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

For the quarterly period ended June 30, 2017

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
smelogohoriz4c1200204.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 26, 2017, the registrant had 111,623,367 shares of common stock, $0.01 par value, outstanding.

1

SM ENERGY COMPANY
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 amounts)
 
June 30,
2017
 
December 31,
2016
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
559,521

 
$
9,372

Accounts receivable
105,713

 
151,950

Derivative asset
85,962

 
54,521

Prepaid expenses and other
18,121

 
8,799

Total current assets
769,317

 
224,642

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
5,631,013

 
5,700,418

Less - accumulated depletion, depreciation, and amortization
(3,117,983
)
 
(2,836,532
)
Unproved oil and gas properties
2,418,984

 
2,471,947

Wells in progress
286,682

 
235,147

Oil and gas properties held for sale, net
18,739

 
372,621

Other property and equipment, net of accumulated depreciation of $47,738 and $42,882, respectively
108,976

 
137,753

Total property and equipment, net
5,346,411

 
6,081,354

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
82,194

 
67,575

Other noncurrent assets
14,683

 
19,940

Total other noncurrent assets
96,877

 
87,515

Total Assets
$
6,212,605

 
$
6,393,511

 
 
 
 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
311,476

 
$
299,708

Derivative liability
36,296

 
115,464

Total current liabilities
347,772

 
415,172

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
—

 
—

Senior Notes, net of unamortized deferred financing costs
2,767,030

 
2,766,719

Senior Convertible Notes, net of unamortized discount and deferred financing costs
134,918

 
130,856

Asset retirement obligation
100,304

 
96,134

Asset retirement obligation associated with oil and gas properties held for sale
234

 
26,241

Deferred income taxes
245,506

 
315,672

Derivative liability
69,915

 
98,340

Other noncurrent liabilities
45,098

 
47,244

Total noncurrent liabilities
3,363,005

 
3,481,206

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,453,476 and 111,257,500 shares, respectively
1,115

 
1,113

Additional paid-in capital
1,729,104

 
1,716,556

Retained earnings
786,608

 
794,020

Accumulated other comprehensive loss
(14,999
)
 
(14,556
)
Total stockholders’ equity
2,501,828

 
2,497,133

Total Liabilities and Stockholders’ Equity
$
6,212,605

 
$
6,393,511


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 amounts)

 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
Operating revenues and other income:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
284,939

 
$
291,142

 
$
618,137

 
$
502,965

Net gain (loss) on divestiture activity
(167,133
)
 
50,046

 
(129,670
)
 
(18,975
)
Other operating revenues
2,915

 
626

 
4,992

 
900

Total operating revenues and other income
120,721


341,814


493,459


484,890

 











Operating expenses:











Oil, gas, and NGL production expense
124,376

 
148,591

 
262,422

 
293,134

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
153,232

 
211,020

 
291,044

 
425,227

Exploration
13,072

 
13,187

 
25,050

 
28,460

Impairment of proved properties
3,806

 
—

 
3,806

 
269,785

Abandonment and impairment of unproved properties
157

 
38

 
157

 
2,349

General and administrative
28,460

 
28,200

 
57,684

 
60,438

Net derivative (gain) loss
(55,189
)
 
163,351

 
(169,963
)
 
149,123

Other operating expenses
445

 
7,976

 
5,304

 
13,648

Total operating expenses
268,359


572,363


475,504


1,242,164

 











Income (loss) from operations
(147,638
)

(230,549
)

17,955


(757,274
)
 











Non-operating income (expense):











Interest expense
(44,595
)
 
(34,035
)
 
(91,548
)
 
(65,123
)
Gain (loss) on extinguishment of debt
—

 
—

 
(35
)
 
15,722

Other, net
1,265

 
5

 
1,600

 
11

 











Loss before income taxes
(190,968
)

(264,579
)

(72,028
)

(806,664
)
Income tax benefit
71,061

 
95,898

 
26,555

 
290,773

 











Net loss
$
(119,907
)
 
$
(168,681
)
 
$
(45,473
)

$
(515,891
)
 











Basic weighted-average common shares outstanding
111,277

 
68,102

 
111,274

 
68,090

Diluted weighted-average common shares outstanding
111,277

 
68,102

 
111,274

 
68,090

Basic net loss per common share
$
(1.08
)
 
$
(2.48
)
 
$
(0.41
)
 
$
(7.58
)
Diluted net loss per common share
$
(1.08
)
 
$
(2.48
)
 
$
(0.41
)
 
$
(7.58
)
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,
 
 
 
2017
 
2016
 
2017
 
2016
Net loss
$
(119,907
)
 
$
(168,681
)
 
$
(45,473
)
 
$
(515,891
)
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Pension liability adjustment
124

 
(269
)
 
(443
)
 
(505
)
Total other comprehensive income (loss), net of tax
124

 
(269
)
 
(443
)
 
(505
)
Total comprehensive loss
$
(119,783
)
 
$
(168,950
)
 
$
(45,916
)
 
$
(516,396
)

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

5

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (UNAUDITED)
(in thousands, except share amounts)




Additional Paid-in Capital



Accumulated Other Comprehensive Loss

 Total Stockholders’ Equity

Common Stock


Retained Earnings



Shares

Amount




Balances, December 31, 2016
111,257,500

 
$
1,113

 
$
1,716,556

 
$
794,020

 
$
(14,556
)
 
$
2,497,133

Net loss
—

 
—

 
—

 
(45,473
)
 
—

 
(45,473
)
Other comprehensive loss
—

 
—

 
—

 
—

 
(443
)
 
(443
)
Cash dividends, $ 0.05 per share
—

 
—

 
—

 
(5,563
)
 
—

 
(5,563
)
Issuance of common stock under Employee Stock Purchase Plan
123,678

 
1

 
1,737

 
—

 
—

 
1,738

Issuance of common stock upon vesting of restricted stock units, net of shares used for tax withholdings
725

 
—

 
(11
)
 
