Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2016
Commission File Number 001-31539
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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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

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 27, 2016, the registrant had 68,466,823 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,
2016
 
December 31,
2015
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
18

 
$
18

Accounts receivable
143,979

 
134,124

Derivative asset
145,576

 
367,710

Prepaid expenses and other
14,901

 
17,137

Total current assets
304,474

 
518,989

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
7,249,808

 
7,606,405

Less - accumulated depletion, depreciation, and amortization
(3,606,829
)
 
(3,481,836
)
Unproved oil and gas properties
222,967

 
284,538

Wells in progress
415,973

 
387,432

Oil and gas properties held for sale, net
173,001

 
641

Other property and equipment, net of accumulated depreciation of $38,175 and $32,956, respectively
146,412

 
153,100

Total property and equipment, net
4,601,332

 
4,950,280

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
113,119

 
120,701

Other noncurrent assets
25,550

 
31,673

Total other noncurrent assets
138,669

 
152,374

Total Assets
$
5,044,475

 
$
5,621,643

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
257,349

 
$
302,517

Derivative liability
63,492

 
8

Total current liabilities
320,841

 
302,525

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
330,500

 
202,000

Senior Notes, net of unamortized deferred financing costs (note 5)
2,272,580

 
2,315,970

Asset retirement obligation
108,331

 
137,284

Asset retirement obligation associated with oil and gas properties held for sale
32,055

 
241

Net Profits Plan liability
9,476

 
7,611

Deferred income taxes
472,355

 
758,279

Derivative liability
104,660

 
—

Other noncurrent liabilities
44,841

 
45,332

Total noncurrent liabilities
3,374,798

 
3,466,717

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 68,274,551 and 68,075,700, respectively
683

 
681

Additional paid-in capital
321,841

 
305,607

Retained earnings
1,040,219

 
1,559,515

Accumulated other comprehensive loss
(13,907
)
 
(13,402
)
Total stockholders’ equity
1,348,836

 
1,852,401

Total Liabilities and Stockholders’ Equity
$
5,044,475

 
$
5,621,643

 
 
 
 
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,
 
2016
 
2015
 
2016
 
2015
Operating revenues:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
291,142


$
441,256


$
502,965


$
834,571

Net gain (loss) on divestiture activity (note 3)
50,046

 
71,884

 
(18,975
)
 
36,082

Other operating revenues
626

 
3,006

 
900

 
11,427

Total operating revenues and other income
341,814


516,146


484,890


882,080













Operating expenses:











Oil, gas, and NGL production expense
148,591

 
173,685


293,134


369,836

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
211,020

 
219,704


425,227


437,105

Exploration
13,187

 
25,541


28,460


62,948

Impairment of proved properties
—

 
12,914

 
269,785

 
68,440

Abandonment and impairment of unproved properties
38

 
5,819

 
2,349

 
17,446

General and administrative
28,200

 
42,605


60,438


86,244

Change in Net Profits Plan liability
3,125


(4,476
)

1,865


(8,810
)
Derivative (gain) loss
163,351

 
80,929


149,123


(73,238
)
Other operating expenses
4,851

 
10,304

 
11,783

 
27,423

Total operating expenses
572,363


567,025


1,242,164


987,394













Loss from operations
(230,549
)

(50,879
)

(757,274
)

(105,314
)












Non-operating income (expense):











Interest income
5

 
25

 
11

 
596

Interest expense
(34,035
)

(30,779
)

(65,123
)

(63,426
)
Gain (loss) on extinguishment of debt
—

 
(16,578
)
 
15,722

 
(16,578
)












Loss before income taxes
(264,579
)

(98,211
)

(806,664
)

(184,722
)
Income tax benefit
95,898

 
40,703


290,773


74,156













Net loss
$
(168,681
)

$
(57,508
)

$
(515,891
)

$
(110,566
)












Basic weighted-average common shares outstanding
68,102

 
67,483

 
68,090

 
67,473













Diluted weighted-average common shares outstanding
68,102

 
67,483

 
68,090

 
67,473













Basic net loss per common share
$
(2.48
)

$
(0.85
)

$
(7.58
)

$
(1.64
)












Diluted net loss per common share
$
(2.48
)

$
(0.85
)

$
(7.58
)

$
(1.64
)












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,
 
 
 
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
Net loss
$
(168,681
)
 
$
(57,508
)
 
$
(515,891
)
 
$
(110,566
)
Other comprehensive loss, net of tax:
 
 
 
 
 
 
 
Pension liability adjustment
(269
)
 
(576
)
 
(505
)
 
(752
)
Total other comprehensive loss, net of tax
(269
)
 
(576
)
 
(505
)
 
(752
)
Total comprehensive loss
$
(168,950
)
 
$
(58,084
)
 
$
(516,396
)
 
$
(111,318
)

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,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(515,891
)
 
$
(110,566
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Net (gain) loss on divestiture activity
18,975

 
(36,082
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
425,227

 
437,105

Exploratory dry hole expense
(24
)
 
22,896

Impairment of proved properties
269,785

 
68,440

Abandonment and impairment of unproved properties
2,349

 
17,446

Stock-based compensation expense
13,915

 
13,215

Change in Net Profits Plan liability
1,865

 
(8,810
)
Derivative (gain) loss
149,123

 
(73,238
)
Derivative settlement gain
248,738

 
274,024

Amortization of deferred financing costs
1,930

 
3,892

Non-cash (gain) loss on extinguishment of debt, net
(15,722
)
 
4,123

Deferred income taxes
(291,014
)
 
(84,556
)
Plugging and abandonment
(2,716
)
 
(3,386
)
Other, net
676

 
(434
)
Changes in current assets and liabilities:
 
 
 
Accounts receivable
(11,220
)
 
38,951

Prepaid expenses and other
8,487

 
2,933

Accounts payable and accrued expenses
(61,727
)
 
(34,040
)
Accrued derivative settlements
14,117

 
17,595

Net cash provided by operating activities
256,873

 
549,508

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
12,967

 
334,988

Capital expenditures
(345,570
)
 
(974,130
)
Acquisition of proved and unproved oil and gas properties
(17,751
)
 
(6,588
)
Other, net
(900
)
 
(996
)
Net cash used in investing activities
(351,254
)
 
(646,726
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
585,000

 
1,230,500

Repayment of credit facility
(456,500
)
 
(1,274,500
)
Debt issuance costs related to credit facility
(3,132
)
 
—

Net proceeds from Senior Notes
—

 
491,557

Cash paid to repurchase Senior Notes
(29,904
)
 
(350,000
)
Proceeds from sale of common stock
2,354

 
3,157

Dividends paid
(3,404
)
 
(3,373
)
Other, net
(33
)
 
(161
)
Net cash provided by financing activities
94,381

 
97,180

 
 
 
 
Net change in cash and cash equivalents
—

 
(38
)
Cash and cash equivalents at beginning of period
18

 
120

Cash and cash equivalents at end of period
$
18

 
$
82

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)

Supplemental schedule of additional cash flow information and non-cash activities:
 
For the Six Months Ended June 30,
 
2016
 
2015
 
(in thousands)
Cash paid for interest, net of capitalized interest
$
63,590

 
$
64,899

 
 
 
 
Net cash (refunded) paid for income taxes
$
(4,564
)
 
$
380


As of June 30, 2016, and 2015, $106.7 million and $164.9 million, respectively, of accrued capital expenditures were included in accounts payable and accrued expenses in the Company’s condensed consolidated balance sheets. These oil and gas property additions are reflected in net cash used in investing activities in the periods during which the payables are settled.

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 - The Company and Business

SM Energy Company (“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, 2015 (the “2015 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, 2016, through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current period 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 to the Company’s consolidated financial statements in its 2015 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 2015 Form 10-K.

Recently Issued Accounting Standards

Effective January 1, 2016, the Company adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU clarifies the consolidation reporting guidance in GAAP. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which changes the accounting for leases. This guidance is to be applied using a modified retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) for the recognition of revenue from contracts with customers. Subsequent to the issuance of this ASU, the FASB has issued additional related ASUs as follows:

•
In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. This ASU deferred the effective date of ASU 2014-09 by one year.
•
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09.
•
In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09.

