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EX-12.1 - EXHIBIT 12.1 - SM Energy Coexhibit121-ratioofearnings.htm
EX-32.1 - EXHIBIT 32.1 - SM Energy Coexhibit321906certification.htm
EX-31.2 - EXHIBIT 31.2 - SM Energy Coexhibit312certificationwpu.htm
EX-31.1 - EXHIBIT 31.1 - SM Energy Coexhibit311certificationjot.htm
EX-10.1 - EXHIBIT 10.1 - SM Energy Coexhibit101psuawardagreemen.htm


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 June 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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  
(Do not check if a smaller reporting company)
 
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 July 25, 2018, the registrant had 112,137,582 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)
 
June 30,
2018
 
December 31,
2017
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
615,906

 
$
313,943

Accounts receivable
178,682

 
160,154

Derivative assets
146,329

 
64,266

Prepaid expenses and other
14,293

 
10,752

Total current assets
955,210

 
549,115

Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
6,372,956

 
6,139,379

Accumulated depletion, depreciation, and amortization
(3,041,653
)
 
(3,171,575
)
Unproved oil and gas properties
1,917,883

 
2,047,203

Wells in progress
361,238

 
321,347

Oil and gas properties held for sale, net
5,040

 
111,700

Other property and equipment, net of accumulated depreciation of $53,483 and $49,985, respectively
102,986

 
106,738

Total property and equipment, net
5,718,450

 
5,554,792

Noncurrent assets:
 
 
 
Derivative assets
31,151

 
40,362

Other noncurrent assets
31,674

 
32,507

Total noncurrent assets
62,825

 
72,869

Total assets
$
6,736,485

 
$
6,176,776

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
446,318

 
$
386,630

Current portion of Senior Notes, net of unamortized deferred financing costs (note 5)
342,301

 

Derivative liabilities
259,338

 
172,582

Total current liabilities
1,047,957

 
559,212

Noncurrent liabilities:
 
 
 
Revolving credit facility

 

Noncurrent portion of Senior Notes, net of unamortized deferred financing costs
2,429,994

 
2,769,663

Senior Convertible Notes, net of unamortized discount and deferred financing costs
143,430

 
139,107

Asset retirement obligations
87,279

 
103,026

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

 
11,369

Deferred income taxes
177,709

 
79,989

Derivative liabilities
67,583

 
71,402

Other noncurrent liabilities
45,906

 
48,400

Total noncurrent liabilities
2,951,901

 
3,222,956

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,846,998 and 111,687,016 shares, respectively
1,118

 
1,117

Additional paid-in capital
1,754,169

 
1,741,623

Retained earnings (1)
997,641

 
665,657

Accumulated other comprehensive loss (1)
(16,301
)
 
(13,789
)
Total stockholders equity
2,736,627

 
2,394,608

Total liabilities and stockholders equity
$
6,736,485

 
$
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 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
 
 
(as adjusted)
 
 
 
(as adjusted)
Operating revenues and other income:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
402,558

 
$
284,939

 
$
785,444

 
$
618,137

Net gain (loss) on divestiture activity
39,501

 
(167,133
)
 
424,870

 
(129,670
)
Other operating revenues
1,857

 
2,915

 
3,197

 
4,992

Total operating revenues and other income
443,916


120,721


1,213,511


493,459

Operating expenses:











Oil, gas, and NGL production expense
117,400

 
124,376

 
238,279

 
262,422

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
151,765

 
153,232

 
282,238

 
291,044

Exploration
14,056

 
12,983

 
27,783

 
24,800

Abandonment and impairment of unproved properties
11,935

 
157

 
17,560

 
157

General and administrative
28,920

 
28,237

 
56,602

 
57,054

Net derivative (gain) loss
63,749

 
(55,189
)
 
71,278

 
(169,963
)
Other operating expenses, net
(57
)
 
4,251

 
4,555

 
9,110

Total operating expenses
387,768


268,047


698,295


474,624

Income (loss) from operations
56,148


(147,326
)

515,216


18,835

Interest expense
(41,654
)
 
(44,595
)
 
(84,739
)
 
(91,548
)
Loss on extinguishment of debt

 

 

 
(35
)
Other non-operating income, net
1,802

 
953

 
2,211

 
720

Income (loss) before income taxes
16,296


(190,968
)

432,688


(72,028
)
Income tax (expense) benefit
901

 
71,061

 
(98,090
)
 
26,555

Net income (loss)
$
17,197

 
$
(119,907
)
 
$
334,598


$
(45,473
)
 











Basic weighted-average common shares outstanding
111,701

 
111,277

 
111,698

 
111,274

Diluted weighted-average common shares outstanding
113,630

 
111,277

 
113,267

 
111,274

Basic net income (loss) per common share
$
0.15

 
$
(1.08
)
 
