOME TAX BENEFIT
(69
)
 
—

 
—

 
—

 
(69
)
 
 
 
 
 
 
 
 
 
 
NET INCOME (LOSS)
$
201,409

 
$
263,036

 
$
(560
)
 
$
(262,476
)
 
$
201,409




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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
 
Three months ended June 30, 2019
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
234,956

 
$
78,291

 
$
(104
)
 
$
(78,187
)
 
$
234,956

Foreign currency translation adjustment
3,610

 
61

 
3,549

 
(3,610
)
 
3,610

Other comprehensive income (loss)
3,610

 
61

 
3,549

 
(3,610
)
 
3,610

Comprehensive income (loss)
$
238,566

 
$
78,352

 
$
3,445

 
$
(81,797
)
 
$
238,566




 
Three months ended June 30, 2018
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
111,319

 
$
176,350

 
$
(229
)
 
$
(176,121
)
 
$
111,319

Foreign currency translation adjustment
(3,364
)
 
14

 
(3,378
)
 
3,364

 
(3,364
)
Other comprehensive (loss) income
(3,364
)
 
14

 
(3,378
)
 
3,364

 
(3,364
)
Comprehensive income (loss)
$
107,955

 
$
176,364

 
$
(3,607
)
 
$
(172,757
)
 
$
107,955




 
Six months ended June 30, 2019
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
297,198

 
$
176,933

 
$
(498
)
 
$
(176,435
)
 
$
297,198

Foreign currency translation adjustment
7,411

 
155

 
7,256

 
(7,411
)
 
7,411

Other comprehensive income (loss)
7,411

 
155

 
7,256

 
(7,411
)
 
7,411

Comprehensive income (loss)
$
304,609

 
$
177,088

 
$
6,758

 
$
(183,846
)
 
$
304,609




 
Six months ended June 30, 2018
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
Net income (loss)
$
201,409

 
$
263,036

 
$
(560
)
 
$
(262,476
)
 
$
201,409

Foreign currency translation adjustment
(8,867
)
 
(173
)
 
(8,694
)
 
8,867

 
(8,867
)
Other comprehensive (loss) income
(8,867
)
 
(173
)
 
(8,694
)
 
8,867

 
(8,867
)
Comprehensive income (loss)
$
192,542

 
$
262,863

 
$
(9,254
)
 
$
(253,609
)
 
$
192,542



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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Amounts in thousands)
 
Six months ended June 30, 2019
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
230,776

 
$
74,857

 
$
3,355

 
$
1

 
$
308,989

 
 
 
 
 
 
 
 
 
 
Net cash (used in) provided by investing activities
(324,357
)
 
(91,769
)
 
(3,751
)
 
432

 
(419,445
)
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) financing activities
78,936

 
—

 
433

 
(433
)
 
78,936

 
 
 
 
 
 
 
 
 
 
Net (decrease) increase in cash, cash equivalents and restricted cash
(14,645
)
 
(16,912
)
 
37

 
—

 
(31,520
)
 
 
 
 
 
 
 
 
 
 
Cash, cash equivalents and restricted cash at beginning of period
25,585

 
26,711

 
1

 
—

 
52,297

 
 
 
 
 
 
 
 
 
 
Cash, cash equivalents and restricted cash at end of period
$
10,940

 
$
9,799

 
$
38

 
$
—

 
$
20,777




 
Six months ended June 30, 2018
 
Parent
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
370,965

 
$
40,078

 
$
—

 
$
1

 
$
411,044

 
 
 
 
 
 
 
 
 
 
Net cash (used in) provided by investing activities
(327,362
)
 
(33,103
)
 
(1,569
)
 
1,569

 
(360,465
)
 
 
 
 
 
 
 
 
 
 
Net cash (used in) provided by financing activities
(30,906
)
 
—

 
1,570

 
(1,570
)
 
(30,906
)
 
 
 
 
 
 
 
 
 
 
Net increase in cash, cash equivalents and restricted cash
12,697

 
6,975

 
1

 
—

 
19,673

 
 
 
 
 
 
 
 
 
 
Cash, cash equivalents and restricted cash at beginning of period
67,908

 
31,649

 
—

 
—

 
99,557

 
 
 
 
 
 
 
 
 
 
Cash, cash equivalents and restricted cash at end of period
$
80,605

 
$
38,624

 
$
1

 
$
—

 
$
119,230




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15.
RECENT ACCOUNTING PRONOUNCEMENTS
In February 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. Subsequent to ASU 2016-02, the FASB issued several related ASU’s to clarify the application of the lease standard. The Company adopted the new standard as of January 1, 2019 on a prospective basis using the simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 12 for further discussion of the lease standard.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures and does not anticipate it to have a material effect.

In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company assessed the impact of the ASU on its consolidated financial statements and related disclosures, and determined there was no material impact.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.
In August 2018, the FASB also issued ASU No. 2018-15 , Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.
In November 2018, the FASB also issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.
16.
SUBSEQUENT EVENTS
Sale of Southern Louisiana Assets
In December of 2018, the Company entered into an agreement to sell its non-core assets located in the WCBB and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. The Company

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received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding certain thresholds over the next two years. The buyer has agreed to assume all plugging and abandonment liabilities associated with these assets. The effective date of the transaction is August 15, 2018. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions.
Debt Repurchases
In July 2019, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $104.4 million aggregate principal amount of its outstanding 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes for $80.3 million.