—

 
—

 
(11
)
Stock-based compensation expense
71,573

 
1

 
9,812

 
—

 
—

 
9,813

Cumulative effect of accounting change (1)
—

 
—

 
1,108

 
43,624

 
—

 
44,732

Other
—

 
—

 
(98
)
 
—

 
—

 
(98
)
Balances, June 30, 2017
111,453,476

 
$
1,115

 
$
1,729,104

 
$
786,608

 
$
(14,999
)
 
$
2,501,828

____________________________________________
(1) 
Refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards.

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)
(in thousands)

 
For the Six Months Ended 
 June 30,
 
2017
 
2016
Cash flows from operating activities:
 
 
 
Net loss
$
(45,473
)
 
$
(515,891
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Net loss on divestiture activity
129,670

 
18,975

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
291,044

 
425,227

Impairment of proved properties
3,806

 
269,785

Abandonment and impairment of unproved properties
157

 
2,349

Stock-based compensation expense
9,813

 
13,915

Net derivative (gain) loss
(169,963
)
 
149,123

Derivative settlement gain
16,310

 
248,738

Amortization of debt discount and deferred financing costs
8,679

 
1,930

Non-cash (gain) loss on extinguishment of debt, net
22

 
(15,722
)
Deferred income taxes
(30,790
)
 
(291,014
)
Plugging and abandonment
(1,609
)
 
(2,716
)
Other, net
2,267

 
2,517

Changes in current assets and liabilities:
 
 
 
Accounts receivable
46,993

 
(11,220
)
Prepaid expenses and other
(9,321
)
 
8,487

Accounts payable and accrued expenses
(8,973
)
 
(61,727
)
Accrued derivative settlements
(517
)
 
14,117

Net cash provided by operating activities
242,115

 
256,873

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
766,247

 
12,967

Capital expenditures
(366,743
)
 
(345,570
)
Acquisition of proved and unproved oil and gas properties
(88,140
)
 
(17,751
)
Other, net
3,000

 
(900
)
Net cash provided by (used in) investing activities
314,364

 
(351,254
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
406,000

 
585,000

Repayment of credit facility
(406,000
)
 
(456,500
)
Debt issuance costs related to credit facility
—

 
(3,132
)
Cash paid to repurchase Senior Notes
(2,344
)
 
(29,904
)
Net proceeds from sale of common stock
1,738

 
2,354

Dividends paid
(5,563
)
 
(3,404
)
Other, net
(161
)
 
(33
)
Net cash provided by (used in) financing activities
(6,330
)
 
94,381

 
 
 
 
Net change in cash and cash equivalents
550,149

 
—

Cash and cash equivalents at beginning of period
9,372

 
18

Cash and cash equivalents at end of period
$
559,521

 
$
18

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

7

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,
 
2017
 
2016
Supplemental Cash Flow Information:
 
 
 
Operating Activities:
 
 
 
Cash paid for interest, net of capitalized interest
$
(83,493
)
 
$
(63,590
)
Net cash (paid) refunded for income taxes
$
(8,220
)
 
$
4,564

Investing Activities:
 
 
 
Changes in capital expenditure accruals and other
$
44,770

 
$
2,986

 
 
 
 
Supplemental Non-Cash Investing Activities:
 
 
 
Value of properties exchanged
$
279,750

 
$
733


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

8

SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 - The Company and Business

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.

Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and 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 consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 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, 2017, and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies to the Company’s consolidated financial statements in its 2016 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the 2016 Form 10-K.

Recently Issued Accounting Standards

Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the various applicable amendments as summarized below:
•
On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Additionally, going forward excess tax benefits will be presented in operating activities on the statement of cash flows.
•
Also on January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in a net $0.7 million cumulative effect adjustment to retained earnings with a corresponding increase in additional paid-in capital and decrease in deferred tax assets.
•
As a result of adoption, excess tax benefits and deficiencies from share-based payments are expected to impact the Company’s effective tax rate between periods. Please refer to Note 4 - Income Taxes for additional discussion.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Under the new standard, 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. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several amendments to the standard which provided additional implementation guidance and deferred the effective date of ASU

9

2014-09. While the Company does not expect net income (loss) or cash flows to be materially impacted, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies, and control activities that will occur as a result of the adoption of this ASU, and has not yet developed estimates of the quantitative impact to its consolidated statements of financial position and operations. The Company plans to adopt the guidance using the modified retrospective method on the effective date of January 1, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) which requires lessees to recognize a right-of-use asset and a lease liability for virtually all leases currently classified as operating leases. The Company is currently analyzing the impact this standard has on the Company’s contract portfolio, including non-cancelable leases, drilling rig contracts, pipeline gathering, transportation and gas processing agreements, as well as other existing arrangements and is evaluating current accounting policies that will change as a result of this ASU. Appropriate systems, controls, and processes to support the recognition and disclosure of the new standard are also being evaluated. Based upon an initial assessment, adoption of this ASU is expected to result in: (i) an increase in assets and liabilities recorded, (ii) an increase in depreciation, depletion and amortization expense recorded, and (iii) an increase in interest expense recorded. The Company plans to adopt the guidance on the effective date of January 1, 2019.

In March 2017, the FASB issued 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”). This ASU 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 operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company plans to adopt ASU 2017-07 on January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost in the consolidated statements of operations and prospective application for the capitalization of the service cost component of net benefit costs in assets. The Company is evaluating the impact of this ASU on its consolidated financial statements.

Other than as disclosed above or in the 2016 Form 10-K, there are no other ASUs applicable to the Company that would have a material effect on the Company’s financial statements and related disclosures that have been issued but not yet adopted by the Company as of June 30, 2017, and through the filing of this report.

Note 3 - Divestitures, Assets Held for Sale, and Acquisitions
Divestitures

On March 10, 2017, the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for total cash received at closing, net of commissions (referred to throughout this report as “net divestiture proceeds”), of $747.4 million, and recorded an estimated net gain of $397.4 million for the six months ended June 30, 2017. These assets were classified as held for sale as of December 31, 2016.