$
3.00

 
$
(0.41
)
Diluted net income (loss) per common share
$
0.15

 
$
(1.08
)
 
$
2.95

 
$
(0.41
)
Dividends per common share
$

 
$

 
$
0.05

 
$
0.05

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 
 June 30,
 
For the Six Months Ended 
 June 30,
 
 
 
2018
 
2017
 
2018
 
2017
Net income (loss)
$
17,197

 
$
(119,907
)
 
$
334,598

 
$
(45,473
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Pension liability adjustment
198

 
124

 
458

 
(443
)
Total other comprehensive income (loss), net of tax
198

 
124

 
458

 
(443
)
Total comprehensive income (loss)
$
17,395

 
$
(119,783
)
 
$
335,056

 
$
(45,916
)
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 Six Months Ended 
 June 30,
 
2018
 
2017
 
 
 
(as adjusted)
Cash flows from operating activities:
 
 
 
Net income (loss)
$
334,598

 
$
(45,473
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Net (gain) loss on divestiture activity
(424,870
)
 
129,670

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
282,238

 
291,044

Abandonment and impairment of unproved properties
17,560

 
157

Stock-based compensation expense
10,676

 
9,813

Net derivative (gain) loss
71,278

 
(169,963
)
Derivative settlement gain (loss)
(61,193
)
 
16,310

Amortization of debt discount and deferred financing costs
7,750

 
8,679

Loss on extinguishment of debt

 
35

Deferred income taxes
97,505

 
(30,790
)
Other, net
(2,302
)
 
4,464

Net change in working capital
(21,722
)
 
28,182

Net cash provided by operating activities
311,518

 
242,128

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
742,215

 
766,247

Capital expenditures
(723,319
)
 
(366,743
)
Acquisition of proved and unproved oil and gas properties
(24,615
)
 
(88,140
)
Net cash provided by (used in) investing activities
(5,719
)
 
311,364

 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility

 
406,000

Repayment of credit facility

 
(406,000
)
Cash paid to repurchase Senior Notes

 
(2,344
)
Cash paid for extinguishment of debt

 
(13
)
Net proceeds from sale of common stock
1,881

 
1,738

Dividends paid
(5,584
)
 
(5,563
)
Other, net
(133
)
 
(161
)
Net cash used in financing activities
(3,836
)
 
(6,343
)
 
 
 
 
Net change in cash, cash equivalents, and restricted cash (1)
301,963

 
547,149

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)
$
615,906

 
$
559,521

____________________________________________
(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 Six Months Ended 
 June 30,
 
2018
 
2017
 
 
 
(as adjusted)
Operating activities:
 
 
 
Cash paid for interest, net of capitalized interest
$
(77,803
)
 
$
(83,493
)
Net cash (paid) refunded for income taxes
$
207

 
$
(8,220
)
 
 
 
 
Investing activities:
 
 
 
Changes in capital expenditure accruals and other
$
62,167

 
$
44,770

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

 
$
279,750

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

 
$
22

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 June 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 Immaterial Errors

The accompanying unaudited condensed consolidated financial statements for the three months ended June 30, 2018, include non-cash adjustments that relate to the prior quarter.  For the three months ended June 30, 2018, the net gain (loss) on divestiture activity line item on the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) includes $17.7 million of loss (approximately $13.7 million, net of tax) that should have been included in the estimated non-cash write down to fair value less selling costs recorded as of March 31, 2018, for the Divide County, North Dakota assets held for sale.  Additionally, for the three months ended June 30, 2018, the depletion, depreciation, amortization, and asset retirement obligation liability accretion expense line item on the accompanying statements of operations includes $6.7 million of additional expense (approximately $5.2 million, net of tax) that should have been recognized during the first quarter of 2018. Aggregated, these non-cash adjustments resulted in reported net income for the three months ended March 31, 2018, to be overstated by approximately $18.9 million (net of tax) with the corrections being recorded during the three months ended June 30, 2018, resulting in net income for the three months ended June 30, 2018, to be understated by approximately $18.9 million (net of tax). These non-cash adjustments are not deemed material with respect to the first or second quarters of 2018, or the anticipated results for fiscal year 2018. Further, these non-cash adjustments do not have an impact on the unaudited condensed consolidated financial statements for the six months ended June 30, 2018.

Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies to 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. 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 six months ended June 30, 2017, are summarized as follows:
 
For the Six Months Ended June 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
$
242,115

 
$
242,128

 
 
 
 
Cash flows from investing activities:
 
 
 
Other, net
$
3,000

 
N/A

Net cash provided by (used in) investing activities
$
314,364

 
$
311,364

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

 
$
(13
)
Net cash used in financing activities
$
(6,330
)
 
$
(6,343
)
 
 
 
 
Net change in cash and cash equivalents
$
550,149

 
N/A

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

 
$
547,149

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
$
559,521

 
N/A

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

 
$
559,521

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets:
 
As of June 30, 2018
 
As of December 31, 2017
 
(in thousands)
Cash and cash equivalents
$
615,906

 
$
313,943

Restricted cash

 

Total cash, cash equivalents, and restricted cash
$
615,906

 
$
313,943

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 six months ended June 30, 2017, are summarized as follows:
 
For the Three Months Ended June 30, 2017
 
For the Six Months Ended June 30, 2017
 
As Reported
 
As Adjusted
 
As Reported
 
As Adjusted
 
(in thousands)
Operating expenses:
 
 
 
 
 
 
 
Exploration
$
13,072

 
$
12,983

 
$
25,050

 
$
24,800

General and administrative
$
28,460

 
$
28,237

 
$
57,684

 
$
57,054

Total operating expenses
$
268,359

 
$
268,047

 
$
475,504

 
$
474,624

 
 
 
 
 
 
 
 
Income (loss) from operations
$
(147,638
)
 
$
(147,326
)
 
$
17,955

 
$
18,835

 
 
 
 
 
 
 
 
Other non-operating income, net
$
1,265

 
$
953

 
$
1,600

 
$
720

Effective January 1, 2018, the Company early adopted 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. Under ASU 2016-02, companies are permitted to make a policy election to not recognize lease assets or liabilities when the term of the lease is less than twelve months. For agreements that contain both lease and non-lease components, companies are also permitted to make a policy election to combine both the lease and non-lease components together and account for these arrangements as a single lease. 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. Further, the Company is also evaluating policies, controls, and processes that will be necessary to support the additional accounting and disclosure requirements. The Company is also in the process of designing and implementing a lease administration system that will support the on-going maintenance and accounting for leases after adoption. The Company will adopt ASU 2016-02 on January 1, 2019, and plans on 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 is currently evaluating ASU 2018-11 as part of its overall assessment of ASU 2016-02, and will adopt ASU 2018-11 at the same time it adopts ASU 2016-02.
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 June 30, 2018, and through the filing of this report.

10


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, the Company does not expect any additional 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 six months ended June 30, 2018, and 2017:
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Total
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
Three Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Oil, gas, and NGL production revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil production revenue
$
227,636

 
$
78,554

 
$
19,346

 
$
13,072

 
$
19,168

 
$
37,248

 
$
266,150

 
$
128,874

Gas production revenue
31,734

 
12,937

 
52,235

 
87,760

 
95

 
1,043

 
84,064

 
101,740

NGL production revenue
129

 
107

 
52,248

 
53,558

 
(33
)
 
660

 
52,344

 
54,325

Total
$
259,499

 
$
91,598

 
$
123,829

 
$
154,390

 
$
19,230

 
$
38,951

 
$
402,558

 
$
284,939

Relative percentage
64
%
 
32
%
 
31
%
 
54
%
 
5
%
 
14
%
 
100
%
 
100
%
____________________________________________
Note: Amounts may not calculate due to rounding.
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Total
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Oil, gas, and NGL production revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil production revenue
$
433,430

 
$
160,053

 
$
38,929

 
$
51,936

 
$
54,851

 
$
84,509

 
$
527,210

 
$
296,498

Gas production revenue
56,611

 
24,246

 
104,968

 
175,961

 
1,594

 
2,714

 
163,173

 
202,921

NGL production revenue
253

 
254

 
94,018

 
116,915

 
790

 
1,549

 
95,061

 
118,718

Total
$
490,294

 
$
184,553

 
$
237,915

 
$
344,812

 
$
57,235

 
$
88,772

 
$
785,444

 
$
618,137

Relative percentage
63
%
 
30
%
 
30
%
 
56
%
 
7
%
 
14
%
 
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 and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue above 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 June 30, 2018, and December 31, 2017, were $115.0 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 six months ended June 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 $410.1 million for the six months ended June 30, 2018.
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 $15.7 million for the six months ended June 30, 2018. Please refer to Note 1 - Summary of Significant Accounting Policies for a discussion of an immaterial non-cash adjustment related to the Divide County Divestiture that was recorded in the second quarter of 2018.
The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the three and six months ended June 30, 2018, and 2017. The Divide County Divestiture was considered a disposal of a significant asset group.
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Loss before income taxes (1)
$
(17,478
)
 
$
(153,442
)
 
$
(28,975
)
 