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ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes included in our Annual Report on Form 10-K and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.
Cautionary Note Regarding Forward-Looking Statements
This report includes “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"). When used in this Quarterly Report, the words "could", "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.
All statements other than statements of historical facts included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including, general economic, market or business conditions; commodity prices; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; adverse developments or losses from pending or future litigation and regulatory proceedings; our ability to identify, complete and integrate acquisitions of properties and businesses; changes in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and other factors, including those listed under Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018, this Quarterly Report on Form 10-Q and in our other filings with the SEC, many of which are beyond our control and may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. 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 events or circumstances after the date of this Quarterly Report
Investors should note that Gulfport announces financial information in SEC filings, press releases and public conference calls. Gulfport may use the Investors section of its website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on Gulfport’s website is not part of this Quarterly Report on Form 10-Q.
Overview
We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquids, or NGLs, in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, among other interests, we hold an acreage

36
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position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC ("Grizzly"), and an approximate 21.8% equity interest in Mammoth Energy Services, Inc. ("Mammoth Energy"), an energy services company listed on the Nasdaq Global Select Market (TUSK). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.
2019 Operational and Other Highlights
•
During the six months ended June 30, 2019, we spud 11 gross (9.4 net) wells in the Utica Shale and participated in three additional gross (0.8 net) wells that were drilled by other operators on our Utica Shale acreage. In addition, during the six months ended June 30, 2019, we spud seven gross (5.7 net) wells in the SCOOP and participated in an additional 28 gross (0.6 net) wells that were drilled by other operators on our SCOOP acreage. Of the 18 new wells we spud, at June 30, 2019, 16 were in various stages of completion and two were being drilled. In addition, 31 gross and net operated wells were turned-to-sales in our Utica Shale operating area and nine gross (8.7 net) operated wells were turned-to-sales in our SCOOP operating area during the six months ended June 30, 2019.
•
For the six months ended June 30, 2019, we decreased our unit general and administrative expense by 9% to $0.10 per Mcfe from $0.11 per Mcfe for the six months ended June 30, 2018.

•
In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period, which we believe underscores the confidence we have in our business model, financial performance and asset base. As of July 26, 2019, we have repurchased approximately 3.8 million shares of our outstanding common stock pursuant to the plan for total consideration of approximately $30.0 million.
•
In December of 2018, we entered into an agreement to sell our non-core assets located in the WCBB and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. We received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, we could also receive contingent payments based on commodity prices exceeding certain thresholds over the next two years. The buyer has agreed to assume all plugging and abandonment liabilities associated with these assets. The effective date of the transaction is August 15, 2018. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions.
•
In July 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $104.4 million aggregate principal amount of our outstanding 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes for $80.3 million.





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2019 Production and Drilling Activity
During the three months ended June 30, 2019, our total net production was 111,602,875 thousand cubic feet, or Mcf, of natural gas, 649,216 barrels of oil and 57,188,687 gallons of NGLs for a total of 123,668 million cubic feet of natural gas equivalent, or MMcfe, as compared to 108,236,412 Mcf of natural gas, 744,311 barrels of oil and 58,511,924 gallons of NGLs, or 121,061 MMcfe, for the three months ended June 30, 2018. Our total net production averaged approximately 1,359.0 MMcfe per day during the three months ended June 30, 2019, as compared to 1,330.3 MMcfe per day during the same period in 2018. The 2% increase in production is largely the result of the continuing development of our Utica Shale and SCOOP acreage.
Utica Shale. From January 1, 2019 through June 30, 2019, we spud 11 gross (9.4 net) wells in the Utica Shale, of which one was being drilled and ten were in various stages of completion at June 30, 2019. We also participated in three additional gross (0.8 net) wells that were drilled by other operators on our Utica Shale acreage. From July 1, 2019 through July 26, 2019, we spud two gross (2.0 net) well in the Utica Shale.
As of July 26, 2019, we had one operated horizontal rig running in the Utica Shale. We currently intend to spud 13 to 15 gross (10 to 11 net) horizontal wells, and commence sales from 47 to 51 gross (40 to 45 net) horizontal wells, on our Utica Shale acreage in 2019. We also anticipate an additional two to three net horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, on our Utica Shale acreage by other operators during 2019.
Aggregate net production from our Utica Shale acreage during the three months ended June 30, 2019 was approximately 95,616 MMcfe, or an average of 1,050.7 MMcfe per day, of which 97% was natural gas and 3% was oil and NGLs.
SCOOP. From January 1, 2019 through June 30, 2019, we spud seven gross (5.7 net) wells in the SCOOP, of which one was being drilled and six were in various stages of completion at June 30, 2019. We also participated in an additional 28 gross (0.6 net) wells that were drilled by other operators on our SCOOP acreage. From July 1, 2019 through July 26, 2019, we did not spud any wells on our SCOOP acreage.
As of July 26, 2019, we had one operated horizontal rig running on our SCOOP acreage. We currently intend to spud nine to ten gross (seven to eight net) horizontal wells, and commence sales from 15 to 17 gross (14 to 15 net) horizontal wells, on our SCOOP acreage in 2019. We also anticipate one to two net wells will be drilled, and sales commenced from one to two net wells on our SCOOP acreage by other operators during 2019.
Aggregate net production from our SCOOP acreage during the three months ended June 30, 2019 was approximately 27,149 MMcfe, or an average of 298.3 MMcfe per day, of which 71% was from natural gas and 29% was from oil and NGLs.
WCBB. From January 1, 2019 through July 3, 2019, we did not spud any new wells or recomplete any wells in the WCBB field. Our aggregate net production from the WCBB field during the three months ended June 30, 2019 was approximately 685 MMcfe, or an average of 7.5 MMcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of all of our WCBB assets.
East Hackberry Field. From January 1, 2019 through July 3, 2019, we did not spud any new wells or recomplete any wells. Our aggregate net production from the East Hackberry field during the three months ended June 30, 2019 was approximately 91.3 MMcfe, or an average of 1.0 MMcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of our East Hackberry assets.
West Hackberry Field. From January 1, 2019 through July 3, 2019, we did not spud any new wells in our West Hackberry field. Our aggregate net production from the West Hackberry field during the three months ended June 30, 2019 was approximately 17.0 MMcfe, or an average of 186.5 Mcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of our West Hackberry assets.
We have no further capital obligations related to the Louisiana fields after July 3, 2019.
Niobrara Formation. From January 1, 2019 through July 26, 2019, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately 17.0 MMcfe, or an average of 187.0 Mcfe per day during the three months ended June 30, 2019, all of which was from oil.