The following table presents income (loss) before income taxes from the outside-operated Eagle Ford shale assets sold for the three and six months ended June 30, 2017, and 2016. This divestiture is considered a disposal of a significant asset group.
 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Income (loss) before income taxes (1)
$
—

 
$
12,832

 
$
24,324

 
$
(273,567
)
____________________________________________
(1) 
Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes included impairment of proved properties expense of approximately $269.6 million for the six months ended June 30, 2016.

During the second quarter of 2017, the Company divested a portion of its Divide County, North Dakota assets for net divestiture proceeds of $24.6 million. Also during the second quarter of 2017, the Company finalized the 2016 divestiture of its Raven/Bear Den assets resulting in a final net gain of $29.1 million.


10

Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty 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 in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”). As of June 30, 2017, there were $18.7 million of assets held for sale presented in the accompanying condensed consolidated balance sheets (“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 due to the assets no longer being actively marketed as valuations in the sales process did not reach the Company’s expectations. 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.

For the first quarter of 2016, certain assets held for sale were written down by $68.3 million to reflect fair value less estimated costs to sell at March 31, 2016. During the second quarter of 2016, the Company estimated an increase in the fair value of certain of these previously impaired assets held for sale due to an increase in estimated selling prices, as evidenced by bid prices received from third parties, resulting in a $49.5 million gain recorded for the three months ended June 30, 2016.

Acquisitions

During the first half of 2017, the Company acquired approximately 3,400 net acres of primarily unproved properties in the Midland Basin in multiple transactions totaling $72.3 million of cash consideration. Under authoritative accounting guidance, these transactions were considered asset acquisitions and the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired.

The Company finalized the 2016 acquisition of Midland Basin properties from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”) during the first quarter of 2017 by paying an additional $7.4 million of cash consideration, resulting in total consideration of $998.4 million paid after final closing adjustments. Subsequent to June 30, 2017, the Company finalized the 2016 acquisition of Midland Basin properties from QStar LLC and RRP-QStar, LLC (referred to as the “QStar Acquisition”). The Company paid an additional $7.1 million of cash consideration during 2017, with the majority of this payment being made in the first quarter of 2017, resulting in total consideration of $1.6 billion after final closing adjustments. There were no material changes to the recorded basis of these proved and unproved properties acquired as a result of the final settlements.

Also, during the first half of 2017, the Company completed several trades of properties, primarily unproved, in Howard and Martin Counties, Texas resulting in the Company acquiring approximately 6,550 net acres in exchange for approximately 5,700 net acres. These trades were recorded at carryover basis with no gain or loss recognized.

Note 4 - Income Taxes

The income tax benefit recorded for the three and six months ended June 30, 2017, and 2016, 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, changes in valuation allowances, excess tax benefits and deficiencies from share-based payment awards, 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.


11

The provision for income taxes for the three and six months ended June 30, 2017, and 2016, consisted of the following:
 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Current portion of income tax benefit (expense):
 
 
 
 
 
 
 
Federal
$
4,607

 
$
—

 
$
(2,832
)
 
$
—

State
2,439

 
(77
)
 
(1,403
)
 
(241
)
Deferred portion of income tax benefit
64,015

 
95,975

 
30,790

 
291,014

Income tax benefit
$
71,061

 
$
95,898

 
$
26,555

 
$
290,773

Effective tax rate
37.2
%
 
36.2
%
 
36.9
%
 
36.0
%

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 among multiple state tax jurisdictions. As a result of adopting ASU 2016-09 on January 1, 2017, excess tax benefits and deficiencies from share-based payment awards are expected to impact the Company’s effective tax rate between periods. As discussed in Note 7 - Compensation Plans, subsequent to June 30, 2017, the Company settled various RSU grants and the 2014 PSU grant. As a result of these share-based award settlements, the Company expects to record an excess tax deficiency in the third quarter of 2017. Cumulative effects of state tax rate changes are reflected in the period legislation is enacted.

The change in the current portion of income tax benefit (expense) and the effective tax rate relates to the effect of anticipated utilization of carryover net operating losses, deferred tax expenses, and carryover tax credits. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013. Its 2003 to 2005 tax years have been reopened for net operating loss carryback claims and are currently under examination by the Internal Revenue Service.

Note 5 - Long-Term Debt

Credit Facility

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 March 31, 2017, the Company entered into a Ninth Amendment to the Credit Agreement (the “Ninth Amendment”) with its lenders. Pursuant to the Ninth Amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were reduced to $925 million. This expected reduction was primarily due to the sale of the Company’s outside-operated Eagle Ford shale assets in the first quarter of 2017 and the decrease in the value of the Company’s proved reserves at December 31, 2016. The borrowing base redetermination process considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report and (b) commodity derivative contracts, each as determined by the Company’s lender group. Additionally, the Ninth Amendment modified the Credit Agreement to allow the Company to enter into derivative contracts for an increased percentage of projected production volumes. As a result of the reduction to the Company’s borrowing base and aggregate lender commitments, the Company recorded approximately $1.1 million of expense related to the acceleration of unamortized deferred financing costs for the six months ended June 30, 2017. The next scheduled redetermination date is October 1, 2017.