$
(486,161
)
____________________________________________
(1) 
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 net divestiture proceeds received at closing of $747.4 million, and net divestiture proceeds of $744.1 million after final purchase price adjustments. The Company recorded an estimated net gain of $397.4 million for the six months ended June 30, 2017, and a final net gain of $396.8 million related to these divested assets for the year ended December 31, 2017. During the second quarter of 2017, the Company divested of assets located in Williams County, North Dakota, for net divestiture proceeds of $24.6 million.
Assets 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 June 30, 2018, there were $5.0 million of assets held for sale presented on the accompanying balance sheets.
During the second quarter of 2017, the Company reclassified its retained Divide County assets previously held for sale to assets held for use. A $359.6 million write-down was recorded on these assets in the first quarter of 2017 based on the estimated fair value less selling costs as of March 31, 2017. An additional $166.9 million write-down was recorded in the second quarter of 2017 based on market conditions that existed on the date the Company made its decision to retain these assets.
Acquisitions
During the second quarter of 2018, the Company acquired approximately 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. During the first half of 2017, the Company

13


acquired approximately 3,400 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $72.3 million of cash consideration, which were accounted for as asset acquisitions.
Also, during the first half of 2017, the Company completed several non-monetary acreage trades of primarily unproved properties in Howard and Martin Counties, Texas, resulting in the Company acquiring approximately 6,550 net acres in exchange for approximately 5,700 net acres, with $279.8 million of carrying value attributed to the properties surrendered by the Company in such trades. 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 six months ended June 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 six months ended June 30, 2018, and 2017, consisted of the following:
 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Current portion of income tax (expense) benefit:
 
 
 
 
 
 
 
Federal
$

 
$
4,607

 
$

 
$
(2,832
)
State
40

 
2,439

 
(585
)
 
(1,403
)
Deferred portion of income tax (expense) benefit
861

 
64,015

 
(97,505
)
 
30,790

Income tax (expense) benefit
$
901

 
$
71,061

 
$
(98,090
)
 
$
26,555

Effective tax rate
(5.5
)%
 
37.2
%
 
22.7
%
 
36.9
%
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 for the three or six months ended June 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. For the three months ended June 30, 2018, the decrease in the effective tax rate year-over-year also reflects the cumulative effects of property divestitures in higher marginal rate states in 2018. Cumulative effects of state tax rate changes are reflected in the period legislation is enacted. Excess tax benefits and deficiencies from share-based payment awards impact the Company’s effective tax rate between periods.
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. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013.

14


Note 5 - Long-Term Debt
Credit Agreement
The Company’s Fifth Amended and Restated Credit Agreement, as amended, (the “Credit Agreement”) provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019. On April 24, 2018, as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were increased to $1.4 billion and $1.0 billion, respectively. Upon completion of the Divide County Divestiture on May 30, 2018, the Company’s borrowing base was reduced to $1.3 billion, while the aggregate lender commitments remained at $1.0 billion. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions for additional discussion on the sale of these assets. The next scheduled redetermination date is October 1, 2018.
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement and was in compliance with all such covenants as of June 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 as presented in Note 5 - Long-Term Debt in the 2017 Form 10-K.  Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and Alternate Base Rate and swingline loans accrue interest at the prime 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 interest expense in the accompanying statements of operations.
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of July 25, 2018, June 30, 2018, and December 31, 2017:
 
As of July 25, 2018
 
As of June 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 $2.4 million and $3.1 million as of June 30, 2018, and December 31, 2017, respectively.
(2) 
Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
Senior Notes
The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). On June 15, 2018, the Company called for redemption all of its 6.50% Senior Notes due 2021 (“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 to be redeemed (“2021 Senior Notes Redemption”). As a result of the 2021 Senior Notes Redemption, the 2021 Senior Notes, net of unamortized deferred financing costs, were classified as a current liability on the accompanying balance sheets as of June 30, 2018. On July 16, 2018, the Company completed the 2021 Senior Notes Redemption, which resulted in the payment of total consideration, including accrued interest, of $355.9 million. The Company will record a loss on extinguishment of debt of $9.8 million for the quarter ended September 30, 2018. This amount will include $7.5 million associated with the premium paid for the 2021 Senior Notes Redemption and $2.3 million related to the acceleration of unamortized deferred financing costs.

15


The current portion of Senior Notes, net of unamortized deferred financing costs and noncurrent portion of Senior Notes, net of unamortized deferred financing costs lines on the accompanying balance sheets as of June 30, 2018, and December 31, 2017, consisted of the following:
 
As of June 30, 2018
 
As of December 31, 2017
 
Principal Amount
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
Principal Amount
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
(in thousands)
6.50% Senior Notes due 2021
$
344,611