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Bakken. As of June 30, 2019, we had an interest in 18 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended June 30, 2019 was approximately 92.5 MMcfe, or an average of 1.0 MMcfe per day, of which 77% was from oil and 23% was from natural gas and natural gas liquids.

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RESULTS OF OPERATIONS
Comparison of the Three Month Periods Ended June 30, 2019 and 2018
We reported net income of $235.0 million for the three months ended June 30, 2019 as compared to net income of $111.3 million for the three months ended June 30, 2018. This $123.7 million period-to-period increase was due primarily to a $206.3 million increase in oil and natural gas revenues and a $179.3 million increase in income tax benefit, partially offset by a $134.5 million increase in loss from equity method investments, including a $125.4 million impairment related to our investment in Mammoth Energy and a $122.0 million decrease in gain on sale of equity method investments for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. If Mammoth Energy's common stock continues to trade below our carrying value for a prolonged period of time, further impairment of our investment in Mammoth Energy may be necessary. The gain on sale of equity investments in 2018 was the result of the sale of our interest in Strike Force and the sale of Mammoth Energy common stock during 2018.
Natural Gas, Oil and NGL Revenues. For the three months ended June 30, 2019, we reported oil and natural gas revenues of $459.0 million as compared to oil and natural gas revenues of $252.7 million during the same period in 2018. This $206.3 million, or 82%, increase in revenues was primarily attributable to the following:
•
A $241.7 million increase in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $224.6 million was due to a favorable change in the fair value of our open derivative positions in each period and $17.1 million was due to favorable changes in settlements related to our derivative positions. The favorable change in fair value of our open derivative positions is primarily a result of the decrease in the forward curve prices for natural gas from the previous reporting period.
Such increases were partially offset by:
•
A $12.4 million decrease in oil and condensate sales without the impact of derivatives due to a 14% decrease in oil and condensate market prices and a 13% decrease in oil and condensate sales volumes.

•
A $15.6 million decrease in NGLs sales without the impact of derivatives due to a 36% decrease in NGLs market prices and a 2% decrease in NGLs sales volumes.

•
A $7.4 million decrease in natural gas sales without the impact of derivatives due to a 6% decrease in natural gas market prices, partially offset by a 3% increase in natural gas sales volumes.


The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the three months ended June 30, 2019, as compared to such data for the three months ended June 30, 2018:
 
Three months ended June 30,
 
2019
 
2018
 
($ In thousands)
Natural gas sales
 
 
 
Natural gas production volumes (MMcf)
111,603

 
108,236

 
 
 
 
Total natural gas sales
$
225,257

 
$
232,695

 
 
 
 
Natural gas sales without the impact of derivatives ($/Mcf)
$
2.02

 
$
2.15

Impact from settled derivatives ($/Mcf)
$
0.18

 
$
0.17

Average natural gas sales price, including settled derivatives ($/Mcf)
$
2.20

 
$
2.32

 
 
 
 
Oil and condensate sales
 
 
 
Oil and condensate production volumes (MBbls)
649

 
744

 
 
 
 

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Total oil and condensate sales
$
36,910

 
$
49,319

 
 
 
 
Oil and condensate sales without the impact of derivatives ($/Bbl)
$
56.85

 
$
66.26

Impact from settled derivatives ($/Bbl)
$
0.57

 
$
(10.97
)
Average oil and condensate sales price, including settled derivatives ($/Bbl)
$
57.42

 
$
55.29

 
 
 
 
NGLs sales
 
 
 
NGLs production volumes (MGal)
57,189

 
58,512

 
 
 
 
Total NGLs
$
25,687

 
$
41,271

 
 
 
 
NGLs sales without the impact of derivatives ($/Gal)
$
0.45

 
$
0.71

Impact from settled derivatives ($/Gal)
$
0.06

 
$
(0.07
)
Average NGLs sales price, including settled derivatives ($/Gal)
$
0.51

 
$
0.64

 
 
 
 
Natural gas, oil and condensate and NGLs sales
 
 
 
Natural gas equivalents (MMcfe)
123,668

 
121,061

 
 
 
 
Total natural gas, oil and condensate and NGLs sales
$
287,854


$
323,285

 
 
 
 
Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)
$
2.33

 
$
2.67

Impact from settled derivatives ($/Mcfe)
$
0.19

 
$
0.05

Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)
$
2.52

 
$
2.72

 
 
 
 
Production Costs:
 
 
 
Average production costs ($/Mcfe)
$
0.18

 
$
0.19

Average production taxes ($/Mcfe)
$
0.07

 
$
0.06

Average midstream gathering and processing ($/Mcfe)
$
0.58

 
$
0.59

Total production costs, midstream costs and production taxes ($/Mcfe)
$
0.83

 
$
0.84


Lease Operating Expenses. Lease operating expenses ("LOE") not including production taxes decreased to $22.4 million for the three months ended June 30, 2019 from $22.9 million for the three months ended June 30, 2018. This $0.5 million, or 2%, decrease was primarily the result of a decrease in wireline services, production chemicals, contract labor and facility maintenance expense, partially offset by an increase in disposal costs, location repairs and ad valorem taxes. In addition, due to increased efficiencies and a 2% increase in our production volumes for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018, our per unit LOE decreased by 5% from $0.19 per Mcfe to $0.18 per Mcfe.

