Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

OR

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

For the transition period from ___________ to ___________

Commission File Number 001-31539
smenergylogohorizontala.jpg
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
 
41-0518430
(I.R.S. Employer
Identification No.)
 
 
 
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
 
80203
(Zip Code)
(303) 861-8140
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
 
Accelerated filer o
 
 
 
Non-accelerated filer o
 
Smaller reporting company o
 
 
 
 
 
Emerging growth company o 
 
 
 
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. o 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
As of October 24, 2018, the registrant had 112,142,751 shares of common stock, $0.01 par value, outstanding.

1

TABLE OF CONTENTS

 
 
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share data)
 
September 30,
2018
 
December 31,
2017
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
176,806

 
$
313,943

Accounts receivable
179,347

 
160,154

Derivative assets
81,163

 
64,266

Prepaid expenses and other
15,826

 
10,752

Total current assets
453,142

 
549,115

Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
6,686,922

 
6,139,379

Accumulated depletion, depreciation, and amortization
(3,240,124
)
 
(3,171,575
)
Unproved oil and gas properties
1,892,557

 
2,047,203

Wells in progress
328,808

 
321,347

Properties held for sale, net
5,040

 
111,700

Other property and equipment, net of accumulated depreciation of $56,067 and $49,985, respectively
102,984

 
106,738

Total property and equipment, net
5,776,187

 
5,554,792

Noncurrent assets:
 
 
 
Derivative assets
8,853

 
40,362

Other noncurrent assets
35,539

 
32,507

Total noncurrent assets
44,392

 
72,869

Total assets
$
6,273,721

 
$
6,176,776

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
429,698

 
$
386,630

Derivative liabilities
304,159

 
172,582

Total current liabilities
733,857

 
559,212

Noncurrent liabilities:
 
 
 
Revolving credit facility
—

 
—

Senior Notes, net of unamortized deferred financing costs
2,447,290

 
2,769,663

Senior Convertible Notes, net of unamortized discount and deferred financing costs
145,662

 
139,107

Asset retirement obligations
88,149

 
103,026

Asset retirement obligations associated with oil and gas properties held for sale
—

 
11,369

Deferred income taxes
140,949

 
79,989

Derivative liabilities
72,605

 
71,402

Other noncurrent liabilities
45,810

 
48,400

Total noncurrent liabilities
2,940,465

 
3,222,956

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,137,582 and 111,687,016 shares, respectively
1,121

 
1,117

Additional paid-in capital
1,758,205

 
1,741,623

Retained earnings (1)
856,111

 
665,657

Accumulated other comprehensive loss (1)
(16,038
)
 
(13,789
)
Total stockholders’ equity
2,599,399

 
2,394,608

Total liabilities and stockholders’ equity
$
6,273,721

 
$
6,176,776

____________________________________________
(1) The Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. Please refer to Note 1 - Summary of Significant Accounting Policies for further detail.
The accompanying notes are an integral part of these condensed consolidated financial statements.

3

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share data)
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
(as adjusted)
 
 
 
(as adjusted)
Operating revenues and other income:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
458,382

 
$
294,459

 
$
1,243,826

 
$
912,596

Net gain (loss) on divestiture activity
786

 
(1,895
)
 
425,656

 
(131,565
)
Other operating revenues
201

 
2,815

 
3,398

 
7,807

Total operating revenues and other income
459,369


295,379


1,672,880


788,838

Operating expenses:











Oil, gas, and NGL production expense
127,638

 
122,651

 
365,917

 
385,073

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
201,105

 
134,599

 
483,343

 
425,643

Exploration
13,061

 
14,119

 
40,844

 
38,919

Abandonment and impairment of unproved properties
9,055

 
—

 
26,615

 
157

General and administrative
29,464

 
27,564

 
86,066

 
84,618

Net derivative (gain) loss
178,026

 
80,599

 
249,304

 
(89,364
)
Other operating expenses, net
9,664

 
999

 
14,219

 
10,109

Total operating expenses
568,013


380,531


1,266,308


855,155

Income (loss) from operations
(108,644
)

(85,152
)

406,572


(66,317
)
Interest expense
(38,111
)
 
(44,091
)
 
(122,850
)
 
(135,639
)
Loss on extinguishment of debt
(26,722
)
 
—

 
(26,722
)
 
(35
)
Other non-operating income, net
806

 
861

 
3,017

 
1,581

Income (loss) before income taxes
(172,671
)

(128,382
)

260,017


(200,410
)
Income tax (expense) benefit
36,748

 
39,270

 
(61,342
)
 
65,825

Net income (loss)
$
(135,923
)
 
$
(89,112
)
 
$
198,675


$
(134,585
)
 











Basic weighted-average common shares outstanding
112,107

 
111,575

 
111,836

 
111,366

Diluted weighted-average common shares outstanding
112,107

 
111,575

 
113,600

 
111,366

Basic net income (loss) per common share
$
(1.21
)
 
$
(0.80
)
 
$
1.78

 
$
(1.21
)
Diluted net income (loss) per common share
$
(1.21
)
 
$
(0.80
)
 
$
1.75

 
$
(1.21
)
Dividends per common share
$
0.05

 
$
0.05

 
$
0.10

 
$
0.10

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

4

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands)
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
 
 
 
2018
 
2017
 
2018
 
2017
Net income (loss)
$
(135,923
)
 
$
(89,112
)
 
$
198,675

 
$
(134,585
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Pension liability adjustment
263

 
(208
)
 
721

 
(651
)
Total other comprehensive income (loss), net of tax
263

 
(208
)
 
721

 
(651
)
Total comprehensive income (loss)
$
(135,660
)
 
$
(89,320
)
 
$
199,396

 
$
(135,236
)
The accompanying notes are an integral part of these condensed consolidated financial statements.

5

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
 
 
(as adjusted)
Cash flows from operating activities:
 
 
 
Net income (loss)
$
198,675

 
$
(134,585
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Net (gain) loss on divestiture activity
(425,656
)
 
131,565

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
483,343

 
425,643

Abandonment and impairment of unproved properties
26,615

 
157

Stock-based compensation expense
17,680

 
16,160

Net derivative (gain) loss
249,304

 
(89,364
)
Derivative settlement gain (loss)
(101,911
)
 
29,402

Amortization of debt discount and deferred financing costs
11,542

 
12,478

Loss on extinguishment of debt
26,722

 
35

Deferred income taxes
60,672

 
(67,458
)
Other, net
(2,084
)
 
6,424

Net change in working capital
(3,725
)
 
40,153

Net cash provided by operating activities
541,177

 
370,610

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
743,199

 
778,365

Capital expenditures
(1,032,588
)
 
(624,969
)
Acquisition of proved and unproved oil and gas properties
(24,571
)
 
(87,389
)
Net cash provided by (used in) investing activities
(313,960
)
 
66,007

 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
—

 
406,000

Repayment of credit facility
—

 
(406,000
)
Debt issuance costs related to credit facility
(4,771
)
 
—

Net proceeds from Senior Notes
492,079

 
—

Cash paid to repurchase Senior Notes, including premium
(844,984
)
 
(2,357
)
Net proceeds from sale of common stock
1,881

 
1,738

Dividends paid
(5,584
)
 
(5,563
)
Other, net
(2,975
)
 
(1,392
)
Net cash used in financing activities
(364,354
)
 
(7,574
)
 
 
 
 
Net change in cash, cash equivalents, and restricted cash (1)
(137,137
)
 
429,043

Cash, cash equivalents, and restricted cash at beginning of period (1)
313,943

 
12,372

Cash, cash equivalents, and restricted cash at end of period (1)
$
176,806

 
$
441,415

____________________________________________
(1) 
Refer to Note 1 - Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”).
The accompanying notes are an integral part of these condensed consolidated financial statements.