 
$
2,310

 
$
342,301

 
$
344,611

 
$
2,656

 
$
341,955

6.125% Senior Notes due 2022
561,796

 
5,211

 
556,585

 
561,796

 
5,800

 
555,996

6.50% Senior Notes due 2023
394,985

 
3,342

 
391,643

 
394,985

 
3,707

 
391,278

5.0% Senior Notes due 2024
500,000

 
5,149

 
494,851

 
500,000

 
5,610

 
494,390

5.625% Senior Notes due 2025
500,000

 
6,261

 
493,739

 
500,000

 
6,714

 
493,286

6.75% Senior Notes due 2026
500,000

 
6,824

 
493,176

 
500,000

 
7,242

 
492,758

Total
$
2,801,392

 
$
29,097

 
$
2,772,295

 
$
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 June 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.
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 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 June 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 June 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 June 30, 2018, and 2017, respectively, and totaled $5.2 million and $4.9 million for the six months ended June 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. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of June 30, 2018, and December 31, 2017, consisted of the following:
 
As of June 30, 2018
 
As of December 31, 2017
 
(in thousands)
Principal amount of Senior Convertible Notes
$
172,500

 
$
172,500

Unamortized debt discount
(26,319
)
 
(30,183
)
Unamortized deferred financing costs
(2,751
)
 
(3,210
)
Senior Convertible Notes, net of unamortized discount and deferred financing costs
$
143,430

 
$
139,107


16


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 June 30, 2018, and through the filing of this report.
Note 6 - Commitments and Contingencies
Commitments
As of June 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 31 MMBbl of oil, 737 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 June 30, 2018, would total approximately $360.6 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 six months of 2018 and subsequent to June 30, 2018. As of the filing of this report, the Company’s drilling rig and completion service contract commitments totaled $103.1 million; however, if the Company terminated these contracts immediately, it would incur penalties of $40.4 million.
Additionally, as of June 30, 2018, the Company had fixed price contracts with various third parties to purchase electricity through 2027 for a total of $30.8 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 six 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 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.
Note 7 - Compensation Plans
Equity Incentive Compensation Plan
As of June 30, 2018, 6.8 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. For PSUs that were granted in 2015, 2016, and 2017, the performance criteria is based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards.
Total compensation expense recorded for PSUs was $2.4 million and $1.7 million for the three months ended June 30, 2018, and 2017, respectively, and was $4.8 million and $4.2 million for the six months ended June 30, 2018, and 2017, respectively. As of June 30, 2018, there was $12.4 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2020. There were no material changes to the outstanding and non-vested PSUs during the six months ended June 30, 2018.

17


Subsequent to June 30, 2018, the Company granted 572,924 PSUs with a fair value of $14.0 million (“2018 PSU Grant”). The fair value of the 2018 PSU Grant was measured at the grant date using a stochastic Monte Carlo simulation using geometric Brownian motion.  The number of shares of the Company’s common stock issued to settle the 2018 PSU Grant, after the completion of a three-year performance period, will range from zero to two times the number of PSUs granted on the award date, depending on the extent to which the Company has achieved certain performance criteria and to the extent the PSUs have vested. As outlined in the 2018 PSU Grant agreement, performance measurements affecting vesting are based on a combination of relative performance of the Company’s annualized TSR compared with the annualized TSR of certain peer companies over the three-year performance period, and relative performance of the Company’s debt adjusted per share cash flow growth (“DACFG”) compared with the DACFG of certain peer companies over the three-year performance period. In addition to these performance measures, the 2018 PSU Grant agreement also stipulates that if the Company’s annualized 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 peers. Compensation expense associated with the 2018 PSU Grant will be evaluated on a quarterly basis and may be adjusted depending on the likelihood of achieving certain performance goals. The 2018 PSU Grant generally vests on the third anniversary of the date of the grant. Also, subsequent to June 30, 2018, the Company settled PSUs that were granted in 2015, with no shares issued upon settlement because the grant settled at a zero multiplier.
 
 
 
 
Employee Restricted Stock Units
The Company grants restricted stock units (“RSUs”) to eligible employees 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 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.
Total compensation expense recorded for employee RSUs was $2.3 million and $2.1 million for the three months ended June 30, 2018, and 2017, respectively, and was $5.0 million and $4.6 million for the six months ended June 30, 2018, and 2017, respectively. As of June 30, 2018, there was $12.8 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2020. There were no material changes to the outstanding and non-vested RSUs during the six months ended June 30, 2018.

Subsequent to June 30, 2018, the Company granted 534,770 RSUs with a fair value of $13.7 million. These RSUs generally vest one-third of the total grant on each of the next three anniversary dates of the grant. Also, subsequent to June 30, 2018, the Company settled 406,013 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 290,584 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.
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. There were 100,249 and 123,678 shares issued under the ESPP during the second quarters of 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 six months ended June 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.