Production Taxes. Production taxes increased $0.4 million, or 5%, to $8.1 million for the three months ended June 30, 2019 from $7.7 million for the three months ended June 30, 2018. This increase was primarily due to an increase in production volumes and an increase in the production tax rate associated with our SCOOP production.
Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased to $72.0 million for the three months ended June 30, 2019 from $71.4 million for the same period in 2018. This $0.6 million, or 1%, increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2019 drilling activities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ("DD&A") expense increased to $125.0 million for the three months ended June 30, 2019, and consisted of $122.5 million in depletion of oil and natural gas

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properties and $2.5 million in depreciation of other property and equipment, as compared to total DD&A expense of $121.9 million for the three months ended June 30, 2018. This $3.1 million, or 3%, increase was primarily due to an increase in our depletion rate as a result of a decrease in our full cost pool and a decrease in our total proved reserves volumes used to calculate our total DD&A expense, as well as an increase in our production.
General and Administrative Expenses. Net general and administrative expenses decreased to $13.3 million for the three months ended June 30, 2019 from $14.0 million for the three months ended June 30, 2018. This $0.7 million, or 5%, decrease was primarily due to decreases in consulting fees and travel expense, partially offset by increases in computer support and tax services. In addition, for the three months ended June 30, 2019, we decreased our unit general and administrative expense by 8% to $0.11 per Mcfe from $0.12 per Mcfe for the three months ended June 30, 2018.
Interest Expense. Interest expense increased to $34.9 million for the three months ended June 30, 2019 as compared to $33.7 million for the three months ended June 30, 2018 due primarily to increased borrowings on our revolving credit facility as compared to the same period in 2018. In addition, total weighted average debt outstanding under our revolving credit facility was $168.8 million for the three months ended June 30, 2019 as compared to $112.9 million debt outstanding under such facility. As of June 30, 2019, amounts borrowed under our revolving credit facility bore interest at a weighted average rate of 3.93%. In addition, we capitalized approximately $1.0 million and $1.5 million in interest expense to undeveloped oil and natural gas properties during the three months ended June 30, 2019 and 2018, respectively. This $0.5 million decrease in capitalized interest in the 2019 period was primarily the result of changes to our development plan for our oil and natural gas properties.
Income Taxes. As of June 30, 2019, we had a federal net operating loss carryforward of approximately $920.4 million from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. During the three months ending June 30, 2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of $179.3 million. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $27.7 million with respect to current year earnings. We will maintain a valuation allowance of $4.8 million against the net deferred tax asset for certain tax attributes for which we have determined it is more likely than not those attribute carryforwards will expire prior to utilization.
Comparison of the Six Month Periods Ended June 30, 2019 and 2018
We reported net income of $297.2 million for the six months ended June 30, 2019 as compared to net income of $201.4 million for the six months ended June 30, 2018. This $95.8 million period-to-period increase was due primarily to a $201.4 million increase in natural gas, oil and NGL revenues and a $179.3 million increase in income tax benefit, partially offset by a $143.7 million increase in loss from equity method investments, including a $125.4 million impairment related to our investment in Mammoth Energy, a $122.0 million decrease in gain on sale of equity method investments, a $10.5 million increase in DD&A and a $6.7 million increase in midstream gathering and processing expenses for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. If Mammoth Energy's common stock continues to trade below our carrying value for a prolonged period of time, further impairment of our investment in Mammoth Energy may be necessary. The gain on sale of equity investments in 2018 was a result of the sale of our interest in Strike Force and the sale of Mammoth Energy common stock during 2018.
Oil and Gas Revenues. For the six months ended June 30, 2019, we reported oil and natural gas revenues of $779.6 million as compared to oil and natural gas revenues of $578.1 million during the same period in 2018. This $201.4 million, or 35%, increase in revenues was primarily attributable to the following:
•
A $238.1 million increase in in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $254.8 million was due to favorable changes in the fair value of our open derivative positions in each period, partially offset by a $16.7 million unfavorable change in settlements related to our derivative positions. The favorable change in fair value of our open derivative positions is primarily a result of the decrease in the forward curve prices for natural gas from the previous reporting period.
•
A $19.2 million increase in natural gas sales without the impact of derivatives due to a 2% increase in natural gas sales volumes and a 2% increase in natural gas market prices.

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Such increases were partially offset by:

•
A $25.6 million decrease in oil and condensate sales without the impact of derivatives due to a 16% decrease in oil and condensate sales volumes and a 13% decrease in oil and condensate market prices.

•
A $30.3 million decrease in NGLs sales without the impact of derivatives due to a 28% decrease in NGLs market prices and a 9% decrease in NGLs sales volumes.