8

•
In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.

ASU 2014-09 and each update have the same effective date and transition requirements. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the level of effort needed to implement the standards, evaluating the provisions of each of these standards, and assessing their impact on the Company’s financial statements and disclosures, as well as determining whether to use the full retrospective method or the modified retrospective method.

In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU makes targeted amendments to the accounting for employee share-based payments. This guidance is to be applied using various transition methods, such as full retrospective, modified retrospective, and prospective, based on the criteria for the specific amendments as outlined in the guidance. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted, as long as all of the amendments are adopted in the same period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

Other than as disclosed above or in the 2015 Form 10-K, there are no other accounting standards 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, 2016, and through the filing date of this report.

Note 3 – Assets Held for Sale and Divestitures
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. Any subsequent changes to the fair value less estimated costs to sell impact the measurement of assets held for sale with any gain or loss 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, 2016, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $173.0 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consists of certain non-core assets in each of the Company’s operating regions. A corresponding aggregate asset retirement obligation liability of $32.1 million is separately presented. Certain of these assets were written down by $68.3 million to reflect fair value less estimated costs to sell upon reclassification to assets held for sale, as of March 31, 2016. During the second quarter of 2016, the Company estimated an increase in the fair value of certain previously impaired assets held for sale due to an increase in estimated selling prices, as evidenced by recent bid prices received from third parties, resulting in a $49.5 million gain recorded for the three months ended June 30, 2016. The Company expects to close the asset sale transactions prior to December 31, 2016. There were no material assets held for sale as of December 31, 2015.

Subsequent to June 30, 2016, the Company entered into separate purchase and sale agreements for the sale of certain of its Permian and Rocky Mountain assets that were classified as held for sale as of June 30, 2016. The Company expects to close these transactions prior to December 31, 2016. The closings of these transactions are subject to the satisfaction of customary closing conditions, and there can be no assurance that these transactions will close on the expected closing dates or at all.

Divestitures

During the second quarter of 2015, the Company divested its Mid-Continent assets in separate packages for total cash proceeds received at closing of $316.5 million and recorded an estimated net gain of $107.8 million for the six months ended June 30, 2015. These assets were classified as held for sale as of March 31, 2015, and certain of these assets were written down by $30.0 million during the three months ended March 31, 2015, to reflect their fair value less estimated costs to sell. This write-down is reflected in the total net gain of $107.8 million discussed above. In conjunction with this divestiture, the Company closed its Tulsa, Oklahoma office in 2015 and incurred $5.0 million and $8.5 million of exit and disposal costs for the three and six months ended

9

June 30, 2015, respectively. Offsetting the net gain recorded on the divestiture of the Company’s Mid-Continent assets were write-downs recorded during the three months ended June 30, 2015, on certain other assets held for sale totaling $66.0 million.

The Company determined that neither these planned nor executed asset sales qualified for discontinued operations accounting under financial statement presentation authoritative guidance.

Note 4 - Income Taxes

The income tax benefit recorded for the three and six months ended June 30, 2016, and 2015, 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, research and development (“R&D”) credits, and other permanent differences. The quarterly rate can also be affected by the proportional effects of forecasted net income or loss as of each period end presented.

The provision for income taxes consists of the following:

 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Current portion of income tax expense (benefit):
 
 
 
 
 
 
 
Federal
$
—

 
$
—

 
$
—

 
$
—

State
77

 
10,126

 
241

 
10,400

Deferred portion of income tax benefit
(95,975
)
 
(50,829
)
 
(291,014
)
 
(84,556
)
Total income tax benefit
$
(95,898
)
 
$
(40,703
)
 
$
(290,773
)
 
$
(74,156
)
Effective tax rate
36.2
%
 
41.4
%
 
36.0
%
 
40.1
%

On a year-to-date basis, a change in the Company’s effective tax rate between reported periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income or loss from various state tax jurisdictions. Cumulative effects of state rate changes are reflected in the period legislation is enacted.

The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2012. During the first quarter of 2016, the Company received an expected $4.9 million refund of tax and interest after the Company and the Internal Revenue Service (“IRS”) reached a final agreement on the examination of the Company’s 2007 - 2011 tax years. There were no material adjustments to previously reported amounts. During the quarter ended September 30, 2015, the IRS initiated an audit of the tax partnership between the Company and Mitsui E&P Texas LP for the 2013 tax year. The Company has a significant investment in the underlying assets of this tax partnership. The Company received notice during the first quarter of 2016 that the IRS concluded the audit with no adjustments.

Note 5 - Long-Term Debt

Revolving Credit Facility

On April 8, 2016, the Company entered into a Sixth Amendment to the Fifth Amended and Restated Credit Agreement (the “Credit Agreement” and as amended, the “Amended Credit Agreement”) with its lenders. The Company incurred approximately $3.1 million in deferred financing costs associated with the amendment of this credit facility. The Amended Credit Agreement provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019. Pursuant to the amendment, and as part of the regular, semi-annual borrowing base redetermination process, the Company’s borrowing base was reduced to $1.25 billion. This expected reduction was primarily due to the decline in commodity prices, which had resulted in a decrease in the Company’s proved reserves as of December 31, 2015. The next scheduled redetermination date is October 1, 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. The amendment also reduced the aggregate lender commitments to $1.25 billion, and changed the required percentage of oil and gas properties subject to a mortgage 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. Further, the amendment revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below.
 

10

The Company must comply with certain financial and non-financial covenants under the terms of the Amended Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Amended Credit Agreement. Financial covenants under the Amended 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 Amended Credit Agreement as of June 30, 2016, and through the filing date of this report.

Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Amended Credit Agreement.  Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at prime plus the applicable margin from the utilization table below.  Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. Effective as of April 8, 2016, the revised borrowing base utilization grid under the Amended Credit Agreement is as follows:

Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage
 
<25%
 
≥25% <50%
 
≥50% <75%
 
≥75% <90%
 
≥90%
Eurodollar Loans
 
1.750
%
 
2.000
%
 
2.250
%
 
2.500
%
 
2.750
%
ABR Loans or Swingline Loans
 
0.750
%
 
1.000
%
 
1.250
%
 
1.500
%
 
1.750
%
Commitment Fee Rate
 
0.300
%
 
0.300
%
 
0.350
%
 
0.375
%
 
0.375
%

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Amended Credit Agreement as of July 27, 2016, and June 30, 2016, and under the Credit Agreement as of December 31, 2015:

 
As of July 27, 2016
 
As of June 30, 2016
 
As of December 31, 2015
 
(in thousands)
Credit facility balance (1)
$
330,000

 
$
330,500

 
$
202,000

Letters of credit (2)
$
200

 
$
200

 
$
200

Available borrowing capacity
$
919,800

 
$
919,300

 
$
1,297,800

____________________________________________
(1) Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance.
(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

11

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, and 5.625% Senior Notes due 2025 (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, 2016, and December 31, 2015, consisted of the following:

 
As of June 30, 2016
 
As of December 31, 2015
 
Senior Notes
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
Senior Notes
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
(in thousands)
6.50% Senior Notes due 2021
$
346,955

 
$
3,721

 
$
343,234

 
$
350,000

 
$
4,106

 
$
345,894

6.125% Senior Notes due 2022
561,796

 
7,569

 
554,227

 
600,000

 
8,714

 
591,286

6.50% Senior Notes due 2023
394,985

 
4,801

 
390,184

 
400,000

 
5,231

 
394,769

5.0% Senior Notes due 2024
500,000

 
6,994

 
493,006

 
500,000

 
7,455

 
492,545

5.625% Senior Notes due 2025
500,000

 
8,071

 
491,929

 
500,000

 
8,524

 
491,476

Total
$
2,303,736

 
$
31,156

 
$
2,272,580

 
$
2,350,000

 
$
34,030

 
$
2,315,970


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 that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; however, the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company was in compliance with all covenants under its Senior Notes as of June 30, 2016, and through the filing date 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.