18


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.
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 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Service cost
$
1,705

 
$
1,269

 
$
3,365

 
$
3,319

Interest cost
637

 
617

 
1,310

 
1,344

Expected return on plan assets that reduces periodic pension benefit cost
(370
)
 
(563
)
 
(931
)
 
(1,122
)
Amortization of prior service cost
5

 
5

 
9

 
9

Amortization of net actuarial loss
340

 
253

 
664

 
649

Net periodic benefit cost
$
2,317

 
$
1,581

 
$
4,417

 
$
4,199

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 $6.1 million to the Qualified Pension Plan during the six months ended June 30, 2018.


19


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 six months ended June 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 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Anti-dilutive

 
44

 

 
59

The following table sets forth the calculations of basic and diluted net income (loss) per common share:
 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per share data)
Net income (loss)
$
17,197

 
$
(119,907
)
 
$
334,598

 
$
(45,473
)
 
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
111,701

 
111,277

 
111,698

 
111,274

Dilutive effect of non-vested RSUs and contingent PSUs
1,929

 

 
1,569

 

Dilutive effect of Senior Convertible Notes

 

 

 

Diluted weighted-average common shares outstanding
113,630

 
111,277

 
113,267

 
111,274

 
 
 
 
 
 
 
 
Basic net income (loss) per common share
$
0.15

 
$
(1.08
)
 
$
3.00

 
$
(0.41
)
Diluted net income (loss) per common share
$
0.15

 
$
(1.08
)
 
$
2.95

 
$
(0.41
)
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 June 30, 2018, all derivative counterparties were members of the Company’s credit facility 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

20


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.
As of June 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)
Third quarter 2018
 
1,769

 
$
49.77

Fourth quarter 2018
 
1,894

 
$
49.87

2019
 
1,940

 
$
50.70

Total
 
5,603

 
 
Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(MBbl)
 
(per Bbl)
 
(per Bbl)
Third quarter 2018
 
1,948

 
$
50.00

 
$
58.61

Fourth quarter 2018
 
2,222

 
$
50.00

 
$
58.44

2019
 
10,055

 
$
50.59

 
$
63.62

2020
 
366

 
$
55.00

 
$
67.01

Total
 
14,591

 
 
 
 
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)
Third quarter 2018
 
3,018

 
$
(1.06
)
 

 
$

Fourth quarter 2018
 
3,327

 
$
(1.08
)
 

 
$

2019
 
11,217

 
$
(3.36
)
 

 
$

2020
 
7,250

 
$
(1.13
)
 
1,288

 
$
(7.97
)
2021
 

 
$

 
1,460

 
$
(7.80
)
2022
 

 
$

 
274

 
$
(7.67
)
Total
 
24,812

 
 
 
3,022

 
 
____________________________________________
(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).

21


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)
Third quarter 2018
 
28,218

 
$
3.25

 
(7,480
)
 
$
4.23

 
20,738

 
$
2.90

Fourth quarter 2018
 
28,204

 
$
3.27

 
(7,210
)
 
$
4.27

 
20,994

 
$
2.92

2019
 
41,394

 
$
3.87

 
(24,415
)
 
$
4.34

 
16,979

 
$
2.92

Total
 
97,816

 
 
 
(39,105
)
 
 
 
58,711

 
 
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

Total
 
14,242

 
 
 
 
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)
Third quarter 2018
 
1,033

$
10.99

 
610

$
24.27

 
93

$
35.70

 
70

$
35.07

 
202

$
51.13

Fourth quarter 2018
 
1,146

$
11.18

 
671

$
24.39

 
102

$
35.70

 
76

$
35.07

 
208

$
50.99

2019
 
3,533

$
12.31

 
1,503

$
27.83

 
154

$
35.64

 
117

$
35.70

 
197

$
50.93

2020
 
539

$
11.13

 

$

 

$

 

$

 

$

Total
 
6,251

 
 
2,784

 
 
349

 
 
263

 
 
607

 
Commodity Derivative Contracts Entered Into Subsequent to June 30, 2018
Subsequent to June 30, 2018, the Company entered into various commodity derivative contracts, as summarized below:
NYMEX WTI costless collar contracts for 2020 for a total of 0.8 MMBbl of oil production with contract floor prices of $55.00 per Bbl and contract ceiling prices ranging from $64.50 per Bbl to $67.67 per Bbl;
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2020 for a total of 0.6 MMBbl of oil production at contract prices ranging from ($8.06) per Bbl to ($8.15) per Bbl;
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2021 for a total of 1.8 MMBbl of oil production at contract prices ranging from ($7.75) per Bbl to ($8.00) per Bbl;
fixed price NYMEX WTI-ICE Brent basis swap contracts for 2022 for a total of 2.6 MMBbl of oil production at contract prices ranging from ($7.60) per Bbl to ($7.90) per Bbl; and
fixed price OPIS Propane Mont Belvieu Non-TET swap contracts for 2019 for a total of 0.5 MMBbl of NGL production at contract prices ranging from $32.21 per Bbl to $32.26 per Bbl.