    
The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the six months ended June 30, 2019, as compared to such data for the six months ended June 30, 2018:

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Six months ended June 30,
 
2019
 
2018
 
($ In thousands)
Natural gas sales
 
 
 
Natural gas production volumes (MMcf)
213,682

 
210,278

 
 
 
 
Total natural gas sales
$
501,273

 
$
482,094

 
 
 
 
Natural gas sales without the impact of derivatives ($/Mcf)
$
2.35

 
$
2.29

Impact from settled derivatives ($/Mcf)
$
(0.03
)
 
$
0.17

Average natural gas sales price, including settled derivatives ($/Mcf)
$
2.32

 
$
2.46

 
 
 
 
Oil and condensate sales
 
 
 
Oil and condensate production volumes (MBbls)
1,261

 
1,501

 
 
 
 
Total oil and condensate sales
$
69,392

 
$
95,005

 
 
 
 
Oil and condensate sales without the impact of derivatives ($/Bbl)
$
55.03

 
$
63.29

Impact from settled derivatives ($/Bbl)
$
0.31

 
$
(8.29
)
Average oil and condensate sales price, including settled derivatives ($/Bbl)
$
55.34

 
$
55.00

 
 
 
 
NGLs sales
 
 
 
NGLs production volumes (MGal)
113,019

 
124,268

 
 
 
 
Total NGLs sales
$
57,812

 
$
88,107

 
 
 
 
NGLs sales without the impact of derivatives ($/Gal)
$
0.51

 
$
0.71

Impact from settled derivatives ($/Gal)
$
0.04

 
$
(0.05
)
Average NGLs sales price, including settled derivatives ($/Gal)
$
0.55

 
$
0.66

 
 
 
 
Natural gas, oil and condensate and NGLs sales
 
 
 
Gas equivalents (MMcfe)
237,394

 
237,038

 
 
 
 
Total natural gas, oil and condensate and NGLs sales
$
628,477

 
$
665,206

 
 
 
 
Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)
$
2.65

 
$
2.81

Impact from settled derivatives ($/Mcfe)
$
(0.01
)
 
$
0.06

Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)
$
2.64

 
$
2.87

 
 
 
 
Production Costs:
 
 
 
Average production costs ($/Mcfe)
$
0.18

 
$
0.18

Average production taxes ($/Mcfe)
$
0.07

 
$
0.06

Average midstream gathering and processing ($/Mcfe)
$
0.60

 
$
0.57

Total production costs, midstream costs and production taxes ($/Mcfe)
$
0.85

 
$
0.81



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Lease Operating Expenses. Lease operating expenses not including production taxes increased to $42.2 million for the six months ended June 30, 2019 from $41.8 million for the six months ended June 30, 2018. This $0.4 million, or 1%, increase was primarily the result of an increase in expenses related to location repair, disposal costs and ad valorem taxes, partially offset by a decrease in wireline services, facility maintenance expense and surface rentals.
Production Taxes. Production taxes increased to $16.0 million for the six months ended June 30, 2019 from $14.5 million for the same period in 2018. This $1.5 million, or 10%, increase was primarily related to an increase in the production tax rate associated with our SCOOP production.
Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased to $142.3 million for the six months ended June 30, 2019 from $135.6 million for the same period in 2018. This $6.7 million, or 5%, increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2019 drilling activities as well as routine contract escalations associated with our Utica Shale production.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to $243.4 million for the six months ended June 30, 2019, and consisted of $237.7 million in depletion of oil and natural gas properties and $5.7 million in depreciation of other property and equipment, as compared to total DD&A expense of $232.9 million for the six months ended June 30, 2018. This $10.5 million, or 4%, increase was primarily due to an increase in our depletion rate as a result of a decrease in our full cost pool and a decrease in our total proved reserves volumes used to calculate our total DD&A expense and an increase in our production.
General and Administrative Expenses. Net general and administrative expenses decreased to $24.8 million for the six months ended June 30, 2019 from $27.1 million for the six months ended June 30, 2018. This $2.3 million, or 8%, decrease was primarily due to decreases in consulting fees and travel expenses, partially offset by increases in tax services and computer support. In addition, for the six months ended June 30, 2019, we decreased our unit general and administrative expense by 9% to $0.10 per Mcfe from $0.11 per Mcfe the six months ended June 30, 2018.
Interest Expense. Interest expense increased to $69.0 million for the six months ended June 30, 2019 from $67.7 million for the six months ended June 30, 2018 due primarily to increased borrowings on our revolving credit facility. Total weighted average debt outstanding under our revolving credit facility was $123.3 million for the six months ended June 30, 2019 as compared to $100.1 million for the same period in 2018. Additionally, we capitalized approximately $1.8 million and $2.4 million in interest expense to undeveloped oil and natural gas properties during the six months ended June 30, 2019 and June 30, 2018, respectively. This $0.6 million decrease in capitalized interest in the 2019 period was primarily the result of changes to our development plan for our oil and natural gas properties.
Income Taxes. As of June 30, 2019, we had a federal net operating loss carryforward of approximately $920.4 million from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. During the six months ending June 30, 2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of $179.3 million. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $27.7 million with respect to current year earnings. We will maintain a valuation allowance of $4.8 million against the net deferred tax asset for certain tax attributes for which we have determined it is more likely than not those attribute carryforwards will expire prior to utilization.
Liquidity and Capital Resources
Overview.
Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and natural gas production.
Net cash flow provided by operating activities was $309.0 million for the six months ended June 30, 2019 as compared to $411.0 million for the same period in 2018. This $102.0 million decrease was primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to an 8% decrease in net revenues after giving effect to settled derivative