6

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)
(in thousands)
Supplemental schedule of additional cash flow information and non-cash activities:
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
 
 
(as adjusted)
Operating activities:
 
 
 
Cash paid for interest, net of capitalized interest
$
(124,435
)
 
$
(124,443
)
Net cash paid for income taxes
$
(9,085
)
 
$
(2,800
)
 
 
 
 
Investing activities:
 
 
 
Changes in capital expenditure accruals and other
$
19,811

 
$
2,788

 
 
 
 
Supplemental non-cash investing activities:
 
 
 
Carrying value of properties exchanged
$
95,121

 
$
283,651

 
 
 
 
Supplemental non-cash financing activities:
 
 
 
Non-cash loss on extinguishment of debt, net
$
6,334

 
$
22

Dividends declared, but not paid
$
5,607

 
$
5,581

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

7

SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 1 - Summary of Significant Accounting Policies
Description of Operations
SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report) in onshore North America.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of September 30, 2018, and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying unaudited condensed consolidated financial statements.
Correction of an Immaterial Error
The accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2018, include a non-cash adjustment that relates to prior years.  For the three and nine months ended September 30, 2018, the depletion, depreciation, amortization, and asset retirement obligation liability accretion expense line item on the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) includes $11.8 million of additional expense that should have been recognized in prior years. This non-cash adjustment, net of tax, resulted in reported net income for the nine months ended September 30, 2018, to be understated by $9.0 million, and reported net loss for the three months ended September 30, 2018, to be overstated by $9.0 million. This non-cash adjustment is not deemed material with respect to any prior period reported, the third quarter of 2018, or the anticipated results for fiscal year 2018.
Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2017 Form 10-K.
Recently Issued Accounting Standards
Effective December 31, 2017, the Company early adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) and FASB ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows and ASU 2016-18 is intended to clarify guidance on the classification and presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The Company did not have restricted cash reported within the accompanying balance sheets as of September 30, 2018, or December 31, 2017. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for more information.

8

The accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 for the nine months ended September 30, 2017, are summarized as follows:
 
For the Nine Months Ended
September 30, 2017
 
As Reported
 
As Adjusted
 
(in thousands)
Cash flows from operating activities:
 
 
 
Non-cash (gain) loss on extinguishment of debt, net
$
22

 
N/A

Loss on extinguishment of debt
N/A

 
$
35

Net cash provided by operating activities
$
370,597

 
$
370,610

 
 
 
 
Cash flows from investing activities:
 
 
 
Acquisition deposit held in escrow
$
3,000

 
N/A

Net cash provided by (used in) investing activities
$
69,007

 
$
66,007

 
 
 
 
Cash flows from financing activities:
 
 
 
Cash paid for extinguishment of debt (1)
N/A

 
$
(13
)
Net cash used in financing activities
$
(7,561
)
 
$
(7,574
)
 
 
 
 
Net change in cash and cash equivalents
$
432,043

 
N/A

Net change in cash, cash equivalents, and restricted cash
N/A

 
$
429,043

Cash and cash equivalents at beginning of period
$
9,372

 
N/A

Cash, cash equivalents, and restricted cash at beginning of period
N/A

 
$
12,372

Cash and cash equivalents at end of period
$
441,415

 
N/A

Cash, cash equivalents, and restricted cash at end of period
N/A

 
$
441,415

____________________________________________
(1)
Included as a component within the cash paid to repurchase Senior Notes, including premium line item on the accompanying statements of cash flows.
Effective January 1, 2018, the Company adopted FASB ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and all related ASUs (“ASU 2014-09”). Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The Company adopted ASU 2014-09 using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adopting ASU 2014-09, the Company expanded its disclosures to comply with the expanded disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.
Effective January 1, 2018, the Company adopted FASB ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item, outside of operating items, which the Company adopted with retrospective application. In addition, only the service component of the net benefit cost is eligible for capitalization, which the Company adopted with prospective application. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for more information.

9

The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the three and nine months ended September 30, 2017, are summarized as follows:
 
For the Three Months Ended September 30, 2017
 
For the Nine Months Ended September 30, 2017
 
As Reported
 
As Adjusted
 
As Reported
 
As Adjusted
 
(in thousands)
Operating expenses:
 
 
 
 
 
 
 
Exploration
$
14,243

 
$
14,119

 
$
39,293

 
$
38,919

General and administrative
$
27,880

 
$
27,564

 
$
85,564

 
$
84,618

Total operating expenses
$
380,971

 
$
380,531

 
$
856,475

 
$
855,155

 
 
 
 
 
 
 
 
Income (loss) from operations
$
(85,592
)
 
$
(85,152
)
 
$
(67,637
)
 
$
(66,317
)
 
 
 
 
 
 
 
 
Other non-operating income, net
$
1,301

 
$
861

 
$
2,901

 
$
1,581

Effective January 1, 2018, the Company early adopted FASB ASU No. 2018-02, Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”) by applying the changes in the period of adoption. ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the enactment into law on December 22, 2017, of H.R.1, formally the Tax Cuts and Jobs Act (the “2017 Tax Act”). As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires recognition of right-of-use assets and lease payment liabilities on the balance sheet by lessees for virtually all leases currently classified as operating leases. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. The Company has established a cross-functional project team and is leveraging external consultants to evaluate the impacts of ASU 2016-02, which includes an analysis of non-cancelable leases, drilling rig contracts, certain midstream agreements, and other existing arrangements that may contain a lease component. The Company has substantially completed the process of reviewing and determining the contracts to which the new guidance applies. Further, the Company is also evaluating policies, internal controls, and processes that will be necessary to support the additional accounting and disclosure requirements. The Company will continue to monitor guidance issued by the FASB to clarify ASU 2016-02 and certain industry implementation issues. The Company is in the final stages of implementing a lease administration system that will support the on-going maintenance and accounting for leases after adoption. Policy elections allowed under ASU 2016-02 that the Company anticipates making as part of its adoption include (a) not recognizing lease assets or liabilities when lease terms are less than twelve months, and (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease. Other policy elections allowed for under ASU 2016-02 are still being evaluated. The Company will adopt ASU 2016-02 on January 1, 2019, using the modified retrospective approach. Adoption of this guidance is expected to result in an increase in right-of-use assets and related liabilities on the Company’s consolidated balance sheets; however, the full impact to the Company’s financial statements and related disclosures is still being evaluated.
In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”), which provides an optional transitional practical expedient that allows entities to exclude from evaluation land easements that existed or expired before adoption of ASU 2016-02. Companies that elect this practical expedient will need to evaluate new or modified land easements after adopting ASU 2016-02. If this practical expedient is not elected, companies will need to evaluate all existing or expired land easements as part of the overall adoption of ASU 2016-02. The Company expects to elect to use this practical expedient as outlined in ASU 2018-01 and will adopt ASU 2018-01 at the same time it adopts ASU 2016-02.
In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). ASU 2018-11 provides an additional transition method for adopting ASU 2016-02, as well as provides lessors with a practical expedient when applying ASU 2016-02 to certain leases. The Company anticipates making a policy election in connection with adopting ASU 2018-11, which will eliminate the need for adjusting prior period comparable financial statements prepared under current lease accounting guidance. The Company will adopt ASU 2018-11 at the same time it adopts ASU 2016-02.
In August 2018, the FASB issued ASU No. 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 provides updated disclosure requirements related to retirement benefits and defined pension plans with the purpose of improving the effectiveness of disclosures with regard to such topics. The guidance is to be applied using a retrospective method and is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company expects to early adopt ASU