22


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 $149.4 million and $139.4 million as of June 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 June 30,
2018
 
As of December 31, 2017
 
(in thousands)
Derivative assets:
 
 
 
Current assets
$
146,329

 
$
64,266

Noncurrent assets
31,151

 
40,362

Total derivative assets
$
177,480

 
$
104,628

Derivative liabilities:
 
 
 
Current liabilities
$
259,338

 
$
172,582

Noncurrent liabilities
67,583

 
71,402

Total derivative liabilities
$
326,921

 
$
243,984

Offsetting of Derivative Assets and Liabilities
As of June 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.
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
 
June 30, 
 2018
 
December 31, 2017
 
June 30, 
 2018
 
December 31, 2017
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
$
177,480

 
$
104,628

 
$
(326,921
)
 
$
(243,984
)
Amounts not offset in the accompanying balance sheets
(147,009
)
 
(100,035
)
 
147,009

 
100,035

Net amounts
$
30,471

 
$
4,593

 
$
(179,912
)
 
$
(143,949
)

23


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 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Derivative settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
24,430

 
$
2,754

 
$
45,178

 
$
11,838

Gas contracts
757

 
(21,751
)
 
(5,653
)
 
(39,257
)
NGL contracts
11,478

 
2,694

 
21,668

 
11,109

Total derivative settlement (gain) loss
$
36,665

 
$
(16,303
)
 
$
61,193

 
$
(16,310
)
 
 
 
 
 
 
 
 
Net derivative (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
22,402

 
$
(38,194
)
 
$
36,368

 
$
(87,784
)
Gas contracts
7,000

 
(6,038
)
 
16,990

 
(50,506
)
NGL contracts
34,347

 
(10,957
)
 
17,920

 
(31,673
)
Total net derivative (gain) loss
$
63,749

 
$
(55,189
)
 
$
71,278

 
$
(169,963
)
Credit Related Contingent Features
As of June 30, 2018, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. Under the Credit Agreement and derivative contracts, the Company is required to secure mortgages on assets having a value equal to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report.
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
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 June 30, 2018:

Level 1

Level 2

Level 3

(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$

 
$
177,480

 
$

Liabilities:
 
 
 
 
 
Derivatives (1)
$

 
$
326,921

 
$

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


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 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. The calculation of the discount rates is based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir-specific weightings of future estimated proved and unproved cash flows as of June 30, 2018, and December 31, 2017. The Company believes the discount rates are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. There were no material impairments of proved properties during the three and six months ended June 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 six months ended June 30, 2018, the Company recorded $11.9 million and $17.6 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 or six months ended June 30, 2017.

25


Oil and gas properties held for sale. Proved and unproved oil and gas properties classified as held for sale, including the 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 income 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 June 30, 2018, or as of December 31, 2017. For the six months ended June 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 as well as in the 2017 Form 10-K for more information regarding the Company’s oil and gas properties held for sale.
Long-Term Debt
The following table reflects the fair value of the Senior Notes and Senior Convertible Notes 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 June 30, 2018, or December 31, 2017, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. On July 16, 2018, the 2021 Senior Notes were redeemed. Please refer to Note 5 - Long-Term Debt for additional discussion.
 