During the first quarter of 2016, the Company repurchased in open market transactions a total of $46.3 million in aggregate principal amount of its 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023 for a settlement amount of $29.9 million, excluding interest. Of the $29.9 million settlement amount, $10.0 million related to purchases during the first quarter of 2016, in which the related cash settlement occurred during the three months ended June 30, 2016. 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 $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $700,000 related to the acceleration of unamortized deferred financing costs. The Company accounted for the repurchases under the extinguishment method of accounting. The Company canceled all repurchased notes upon cash settlement.

Note 6 - Commitments and Contingencies

Commitments

There were no material changes in commitments during the first half of 2016, except as discussed below. Please refer to Note 6 - Commitments and Contingencies in the Company’s 2015 Form 10-K for additional discussion.

During the second quarter of 2016, the Company entered into a water disposal agreement. Under the agreement, the Company is committed to deliver 25.4 MMBbl of water for treatment through 2026. In the event that the Company does not deliver any volumes under this agreement, the Company’s aggregate undiscounted deficiency payments would be approximately $23.0 million. This commitment will not be effective until the counterparty constructs and places the associated pipeline into operation, which is expected to be by the end of 2016.


12

During the first half of 2016, the Company renegotiated the terms of certain drilling rig contracts to provide flexibility concerning the timing of activity and payment. For the three and six months ended June 30, 2016, the Company incurred $2.6 million and $7.6 million, respectively, of expense related to the early termination of drilling rig contracts or fees incurred for rigs placed on standby, which are recorded in the other operating expenses line item in the accompanying statements of operations. For the three and six months ended June 30, 2015, the Company incurred drilling rig termination fees of $2.7 million and $5.9 million, respectively.

During the first quarter of 2016, the Company entered into amendments to certain oil gathering and gas gathering agreements related to its outside-operated Eagle Ford shale assets, neither of which previously had a minimum volume commitment, in order to obtain more favorable rates and terms. Under these amended agreements, as of June 30, 2016, the Company is now committed to deliver 296 Bcf of natural gas and 39 MMBbl of oil through 2034. In the event that the Company delivers no product under these amended agreements, the Company’s aggregate undiscounted deficiency payments would be approximately $342.0 million at June 30, 2016; however, because of the Company’s partial ownership interest in the gathering systems used to provide the services under these agreements, the Company is entitled to receive its share of operating income generated by the systems, and thus would expect to receive approximately $241.4 million if the $342.0 million shortfall payment was required.

During the first quarter of 2016, the Company entered into an amendment to a gas gathering agreement related to its operated Eagle Ford shale assets, which reduced the Company’s volume commitment amount as of December 31, 2015, by 829 Bcf, and reduced the aggregate undiscounted deficiency payments, in the event no product is delivered, by $118.2 million through 2021.

As of June 30, 2016, the Company had total gas, oil, and NGL gathering, processing, and transportation throughput commitments with various third parties that require delivery of a minimum amount of 1,590 Bcf of natural gas, 72 MMBbl of crude oil, and 14 MMBbl of natural gas liquids through 2034. If the Company delivers no product, the aggregate undiscounted deficiency payments total approximately $1.0 billion through 2034, prior to considering the $241.4 million of operating income the Company would expect to receive if certain payments were required as discussed above.

As of the filing date of this report, the Company does not expect to incur any material shortfalls with regard to its gas, oil, and NGL gathering, processing, and transportation throughput 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 expected results of any pending litigation and claims will not have a material effect on the results of operations, the financial position, or the cash flows of the Company.

The Company is subject to routine severance, royalty and joint interest audits from regulatory authorities, non-operators and others, as the case may be, and records accruals for estimated exposure when a claim is deemed probable and the amount can be reasonably estimated. Additionally, the Company is subject to various possible contingencies that arise from third party interpretations of the Company’s contracts or otherwise affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices that royalty owners are paid for production from their leases, allowable costs under joint interest arrangements, and other matters. As of June 30, 2016, the Company had $4.4 million accrued for estimated exposure related to potential claims for payment of royalties on certain Federal and Indian oil and gas leases. Although the Company believes that it has properly estimated its potential exposure with respect to these claims based on various contracts, laws and regulations, administrative rulings, and interpretations thereof, adjustments could be required as new interpretations and regulations arise.


13

Note 7 - Compensation Plans

Equity Incentive Compensation Plan

As of June 30, 2016, 6.2 million shares of common stock remained available for grant under the Equity Incentive Compensation Plan.

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 the 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, 2016, and 2015, was $3.0 million and $2.7 million, respectively, and $5.9 million and $5.0 million for the six months ended June 30, 2016, and 2015, respectively. As of June 30, 2016, there was $12.3 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2018. There were no material changes to the outstanding and non-vested PSUs during the six months ended June 30, 2016.

Subsequent to June 30, 2016, as part of its regular annual long-term equity compensation program, the Company granted 447,971 PSUs with a fair value of $11.9 million. These PSUs will fully vest on the third anniversary of the date of the grant. Also, subsequent to June 30, 2016, the Company settled PSUs that were granted in 2013, which earned a 0.2 times multiplier, by issuing a net 30,061 shares of the Company’s common stock in accordance with the terms of the respective PSU awards. 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, 14,809 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs.

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 award.

Total compensation expense recorded for RSUs was $3.3 million and $2.9 million for the three months ended June 30, 2016, and 2015, respectively, and $6.5 million and $5.8 million for the six months ended June 30, 2016, and 2015, respectively. As of June 30, 2016, there was $12.0 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2018. There were no material changes to the outstanding and non-vested RSUs during the six months ended June 30, 2016.

Subsequent to June 30, 2016, as part of its regular annual long-term equity compensation program, the Company granted 417,065 RSUs with a fair value of $11.7 million. These RSUs will vest one-third of the total grant on each of the next three anniversary dates of the grant. Also, subsequent to June 30, 2016, the Company settled 232,258 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 162,211 net shares of common stock. The remaining 70,047 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 first half of 2016 and 2015, the Company issued 53,473 and 37,950 shares, respectively, of its common stock to its non-employee directors, under the Company’s Equity Incentive Compensation Plan and recorded $517,000 and $1.2 million, respectively, of compensation expense.


14

Beginning with 2016, all shares issued to non-employee directors fully vest on December 31st of the year granted.

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 the first or last day of the purchase period, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code (“IRC”). The Company had 808,854 shares available for issuance under the ESPP as of June 30, 2016. There were 140,853 and 96,285 shares issued under the ESPP during the second quarters of 2016, and 2015, 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, 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,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Service cost
$
2,113

 
$
2,390

 
$
4,100

 
$
3,974

Interest cost
830

 
700

 
1,454

 
1,248

Expected return on plan assets that reduces periodic pension cost
(573
)
 
(597
)
 
(1,118
)
 
(1,091
)
Amortization of prior service cost
5

 
5

 
9

 
9

Amortization of net actuarial loss
419

 
571

 
791

 
743

Net periodic benefit cost
$
2,794

 
$
3,069

 
$
5,236

 
$
4,883


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 and the market-related value of assets are amortized over the average remaining service period of active participants.

Contributions

The Company contributed $6.0 million to the Pension Plans during the six months ended June 30, 2016.

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 common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs and contingent PSUs. The treasury stock method is used to measure the dilutive impact of these stock awards.


15

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 subsequent to June 30, 2016, as part of the Company’s regular annual long-term equity compensation program, in addition to the net RSUs and PSUs settled.

When the Company recognizes a loss from continuing operations, as was the case for the three and six months ended June 30, 2016, and 2015, 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 related to RSUs and PSUs for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Anti-dilutive
155

 
590

 
70

 
490


The following table sets forth the calculations of basic and diluted earnings per share:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except per share amounts)
Net loss
$
(168,681
)
 
$
(57,508
)
 
$
(515,891
)
 
$
(110,566
)
Basic weighted-average common shares outstanding
68,102

 
67,483

 
68,090

 
67,473

Add: dilutive effect of unvested RSUs and contingent PSUs
—

 
—

 
—

 
—

Diluted weighted-average common shares outstanding
68,102

 
67,483

 
68,090

 
67,473

Basic net loss per common share
$
(2.48
)
 
$
(0.85
)
 
$
(7.58
)
 
$
(1.64
)
Diluted net loss per common share
$
(2.48
)
 
$
(0.85
)
 
$
(7.58
)
 
$
(1.64
)

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. All contracts are entered into for other-than-trading purposes. The Company’s derivative contracts consist of swap and collar arrangements for oil, gas, and NGLs. 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, 2016, the Company had commodity derivative contracts outstanding through the second quarter of 2020 as summarized in the tables below. During the three months ended March 31, 2016, the Company restructured certain of its 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 cash or other consideration was included as part of the restructuring.