10

2018-14 on December 31, 2018. The Company is evaluating the impact of this guidance on its consolidated financial statements, but does not expect the impact to be material.
In August 2018, the FASB 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 (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company expects to adopt ASU 2018-15 on January 1, 2020, with prospective application. The Company is evaluating the impact of ASU 2018-15 on its consolidated financial statements.
Other than as disclosed above or in the 2017 Form 10-K, there are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of September 30, 2018, and through the filing of this report.
Note 2 - Revenue from Contracts with Customers
The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Permian, South Texas & Gulf Coast, and Rocky Mountain regions. During the first quarter of 2018, the Company entered into two definitive agreements to sell all of its producing properties in its Rocky Mountain region. One transaction closed in the first quarter of 2018, and the second transaction closed in the second quarter of 2018. As a result of these divestitures, there has been no production revenue from the Rocky Mountain region after the second quarter of 2018. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions for additional detail. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers.
The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three and nine months ended September 30, 2018, and 2017:
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Total
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Oil, gas, and NGL production revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil production revenue
$
270,086

 
$
107,248

 
$
17,436

 
$
13,726

 
$
—

 
$
33,229

 
$
287,522

 
$
154,203

Gas production revenue
40,364

 
16,034

 
56,446

 
69,069

 
—

 
1,162

 
96,810

 
86,265

NGL production revenue
563

 
151

 
73,487

 
53,023

 
—

 
817

 
74,050

 
53,991

Total
$
311,013

 
$
123,433

 
$
147,369

 
$
135,818

 
$
—

 
$
35,208

 
$
458,382

 
$
294,459

Relative percentage
68
%
 
42
%
 
32
%
 
46
%
 
—
%
 
12
%
 
100
%
 
100
%
____________________________________________
Note: Amounts may not calculate due to rounding.
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Total
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Oil, gas, and NGL production revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil production revenue
$
703,516

 
$
267,301

 
$
56,365

 
$
65,662

 
$
54,851

 
$
117,738

 
$
814,732

 
$
450,701

Gas production revenue
96,974

 
40,280

 
161,414

 
245,030

 
1,595

 
3,846

 
259,983

 
289,156

NGL production revenue
816

 
405

 
167,505

 
169,938

 
790

 
2,396

 
169,111

 
172,739

Total
$
801,306

 
$
307,986

 
$
385,284

 
$
480,630

 
$
57,236

 
$
123,980

 
$
1,243,826

 
$
912,596

Relative percentage
64
%
 
34
%
 
31
%
 
53
%
 
5
%
 
13
%
 
100
%
 
100
%
____________________________________________
Note: Amounts may not calculate due to rounding.
    

11

The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has four general categories under which oil, gas, and NGL production revenue is generated. Each of the Company’s operating regions generate production revenue from a combination of some or all of the four different contract types summarized below:
1)
The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.
2)
The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.
3)
The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.
4)
The Company has certain midstream processing arrangements where unprocessed gas is delivered to the inlet of the midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the processed NGLs and residue gas and remits the proceeds to the Company from the sale of the products to third-party customers. In these arrangements, control transfers at the tailgate of the midstream processing facility for both products. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.
Significant judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are generally received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within accounts receivable on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of September 30, 2018, and December 31, 2017, were $120.3 million and $96.6 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized for the three and nine months ended September 30, 2018, that related to performance obligations satisfied in prior reporting periods was immaterial.


12

Note 3 - Divestitures, Assets Held for Sale, and Acquisitions
Divestitures
On March 26, 2018, the Company divested approximately 112,000 net acres of its Powder River Basin assets (the “PRB Divestiture”) for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $490.8 million, subject to final purchase price adjustments, and recorded an estimated net gain of $410.6 million for the nine months ended September 30, 2018. These assets were recorded as properties held for sale as of December 31, 2017.
During the second quarter of 2018, the Company completed the divestitures of its remaining assets in the Williston Basin located in Divide County, North Dakota (the “Divide County Divestiture”) and its Halff East assets in the Midland Basin (the “Halff East Divestiture”), for combined net divestiture proceeds received at closing of $250.8 million, subject to final purchase price adjustments, and recorded a combined estimated net gain of $15.4 million for the nine months ended September 30, 2018. A portion of these assets were recorded as properties held for sale as of December 31, 2017.
The following table presents income (loss) before income taxes from the Divide County, North Dakota assets sold for the three and nine months ended September 30, 2018, and 2017. The Divide County Divestiture was considered a disposal of a significant asset group.
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Income (loss) before income taxes (1)
$
—

 
$
7,593

 
$
(28,975
)
 
$
(478,572
)
____________________________________________
(1) 
Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity.
On March 10, 2017, the Company closed the divestiture of its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for final net divestiture proceeds of $744.1 million. The Company recorded a final net gain of $396.8 million related to these divested assets for the year ended December 31, 2017. Additionally, during the first nine months of 2017, the Company divested certain non-core properties in its Rocky Mountain and Permian regions for net divestiture proceeds of $31.0 million.
Properties Held for Sale
Assets are classified as held for sale when the Company commits to a plan to sell the assets and it is probable the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. When assets no longer meet the criteria of assets held for sale, they are measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense that would have been recognized, or the fair value at the date they are reclassified to assets held for use. Any gain or loss recognized on assets held for sale or on assets held for sale that are subsequently reclassified to assets held for use is reflected in the net gain (loss) on divestiture activity line item on the accompanying statements of operations. As of September 30, 2018, and December 31, 2017, there were $5.0 million and $111.7 million, respectively, of assets held for sale presented on the accompanying balance sheets. The balance as of December 31, 2017, consisted primarily of approximately 112,000 net acres in the Powder River Basin, and is presented net of accumulated depletion, depreciation, and amortization expense. As discussed above, the Company sold these assets in the first quarter of 2018.
During the nine months ended September 30, 2017, the Company recorded a $526.5 million write-down on its Divide County, North Dakota, assets previously held for sale. As discussed above, the Company sold these assets in the second quarter of 2018.
Acquisitions
During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily unproved properties located in Howard and Martin Counties, Texas, resulting in the Company receiving 2,658 net acres in exchange for 2,654 net acres, with $95.1 million of carrying value attributed to the properties surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized. During the second quarter of 2018, the Company acquired 720 net acres of unproved properties in Martin County, Texas, for $24.6 million. Under authoritative accounting guidance, this transaction was considered an asset acquisition. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired.