The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. Certain financial covenants under the Credit Agreement require, as of the last day of each of the Company’s fiscal quarters, the Company’s (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0. The Company was in compliance with all financial and non-financial covenants under the Credit Agreement as of June 30, 2017, 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 and presented in Note 5 - Long-Term Debt to the Company’s consolidated financial statements in its 2016 Form 10-K.  Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table, and Alternate Base Rate and swingline loans accrue interest at the prime rate, plus the applicable margin from the utilization table.  Commitment fees are accrued

12

on the unused portion of the aggregate lender commitment amount 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 26, 2017, June 30, 2017, and December 31, 2016:
 
As of July 26, 2017
 
As of June 30, 2017
 
As of December 31, 2016
 
(in thousands)
Credit facility balance (1)
$
—

 
$
—

 
$
—

Letters of credit (2)
200

 
200

 
200

Available borrowing capacity
924,800

 
924,800

 
1,164,800

Total aggregate lender commitment amount
$
925,000

 
$
925,000

 
$
1,165,000

____________________________________________
(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 $3.9 million and $5.9 million as of June 30, 2017, and December 31, 2016, 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”). The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of June 30, 2017, and December 31, 2016, consisted of the following:
 
As of June 30, 2017
 
As of December 31, 2016
 
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 (1) (2)
$
344,611

 
$
3,003

 
$
341,608

 
$
346,955

 
$
3,372

 
$
343,583

6.125% Senior Notes due 2022 (2)
561,796

 
6,390

 
555,406

 
561,796

 
6,979

 
554,817

6.50% Senior Notes due 2023 (2)
394,985

 
4,071

 
390,914

 
394,985

 
4,436

 
390,549

5.0% Senior Notes due 2024
500,000

 
6,072

 
493,928

 
500,000

 
6,533

 
493,467

5.625% Senior Notes due 2025
500,000

 
7,166

 
492,834

 
500,000

 
7,619

 
492,381

6.75% Senior Notes due 2026
500,000

 
7,660

 
492,340

 
500,000

 
8,078

 
491,922

Total
$
2,801,392

 
$
34,362

 
$
2,767,030

 
$
2,803,736

 
$
37,017

 
$
2,766,719

____________________________________________
(1) 
During the first quarter of 2017, the Company repurchased a total of $2.3 million in aggregate principal amount of 6.50% Senior Notes due 2021 in open market transactions at a slight premium. The Company canceled all of these repurchased Senior Notes upon cash settlement.
(2) 
During the first quarter of 2016, the Company repurchased a total of $46.3 million in aggregate principal amount of certain of its Senior Notes in open market transactions for a settlement amount of $29.9 million, excluding interest. The Company recorded a net gain on extinguishment of debt of approximately $15.7 million for the six months ended June 30, 2016. This amount includes a gain of approximately $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. The Company canceled all of these repurchased Senior Notes upon cash settlement.

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 covenants as of June 30, 2017, 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.

13


Senior Convertible Notes

On August 12, 2016, the Company issued $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.

The Senior Convertible Notes mature on July 1, 2021, unless earlier converted. Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under certain circumstances as outlined in the indenture governing the Senior Convertible Notes and in Note 5 – Long-Term Debt to the Company’s consolidated financial statements in its 2016 Form 10-K. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment.
    
The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount in cash with any excess value in shares of the Company’s common stock. The Senior Convertible Notes were not convertible at the option of holders as of June 30, 2017, 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, 2017, did not exceed the principal amount.

Upon the issuance of the Senior Convertible Notes, the Company recorded $132.3 million as the initial carrying amount of the debt component, which approximated its fair value at issuance, and was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25 percent. The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. 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 $2.5 million and $4.9 million for the three and six months ended June 30, 2017, respectively.

The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets as of June 30, 2017, and December 31, 2016, consisted of the following:
 
As of June 30, 2017
 
As of December 31, 2016
 
(in thousands)
Principal amount of Senior Convertible Notes
$
172,500

 
$
172,500

Unamortized debt discount
(33,913
)
 
(37,513
)
Unamortized deferred financing costs
(3,669
)
 
(4,131
)
Net carrying amount
$
134,918

 
$
130,856


The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of June 30, 2017, and through the filing of this report.

Capped Call Transactions

In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The capped call transactions are generally expected to reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call transactions, there could be dilution or there would not be an offset of such potential cash payments.


14

Note 6 - Commitments and Contingencies

Commitments

During the first quarter of 2017, the Company completed the divestiture of its outside-operated Eagle Ford shale assets. Upon closing of the sale, the Company is no longer subject to gathering, processing, and transportation throughput commitments totaling 514 Bcf of natural gas, 52 MMBbl of oil, and 13 MMBbl of NGLs, or $501.9 million of the potential undiscounted deficiency payments as of December 31, 2016. As of June 30, 2017, the Company had total gathering, processing, transportation throughput, and purchase commitments with various third parties that require delivery of a minimum quantity of 883 Bcf of natural gas, 16 MMBbl of crude oil, and 25 MMBbl of water through 2028 and a minimum purchase quantity of 16 MMBbl of water by 2022. If the Company fails to deliver or purchase any product, as applicable, the aggregate undiscounted deficiency payments totaled approximately $456.4 million as of June 30, 2017. As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to these commitments.

Additionally, the Company entered into new and amended drilling rig contracts during the first half of 2017 and subsequent to June 30, 2017. As of July 26, 2017, the Company’s total drilling rig commitment was $23.7 million; however, if the Company terminated these rig contracts immediately, it would incur penalties of $15.1 million.

There were no other material changes in commitments during the first half of 2017. Please refer to Note 6 - Commitments and Contingencies to the Company’s consolidated financial statements in its 2016 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

Performance Share Units Under the Equity Incentive Compensation Plan

The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0% to 200% of the number of PSUs awarded and is determined based on certain performance criteria over a three-year measurement period. The performance criteria for PSUs are 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 and exploration expense over the vesting periods of the respective awards.

Total compensation expense recorded for PSUs for the three months ended June 30, 2017, and 2016, was $1.7 million and $3.0 million, respectively, and $4.2 million and $5.9 million for the six months ended June 30, 2017, and 2016, respectively. As of June 30, 2017, there was $10.6 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2019. There were no material changes to the outstanding and non-vested PSUs during the six months ended June 30, 2017.

Subsequent to June 30, 2017, the Company granted 977,731 PSUs with a fair value of $15.5 million. These PSUs generally vest on the third anniversary of the date of the grant. Also, subsequent to June 30, 2017, the Company settled PSUs that were granted in 2014 with no shares issued upon settlement as the grant settled at a zero multiplier.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants restricted stock units (“RSUs”) as part of its long-term equity 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.