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instruments and an increase in our operating expenses. In addition, we received $2.5 million in dividends from our investment in Mammoth Energy during the six months ended June 30, 2019.
Net cash used in investing activities for the six months ended June 30, 2019 was $419.4 million as compared to $360.5 million for the same period in 2018. During the six months ended June 30, 2019, we spent $417.5 million in additions to oil and natural gas properties, of which $256.7 million was spent on our 2019 drilling and completion activities, $83.9 million was spent on expenses attributable to wells spud, completed and recompleted during 2018, $25.8 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $27.8 million was spent on tubulars, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. During the six months ended June 30, 2019, we invested $0.4 million in Grizzly and received a distribution of $1.9 million from Tatex. We did not make any investments in our other equity investments during the six months ended June 30, 2019.
Net cash provided by financing activities for the six months ended June 30, 2019 was $78.9 million as compared to net cashed used in financing activities of $30.9 million for the same period in 2018. The 2019 amount provided by financing activities is primarily attributable to net borrowings under our credit facility partially offset by purchases under our stock repurchase program of approximately $30.0 million.
Credit Facility.
We have entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of June 30, 2019, we had a borrowing base of $1.4 billion, with an elected commitment of $1.0 billion, and $155.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $251.5 million of outstanding letters of credit, were $593.5 million as of June 30, 2019. This facility is secured by substantially all of our assets. Our wholly owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings") and Mule Sky LLC ("Mule Sky") guarantee our obligations under our revolving credit facility.
Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At June 30, 2019, amounts borrowed under our credit facility bore interest at a weighted average rate of 3.93%.
Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investment plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than

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4.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at June 30, 2019.
Senior Notes.
In April 2015, we issued an aggregate of $350.0 million in principal amount of our Senior Notes due 2023 (the "2023 Notes"). Interest on these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1, 2023.
On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our Senior Notes due 2024 (the "2024 Notes"). Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024.
On December 21, 2016, we issued an aggregate of $600.0 million in principal amount of our Senior Notes due 2025 (the "2025 Notes"). Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of our Senior Notes due 2026 (the "2026 Notes" and, together with the 2023 Notes, the 2024 Notes, and the 2025 Notes, the "Notes"). Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. We received approximately $444.1 million in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of our outstanding borrowings under our secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to our 2017 capital development plans.
All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings or Mule Sky, and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors’ secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Notes.
If we experience a change of control (as defined in the senior note indentures relating to the Notes), we will be required to make an offer to repurchase the Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Under the indentures relating to the Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the Notes are ranked as “investment grade.”
In connection with the issuance of the 2024 Notes, 2025 Notes and 2026 Notes, we and our subsidiary guarantors entered into registration rights agreements, pursuant to which we agreed to file a registration statement with respect to offers to exchange the 2024 Notes, 2025 Notes and 2026 Notes, as applicable, for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were completed on September 13, 2017, and the exchange offer for the 2026 Notes was completed on March 22, 2018.

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We may use a combination of cash and borrowings under our revolving credit facility to retire our outstanding debt, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
Construction Loan.
On June 4, 2015, we entered into a construction loan agreement (the "construction loan") with InterBank for the construction of our new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The construction loan allows for maximum principal borrowings of $24.5 million and required us to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and we make monthly payments of interest and principal. The final payment is due June 4, 2025. As of June 30, 2019, the total borrowings under the construction loan were approximately $22.7 million.
Capital Expenditures.
Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions in the Utica Shale and our SCOOP acquisition in 2017, and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities.
Of our net reserves at December 31, 2018, 55.4% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.
For further discussion on activities related to our capital expenditures incurred through June 30, 2019 see 2019 Production and Drilling Activity section above.
As of June 30, 2019, our net investment in Grizzly was approximately $51.6 million. We do not currently anticipate any material capital expenditures in 2019 related to Grizzly’s activities.
We had no capital expenditures during the six months ended June 30, 2019 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2019.
In response to current declining forward natural gas prices, we are shifting to building an organization that is focused on disciplined capital allocation, cash flow generation and a commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our stockholders. We plan to maximize results with the core assets in our portfolio today and focus on returns that will allow us to operate within our cash flow in 2019. As a result, we currently expect to reduce our planned capital expenditures by approximately 29% as compared to 2018.
Our total capital expenditures for 2019 are currently estimated to be in the range of $525.0 million to $550.0 million for drilling and completion expenditures, with activity weighted to the first half of the year, of which $436.0 million was spent as of June 30, 2019. In addition, we currently expect to spend $40.0 to $50.0 million in 2019 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale, of which $23.2 million was spent as of June 30, 2019. The 2019 range of capital expenditures is lower than the $814.7 million spent in 2018, primarily due to the decrease in current commodity prices, specifically natural gas prices, and our desire to fund our capital development program within cash flow, as well as to generate free cash flow.
In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period. We intend to purchase shares under the repurchase program opportunistically with available funds primarily from cash flow from operations and sale of non-core assets while maintaining sufficient liquidity to fund our capital development programs.
We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We believe that

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our strong liquidity position, hedge portfolio and conservative balance sheet position us well to react quickly to changing commodity prices and accelerate or decelerate our activity within the Utica Shale and the SCOOP as the market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels, our capital or other costs increase, our equity method investments require additional contributions and/or we pursue additional equity method investments or acquisitions, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. Further, if we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. If the current low commodity price environment worsens, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.
Commodity Price Risk
See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at June 30, 2019.
Contractual and Commercial Obligations
We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.    
Off-balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations.  As of June 30, 2019, our material off-balance sheet arrangements and transactions include $251.5 million in letters of credit outstanding against our 2019 revolving credit facility and $73.9 million in surety bonds issued as financial assurance on midstream firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 7 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Critical Accounting Policies and Estimates
As of June 30, 2019, there have been no significant changes in our critical accounting policies from those disclosed in our 2018 Annual Report on Form 10-K.
New Accounting Pronouncements
In February 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. Subsequent to ASU 2016-02, the FASB issued several related ASU’s to clarify the application of the lease standard. We adopted the new standard as of January 1, 2019 on a prospective basis using the simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 12 to our consolidated financial statements for further discussion of the lease standard.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted. We are currently evaluating the