13

During the nine months ended September 30, 2017, the Company acquired 3,400 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $72.2 million of cash consideration. Each of these transactions was accounted for as an asset acquisition. Also, during the nine months ended September 30, 2017, the Company completed several non-monetary acreage trades of primarily unproved properties in Howard and Martin Counties, Texas, resulting in the Company receiving 7,425 net acres in exchange for 6,725 net acres, with $283.7 million of carrying value attributed to the properties surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized.
Note 4 - Income Taxes
The income tax (expense) benefit recorded for the three and nine months ended September 30, 2018, and 2017, differs from the amounts that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes primarily due to the effect of state income taxes, excess tax benefits and deficiencies from share-based payment awards, changes in valuation allowances, and accumulated impacts of other smaller permanent differences. The quarterly rate can also be affected by the proportional impacts of forecasted net income or loss as of each period end presented.
The provision for income taxes for the three and nine months ended September 30, 2018, and 2017, consisted of the following:
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Current portion of income tax (expense) benefit:
 
 
 
 
 
 
 
Federal
$
—

 
$
2,832

 
$
—

 
$
—

State
(85
)
 
(230
)
 
(670
)
 
(1,633
)
Deferred portion of income tax (expense) benefit
36,833

 
36,668

 
(60,672
)
 
67,458

Income tax (expense) benefit
$
36,748

 
$
39,270

 
$
(61,342
)
 
$
65,825

Effective tax rate
21.3
%
 
30.6
%
 
23.6
%
 
32.8
%
The enactment of the 2017 Tax Act on December 22, 2017, reduced the Company’s federal tax rate for 2018 and future years from 35 percent to 21 percent. Although the Company believes it has properly analyzed the tax accounting impacts of the 2017 Tax Act, it will continue to monitor provisions with discrete rate impacts, such as the limitation on executive compensation for subsequent events and guidance within the one-year measurement period. There are no new estimates or finalized income tax items associated with the 2017 Tax Act included in income tax (expense) benefit for the three and nine months ended September 30, 2018.
On a year-to-date basis, a change in the Company’s effective tax rate between reporting periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income or loss from Company activities, including divestitures, among multiple state tax jurisdictions. Excess tax benefits and deficiencies from share-based payment awards impact the Company’s effective tax rate between periods. Cumulative effects of state tax rate changes are reflected in the period legislation is enacted.
In 2017, the Company re-evaluated various factors affecting deferred tax assets related to net operating losses and tax credits and determined utilization would be appropriate. The change in the current portion of income tax (expense) benefit between periods reflects the effect of this determination.
Subsequent to the quarter ended September 30, 2018, the Company received its anticipated $5.9 million cash refund for a net operating loss carryback claim. During the third quarter of 2018, the Internal Revenue Service finalized its examination of the net operating loss claims back to tax years 2003 through 2005 with no changes to claimed amounts. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2015.

14

Note 5 - Long-Term Debt
Credit Agreement
On September 28, 2018, the Company and its lenders entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”). The Credit Agreement, which replaced the Company’s Fifth Amended and Restated Credit Agreement, provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, an initial borrowing base of $1.5 billion, and initial aggregate lender commitments totaling $1.0 billion. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report; and (b) commodity derivative contracts, each as determined by the Company’s lender group. The next scheduled redetermination date is April 1, 2019.
The Credit Agreement is scheduled to mature on the earlier of September 28, 2023, (the “Scheduled Maturity Date”), and August 16, 2022, to the extent that, on or before such date, the Company’s outstanding 6.125% Senior Notes due 2022 (the “2022 Senior Notes”) are not repurchased, redeemed, or refinanced to have a maturity date at least 91 days after the Scheduled Maturity Date unless, on August 16, 2022, both (i) the aggregate outstanding principal amount of the 2022 Senior Notes is not more than $100.0 million and (ii) after giving pro forma effect to the repayment in full at maturity of the 2022 Senior Notes then outstanding, the aggregate amount of unrestricted cash and certain types of unrestricted investments held by the Company and its Consolidated Restricted Subsidiaries plus the amount of unused availability under the Credit Agreement is at least $300.0 million.
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. The financial covenants under the Credit Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which will use annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Company was in compliance with all financial and non-financial covenants as of September 30, 2018, and through the filing of this report.
Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Credit Agreement.  Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and Alternate Base Rate (“ABR”) loans accrue interest at a market based floating rate, plus the applicable margin from the utilization grid.  Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations. The borrowing base utilization grid under the Credit Agreement is as follows:
Borrowing Base Utilization Percentage
 
<25%
 
≥25% <50%
 
≥50% <75%
 
≥75% <90%
 
≥90%
Eurodollar Loans
 
1.500
%
 
1.750
%
 
2.000
%
 
2.250
%
 
2.500
%
ABR Loans or Swingline Loans
 
0.500
%
 
0.750
%
 
1.000
%
 
1.250
%
 
1.500
%
Commitment Fee Rate
 
0.375
%
 
0.375
%
 
0.500
%
 
0.500
%
 
0.500
%
    
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of October 24, 2018, and September 30, 2018, and under the Fifth Amended and Restated Credit Agreement as of December 31, 2017:
 
As of October 24, 2018
 
As of September 30, 2018
 
As of December 31, 2017
 
(in thousands)
Credit facility balance (1)
$
—

 
$
—

 
$
—

Letters of credit (2)
200

 
200

 
200

Available borrowing capacity
999,800

 
999,800

 
924,800

Total aggregate lender commitment amount
$
1,000,000

 
$
1,000,000

 
$
925,000

____________________________________________
(1) 
Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.7 million and $3.1 million as of September 30, 2018, and December 31, 2017, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.
(2) 
Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

15

Senior Notes
During the third quarter of 2018, the Company redeemed its 6.50% Senior Notes due 2021 (“2021 Senior Notes”), repurchased or redeemed all of its 6.50% Senior Notes due 2023 (“2023 Senior Notes”), repurchased a portion of its 6.125% Senior Notes due 2022 (“2022 Senior Notes”), and issued its 6.625% Senior Notes due 2027 (“2027 Senior Notes”). As of September 30, 2018, the Company’s Senior Notes consisted of 6.125% Senior Notes due 2022, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, 6.75% Senior Notes due 2026, and 6.625% Senior Notes due 2027 (collectively referred to as “Senior Notes”). Please refer to the discussion below for additional information. The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of September 30, 2018, and December 31, 2017, consisted of the following:
 