Subsequent to June 30, 2016, the Company entered into derivative fixed price swap contracts through the first quarter of 2018 for a total of 15.6 million MMBtu of gas production at contract prices ranging from $2.90 to $3.24 per MMBtu, and derivative fixed price swap contracts through the fourth quarter of 2018 for 1.4 million Bbls of NGL production at contract prices ranging from

16

$21.32 per Bbl to $21.79 per Bbl. Additionally, subsequent to June 30, 2016, the Company entered into a derivative collar contract through the fourth quarter of 2017 for a total of 1.4 million Bbls of crude oil production with a contract floor price of $45.00 per Bbl and a contract ceiling price of $56.25 per Bbl.

The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of June 30, 2016:

Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(MBbls)
 
(per Bbl)
Third quarter 2016
 
1,840

 
$
71.80

Fourth quarter 2016
 
1,399

 
$
67.73

2017
 
3,053

 
$
45.61

All oil swaps
 
6,292

 
 

Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(MBbls)
 
(per Bbl)
 
(per Bbl)
Third quarter 2016
 
672

 
$
40.00

 
$
51.57

Fourth quarter 2016
 
881

 
$
40.00

 
$
51.52

2017
 
1,018

 
$
45.00

 
$
51.02

All oil collars
 
2,571

 
 
 
 

Natural Gas Swaps
Contract Period
 
Sold
Volumes
 
Weighted-Average
 Contract Price
 
Purchased Volumes
 
Weighted- Average Contract Price
 
Net
Volumes
 
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
Third quarter 2016
 
25,724

 
$
3.13

 
—

 
$
—

 
25,724

Fourth quarter 2016
 
26,700

 
$
3.34

 
—

 
$
—

 
26,700

2017
 
88,894

 
$
4.04

 
—

 
$
—

 
88,894

2018
 
53,048

 
$
3.75

 
(30,606
)
 
$
4.27

 
22,442

2019
 
24,415

 
$
4.34

 
(24,415
)
 
$
4.34

 
—

All gas swaps*
 
218,781

 
 
 
(55,021
)
 
 
 
163,760

*Total net volumes of natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (97%), and IF NNG Ventura (1%).


17

NGL Swaps
 
 
OPIS Purity Ethane Mont Belvieu
 
OPIS Propane Mont Belvieu Non-TET
 
OPIS Normal Butane Mont Belvieu Non-TET
 
OPS Isobutane 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
 
 
(MBbls)
(per Bbl)
 
(MBbls)
(per Bbl)
 
(MBbls)
(per Bbl)
 
(MBbls)
(per Bbl)
Third quarter 2016
 
751

$
8.70

 
863

$
19.03

 
248

$
22.90

 
200

$
23.24

Fourth quarter 2016
 
687

$
8.71

 
792

$
18.53

 
226

$
22.91

 
182

$
23.25

2017
 
3,062

$
8.92

 
721

$
20.01

 
—

$
—

 
—

$
—

2018
 
2,435

$
10.18

 
—

$
—

 
—

$
—

 
—

$
—

2019
 
1,200

$
10.92

 
—

$
—

 
—

$
—

 
—

$
—

2020
 
539

$
11.13

 
—

$
—

 
—

$
—

 
—

$
—

Total NGL swaps
 
8,674

 
 
2,376

 
 
474

 
 
382

 

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 $90.5 million as of June 30, 2016, and a net asset of $488.4 million as of December 31, 2015.

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:

 
As of June 30, 2016
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
145,576

 
Current liabilities
 
$
63,492

Commodity contracts
Noncurrent assets
 
113,119

 
Noncurrent liabilities
 
104,660

Derivatives not designated as hedging instruments
 
 
$
258,695

 
 
 
$
168,152


 
As of December 31, 2015
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
367,710

 
Current liabilities
 
$
8

Commodity contracts
Noncurrent assets
 
120,701

 
Noncurrent liabilities
 
—

Derivatives not designated as hedging instruments
 
 
$
488,411

 
 
 
$
8


Offsetting of Derivative Assets and Liabilities

As of June 30, 2016, and December 31, 2015, 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.  


18

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, 2016
 
December 31, 2015
 
June 30, 2016
 
December 31, 2015
 
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
 
$
258,695

 
$
488,411

 
$
(168,152
)
 
$
(8
)
Amounts not offset in the accompanying balance sheets
 
(158,955
)
 
(8
)
 
158,955

 
8

Net amounts
 
$
99,740

 
$
488,403

 
$
(9,197
)
 
$
—

    
The following table summarizes the components of the derivative (gain) loss presented in the accompanying statements of operations:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Derivative settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
(72,164
)
 
$
(73,915
)
 
$
(172,156
)
 
$
(180,129
)
Gas contracts (1)
(31,439
)
 
(38,880
)
 
(72,492
)
 
(73,112
)
NGL contracts
1,893

 
—

 
(4,090
)
 
(20,783
)
Total derivative settlement (gain) loss
$
(101,710
)

$
(112,795
)

$
(248,738
)

$
(274,024
)
 
 
 
 
 
 
 
 
Total derivative (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
60,773

 
$
66,749

 
$
50,341

 
$
(7,111
)
Gas contracts
62,489

 
6,070

 
38,466

 
(76,269
)
NGL contracts
40,089

 
8,110

 
60,316

 
10,142

Total derivative (gain) loss:
$
163,351


$
80,929


$
149,123


$
(73,238
)
____________________________________________
(1)  
Natural gas derivative settlements for the three and six months ended June 30, 2015, include a $15.3 million gain on the early settlement of future contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015.

Credit Related Contingent Features

As of June 30, 2016, and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. The Amended Credit Agreement, as discussed above, changed the required percentage of oil and gas properties subject to a mortgage 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.


19

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, 2016:



Level 1

Level 2

Level 3

(in thousands)
Assets:








Derivatives (1)
$
—


$
258,695


$
—

Total property and equipment, net (2)
$
—


$
—


$
99,944

Liabilities:








Derivatives (1)
$
—


$
168,152


$
—

Net Profits Plan (1)
$
—


$
—


$
9,476

____________________________________________
(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.

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, 2015:

 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$
—

 
$
488,411

 
$
—

Total property and equipment, net (2)
$
—

 
$
—

 
$
124,813

Liabilities:
 
 
 
 
 
Derivatives (1)
$
—

 
$
8

 
$
—

Net Profits Plan (1)
$
—

 
$
—

 
$
7,611

____________________________________________
(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.


20

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.

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. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group.

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.

Net Profits Plan

The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability.

The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. A discount rate of 10 percent was used to calculate this liability, and is intended to represent the Company’s best estimate of the present value of expected future payments under the Net Profits Plan.

The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. The Company regularly assesses the current market environment.  The Net Profits Plan liability is determined using price assumptions of five one-year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivative contracts in the relevant periods.  The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets.

If the commodity prices used in the calculation changed by five percent, the liability recorded at June 30, 2016, would differ by approximately $1.5 million. A one percent increase or decrease in the discount rate would result in a change of approximately $400,000. Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated.


21

No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates.
    
The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs:
 
For the Six Months Ended June 30, 2016
 
(in thousands)
Beginning balance
$
7,611

Net increase in liability (1)
4,042

Net settlements (1) (2)
(2,177
)
Transfers in (out) of Level 3
—

Ending balance
$
9,476


____________________________________________
(1) 
Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.
(2) 
Settlements represent cash payments made or accrued under the Net Profits Plan.