15


Total compensation expense recorded for RSUs was $2.1 million and $3.3 million for the three months ended June 30, 2017, and 2016, respectively, and $4.6 million and $6.5 million for the six months ended June 30, 2017, and 2016, respectively. As of June 30, 2017, there was $9.8 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2019. There were no material changes to the outstanding and non-vested RSUs during the six months ended June 30, 2017.

Subsequent to June 30, 2017, the Company granted 1,010,298 RSUs with a fair value of $16.8 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, 2017, the Company settled 243,951 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 169,891 net shares of common stock upon settlement of the awards. The remaining 74,060 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those RSUs.

Director Shares

During the second quarter of 2017, the Company issued 71,573 shares of its common stock and 8,794 RSUs to its non-employee directors, under the Company’s Equity Incentive Compensation Plan, which fully vest on December 31, 2017. The Company issued 53,473 shares of its common stock to its non-employee directors during the second quarter of 2016.

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 (“IRC”). There were 123,678 and 140,853 shares issued under the ESPP during the second quarters of 2017 and 2016, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Note 8 - Pension Benefits

Pension Plans

The Company has a non-contributory defined benefit pension plan covering substantially all of its employees who joined the Company prior to January 1, 2015, and 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”). The Company froze the Pension Plans to new participants, effective as of December 31, 2015. Employees participating in the Pension Plans as of December 31, 2015, 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,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Service cost
$
1,269

 
$
2,113

 
$
3,319

 
$
4,100

Interest cost
617

 
830

 
1,344

 
1,454

Expected return on plan assets that reduces periodic pension benefit cost
(563
)
 
(573
)
 
(1,122
)
 
(1,118
)
Amortization of prior service cost
5

 
5

 
9

 
9

Amortization of net actuarial loss
253

 
419

 
649

 
791

Net periodic benefit cost
$
1,581

 
$
2,794

 
$
4,199

 
$
5,236



16

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.

Contributions

The Company contributed $7.0 million to the Qualified Pension Plan during the six months ended June 30, 2017.

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 of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method.

PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs.

Please refer to Note 7 - Compensation Plans for additional discussion of the RSUs and PSUs granted and the net RSUs and PSUs settled subsequent to June 30, 2017.

On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount of the Senior Convertible Notes in cash and the excess conversion value in shares. However, the Company has not made this a formal legal irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business conditions warrant. 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, 2017, and therefore, the Senior Convertible Notes had no dilutive impact. In connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions are not reflected in diluted net income (loss) per share, nor will they ever be, as they are anti-dilutive. Please refer to Note 5 - Long-Term Debt for additional discussion.

When the Company recognizes a loss from continuing operations, as was the case for all periods presented, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share.

The following table details the weighted-average anti-dilutive securities for the periods presented:
 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Anti-dilutive
44

 
155

 
59

 
70



17

The following table sets forth the calculations of basic and diluted net loss per common share:
 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except per share amounts)
Net loss
$
(119,907
)
 
$
(168,681
)
 
$
(45,473
)
 
$
(515,891
)
Basic weighted-average common shares outstanding
111,277

 
68,102

 
111,274

 
68,090

Add: dilutive effect of non-vested RSUs and contingent PSUs
—

 
—

 
—

 
—

Add: dilutive effect of Senior Convertible Notes
—

 
—

 
—

 
—

Diluted weighted-average common shares outstanding
111,277

 
68,102

 
111,274

 
68,090

Basic net loss per common share
$
(1.08
)
 
$
(2.48
)
 
$
(0.41
)
 
$
(7.58
)
Diluted net loss per common share
$
(1.08
)
 
$
(2.48
)
 
$
(0.41
)
 
$
(7.58
)

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, 2017, 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. 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.
    
As of June 30, 2017, the Company had commodity derivative contracts outstanding as summarized in the tables below:

Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(MBbls)
 
(per Bbl)
Third quarter 2017
 
1,340

 
$
46.66

Fourth quarter 2017
 
1,254

 
$
46.35

2018
 
1,493

 
$
46.82

Total
 
4,087

 
 

Subsequent to June 30, 2017, the Company entered into derivative fixed price swap contracts for 2018 for a total of 2.0 million Bbls of oil production at a weighted-average contract price of $50.37 per Bbl.


18

Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(MBbls)
 
(per Bbl)
 
(per Bbl)
Third quarter 2017
 
583

 
$
45.00

 
$
54.05

Fourth quarter 2017
 
1,086

 
$
47.51

 
$
56.05

2018
 
5,030

 
$
50.00

 
$
58.07

2019
 
3,128

 
$
50.00

 
$
58.84

Total
 
9,827

 
 
 
 

Oil Basis Swaps


Contract Period
 
Midland-Cushing Volumes
 
Weighted-Average
 Contract Price (1)
 
 
(MBbls)
 
(per Bbl)
Third quarter 2017
 
566

 
$
(1.62
)
Fourth quarter 2017
 
1,798

 
$
(1.52
)
2018
 
6,868

 
$
(1.39
)
2019
 
3,963

 
$
(1.45
)
Total
 
13,195

 
 
____________________________________________
(1)  
Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma.

Natural Gas Swaps
Contract Period
 
Sold
Volumes
 
Weighted-Average
 Contract Price
 
Purchased Volumes (1)
 
Weighted- Average Contract Price
 
Net
Volumes
 
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
Third quarter 2017
 
23,657

 
$
4.01

 
—

 
$
—

 
23,657

Fourth quarter 2017
 
22,001

 
$
3.98

 
—

 
$
—

 
22,001

2018
 
93,014

 
$
3.41

 
(30,606
)
 
$
4.27

 
62,408

2019
 
41,394

 
$
3.76

 
(24,415
)
 
$
4.34

 
16,979

Total (2)
 
180,066

 
 
 
(55,021
)
 
 
 
125,045

____________________________________________
(1) 
During 2016, the Company restructured certain of its natural gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No other cash or other consideration was included as part of the restructuring.
(2) 
Total net volumes of natural gas swaps are comprised of IF El Paso Permian (1%), IF HSC (97%), and IF NNG Ventura (2%).