As of September 30, 2018
 
As of December 31, 2017
 
Principal Amount
 
Unamortized Deferred Financing Costs
 
Principal Amount, Net of Unamortized Deferred Financing Costs
 
Principal Amount
 
Unamortized Deferred Financing Costs
 
Principal Amount, Net of Unamortized Deferred Financing Costs
 
(in thousands)
6.50% Senior Notes due 2021
$
—

 
$
—

 
$
—

 
$
344,611

 
$
2,656

 
$
341,955

6.125% Senior Notes due 2022
476,796

 
4,171

 
472,625

 
561,796

 
5,800

 
555,996

6.50% Senior Notes due 2023
—

 
—

 
—

 
394,985

 
3,707

 
391,278

5.0% Senior Notes due 2024
500,000

 
4,919

 
495,081

 
500,000

 
5,610

 
494,390

5.625% Senior Notes due 2025
500,000

 
6,035

 
493,965

 
500,000

 
6,714

 
493,286

6.75% Senior Notes due 2026
500,000

 
6,615

 
493,385

 
500,000

 
7,242

 
492,758

6.625% Senior Notes due 2027
500,000

 
7,766

 
492,234

 
—

 
—

 
—

Total
$
2,476,796

 
$
29,506

 
$
2,447,290

 
$
2,801,392

 
$
31,729

 
$
2,769,663

The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes.  The Company is subject to certain covenants under the indentures governing the Senior Notes and was in compliance with all such covenants as of September 30, 2018, and through the filing of this report. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.
2021 Senior Notes. On June 15, 2018, the Company called for redemption all of the $344.6 million principal outstanding on its 2021 Senior Notes at a redemption price of 102.167% of the principal amount, plus accrued and unpaid interest on the principal amount of the 2021 Senior Notes redeemed (“2021 Senior Notes Redemption”). On July 16, 2018, the Company completed the 2021 Senior Notes Redemption, which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million. The Company recorded a loss on extinguishment of debt of $9.8 million for the quarter ended September 30, 2018. This amount included $7.5 million associated with the premium paid for the 2021 Senior Notes Redemption and $2.3 million of accelerated unamortized deferred financing costs.
Tender Offer and Redemption of the 2023 Senior Notes and 2022 Senior Notes. During the third quarter of 2018, the Company used the proceeds from the issuance of its 2027 Senior Notes, as discussed below, and cash on hand to retire $395.0 million of its 2023 Senior Notes and $85.0 million of its 2022 Senior Notes through a cash tender offer (the “Tender Offer”) and subsequent redemption of the remaining 2023 Senior Notes not repurchased as part of the Tender Offer (“2023 Senior Notes Redemption”). Total consideration paid, including accrued interest, for the retirement of the 2023 Senior Notes and the 2022 Senior Notes was $497.8 million. As a result of the Tender Offer and the 2023 Senior Notes Redemption, the Company recorded a loss on extinguishment of debt of $16.9 million for the quarter ended September 30, 2018.  This amount included $12.9 million of premiums paid for the Tender Offer and 2023 Senior Notes Redemption and $4.0 million of accelerated unamortized deferred financing costs.
2027 Senior Notes. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027. The 2027 Senior Notes were issued at par and mature on January 15, 2027. The Company received net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes.  The net proceeds were used to fund the Tender Offer and 2023 Senior Notes Redemption discussed above.
Senior Convertible Notes
The Company’s Senior Convertible Notes consist of $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to

16

any future subordinated debt. Please refer to Note 5 - Long-Term Debt in the 2017 Form 10-K for additional detail on the Company’s Senior Convertible Notes and associated capped call transactions.
The Senior Convertible Notes were not convertible at the option of holders as of September 30, 2018, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of September 30, 2018, did not exceed the principal amount. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.6 million and $2.5 million for the three months ended September 30, 2018, and 2017, respectively, and totaled $7.8 million and $7.4 million for the nine months ended September 30, 2018, and 2017, respectively.
There have been no changes to the initial net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets since issuance. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of September 30, 2018, and December 31, 2017, consisted of the following:
 
As of September 30, 2018
 
As of December 31, 2017
 
(in thousands)
Principal amount of Senior Convertible Notes
$
172,500

 
$
172,500

Unamortized debt discount
(24,316
)
 
(30,183
)
Unamortized deferred financing costs
(2,522
)
 
(3,210
)
Senior Convertible Notes, net of unamortized discount and deferred financing costs
$
145,662

 
$
139,107

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all such covenants as of September 30, 2018, and through the filing of this report.
Note 6 - Commitments and Contingencies
Commitments
As of September 30, 2018, the Company had total gathering, processing, transportation throughput, and purchase commitments with various third parties that require delivery of a minimum quantity of 30 MMBbl of oil, 691 Bcf of gas, and 22 MMBbl of produced water through 2027 and a minimum purchase quantity of 7 MMBbl of water by 2022. If the Company fails to deliver or purchase any product, as applicable, the aggregate undiscounted future deficiency payments as of September 30, 2018, would total approximately $342.2 million. This amount does not include any costs that may be incurred for certain contracts where the Company cannot predict with accuracy the amount and timing of any payments that may be incurred for not meeting certain minimum commitments, as such payments are dependent upon the price of oil in effect at the time of settlement. Under certain of the Company’s commitment agreements, if the Company is unable to deliver the minimum quantity from its production, it may deliver production acquired from third parties. As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to these commitments.
The Company entered into new and amended drilling rig and completion service contracts during the first nine months of 2018, and subsequent to September 30, 2018. As of the filing of this report, the Company’s drilling rig and completion service contract commitments totaled $93.0 million. If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, would be required to pay $42.7 million in early termination fees.
Additionally, as of September 30, 2018, the Company had fixed price contracts with various third parties to purchase electricity through 2027 for total consideration of $29.9 million. As of the filing of this report, the Company expects to meet these purchase commitments.
There were no other material changes in commitments during the first nine months of 2018. Please refer to Note 6 - Commitments and Contingencies in the 2017 Form 10-K for additional discussion of the Company’s commitments.
Contingencies
The Company is subject to litigation and claims arising in the ordinary course of business.  The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.  In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

17

Note 7 - Compensation Plans
Equity Incentive Compensation Plan
As of September 30, 2018, 5.7 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan.
Performance Share Units
The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity incentive compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three-year performance period. PSUs generally vest on the third anniversary of the date of the grant.
PSUs, which the Company has determined to be equity awards, are subject to a combination of market, performance, and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of the Company’s peer group for the performance period, the fair value is measured at the grant date using a stochastic Monte Carlo simulation using geometric Brownian motion. Compensation expense for market-based PSUs is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards.
For awards that include performance criteria, the grant-date fair value is equal to the Company's stock price on the grant date. Compensation expense for performance-based PSUs will be evaluated on a quarterly basis and may be adjusted as the number of units expected to vest increases or decreases. Currently, the Company uses debt adjusted per share cash flow growth (“DACFG”) compared with the DACFG, as calculated by the Company, of its peer group as the performance criteria that is evaluated over the three-year performance period for PSUs.
Total compensation expense recorded for PSUs was $3.0 million and $2.6 million for the three months ended September 30, 2018, and 2017, respectively, and was $7.7 million and $6.8 million for the nine months ended September 30, 2018, and 2017, respectively. As of September 30, 2018, there was $22.9 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2021.
A summary of the status and activity of non-vested PSUs for the nine months ended September 30, 2018, is presented in the following table:
 
PSUs (1)
 
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year
1,533,491
 
$
22.97

Granted
572,924
 
$
24.45

Vested
(233,102)
 
$
44.25

Forfeited
(97,122)
 
$
22.89

Non-vested at end of quarter
1,776,191
 
$
20.66

____________________________________________
(1)  
The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier which ranges from zero to two.
During the nine months ended September 30, 2018, the Company granted 572,924 PSUs to eligible employees with a fair value of $14.0 million (“2018 PSU Grant”). As outlined in the award agreement for the 2018 PSU Grant, performance measurements affecting vesting are based on a combination of relative performance of the Company’s annualized TSR compared with the annualized TSR of the Company’s peer group over the three-year performance period, and relative performance of the Company’s DACFG compared with its peer group DACFG over the three-year performance period. In addition to these performance measures, the award agreement for the 2018 PSU Grant also stipulates that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and DACFG performance relative to its peer group.
During the nine months ended September 30, 2018, PSUs that were granted in 2015 did not satisfy the minimum performance requirements. This resulted in a multiplier of zero times and therefore no shares were issued upon settlement.
Restricted Stock Units
The Company grants restricted stock units (“RSUs”) to eligible persons as part of its long-term equity incentive compensation program. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end