Long-Term Debt
The following table reflects the fair value of the Senior Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of June 30, 2016, or December 31, 2015, as they were recorded at carrying value, net of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt for discussion of the Company’s repurchase of a portion of its Senior Notes during the first quarter of 2016.

 
As of June 30, 2016
 
As of December 31, 2015
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
(in thousands)
6.50% Senior Notes due 2021
$
346,955

 
$
328,091

 
$
350,000

 
$
262,938

6.125% Senior Notes due 2022
561,796

 
516,852

 
600,000

 
440,250

6.50% Senior Notes due 2023
394,985

 
366,349

 
400,000

 
296,000

5.0% Senior Notes due 2024
500,000

 
426,875

 
500,000

 
334,065

5.625% Senior Notes due 2025
500,000

 
433,125

 
500,000

 
326,875

Total Senior Notes
$
2,303,736

 
$
2,071,292

 
$
2,350,000

 
$
1,660,128


The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.

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

Total property and equipment, net, measured at fair value within the accompanying balance sheets totaled $99.9 million and $124.8 million as of June 30, 2016, and December 31, 2015, respectively.
    
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 were estimated to be 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of June 30, 2016, and December 31, 2015. The Company believes the discount rates are representative of current market conditions and take into account 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

22

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 impairment on proved properties during the three months ended June 30, 2016. For the six months ended June 30, 2016, the Company recorded impairment of proved properties expense of $269.8 million due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows for the Company’s outside-operated Eagle Ford assets, driven by commodity price declines during the first quarter of 2016. The Company recorded impairment of proved oil and gas properties expense of $468.7 million for the year ended December 31, 2015, due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows, driven by commodity price declines. Impairments were recorded mainly in the Company’s east Texas and Powder River Basin programs with smaller impacts on other legacy and non-core assets in the Rocky Mountain region.
 
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: future development plans, risk weighted potential resource recovery, and estimated reserve values. The Company recorded $38,000 and $2.3 million abandonment and impairment expense on unproved properties for the three and six months ended June 30, 2016, respectively, and $78.6 million for the year ended December 31, 2015. In all periods discussed, the abandonment and impairment expense resulted from lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the decline in commodity prices.

Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. Fair value of other property and equipment is valued using an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. The Company recorded impairment of other property and equipment expense of $49.4 million for the year ended December 31, 2015, on the Company’s gathering system assets in east Texas. These assets were impaired in conjunction with the impairment of the associated proved and unproved properties, which the Company does not intend to develop during an environment of sustained low commodity prices.

Proved properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated 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 income valuation technique discussed above. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company estimates acreage value based on the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. As of June 30, 2016, certain assets held for sale are recorded at fair value totaling $99.9 million less estimated selling costs. Certain of these assets were written down during the first quarter of 2016. A subsequent increase in estimated selling prices, as evidenced by recent bid prices received from third parties, resulted in a $49.5 million gain recorded for the three months ended June 30, 2016. Please refer to Note 3 – Assets Held for Sale and Divestitures. There were no assets held for sale recorded at fair value as of December 31, 2015.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.


23

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This management’s discussion and analysis contains forward-looking statements. Refer to Cautionary Information About Forward-Looking Statements at the end of this item for an explanation of 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 profitably build our ownership and operatorship of North American oil, gas, and NGL producing assets that have high operating margins and significant opportunities for additional economic investment. We pursue growth opportunities through both exploration and acquisitions, and we seek to maximize the value of our assets through industry leading technology application and outstanding operational execution. We focus on achieving high full-cycle economic returns on our investments and maintaining a simple, strong balance sheet through a conservative approach to leverage.

We currently focus our capital investments on our development positions in the Eagle Ford shale, Bakken/Three Forks, and Permian Basin resource plays. We also have a delineation and exploration program in the Powder River Basin.

In the second quarter of 2016, we had the following financial and operational results:

•
Average net daily production for the three months ended June 30, 2016, was 45.1 MBbls of oil, 428.2 MMcf of gas, and 40.8 MBbls of NGLs, for a quarterly equivalent daily production rate of 157.2 MBOE, compared with 181.0 MBOE for the same period in 2015. Please see additional discussion below under Production Results.

•
We recorded a net loss of $168.7 million, or $2.48 per diluted share, for the three months ended June 30, 2016, compared with a net loss of $57.5 million, or $0.85 per diluted share, for the three months ended June 30, 2015. Please refer to Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2016, and 2015, below for additional discussion regarding the components of net loss for each period.
 
•
Costs incurred for oil and gas property acquisitions, exploration and development activities for the three months ended June 30, 2016, totaled $177.3 million, compared with $354.0 million for the same period in 2015. Please refer to Costs Incurred in Oil and Gas Producing Activities below for additional discussion.

•
Net cash provided by operating activities for the three months ended June 30, 2016, totaled $138.6 million, compared with $265.6 million for the same period in 2015.

•
Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended June 30, 2016, was $217.1 million, compared with $337.3 million for the same period in 2015. 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.

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. We sell the majority of our gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced.  For assets where high BTU gas is sold at the wellhead, we also receive additional value for the higher energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials. Our oil is sold using the calendar month average of the NYMEX WTI daily contract settlement prices, excluding weekends, during the month of production, adjusted for quality, transportation, American Petroleum Institute (“API”) gravity, and location differentials. 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.


24

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the first and second quarters of 2016, as well as the second quarter of 2015:

 
For the Three Months Ended
 
June 30, 2016
 
March 31, 2016
 
June 30, 2015
Crude Oil (per Bbl):
 
 
 
 
 
Average NYMEX contract monthly price
$
45.59

 
$
33.41

 
$
57.85

Realized price, before the effect of derivative settlements
$
39.38

 
$
25.67

 
$
51.45

Oil derivative settlement gain
$
17.59

 
$
24.27

 
$
14.53

 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Average NYMEX monthly settle price (per MMBtu)
$
1.95

 
$
1.96

 
$
2.73

Realized price, before the effect of derivative settlements (per Mcf)
$
1.79

 
$
1.87

 
$
2.53

Natural gas derivative settlement gain (per Mcf) (1)
$
0.81

 
$
1.15

 
$
0.88

 
 
 
 
 
 
NGLs (per Bbl): 
 
 
 
 
 
Average OPIS price (2)
$
20.04

 
$
15.99

 
$
20.79

Realized price, before the effect of derivative settlements
$
16.12

 
$
11.76

 
$
16.85

NGL derivative settlement (loss) gain
$
(0.51
)
 
$
1.78

 
$
—

____________________________________________
(1)  
Natural gas derivative settlements for the three months ended June 30, 2015, include a $15.3 million gain on the early settlement of future contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015, increasing the effect of derivative settlements by $0.35 per Mcf.
(2)  
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.

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. 

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.  Due to short-term supply reductions and disruptions, crude oil prices gained strength during the second quarter of 2016. However, as those temporary disruptions are rectified, we expect supply to increase back to prior levels while demand for oil and oil products is expected to continue to slow during the remainder of 2016 and remain the main source of uncertainty for future prices. Although the United States is now leading production declines, declines elsewhere in the world are required to balance the market.

Supply for natural gas continued to exceed demand during the second quarter of 2016; however, demand growth from gas fired power generation and exports exceeded expectations causing an uplift in prices late in the second quarter of 2016. We expect prices to continue to recover due to decreased supply from associated oil drilling and ethane recovery, and from 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 recovered in recent months due to oil and natural gas price recovery and we expect continued recovery through 2017 as increased demand from export and petrochemical markets grow. We expect that world-scale ethane crackers currently under construction will come online at the end of the year, increasing demand for propane and ethane as feedstock.

As commodity prices have seen some recovery in the second quarter of 2016, the rig count has slightly increased. Overall, we expect commodity prices to fluctuate but remain near current levels through the remainder of 2016, and we expect prices to increase in 2017 due to reduction in supply and demand increases across all commodities.