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impact this standard will have on our financial statements and related disclosures and do not anticipate it to have a material effect.
In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. We assessed the impact of the ASU on our consolidated financial statements and related disclosures, and determined there was no material impact.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.
In August 2018, the FASB also issued ASU No. 2018-15 , Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.
In November 2018, the FASB also issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2018, West Texas Intermediate ("WTI") prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On July 26, 2019, the WTI posted price for crude oil was $56.20 per Bbl and the Henry Hub spot market price for natural gas was $2.23 per MMBtu. If the prices of oil and natural gas decline from current levels, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.

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To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swap positions at June 30, 2019:
 
Location
Daily Volume (MMBtu/day)
 
Weighted
Average Price
Remaining 2019
NYMEX Henry Hub
1,380,000

 
$
2.81

2020
NYMEX Henry Hub
204,000

 
$
2.77

 
Location
Daily Volume
(Bbls/day)
 
Weighted
Average Price
Remaining 2019
NYMEX WTI
6,000

 
$
60.81

2020
NYMEX WTI
6,000

 
$
59.82


 
Location
Daily Volume
(Bbls/day)
 
Weighted
Average Price
Remaining 2019
Mont Belvieu C2
1,000

 
$
18.48

Remaining 2019
Mont Belvieu C3
4,000

 
$
29.02

Remaining 2019
Mont Belvieu C5
1,000

 
$
53.71

We sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, we pay our counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.
 
Location
Daily Volume (MMBtu/day)
 
Weighted Average Price
Remaining 2019
NYMEX Henry Hub
30,000

 
$
3.10

For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the original terms an additional twelve months for the period January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is included in the natural gas fixed price swaps listed above.
In addition, we have entered into natural gas basis swap positions. As of June 30, 2019, we had the following natural gas basis swap positions open:
 
Gulfport Pays
Gulfport Receives
Daily Volume (MMBtu/day)
 
Weighted Average Fixed Spread
Remaining 2019
Transco Zone 4
NYMEX Plus Fixed Spread
60,000

 
$
(0.05
)
2020
Transco Zone 4
NYMEX Plus Fixed Spread
60,000

 
$
(0.05
)
2020
Fixed Spread
ONEOK Minus NYMEX
10,000

 
$
(0.54
)
Under our 2019 contracts, we have hedged approximately 94% to 96% of our estimated 2019 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. At June 30, 2019, we had a net asset derivative position of $139.5 million as compared to a net liability derivative position of $50.2 million as of June 30, 2018, related to our fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately $99.8 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $99.7 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

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Our revolving amended and restated credit agreement is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the eurodollar rates are elected, the eurodollar rates. At June 30, 2019, we had $155.0 million in borrowings outstanding under our revolving credit facility which bore interest at a weighted average rate of 3.93%. A 1.0% increase in the average interest rate for the six months ended June 30, 2019 would have resulted in an estimated $0.4 million increase in interest expense. As of June 30, 2019, we did not have any interest rate swaps to hedge our interest risks.
ITEM 4.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures. Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
As of June 30, 2019, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of June 30, 2019, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.


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PART II
ITEM 1.
LEGAL PROCEEDINGS
Litigation and Regulatory Proceedings
We are involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. Our total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different.
We, along with a number of other oil and gas companies, have been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The cases have been removed to the United States District Court for the Western District of Louisiana, and motions to remand are pending.
The cases are still in their early stages and the parties have conducted very little discovery. As a result, we have not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to our operations and management cannot determine the amount of loss, if any, that may result.
SEC Investigation
The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, we believe that the outcome of this matter will not have a material effect on our business, financial condition or results of operations.
Business Operations
We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.
We received several Findings of Violation (“FOV”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at less than 20 locations in Ohio. The first FOV for one site was dated December 11,

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2013.  Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019.  We have exchanged information with the USEPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000. 
Other Matters
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations are likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
ITEM 1A.
RISK FACTORS
See risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sales of Equity Securities
None.
Issuer Repurchases of Equity Securities
Our common stock repurchase activity for the three months ended June 30, 2019 was as follows:
Period
 
Total number of shares purchased (2)
 
Average price paid per share
 
Total number of shares purchased as part of publicly announced plans or programs (2)
 
Approximate maximum dollar value of shares that may yet be purchased under the plans or programs (1)
April 2019
 
296,587

 
$
7.65

 
224,563

 
$
370,000,000

May 2019
 
—

 
$
—

 
—

 
$
370,000,000

June 2019
 
—

 
$
—

 
—

 
$
370,000,000

Total
 
296,587

 
$
7.65

 
224,563

 
 
(1)
In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period. This repurchase program may be suspended from time to time, modified, extended or discontinued by our board of directors at any time.
(2)
In April 2019, we repurchased and canceled 224,563 shares under the repurchase program at a weighted average price of $7.96 per share. Additionally, in April 2019, we repurchased and canceled 72,024 shares of our common stock at a weighted average price of $6.69 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards.
ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
Not applicable.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5.
OTHER INFORMATION

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2019 Amended and Restated Stock Incentive Plan