18

of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. RSUs granted to employees generally vest one-third on each anniversary date of the grant over a three-year vesting period.
Total compensation expense recorded for employee RSUs was $3.0 million and $2.9 million for the three months ended September 30, 2018, and 2017, respectively, and was $8.0 million and $7.5 million for the nine months ended September 30, 2018, and 2017, respectively. As of September 30, 2018, there was $24.1 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2021.
A summary of the status and activity of non-vested RSUs granted to employees for the nine months ended September 30, 2018, is presented in the following table:
 
RSUs
 
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year
1,244,262
 
$
20.25

Granted
583,552
 
$
25.77

Vested
(407,529)
 
$
24.30

Forfeited
(112,141)
 
$
17.93

Non-vested at end of quarter
1,308,144
 
$
21.46

During the nine months ended September 30, 2018, the Company granted 583,552 RSUs to eligible employees with a fair value of $15.0 million. During the nine months ended September 30, 2018, the Company settled 407,529 RSUs that related to awards granted in previous years. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the plan document and award agreements. As a result, the Company issued 291,745 net shares of common stock upon settlement of the awards.
Director Shares
During the second quarter of 2018, the Company issued 58,572 shares of its common stock to its non-employee directors under the Company’s Equity Incentive Compensation Plan, which fully vest on December 31, 2018. During the second quarter of 2017, the Company issued 71,573 shares of its common stock to its non-employee directors and 8,794 RSUs to a non-employee director. The Company did not issue any director shares during the third quarters of 2018, or 2017.
Employee Stock Purchase Plan
Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. The Company issued 100,249 and 123,678 shares under the ESPP during the nine months ended September 30, 2018, and 2017, respectively. Total proceeds to the Company for the issuance of these shares was $1.9 million and $1.7 million for the nine months ended September 30, 2018, and 2017, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.
Note 8 - Pension Benefits
Pension Plans
The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). Effective as of January 1, 2016, the Company froze the Pension Plans to new participants, and employees eligible to participate in the Pension Plans prior to them being frozen will continue to earn benefits.

19

Components of Net Periodic Benefit Cost for the Pension Plans
The following table presents the components of the net periodic benefit cost for the Pension Plans:
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Service cost
$
1,683

 
$
1,660

 
$
5,048

 
$
4,979

Interest cost
657

 
673

 
1,967

 
2,017

Expected return on plan assets that reduces periodic pension benefit cost
(466
)
 
(561
)
 
(1,397
)
 
(1,683
)
Amortization of prior service cost
4

 
4

 
13

 
13

Amortization of net actuarial loss
331

 
324

 
995

 
973

Net periodic benefit cost
$
2,209

 
$
2,100

 
$
6,626

 
$
6,299

Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. As a result of the adoption of ASU 2017-07, the service cost component of net periodic benefit cost for the Pension Plans is presented as an operating expense within the general and administrative and exploration expense line items on the accompanying statements of operations while the other components of net periodic benefit cost for the Pension Plans are presented as non-operating expenses within the other non-operating income, net line item on the accompanying statements of operations. Please refer to Note 1 - Summary of Significant Accounting Policies for further detail.
Contributions
The Company contributed $8.1 million to the Qualified Pension Plan during the nine months ended September 30, 2018.

20

Note 9 - Earnings Per Share
Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the three and nine months ended September 30, 2018, and 2017, and therefore the Senior Convertible Notes had no dilutive impact. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for additional detail on these potentially dilutive securities.

When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table presents the weighted-average anti-dilutive securities for the periods presented:
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Anti-dilutive
2,433

 
—

 
—

 
78

The following table sets forth the calculations of basic and diluted net income (loss) per common share:
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per share data)
Net income (loss)
$
(135,923
)
 
$
(89,112
)
 
$
198,675

 
$
(134,585
)
 
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
112,107

 
111,575

 
111,836

 
111,366

Dilutive effect of non-vested RSUs and contingent PSUs
—

 
—

 
1,764

 
—

Dilutive effect of Senior Convertible Notes
—

 
—

 
—

 
—

Diluted weighted-average common shares outstanding
112,107

 
111,575

 
113,600

 
111,366

 
 
 
 
 
 
 
 
Basic net income (loss) per common share
$
(1.21
)
 
$
(0.80
)
 
$
1.78

 
$
(1.21
)
Diluted net income (loss) per common share
$
(1.21
)
 
$
(0.80
)
 
$
1.75

 
$
(1.21
)
Note 10 - Derivative Financial Instruments
Summary of Oil, Gas, and NGL Derivative Contracts in Place
The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of September 30, 2018, all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas production, and swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference.  For collar arrangements, the Company receives the difference between an agreed upon index and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.
The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices.

21

As of September 30, 2018, the Company had commodity derivative contracts outstanding as summarized in the tables below:
Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(MBbl)
 
(per Bbl)
Fourth quarter 2018
 
1,894

 
$
49.87

2019
 
3,733

 
$
59.80

2020
 
2,491

 
$
65.68

Total
 
8,118

 
 
Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(MBbl)
 
(per Bbl)
 
(per Bbl)
Fourth quarter 2018
 
2,222

 
$
50.00

 
$
58.44

2019
 
10,055

 
$
50.59

 
$
63.62

2020
 
1,165

 
$
55.00

 
$
66.47

Total
 
13,442

 
 
 
 
Oil Basis Swaps


Contract Period
 
WTI Midland-NYMEX WTI Volumes
 
Weighted-Average
 Contract Price (1)
 
NYMEX WTI-ICE Brent Volumes
 
Weighted-Average
Contract Price (2)
 
 
(MBbl)
 
(per Bbl)
 
(MBbl)
 
(per Bbl)
Fourth quarter 2018
 
3,327

 
$
(1.08
)
 
—

 
$
—

2019
 
11,217

 
$
(3.36
)
 
—

 
$
—

2020
 
10,960

 
$
(1.05
)
 
1,840

 
$
(8.01
)
2021
 
—

 
$
—

 
3,650

 
$
(7.86
)
2022
 
—

 
$
—

 
3,650

 
$
(7.78
)
Total
 
25,504

 
 
 
9,140

 
 
____________________________________________
(1)  
Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
(2)  
Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
Gas Swaps
Contract Period
 
Sold IF HSC
Volumes
 
Weighted-Average
 Contract Price
 
Purchased IF HSC Volumes
 
Weighted-Average Contract Price
 
Net IF HSC
Volumes
 
Weighted-Average Contract Price
 
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
 
(per MMBtu)
Fourth quarter 2018
 
28,204

 
$
3.27

 
(7,210
)
 
$
4.27

 
20,994

 
$
2.92

2019
 
50,021

 
$
3.58

 
(24,415
)
 
$
4.34

 
25,606

 
$
2.85

2020
 
2,942

 
$
2.82

 
—

 
$
—

 
2,942

 
$
2.82

Total
 
81,167

 
 
 
(31,625
)
 
 
 
49,542

 
 
Gas Collars
Contract Period
 
IF HSC
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(BBtu)
 
(per MMBtu)
 