19

NGL Swaps
 
 
OPIS Purity Ethane 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
 
 
(MBbls)
(per Bbl)
 
(MBbls)
(per Bbl)
 
(MBbls)
(per Bbl)
 
(MBbls)
(per Bbl)
 
(MBbls)
(per Bbl)
Third quarter 2017
 
906

$
9.48

 
588

$
21.91

 
163

$
32.42

 
140

$
33.28

 
222

$
48.43

Fourth quarter 2017
 
966

$
9.65

 
550

$
21.91

 
149

$
32.34

 
128

$
33.23

 
203

$
48.41

2018
 
4,017

$
11.00

 
2,021

$
23.38

 
225

$
33.99

 
188

$
33.56

 
305

$
48.62

2019
 
3,112

$
12.27

 
214

$
22.66

 
—

$
—

 
—

$
—

 
—

$
—

2020
 
539

$
11.13

 
—

$
—

 
—

$
—

 
—

$
—

 
—

$
—

Total
 
9,540

 
 
3,373

 
 
537

 
 
456

 
 
730

 

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 asset of $61.9 million as of June 30, 2017, and a net liability of $91.7 million as of December 31, 2016.

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:
 
As of June 30, 2017
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
85,962

 
Current liabilities
 
$
36,296

Commodity contracts
Noncurrent assets
 
82,194

 
Noncurrent liabilities
 
69,915

Derivatives not designated as hedging instruments
 
 
$
168,156

 
 
 
$
106,211


 
As of December 31, 2016
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
54,521

 
Current liabilities
 
$
115,464

Commodity contracts
Noncurrent assets
 
67,575

 
Noncurrent liabilities
 
98,340

Derivatives not designated as hedging instruments
 
 
$
122,096

 
 
 
$
213,804


Offsetting of Derivative Assets and Liabilities

As of June 30, 2017, and December 31, 2016, 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.  


20

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 derivative contracts:
 
 
Derivative Assets
 
Derivative Liabilities
 
 
As of
 
As of
Offsetting of Derivative Assets and Liabilities
 
June 30, 
 2017
 
December 31, 2016
 
June 30, 
 2017
 
December 31, 2016
 
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
 
$
168,156

 
$
122,096

 
$
(106,211
)
 
$
(213,804
)
Amounts not offset in the accompanying balance sheets
 
(64,628
)
 
(118,080
)
 
64,628

 
118,080

Net amounts
 
$
103,528

 
$
4,016

 
$
(41,583
)
 
$
(95,724
)
    
The following table summarizes the components of the net derivative (gain) loss presented in the accompanying statements of operations:
 
For the Three Months Ended 
 June 30,
 
For the Six Months Ended 
 June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Derivative settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
2,754

 
$
(72,164
)
 
$
11,838

 
$
(172,156
)
Gas contracts
(21,751
)
 
(31,439
)
 
(39,257
)
 
(72,492
)
NGL contracts
2,694

 
1,893

 
11,109

 
(4,090
)
Total derivative settlement gain
$
(16,303
)
 
$
(101,710
)
 
$
(16,310
)
 
$
(248,738
)
 
 
 
 
 
 
 
 
Total net derivative (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
(38,194
)
 
$
60,773

 
$
(87,784
)
 
$
50,341

Gas contracts
(6,038
)
 
62,489

 
(50,506
)
 
38,466

NGL contracts
(10,957
)
 
40,089

 
(31,673
)
 
60,316

Total net derivative (gain) loss
$
(55,189
)
 
$
163,351

 
$
(169,963
)
 
$
149,123


Credit Related Contingent Features

As of June 30, 2017, 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

21

The following table summarizes 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, 2017:

Level 1

Level 2

Level 3

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

 
$
168,156

 
$
—

Liabilities:
 
 
 
 
 
Derivatives (1)
$
—

 
$
106,211

 
$
—

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

The following table summarizes 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, 2016:
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$
—

 
$
122,096

 
$
—

Total property and equipment, net (2)
$
—

 
$
—

 
$
88,205

Liabilities:
 
 
 
 
 
Derivatives (1)
$
—

 
$
213,804

 
$
—

____________________________________________
(1) 
This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2) 
This represents a non-financial asset that is measured at fair value on a nonrecurring 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 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.

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group.

Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date.


22

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments.

Proved and Unproved Oil and Gas Properties and Other Property and Equipment

The Company did not have property and equipment measured at fair value within the accompanying balance sheets as of June 30, 2017. Property and equipment, net measured at fair value totaled $88.2 million as of December 31, 2016, and primarily consisted of the Company’s Powder River Basin assets, which were impaired at year-end as a result of downward performance reserve revisions.
    
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 amounts 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 are 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, 2017, and December 31, 2016. The Company believes the discount rates are representative of current market conditions and consider 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 Mont Belvieu 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.

The Company did not recognize any material impairment of proved properties expenses for the three or six months ended June 30, 2017, or for the three months ended June 30, 2016. The Company recorded impairment of proved properties expense of $269.8 million for the six months ended June 30, 2016, primarily related to the Company’s outside-operated Eagle Ford shale assets and the decline in expected cash flows driven by commodity price declines during the first quarter of 2016.
 
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.  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.

There were no material abandonments or impairments of unproved properties expenses for the three or six months ended June 30, 2017, or 2016.

Oil and gas properties held for sale. Proved and unproved properties and other property and equipment 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, or by recent, comparable market transactions. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. 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.