As of June 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

 
$
352,634

 
$
344,611

 
$
351,682

6.125% Senior Notes due 2022
$
561,796

 
$
573,847

 
$
561,796

 
$
571,627

6.50% Senior Notes due 2023
$
394,985

 
$
401,380

 
$
394,985

 
$
403,434

5.0% Senior Notes due 2024
$
500,000

 
$
468,750

 
$
500,000

 
$
483,440

5.625% Senior Notes due 2025
$
500,000

 
$
485,000

 
$
500,000

 
$
494,355

6.75% Senior Notes due 2026
$
500,000

 
$
502,350

 
$
500,000

 
$
516,350

1.50% Senior Convertible Notes due 2021
$
172,500

 
$
178,446

 
$
172,500

 
$
168,291


26


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion includes 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 plays 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 achieving high full-cycle economic returns on our investments and maintaining a strong balance sheet.
Outlook for 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.
As previously announced, we completed three divestitures of non-core assets during the first half of 2018, which have generated total net proceeds of $741.6 million, subject to final purchase price adjustments. We have used these proceeds to support continued development of our core acreage positions in the Midland Basin and Eagle Ford shale, while maintaining an undrawn balance on our credit facility as of June 30, 2018. These proceeds also were used in part to call all of the $344.6 million aggregate principal amount outstanding on our 2021 Senior Notes, which we redeemed in full on July 16, 2018. 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.
We continue to see significant production growth and value within our Midland Basin assets as our operational execution in this program is yielding stronger than expected well results, which have been key to our continued increase in oil volumes produced. Our focus remains on developing our high-margin assets in the Midland Basin, which we believe will continue to provide us with the best opportunity for positive cash flow growth. Currently, due to robust drilling activity across the Permian Basin, the industry expects takeaway capacity to remain tight through mid-to-late 2019 as announced pipeline infrastructure build-out is completed. We remain proactive in managing risks associated with price and basis differential volatility through the use of commodity derivative instruments, which we expect to help mitigate the expected effects of increasing basis differentials and support our ability to continue to generate positive cash flows from our Midland Basis assets during this period. Please refer to Note 10 - Derivative Financial Instruments 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, which reflects a slight increase of $40 million primarily to account for higher than expected working interests for projects in the Midland Basin. As a result of these higher working interests, we are also expecting a slight increase in full year net well completions for 2018. We expect to invest over 80 percent of our total capital program in drilling and completion activities. We plan to allocate the majority of our 2018 capital to our Midland Basin program, which generates the highest margins and returns in our portfolio. As a result of drilling and completion efficiencies in our Midland Basin program, we have been able to reduce the number of drilling rigs and completion crews that we are using in the area. Planned drilling and completion activity in the Eagle Ford shale continues to be partially funded by a third party as part of our previously announced drilling and completion carry agreement in a focused portion of our Eagle Ford North area. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on our 2018 capital program.

27


Financial Results
We recorded net income of $17.2 million and $334.6 million, or $0.15 and $2.95 per diluted share, for the three and six months ended June 30, 2018, respectively, compared with net loss of $119.9 million and $45.5 million, or $1.08 and $0.41 per diluted share, for the three and six months ended June 30, 2017, respectively. Net income for the three and six months ended June 30, 2018, was driven largely by increased production revenue and net gain on divestiture activity of $39.5 million and $424.9 million, respectively, but was partially offset by net derivative losses of $63.7 million and $71.3 million for the three and six months ended June 30, 2018, respectively. Please refer to Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2018, and 2017 below for additional discussion regarding the components of net income (loss) for each period presented.
We had net cash provided by operating activities of $171.4 million and $311.5 million for the three and six months ended June 30, 2018, respectively, compared with $107.1 million and $242.1 million for the same periods in 2017, respectively. The increases in net cash provided by operating activities for the three and six months ended June 30, 2018, were driven largely by increased production revenue. Please refer to Overview of Liquidity and Capital Resources below for additional discussion of our sources and uses of cash.
Adjusted EBITDAX, a non-GAAP financial measure, for the three and six months ended June 30, 2018, was $225.0 million and $435.1 million, respectively, compared with $154.0 million and $326.0 million for the same periods in 2017, respectively. The increases in adjusted EBITDAX for the three and six months ended June 30, 2018, were driven largely by increased production revenue and lower operating costs. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX.
Operational Activities
In our Midland Basin program, we began the second quarter of 2018 with nine operated drilling rigs and five completion crews. During the quarter, we released one rig and two completion crews. In July 2018, we released a second rig, bringing our total number of operated drilling rigs to seven. For the full year 2018, we anticipate that our Midland Basin program will average seven operated drilling rigs and four completion crews. During the second quarter of 2018, our operations continued to focus on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals in our RockStar acreage in Howard and Martin Counties, Texas, as well as our Sweetie Peck acreage in Upton and Midland Counties, Texas. In addition, we completed the core build out of our water handling system during the second quarter of 2018, which is now operational and serving a significant portion of our water disposal needs on our RockStar acreage. We expect to allocate approximately 86 percent of our budgeted 2018 drilling and completion capital to our Midland Basin program.
During the second quarter of 2018, we expanded our core RockStar acreage position by acquiring approximately 720 contiguous net acres of unproved properties in Martin County, Texas, for cash consideration of $24.6 million. Further, we closed on the previously announced sale of our non-core third-party operated Halff East assets in the Midland Basin during the second quarter of 2018.
In our operated Eagle Ford shale program, we operated two drilling rigs and averaged one completion crew during the second quarter of 2018. For the full year 2018, we anticipate our Eagle Ford shale program will operate approximately one to two drilling rigs and one to 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 second quarter of 2018. We expect the remaining wells associated with this agreement to be drilled and completed in 2018, with minimal capital investment required on our part. We plan to allocate approximately 14 percent of our budgeted 2018 drilling and completion capital to our Eagle Ford shale program.
During the first quarter of 2018, we successfully closed on the sale of our previously announced PRB Divestiture for net divestiture proceeds of $490.8 million, subject to final purchase price adjustments. In addition, during the second quarter of 2018, we closed on our previously announced sale of our remaining Bakken/Three Forks assets in Divide County, North Dakota.

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The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs during the three and six months ended June 30, 2018:
 
Midland Basin
 
Eagle Ford Shale
 
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