25

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 27, 2016, and June 30, 2016:

 
As of July 27, 2016
 
As of June 30, 2016
NYMEX WTI oil (per Bbl)
$
45.07

 
$
50.83

NYMEX Henry Hub gas (per MMBtu)
$
3.02

 
$
3.14

OPIS NGLs (per Bbl)
$
20.48

 
$
22.73


Derivative Activity
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 and gas prices while also setting a price floor for a portion of our 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 2016 Highlights and Outlook for the Remainder of 2016
Operational Activities. Our goal during 2016 is to maintain a strong balance sheet and preserve liquidity in the current commodity price environment while improving our portfolio and holding our quality acreage positions. We expect to incur capital expenditures below adjusted EBITDAX in order to minimize any impact to our total debt. We believe this focus on our liquidity will best preserve our balance sheet and will give us the flexibility to adapt as industry conditions change.
We expect our capital program for 2016 to be approximately $670 million, of which we plan to invest approximately 85 percent in drilling and completion activities with the focus on our core development programs in the Bakken/Three Forks, Permian Basin, and Eagle Ford shale. Our capital expenditure guidance was reduced from the approximate $705 million previously announced, as lower drilling and completion costs and realized efficiencies have contributed to overall capital cost savings. We plan to continue our focus on conducting safe operations even as we pursue cost saving measures throughout our business.
In our operated Eagle Ford shale program, we began the second quarter of 2016 with one active, operated drilling rig. We expect to drop this rig during the third quarter of 2016, and plan to utilize one frac crew through the third quarter of 2016. In 2016, our capital is primarily being spent on wells that were drilled but uncompleted at year-end 2015 and to meet lease obligations. As of June 30, 2016, in our operated Eagle Ford program, we had drilled but not completed 78 gross and net wells. We drilled 13 gross and net wells during the first half of 2016.
In our outside-operated Eagle Ford shale program, the operator has further slowed its pace of development in 2016. We do not expect any additional drilling or completion activity in 2016.
In our Bakken/Three Forks program, we began the second quarter of 2016 with two active, operated drilling rigs. We dropped one drilling rig during the second quarter of 2016, and expect to run the remaining drilling rig for the remainder of 2016. As of June 30, 2016, in our operated Bakken/Three Forks program, we had drilled but not completed 40 gross wells (35 net). We drilled 15 gross wells (13 net) during the first half of 2016.
In our Permian Basin development program, we began the second quarter of 2016 with one operated drilling rig and increased to two drilling rigs during the second quarter of 2016. We are focused on developing the Wolfcamp and Spraberry shale intervals on our Sweetie Peck property in Upton County, Texas. As of June 30, 2016, in our Permian program, we had drilled but not completed eight gross and net wells. We drilled 11 gross and net wells during the first half of 2016.
We have curtailed activity in our delineation and exploration programs to focus our capital spending on our highest return development programs and to meet acreage-holding commitments in our core plays. We dropped our last operated drilling rig in our Powder River Basin program during the first quarter of 2016.

26

We will continue to evaluate our drilling and completion activities throughout the remainder of 2016 as we respond to commodity price changes and costs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion concerning how we intend to fund the remainder of our 2016 capital program.
Production Results. The table below provides a regional breakdown of our production for the three and six months ended June 30, 2016:
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Permian
 
Total (1)
 
Three Months Ended
Six Months Ended
 
Three Months Ended
Six Months Ended
 
Three Months Ended
Six Months Ended
 
Three Months Ended
Six Months Ended
 
June 30, 2016
 
June 30, 2016
 
June 30, 2016
 
June 30, 2016
Oil (MMBbl)
1.4

2.9

 
2.1

4.3

 
0.6

1.0

 
4.1

8.2

Gas (Bcf)
34.9

66.9

 
2.7

5.3

 
1.4

2.4

 
39.0

74.7

NGLs (MMBbl)
3.6

6.9

 
0.1

0.2

 
—

—

 
3.7

7.1

Equivalent (MMBOE)
10.9

21.0

 
2.6

5.3

 
0.8

1.4

 
14.3

27.7

Avg. daily equivalents (MBOE/d)
119.3

115.3

 
28.6

29.4

 
9.3

7.7

 
157.2

152.4

Relative percentage
76
%
76
%
 
18
%
19
%
 
6
%
5
%
 
100
%
100
%
____________________________________________
(1) Amounts may not calculate due to rounding.

Production decreased for the three and six months ended June 30, 2016, compared to the same periods in 2015, driven by the divestiture of properties in our Mid-Continent region in the second quarter of 2015, as well as a reduction in our drilling and completion activity. The table below provides a summary of wells completed in our operated programs during the three and six months ended June 30, 2016.

 
For the Three Months Ended
 
For the Six Months Ended
 
June 30, 2016
 
Gross
Net
 
Gross
Net
Eagle Ford shale
9
9
 
11
11
Bakken/Three Forks
17
14
 
22
18
Permian Basin
8
8
 
12
12

Please refer to Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2016, and 2015 and A three-month and six-month overview of selected production and financial information, including trends below for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
 
For the Three Months Ended
 
For the Six Months Ended
 
June 30, 2016
 
(in millions)
Development costs (1)
$
150.7

 
$
328.9

Exploration costs
23.4

 
56.0

Acquisitions
 
 
 
Proved properties
0.1

 
2.3

Unproved properties (2)
3.1

 
17.5

Total, including asset retirement obligations (3)
$
177.3

 
$
404.7


27

____________________________________________
(1) Includes facility costs of $4.3 million and $12.1 million for the three and six months ended June 30, 2016, respectively.
(2) The three and six months ended June 30, 2016, includes $2.8 million and $16.8 million, respectively, of unproved properties acquired as part of proved property acquisitions. The remaining amount is leasing activity.
(3) The three and six months ended June 30, 2016, includes amounts relating to estimated asset retirement obligations of $1.2 million and $2.1 million, respectively, and capitalized interest of $5.2 million and $10.3 million, respectively.

The majority of costs incurred for oil and gas producing activities during 2016 were in the development of our Bakken/Three Forks, Permian Basin, and Eagle Ford shale programs. Please refer to Production Results above for discussion on completion activity, and to the section Second Quarter 2016 Highlights and Outlook for the Remainder of 2016 above for discussion on wells that have been drilled but not completed as of June 30, 2016. Additionally, please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital expenditure program.

Subsequent Events. Subsequent to June 30, 2016, we entered into separate purchase and sale agreements for the sale of certain of our Permian and Rocky Mountain assets that were classified as held for sale at June 30, 2016. Please refer to Note - Assets Held for Sale and Divestitures in Part I, Item I of this report for additional discussion.

28

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information. A detailed discussion follows.

 
For the Three Months Ended
 
June 30,
 
March 31,
 
December 31,
 
September 30,
 
2016
 
2016
 
2015
 
2015
 
(in millions, except for production data)
Production (MMBOE)
14.3

 
13.4

 
14.9

 
16.1

Oil, gas, and NGL production revenue
$
291.1

 
$
211.8

 
$
298.7

 
$
366.6

Oil, gas, and NGL production expense
$
148.6

 
$
144.5


$
169.2

 
$
184.6

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
211.0

 
$
214.2

 
$
240.0

 
$
243.9

Exploration
$
13.2

 
$
15.3

 
$
37.9

 
$
19.7

General and administrative
$
28.2

 
$
32.2

 
$
33.6

 
$
37.8

Net income (loss)
$
(168.7
)
 
$
(347.2
)
 
$
(340.3
)
 
$
3.1

____________________________________________
Note: Amounts may not calculate due to rounding.

Selected Performance Metrics:

 
For the Three Months Ended
 
June 30,
 
March 31,
 
December 31,
 
September 30,
 
2016
 
2016
 
2015
 
2015
Average net daily production equivalent (MBOE/d)
157.2

 
147.5

 
162.1

 
174.5

Lease operating expense (per BOE)
$
3.31

 
$
3.79

 
$
3.85

 
$
3.86

Transportation costs (per BOE)
$
5.95

 
$
6.06

 
$
6.10

 
$
6.27

Production taxes as a percent of oil, gas, and NGL production revenue
4.6
%
 
4.2
%
 
5.1
%
 
4.2
%
Ad valorem tax expense (per BOE)
$
0.19

 
$
0.27

 
$
0.38

 
$
0.40

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
$
14.75

 
$
15.96

 
$
16.10

 
$
15.19

General and administrative (per BOE)
$
1.97

 
$
2.40

 
$
2.26

 
$
2.35

____________________________________________
Note: Amounts may not calculate due to rounding.

29

A three-month and six-month overview of selected production and financial information, including trends:
 