 On June 6, 2019, at the 2019 Annual Meeting of Stockholders of Gulfport Energy Corporation, our stockholders approved the 2019 Amended and Restated Stock Incentive Plan (as amended and restated, the “Plan”), which amended and restated our 2013 Restated Stock Incentive Plan.  The Plan had previously been unanimously adopted, subject to stockholder approval, by the Compensation Committee (the “Compensation Committee”) of our board of directors (our “Board”), acting upon authority delegated to it by our Board. The Plan, among other things, increases the share reserve by an additional 5,000,000 shares and extends the expiration date from April 18, 2023 to April 28, 2029. A detailed summary of the Plan is set forth in our definitive proxy statement filed with the SEC on April 30, 2019. The description of the Plan herein and the summary of the Plan in the proxy statement are qualified in their entirety by reference to the full text of the Plan, which is attached to hereto as Exhibit 10.1 and incorporated by reference herein.
Indemnification Agreements
 On August 1, 2019, the Company entered into indemnification agreements with each of its directors and David M. Wood, the Company’s Chief Executive Officer and President, Donnie Moore, the Company’s Chief Operating Officer, and Patrick K. Craine, the Company’s General Counsel and Corporate Secretary. The indemnification agreements require the Company to indemnify those individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to the Company, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. The indemnification agreements superseded any existing indemnification agreements between the Company and those individuals.  The description of the indemnification agreements herein is qualified in its entirety by reference to the full text of the form of indemnification agreement, which is attached to hereto as Exhibit 10.2 and incorporated by reference herein.
Employment Agreements
Effective August 1, 2019, the Company entered into employment agreements (the “Employment Agreements”) with David M. Wood, the Company’s Chief Executive Officer and President, Donnie Moore, the Company’s Chief Operating Officer, and Patrick K. Craine, the Company’s General Counsel and Corporate Secretary (each, an “Executive”).
Each Employment Agreement provides for an initial term that extends through December 31, 2023; provided that the agreement will automatically renew for successive one-year terms unless the Company or the Executive gives written notice not to renew at least 90 days before the end of the initial term or any renewal term. If a change in control (as defined in the Employment Agreement) occurs during the term of the Employment Agreement, the term will be extended to the later of the original expiration date of the term or the date that is 24 months after the effective date of the change of control.
The Employment Agreements provide the respective Executive with, among other things: (i) an annual base salary of $834,000, $505,000 and $435,000, for Messrs. Wood, Moore and Craine, respectively, (ii) eligibility to earn a target annual bonus under the Company’s annual incentive plan equal to 125%, 100% and 90% of base salary for Messrs. Wood, Moore and Craine, respectively, (iii) eligibility for annual grants of equity awards as determined in the sole discretion of the Compensation Committee pursuant to the Company's equity compensation plans; provided that, with respect to the calendar year ending December 31, 2020, each of Messrs. Wood, Moore and Craine will receive awards that have a target aggregate fair value of 500%, 350% and 200% of base pay, respectively, and (iv) benefits that are customarily provided to similarly situated executives of the Company.
The Employment Agreements further provide that (i) if the Executive’s employment is terminated without cause by the Company or by the Executive for good reason (as such terms are defined in the Employment Agreements), such Executive is entitled to severance compensation equal to (a) 100% of annual base salary and target annual bonus, (b) pro rata target annual bonus, (c) pro rata vesting of the Executive’s unvested awards (with performance awards vested based on performance through the termination date), (d) immediate vesting of any Company matching or other contributions to the Company’s non-qualified deferred compensation plans, if any (“Company Non-Qualified Contributions”), and (e) a lump sum payment equal to the Executive’s monthly COBRA premium for a 12 month period, and (ii) if the Executive’s employment is terminated without cause by the Company or by the Executive for good reason, in each case, within 24 months following a change in control, such Executive is entitled to severance compensation equal to (v) 200% of annual base salary and target annual bonus, (w) pro rata target annual bonus, (x) immediate vesting of the Executive’s unvested awards (with performance awards vested based on performance through the termination date), (y) immediate vesting of any Company Non-Qualified Contributions, and (z) a lump sum payment equal to the Executive’s monthly COBRA premium for an 18 month period. Any severance benefits

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payable under the Employment Agreement is conditioned on timely execution of a waiver and release of claims. Each Employment Agreement also contains a one-year post-employment non-solicitation clause and standard confidentiality, trade secrets and cooperation provisions.
The description of the Employment Agreements herein is qualified in its entirety by reference to the full text of the Employment Agreements, which are attached to hereto as Exhibits 10.3, 10.4 and 10.5 and incorporated by reference herein.
ITEM 6.
EXHIBITS
Exhibit
Number
 
Description
 
 
3.1
 
 
 
3.2
 
 
 
3.3
 
 
 
3.4
 
 
 
 
3.5
 
 
 
 
3.6
 
 
 
 
4.1
 
 
 
4.5
 
 
 
 
4.6
 
 
 
 
4.7
 
 
 
 
4.8
 
 
 
 
4.9
 
 
 
 
10.1+
 
 
 
 
10.2*+
 
 
 
 
10.3*+
 
 
 
 
10.4*+
 
 
 
 

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10.5*+
 
 
 
 
31.1*
 
 
 
31.2*
 
 
 
32.1*
 
 
 
32.2*
 
 
 
 
101.INS*
 
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*
 
XBRL Taxonomy Extension Schema Document.
 
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
 
101.LAB*
 
XBRL Taxonomy Extension Labels Linkbase Document.
 
 
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document.
 
 
 
104*
 
Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
*
Filed herewith.
+

Management contract, compensation plan or arrangement.


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Table of Contents


SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: August 2, 2019
 
GULFPORT ENERGY CORPORATION
 
 
By:
 
/s/    Keri Crowell
 
 
Keri Crowell
Chief Financial Officer


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