(per MMBtu)
2019
 
14,242

 
$
2.50

 
$
2.83


22

NGL Swaps
 
 
OPIS Ethane Purity Mont Belvieu
 
OPIS Propane Mont Belvieu Non-TET
 
OPIS Normal Butane Mont Belvieu Non-TET
 
OPIS Isobutane Mont Belvieu Non-TET
 
OPIS Natural Gasoline Mont Belvieu Non-TET
Contract Period
 
Volumes
Weighted-Average
 Contract Price
 
Volumes
Weighted-Average
Contract Price
 
Volumes
Weighted-Average
Contract Price
 
Volumes
Weighted-Average
Contract Price
 
Volumes
Weighted-Average
Contract Price
 
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
Fourth quarter 2018
 
1,146

$
11.18

 
671

$
24.39

 
102

$
35.70

 
76

$
35.07

 
208

$
50.99

2019
 
3,533

$
12.31

 
1,980

$
28.89

 
154

$
35.64

 
117

$
35.70

 
197

$
50.93

2020
 
539

$
11.13

 
—

$
—

 
—

$
—

 
—

$
—

 
—

$
—

Total
 
5,218

 
 
2,651

 
 
256

 
 
193

 
 
405

 
Commodity Derivative Contracts Entered Into Subsequent to September 30, 2018
Subsequent to September 30, 2018, the Company entered into various commodity derivative contracts, as summarized below:
•
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2020 for a total of 0.9 MMBbl of oil production at contract prices ranging from ($8.05) per Bbl to ($8.10) per Bbl;
•
IF HSC swap contracts for 2019 for a total of 15,769 BBtu of natural gas production at contract prices ranging from $2.80 per MMBtu to $3.42 per MMBtu;
•
fixed price OPIS Propane Mont Belvieu Non-TET swap contract for the fourth quarter of 2018 for a total of 0.1 MMBbl of propane production at a contract price of $45.59 per Bbl; and
•
fixed price OPIS Propane Mont Belvieu Non-TET swap contracts for 2019 for a total of 0.4 MMBbl of propane production at a contract price of $40.11 per Bbl.
Derivative Assets and Liabilities Fair Value
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net liability of $286.7 million and $139.4 million as of September 30, 2018, and December 31, 2017, respectively.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:
 
As of September 30, 2018
 
As of December 31, 2017
 
(in thousands)
Derivative assets:
 
 
 
Current assets
$
81,163

 
$
64,266

Noncurrent assets
8,853

 
40,362

Total derivative assets
$
90,016

 
$
104,628

Derivative liabilities:
 
 
 
Current liabilities
$
304,159

 
$
172,582

Noncurrent liabilities
72,605

 
71,402

Total derivative liabilities
$
376,764

 
$
243,984

Offsetting of Derivative Assets and Liabilities
As of September 30, 2018, and December 31, 2017, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

23

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:
 
Derivative Assets
 
Derivative Liabilities
 
As of
 
As of
 
September 30, 
 2018
 
December 31, 2017
 
September 30, 
 2018
 
December 31, 2017
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
$
90,016

 
$
104,628

 
$
(376,764
)
 
$
(243,984
)
Amounts not offset in the accompanying balance sheets
(90,016
)
 
(100,035
)
 
90,016

 
100,035

Net amounts
$
—

 
$
4,593

 
$
(286,748
)
 
$
(143,949
)
The following table summarizes the components of the net derivative (gain) loss line item presented in the accompanying statements of operations:
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Derivative settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
16,798

 
$
2,472

 
$
61,976

 
$
14,310

Gas contracts
802

 
(24,088
)
 
(4,851
)
 
(63,345
)
NGL contracts
23,118

 
8,524

 
44,786

 
19,633

Total derivative settlement (gain) loss
$
40,718

 
$
(13,092
)
 
$
101,911

 
$
(29,402
)
 
 
 
 
 
 
 
 
Net derivative (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
110,413

 
$
45,874

 
$
146,781

 
$
(41,910
)
Gas contracts
4,309

 
(6,068
)
 
21,299

 
(56,574
)
NGL contracts
63,304

 
40,793

 
81,224

 
9,120

Total net derivative (gain) loss
$
178,026

 
$
80,599

 
$
249,304

 
$
(89,364
)
Credit Related Contingent Features
As of September 30, 2018, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.
Note 11 - Fair Value Measurements
The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an 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. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
•
Level 1 – quoted prices in active markets for identical assets or liabilities
•
Level 2 – quoted prices in active markets for similar assets or 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

24

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of September 30, 2018:

Level 1

Level 2

Level 3

(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$
—

 
$
90,016

 
$
—

Liabilities:
 
 
 
 
 
Derivatives (1)
$
—

 
$
376,764

 
$
—

__________________________________________
(1) 
This represents a financial asset or liability that is measured at fair value on a recurring basis.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2017:
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$
—

 
$
104,628

 
$
—

Liabilities:
 
 
 
 
 
Derivatives (1)
$
—

 
$
243,984

 
$
—

____________________________________________
(1) 
This represents a financial asset or liability that is measured at fair value on a recurring basis.
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.
Please refer to Note 10 - Derivative Financial Instruments and to Note 11 - Fair Value Measurements in the 2017 Form 10-K for more information regarding the Company’s derivative instruments.
Proved and Unproved Oil and Gas Properties and Other Property and Equipment
Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. There were no material impairments of proved properties during the three and nine months ended September 30, 2018, or 2017.
Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable.  Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. During the three and nine months ended September 30, 2018, the Company recorded $9.1 million and $26.6 million, respectively, in abandonment and impairment of unproved properties expense related to lease expirations. There were no material abandonments or impairments of unproved properties expenses for the three and nine months ended September 30, 2017.

25

Properties held for sale. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations.
There were no material assets held for sale that were recorded at fair value as of September 30, 2018. The Company had $111.7 million of assets classified as held for sale as of December 31, 2017; however, none of these properties were recorded at fair value as the carrying value of these assets was below their estimated fair value less selling costs. For the nine months ended September 30, 2017, the Company recorded a $526.5 million write-down on assets previously held for sale. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions above and in the 2017 Form 10-K for more information regarding the Company’s oil and gas properties held for sale.
Please refer to Note 11 - Fair Value Measurements in the 2017 Form 10-K for more information regarding the Company’s approach in determining fair value of its properties, including assets held for sale.
Long-Term Debt
The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of September 30, 2018, or December 31, 2017, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion.
 