For the Three Months Ended June 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
For the Six Months Ended June 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
2016
 
2015
 
 
2016
 
2015
 
Net production volumes (1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
4.1

 
5.1

 
(1.0
)
 
(19
)%
 
8.2

 
10.3

 
(2.1
)
 
(20
)%
Gas (Bcf)
39.0

 
44.2

 
(5.2
)
 
(12
)%
 
74.7

 
90.1

 
(15.5
)
 
(17
)%
NGLs (MMBbl)
3.7

 
4.0

 
(0.3
)
 
(8
)%
 
7.1

 
7.9

 
(0.9
)
 
(11
)%
Equivalent (MMBOE)
14.3

 
16.5

 
(2.2
)
 
(13
)%
 
27.7

 
33.3

 
(5.5
)
 
(17
)%
Average net daily production (1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbl per day)
45.1

 
55.9

 
(10.8
)
 
(19
)%
 
45.2

 
57.0

 
(11.8
)
 
(21
)%
Gas (MMcf per day)
428.2

 
485.8

 
(57.6
)
 
(12
)%
 
410.2

 
498.0

 
(87.8
)
 
(18
)%
NGLs (MBbl per day)
40.8

 
44.2

 
(3.4
)
 
(8
)%
 
38.8

 
43.8

 
(5.0
)
 
(11
)%
Equivalent (MBOE per day)
157.2

 
181.0

 
(23.8
)
 
(13
)%
 
152.4

 
183.7

 
(31.4
)
 
(17
)%
Oil, gas, and NGL production revenue (in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil production revenue
$
161.6

 
$
261.7

 
$
(100.1
)
 
(38
)%
 
$
267.4

 
$
463.2

 
$
(195.8
)
 
(42
)%
Gas production revenue
69.7

 
111.9

 
(42.2
)
 
(38
)%
 
136.4

 
238.7

 
(102.3
)
 
(43
)%
NGL production revenue
59.8

 
67.7

 
(7.9
)
 
(12
)%
 
99.2

 
132.7

 
(33.5
)
 
(25
)%
Total
$
291.1

 
$
441.3

 
$
(150.2
)
 
(34
)%
 
$
503.0

 
$
834.6

 
$
(331.6
)
 
(40
)%
Oil, gas, and NGL production expense (in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating expense
$
47.4

 
$
53.8

 
$
(6.4
)
 
(12
)%
 
$
98.2

 
$
120.3

 
$
(22.1
)
 
(18
)%
Transportation costs
85.1

 
92.9

 
(7.8
)
 
(8
)%
 
166.4

 
194.9

 
(28.5
)
 
(15
)%
Production taxes
13.3

 
22.9

 
(9.6
)
 
(42
)%
 
22.2

 
41.7

 
(19.5
)
 
(47
)%
Ad valorem tax expense
2.8

 
4.1

 
(1.3
)
 
(32
)%
 
6.3

 
12.9

 
(6.6
)
 
(51
)%
Total
$
148.6

 
$
173.7

 
$
(25.1
)
 
(14
)%
 
$
293.1

 
$
369.8

 
$
(76.7
)
 
(21
)%
Realized price (before the effect of derivative settlements)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
39.38

 
$
51.45

 
$
(12.07
)
 
(23
)%
 
$
32.51

 
$
44.92

 
$
(12.41
)
 
(28
)%
Gas (per Mcf)
$
1.79

 
$
2.53

 
$
(0.74
)
 
(29
)%
 
$
1.83

 
$
2.65

 
$
(0.82
)
 
(31
)%
NGLs (per Bbl)
$
16.12

 
$
16.85

 
$
(0.73
)
 
(4
)%
 
$
14.05

 
$
16.76

 
$
(2.71
)
 
(16
)%
Per BOE
$
20.35

 
$
26.78

 
$
(6.43
)
 
(24
)%
 
$
18.14

 
$
25.10

 
$
(6.96
)
 
(28
)%
Per BOE Data (1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Production costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating expense
$
3.31

 
$
3.26

 
$
0.05

 
2
 %
 
$
3.54

 
$
3.62

 
$
(0.08
)
 
(2
)%
Transportation costs
$
5.95

 
$
5.64

 
$
0.31

 
5
 %
 
$
6.00

 
$
5.86

 
$
0.14

 
2
 %
Production taxes
$
0.93

 
$
1.39

 
$
(0.46
)
 
(33
)%
 
$
0.80

 
$
1.25

 
$
(0.45
)
 
(36
)%
Ad valorem tax expense
$
0.19

 
$
0.25

 
$
(0.06
)
 
(24
)%
 
$
0.23

 
$
0.39

 
$
(0.16
)
 
(41
)%
General and administrative
$
1.97

 
$
2.59

 
$
(0.62
)
 
(24
)%
 
$
2.18

 
$
2.59

 
$
(0.41
)
 
(16
)%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
14.75

 
$
13.34

 
$
1.41

 
11
 %
 
$
15.34

 
$
13.14

 
$
2.20

 
17
 %
Derivative settlement gain (2)
$
7.10

 
$
6.85

 
$
0.25

 
4
 %
 
$
8.97

 
$
8.24

 
$
0.73

 
9
 %
Earnings per share information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic net loss per common share
$
(2.48
)
 
$
(0.85
)
 
$
(1.63
)
 
(192
)%
 
$
(7.58
)
 
$
(1.64
)
 
$
(5.94
)
 
(362
)%
Diluted net loss per common share
$
(2.48
)
 
$
(0.85
)
 
$
(1.63
)
 
(192
)%
 
$
(7.58
)
 
$
(1.64
)
 
$
(5.94
)
 
(362
)%
Basic weighted-average common shares outstanding (in thousands)
68,102

 
67,483

 
619

 
1
 %
 
68,090

 
67,473

 
617

 
1
 %
Diluted weighted-average common shares outstanding (in thousands)
68,102

 
67,483

 
619

 
1
 %
 
68,090

 
67,473

 
617

 
1
 %

30

______________________________________
(1) Amount and percentage changes may not calculate due to rounding.
(2) Derivative settlements for the three and six months ended June 30, 2016, and 2015, respectively, are included within the derivative (gain) loss line item in the accompanying statements of operations. Natural gas derivative settlements for the three and six months ended June 30, 2015, include a $15.3 million gain on the early settlement of future contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015. This settlement gain increased our derivative settlement gain by $0.93 and $0.46 per BOE for the three and six months ended June 30, 2015, respectively.

We present per BOE information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis. Average daily production for the three and six months ended June 30, 2016, decreased 13 percent and 17 percent, respectively, compared with the same periods in 2015. The decreases were due to the sale of our Mid-Continent assets during the second quarter of 2015, which produced 7.4 MBOE per day and 9.3 MBOE per day during the three and six months ended June 30, 2015, respectively, and due to our reduced drilling and completion activity throughout 2015 and 2016. Overall, we expect our production to be relatively flat quarter-over-quarter for the remainder of 2016, resulting in an overall decrease in production for the full-year 2016 compared to the full-year 2015. Please refer to Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2016, and 2015 below for additional discussion.

Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized prices on a per BOE basis for the three and six months ended June 30, 2016, decreased 24 percent and 28 percent, respectively, compared to the same periods in 2015, as a result of lower commodity prices.

Lease operating expense (“LOE”) on a per BOE basis remained relatively flat for the three and six months ended June 30, 2016, compared to the same periods in 2015. Our LOE is comprised of recurring LOE and workover expense. We experience volatility in our LOE as a result of the impact industry activity has on service provider costs and seasonality in workover expense. For full-year 2016, we expect LOE on a per BOE basis to be slightly lower than full-year 2015 as a result of lower service provider costs.