There were no assets held for sale that were recorded at fair value as of June 30, 2017. However, for the six months ended June 30, 2017, the Company recorded a $526.5 million write-down on its Divide County assets previously held for sale, of which $359.6 million was recorded in the first quarter of 2017 based on an estimated fair value less selling costs and $166.9 million was recorded in the second quarter of 2017 based on market conditions that existed on the date the Company decided to retain the assets. Certain assets held for sale as of June 30, 2016, were written down by $68.3 million during the first quarter of 2016 and subsequently written up by $49.5 million in the second quarter of 2016 due to an increase in estimated selling prices, as evidenced by bid prices received from third parties. Certain of these assets were subsequently sold in the third quarter of 2016 for a small net gain due to successful marketing efforts. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions for additional discussion.

23


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, 2017, or December 31, 2016, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion.
 
As of June 30, 2017
 
As of December 31, 2016
 
Principal Amount
 
Fair Value
 
Principal Amount
 
Fair Value
 
(in thousands)
6.50% Senior Notes due 2021
$
344,611

 
$
338,794

 
$
346,955

 
$
354,546

6.125% Senior Notes due 2022
$
561,796

 
$
536,347

 
$
561,796

 
$
570,925

6.50% Senior Notes due 2023
$
394,985

 
$
377,211

 
$
394,985

 
$
403,134

5.0% Senior Notes due 2024
$
500,000

 
$
445,465

 
$
500,000

 
$
475,975

5.625% Senior Notes due 2025
$
500,000

 
$
449,335

 
$
500,000

 
$
485,000

6.75% Senior Notes due 2026
$
500,000

 
$
479,840

 
$
500,000

 
$
516,565

1.50% Senior Convertible Notes due 2021
$
172,500

 
$
154,612

 
$
172,500

 
$
202,189


24


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, Highlights, and Outlook

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. Our strategic objective is to become 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 prospective drilling opportunities, which we believe provide for long-term production and reserves growth. We focus on achieving high full-cycle economic returns on our investments and maintaining a simple, strong balance sheet.

We currently have material acreage positions in the Midland Basin and Eagle Ford shale in Texas, the Powder River Basin in Wyoming, and the Bakken/Three Forks play in North Dakota. During 2016, and continuing into 2017, we made several proved and unproved property acquisitions and trades in the Midland Basin, while divesting non-core assets in other areas. By actively managing our asset portfolio in this way, we are seeking to concentrate our investments in areas with the highest economic returns and provide value through accelerated development activity.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the second and first quarters of 2017, as well as the second quarter of 2016:
 
For the Three Months Ended
 
June 30, 2017
 
March 31, 2017
 
June 30, 2016
Crude Oil (per Bbl):
 
 
 
 
 
Average NYMEX contract monthly price
$
48.28

 
$
51.91

 
$
45.59

Realized price, before the effect of derivative settlements
$
44.30

 
$
47.55

 
$
39.38

Effect of oil derivative settlements
$
(0.94
)
 
$
(2.58
)
 
$
17.59

 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Average NYMEX monthly settle price (per MMBtu)
$
3.18

 
$
3.32

 
$
1.95

Realized price, before the effect of derivative settlements (per Mcf)
$
2.99

 
$
2.98

 
$
1.79

Effect of natural gas derivative settlements (per Mcf)
$
0.64

 
$
0.52

 
$
0.81

 
 
 
 
 
 
NGLs (per Bbl): 
 
 
 
 
 
Average OPIS price (1)
$
24.11

 
$
26.74

 
$
20.04

Realized price, before the effect of derivative settlements
$
19.71

 
$
22.06

 
$
16.12

Effect of NGL derivative settlements
$
(0.98
)
 
$
(2.88
)
 
$
(0.51
)
____________________________________________
(1)  
Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.


25

We expect future prices for oil, gas, and NGLs to continue to be volatile.  In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in all regions of the world as well as the relative strength of the dollar compared to other currencies. Oil markets continue to be unstable due to over-supply, high inventory levels, and uncertainty in global demand. The increase in oil prices at the end of 2016 was primarily attributable to the Organization of Petroleum Exporting Countries (“OPEC”) and several non-OPEC exporting countries agreeing to cut production. While participating countries have largely adhered to agreed upon production cuts, uncertainty remains concerning whether these cuts will be sustained. Drilling activity in the United States has increased in recent months, putting continued downward pressure on oil prices in the near term.

There has been improvement in natural gas pricing over the last year, largely as a result of demand growth from gas fired power generation and both LNG exports and exports to Mexico exceeding prior expectations. We expect prices to remain near current levels in the near term as drilling rigs in operation have increased in recent months leading to increased supply, which we expect will be offset by continued demand growth from LNG exports and exports to Mexico. We also expect prices to fluctuate with changes in demand resulting from the weather.

NGL prices have also improved over the last year due to oil and natural gas price recovery. We expect NGL prices to remain near current levels through 2017, as we expect increased demand from export and petrochemical markets to be offset by increased drilling activity.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of July 26, 2017, and June 30, 2017:
 
As of July 26, 2017
 
As of June 30, 2017
NYMEX WTI oil (per Bbl)
$
49.19

 
$
47.10

NYMEX Henry Hub gas (per MMBtu)
$
3.01

 
$
3.09

OPIS NGLs (per Bbl)
$
25.38

 
$
23.42

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives.  The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity contracts.  With our current derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil prices while also setting a price floor for a portion of our oil production. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and the caption titled Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Second Quarter 2017 Highlights and Outlook for the Remainder of 2017

Our priorities for 2017, as set at the beginning of the year, were to:

•
demonstrate the value of our 2016 and 2017 acquisitions in the Midland Basin;
•
generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;
•
successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and
•
reduce our outstanding debt.