As of September 30, 2018
 
As of December 31, 2017
 
Principal Amount
 
Fair Value
 
Principal Amount
 
Fair Value
 
(in thousands)
6.50% Senior Notes due 2021
$
—

 
$
—

 
$
344,611

 
$
351,682

6.125% Senior Notes due 2022
$
476,796

 
$
491,076

 
$
561,796

 
$
571,627

6.50% Senior Notes due 2023
$
—

 
$
—

 
$
394,985

 
$
403,434

5.0% Senior Notes due 2024
$
500,000

 
$
491,000

 
$
500,000

 
$
483,440

5.625% Senior Notes due 2025
$
500,000

 
$
498,125

 
$
500,000

 
$
494,355

6.75% Senior Notes due 2026
$
500,000

 
$
522,150

 
$
500,000

 
$
516,350

6.625% Senior Notes due 2027
$
500,000

 
$
517,250

 
$
—

 
$
—

1.50% Senior Convertible Notes due 2021
$
172,500

 
$
191,044

 
$
172,500

 
$
168,291


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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes certain forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements at the end of this item for important information about these types of statements.
Overview of the Company
General Overview
We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. We currently have producing assets and significant acreage positions in the Midland Basin and Eagle Ford shale in Texas. Our strategic objective is to be a premier operator of top-tier assets. We seek to maximize the value of our assets by applying industry leading technology and outstanding operational execution. Our portfolio is comprised of unconventional resource prospects with expanding prospective drilling opportunities, which we believe provide for long-term production and reserves growth. We are focused on generating strong full-cycle economic returns on our investments and maintaining a strong balance sheet.
Third Quarter 2018 Highlights and Outlook for the Remainder of 2018
Our priorities for 2018, as set at the beginning of the year, are to:
•
continue generating high margin returns from top-tier projects that drive cash flow growth;
•
core up our portfolio to focus on assets that generate the highest returns; and
•
improve our credit metrics and maintain strong financial flexibility.
With respect to our priorities, we have substantially completed our multi-year portfolio transformation, and are now fully focused on developing and maximizing the value of our remaining core acreage positions in the Midland Basin and Eagle Ford shale. As part of our coring up strategy, we completed three divestitures of non-core assets in the first half of 2018, and used the proceeds, along with operating cash flows, to fund our Midland Basin and Eagle Ford shale capital programs, while maintaining an undrawn balance on our credit facility through September 30, 2018. Divestiture proceeds have also supported our ability to meaningfully reduce total long-term debt, as we retired our 2021 Senior Notes with cash on hand. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions and Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Our capital program for 2018, excluding acquisitions, is expected to be approximately $1.31 billion. The majority of our 2018 capital has been allocated to our Midland Basin program. We anticipate that our Midland Basin program will average seven operated drilling rigs and four completion crews during 2018. Activity in our Eagle Ford shale program continues to be partially funded by a third party as part of our previously announced drilling and completion carry agreement. We anticipate our Eagle Ford shale program will average between one and two operated drilling rigs and one and two completion crews during 2018. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on our 2018 capital program.
Operational and Financial Results. During the third quarter of 2018, we had the following operational and financial results:
•
Average net daily production for the three months ended September 30, 2018, was 130.2 MBOE, compared with 116.0 MBOE for the same period in 2017. The increase was primarily driven by our Permian region, which had a 100 percent increase in production volumes in the third quarter of 2018 compared to the same period in 2017. Please refer to A Three-Month and Nine-Month Overview of Selected Production and Financial Information, Including Trends below for additional discussion on production.
•
Net cash provided by operating activities was $229.7 million for the three months ended September 30, 2018, compared with $128.5 million for the same period in 2017. The increase in net cash provided by operating activities for the three months ended September 30, 2018, was primarily the result of a 48 percent growth in higher margin oil production, which drove our 39 percent increase in pre-hedge realized price and 12 percent increase in net equivalent volumes produced. Partially offsetting the increase was a realized settlement loss on derivatives of $40.7 million during the third quarter of 2018, compared to a realized settlement gain of $13.1 million during the same period in 2017. Please refer to Overview of Liquidity and Capital Resources below for additional discussion of our sources and uses of cash.
•
We recorded a net loss of $135.9 million, or $1.21 per diluted share, for the three months ended September 30, 2018, compared with a net loss of $89.1 million, or $0.80 per diluted share, for the same period in 2017. Our net loss for the third quarter of 2018, was driven primarily by net derivative losses of $178.0 million and a loss on extinguishment of debt of $26.7 million. Please refer to Comparison of Financial Results and Trends Between the Three Months and Nine Months Ended September 30, 2018, and 2017 below for additional discussion regarding the components of net income (loss) for each of the periods presented.
•
Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2018, was $256.1 million, compared with $164.3 million for the same period in 2017. The increase in the third quarter of 2018 compared to the same period in 2017 was driven largely by increased production revenue, which was partially offset by increased losses

27

on derivative settlements. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to our net income (loss) and net cash provided by operating activities.
Long-Term Debt. During the third quarter of 2018, we executed certain long-term debt transactions and agreements, which are summarized below:
•
2021 Senior Notes Redemption. On July 16, 2018, we redeemed all of the $344.6 million principal outstanding of our 2021 Senior Notes for total cash consideration, including the premium paid and accrued interest, of $355.9 million. Redemption of the 2021 Senior Notes resulted in a loss on extinguishment of debt of $9.8 million for the quarter ended September 30, 2018.
•
2027 Senior Notes Issuance. On August 20, 2018, we issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027. The 2027 Senior Notes were issued at par and mature on January 15, 2027. We received net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes.  The net proceeds were used to fund the Tender Offer and 2023 Senior Notes Redemption discussed below.
•
Tender Offer and Redemption of our 2023 Senior Notes and a Portion of our 2022 Senior Notes. Concurrently with our 2027 Senior Notes offering, as discussed above, we announced our Tender Offer for all of our 2023 Senior Notes and a portion of our 2022 Senior Notes, and our intention to redeem any remaining 2023 Senior Notes outstanding upon completion of the Tender Offer. Upon completing the Tender Offer and subsequent redemption, we retired all of the $395.0 million principal outstanding of our 2023 Senior Notes and $85.0 million principal outstanding of our 2022 Senior Notes. Consideration paid to complete these transactions totaled $497.8 million, including the premium paid and accrued interest. The Tender Offer and subsequent redemption of the remaining 2023 Senior Notes resulted in a loss on extinguishment of debt of $16.9 million for the quarter ended September 30, 2018.
•
Credit Agreement. On September 28, 2018, we entered into the Credit Agreement with our lenders which provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, an initial borrowing base of $1.5 billion, and initial aggregate lender commitments totaling $1.0 billion. The Credit Agreement is scheduled to mature on September 28, 2023. The maturity date could, however, occur earlier on August 16, 2022, to the extent we have not completed certain repurchase, redemption, or refinancing activities associated with our 2022 Senior Notes as outlined in the Credit Agreement.
Please refer to Overview of Liquidity and Capital Resources below and Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Operational Activities. In our Midland Basin program, we began the third quarter of 2018 with seven operated drilling rigs and three completion crews. During the quarter, we maintained three completion crews and released one drilling rig, bringing our total number of operated drilling rigs to six as of September 30, 2018. During the third quarter of 2018, operations on our RockStar acreage in Howard and Martin Counties, Texas, as well as on our Sweetie Peck acreage in Upton and Midland Counties, Texas, continued to focus on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals. We expect to allocate approximately 86 percent of our expected 2018 drilling and completion capital to our Midland Basin program.
During the third quarter of 2018, we completed two non-monetary acreage trades where we acquired 2,658 net acres in exchange for 2,654 net acres in the Midland Basin. These trades increased our working interest in existing drilling units and also provide us the opportunity to drill longer lateral wells.
In our operated Eagle Ford shale program, we ended the third quarter of 2018 with one operated drilling rig and two completion crews. In October 2018, we released one of our two completion crews. Drilling and completion activities related to our previously announced drilling and completion carry agreement in a defined portion of our Eagle Ford North area continued throughout the third quarter of 2018. We expect the remaining wells associated with this agreement to be completed in the fourth quarter of 2018. We expect to allocate approximately 14 percent of our expected 2018 drilling and completion capital to our Eagle Ford shale program.


28

The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the nine months ended September 30, 2018:
 
Permian
 
South Texas & Gulf Coast

 
Bakken/Three Forks (2)
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells drilled but not completed at December 31, 2017
49

 
41

 
33

 
30

 
18

 
15

 
100

 
86

Wells drilled
35

 
33

 
11

 
8

 
—

 
—

 
46

 
41

Wells completed
(22
)
 
(17