With respect to our 2017 priorities, we continued our focus in the second quarter on demonstrating the significant value potential of our Midland Basin position and coring up this position in order to maximize long-term growth. We successfully closed the sale of our outside-operated Eagle Ford shale assets in the first quarter of 2017 for net divestiture proceeds of $747.4 million. Proceeds from this divestiture continue to provide us with significant liquidity and will support funding our capital program for the remainder of the year. As previously announced, we made the decision during the second quarter of 2017 to retain our Divide County assets, as valuations in the sales process did not reach our expectations.  We will continue to leverage cash flows from our Divide County assets to fund higher margin production growth projects within our portfolio.
We expect our capital program for 2017, excluding acquisitions, to be approximately $875 million. By concentrating our capital on the highest return programs and operating at strong performance levels, we expect to generate higher company-wide

26

margins and cash flow growth while creating value for our stockholders. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our 2017 capital program.
Operational Activities. In our Midland Basin program, we operated seven drilling rigs, one of which focused on drilling data acquisition wells, as well as three completion crews during the second quarter of 2017. Of these seven drilling rigs, five were focused on delineating and developing the Lower and Middle Spraberry and Wolfcamp A and B shale intervals on our acreage position in Howard and Martin Counties, Texas, and the other two drilling rigs focused on developing the Wolfcamp A and B and Lower Spraberry shale intervals on our Sweetie Peck property in Upton County, Texas. We expect to maintain this rig and completion crew count through the end of 2017 and expect approximately 80 percent of our 2017 capital program to be dedicated to our Midland Basin program.
During the first half of 2017, we acquired approximately 3,400 net acres of primarily unproved properties in the Midland Basin in multiple transactions totaling $72.3 million of cash consideration. Additionally, we completed various acreage trades consisting primarily of unproved acreage of approximately 6,550 net acres in exchange for approximately 5,700 net acres in Howard and Martin Counties, Texas. These trades increased our working interest in existing drilling units and also provide us the opportunity to drill longer lateral wells.
In our Eagle Ford shale program, we continued running one drilling rig and one completion crew during the second quarter of 2017. We plan to add another drilling rig in the third quarter of 2017 and remain focused on drilling and completion optimization and meeting lease obligations. We expect approximately 20 percent of our 2017 capital program to be dedicated to our Eagle Ford shale program.
In our Powder River Basin program, we continued running one drilling rig during the second quarter of 2017 under an acquisition and development funding agreement with a third party, pursuant to which the third party is carrying our drilling and completion costs.
Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, totaled $258.0 million and $515.0 million for the three and six months ended June 30, 2017, respectively, and were incurred primarily in our Midland Basin and operated Eagle Ford shale programs. Of our total costs incurred for the three and six months ended June 30, 2017, $15.7 million and $77.0 million, respectively, related to property acquisitions, primarily unproved, in Howard and Martin Counties, Texas. Additionally, we completed several non-monetary acreage trades in the Midland Basin during the first half of 2017 totaling $279.8 million of value attributed to the properties surrendered. This non-monetary consideration is not reflected in the costs incurred amounts presented above.

Drilling and Completion Activity. 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, 2017:
 
Midland Basin
 
Eagle Ford Shale
 
Bakken/Three Forks
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells drilled but not completed at December 31, 2016
17

 
17

 
47

 
47

 
20

 
17

 
84

 
81

Wells drilled
19

 
19

 
5

 
5

 
—

 
—

 
24

 
24

Wells completed
(16
)
 
(16
)
 
(17
)
 
(17
)
 
—

 
—

 
(33
)
 
(33
)
Wells drilled but not completed at March 31, 2017
20

 
20

 
35

 
35

 
20

 
17

 
75

 
72

Wells drilled
24

 
23

 
6

 
6

 
—

 
—

 
30

 
29

Wells completed
(9
)
 
(9
)
 
(14
)
 
(14
)
 
—

 
—

 
(23
)
 
(23
)
Wells drilled but not completed at June 30, 2017
35

 
34

 
27

 
27

 
20

 
17

 
82

 
78



27

Production Results. The table below provides a regional breakdown of our production for the three and six months ended June 30, 2017:
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Total
 
Three Months Ended
Six Months Ended
 
Three Months Ended
Six Months Ended
 
Three Months Ended
Six Months Ended
 
Three Months Ended
Six Months Ended
Oil (MMBbl)
1.7

3.3

 
0.4

1.3

 
0.9

1.8

 
2.9

6.4

Gas (Bcf)
3.4

6.2

 
29.6

59.6

 
1.1

2.1

 
34.0

67.9

NGLs (MMBbl)
—

—

 
2.7

5.6

 
—

0.1

 
2.8

5.7

Equivalent (MMBOE)
2.3

4.4

 
8.0

16.8

 
1.1

2.3

 
11.3

23.4

Avg. daily equivalents (MBOE/d)
24.9

24.2

 
88.0

92.7

 
11.7

12.5

 
124.6

129.5

Relative percentage
20
%
19
%
 
71
%
71
%
 
9
%
10
%
 
100
%
100
%
____________________________________________
Note: Amounts may not calculate due to rounding.

Production on an equivalent basis decreased 21 percent and 15 percent for the three and six months ended June 30, 2017, compared with the same periods in 2016, primarily as a result of the divestitures of properties across our regions in the last half of 2016 and the first quarter of 2017, specifically our Raven/Bear Den and outside-operated Eagle Ford shale assets. Please refer to A Three-Month and Six-Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2017, and 2016 below for additional discussion on production.

Financial Results. In the second quarter of 2017, we had the following financial results:

•
We recorded a net loss of $119.9 million, or $1.08 per diluted share, for the three months ended June 30, 2017, compared with a net loss of $168.7 million, or $2.48 per diluted share, for the same period in 2016. The net loss for the three months ended June 30, 2017, was driven largely by the additional $166.9 million write-down recorded on our Divide County assets based on market conditions that existed when we decided to retain these assets, partially offset by a net derivative gain of $55.2 million. Please refer to Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2017, and 2016 below for additional discussion regarding the components of net loss for each period presented.

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We had net cash provided by operating activities of $107.1 million for the three months ended June 30, 2017, compared with $138.6 million for the same period in 2016. Please refer to Overview of Liquidity and Capital Resources below for additional discussion of our sources and uses of cash.

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Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended June 30, 2017, was $154.1 million, compared with $217.1 million for the same period in 2016. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net loss and net cash provided by operating activities to adjusted EBITDAX.