Transportation expense on a per BOE basis slightly increased for the three and six months ended June 30, 2016, compared to the same periods in 2015, due to selling our Mid-Continent assets during the second quarter of 2015, which resulted in our higher cost Eagle Ford shale assets becoming a larger portion of our total production. As a result of this divestiture, we expect the change in our production mix to result in slightly higher transportation costs on a per BOE basis when comparing full-year 2016 to full-year 2015.

Production taxes on a per BOE basis decreased 33 percent and 36 percent for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 in line with the decrease in production revenues. Our production tax rate for the three and six months ended June 30, 2016, was 4.6 percent and 4.4 percent, respectively, compared to 5.2 percent and 5.0 percent, respectively, for the same periods in 2015. This decrease in our company-wide production tax rate is primarily a result of divesting our Mid-Continent properties in the second quarter of 2015. We generally expect absolute production tax expense to trend with oil, gas, and NGL production revenue. Product mix, the location of production, and incentives to encourage oil and gas development can also impact or change the amount of production tax we recognize.

Ad valorem tax expense on a per BOE basis decreased 24 percent and 41 percent for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. The decrease in ad valorem tax expense on a per BOE basis is primarily due to the lower valuation of properties subject to ad valorem taxes in 2016 as a result of declining commodity prices. We expect ad valorem tax expense to fluctuate throughout the year on an absolute and on a per BOE basis as valuations and county tax rates are finalized.

General and administrative (“G&A”) expense on a per BOE basis decreased 24 percent and 16 percent for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015, as our absolute G&A expense decreased at a faster rate than the decrease in production volumes. Absolute G&A expense decreased for the three and six months ended June 30, 2016, compared to the same periods in 2015 primarily due to lower headcount in 2016 than in 2015, and due to the exit and disposal costs incurred during the second quarter of 2015 relating to the closure of our Tulsa, Oklahoma office. Overall, we expect G&A expense on a per BOE basis to be lower for the full-year 2016 compared to the full-year 2015 due to lower headcount and exit and disposal costs incurred during 2015.


31

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased 11 percent and 17 percent for the three and six months ended June 30, 2016, compared to the same periods in 2015. Our DD&A rate can fluctuate as a result of impairments, planned and closed divestitures, and changes in the mix of our production and the underlying proved reserve volumes. The decrease in commodity prices has resulted in a decrease in proved reserve volumes and consequently an increased DD&A rate in 2016 compared to 2015. However, the marketing of certain non-core assets in each of our operating regions caused a reduction in our DD&A expense on a per BOE basis in the second quarter of 2016, as these assets were held for sale with no DD&A expense recorded for these assets for the three months ended June 30, 2016. Changes in commodity prices impact our proved reserve volumes, and consequently, we would expect a decrease in commodity prices to increase our DD&A rate and an increase in commodity prices to lower our DD&A rate. For the remainder of 2016, we expect DD&A expense on a per BOE basis to be in line with our second quarter rate or slightly higher upon the closure of divestitures of the properties held for sale at June 30, 2016.

Please refer to Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2016, and 2015 below for additional discussion on operating expenses.
Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for discussion on the types of shares included in our basic and diluted net loss per common share calculations. For the three and six months ended June 30, 2016, and 2015, we recorded losses from continuing operations and all potentially dilutive shares were anti-dilutive and excluded from the calculation of diluted net loss per common share.

Comparison of Financial Results and Trends Between the Three Months and Six Months Ended June 30, 2016, and 2015

Oil, gas, and NGL production, revenue, and costs

The following table presents the regional changes in our oil, gas, and NGL production, production revenues, and production costs between the three months ended June 30, 2016, and 2015:

 
Average Net Daily Production
Increase (Decrease)
 
Production Revenues Decrease
 
Production Costs
Increase (Decrease)
 
(MBOE/d)
 
(in millions)
 
(in millions)
South Texas & Gulf Coast
(13.7
)
 
$
(94.6
)
 
$
(17.7
)
Rocky Mountain
(3.9
)
 
(45.1
)
 
(2.2
)
Permian
1.2

 
(1.6
)
 
0.2

Mid-Continent (1)
(7.4
)
 
(8.9
)
 
(5.4
)
Total
(23.8
)
 
$
(150.2
)
 
$
(25.1
)
____________________________________________
(1) We divested our Mid-Continent assets in the second quarter of 2015.

The 13 percent decrease in net equivalent production volumes combined with a 24 percent decrease in realized prices on a per BOE basis, resulted in a 34 percent decrease in oil, gas, and NGL production revenues between the three months ended June 30, 2016, and 2015.
    
Total production costs decreased 14 percent for the three months ended June 30, 2016, compared with the same period of 2015, primarily due to a 13 percent decrease in net equivalent production volumes and the changes in costs on a per BOE basis discussed above.

32

The following table presents the regional changes in our oil, gas, and NGL production, production revenues, and production costs between the six months ended June 30, 2016, and 2015:

 
Average Net Daily Production
Decrease
 
Production Revenues Decrease
 
Production Costs
Decrease
 
(MBOE/d)
 
(in millions)
 
(in millions)
South Texas & Gulf Coast
(19.4
)
 
$
(212.1
)
 
$
(49.4
)
Rocky Mountain
(1.9
)
 
(78.7
)
 
(7.3
)
Permian
(0.8
)
 
(16.8
)
 
(7.6
)
Mid-Continent (1)
(9.3
)
 
(24.0
)
 
(12.4
)
Total
(31.4
)
 
$
(331.6
)
 
$
(76.7
)
____________________________________________
(1) We divested our Mid-Continent assets in the second quarter of 2015.
    
The 17 percent decrease in net equivalent production volumes combined with a 28 percent decrease in realized prices on a per BOE basis, resulted in a 40 percent decrease in oil, gas, and NGL production revenues between the six months ended June 30, 2016, and 2015.

Total production costs decreased 21 percent for the six months ended June 30, 2016, compared with the same period of 2015, primarily due to a 17 percent decrease in net equivalent production volumes and the changes in costs on a per BOE basis discussed above.

Please refer to A three-month and six-month overview of selected production and financial information, including trends above for realized prices received before the effects of derivative settlements for the three and six months ended June 30, 2016, and 2015, and discussion of trends on a per BOE basis. We expect our realized prices to trend with commodity prices.

Net gain (loss) on divestiture activity

The following table presents our net gain (loss) on divestiture activity for the periods presented:

 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Net gain (loss) on divestiture activity
$
50.0

 
$
71.9

 
$
(19.0
)
 
$
36.1


The net gain on divestiture activity recorded for the three months ended June 30, 2016, is primarily due to an increase in estimated selling prices, as evidenced by recent bid prices received from third parties, on certain previously impaired assets held for sale. The net gain on divestiture activity recorded for the same period in 2015 is related to the gain on the sale of our Mid-Continent assets, partially offset by the write-down to fair value less costs to sell on certain assets held for sale as of June 30, 2015.

The net loss on divestiture activity recorded for the six months ended June 30, 2016, is primarily due to the $68.3 million write-down to fair value less estimated costs to sell on certain assets held for sale during the first quarter of 2016, partially offset by a subsequent write-up recorded on certain assets held for sale during the second quarter of 2016 as discussed above. The net gain recorded for the six months ended June 30, 2015, was due to the gain recorded on the sale of our Mid-Continent assets in the second quarter of 2015, partially offset by the write-down to fair value less costs to sell on certain assets held for sale in both the first and second quarters of 2015.

Please refer to Note 3 – Assets Held for Sale and Divestitures in Part I, Item 1 of this report for additional discussion.


33

Other operating revenues

The following table presents our other operating revenues for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Other operating revenues
$
0.6

 
$
3.0

 
$
0.9

 
$
11.4


The decrease in other operating revenues for the three and six months ended June 30, 2016, compared to the same periods in 2015, is driven by the sale of our Mid-Continent gas assets in the second quarter of 2015, which eliminated all marketed gas volumes and thus all marketed gas system revenues.

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

The following table presents our DD&A expense for the periods presented:

 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
211.0

 
$
219.7

 
$
425.2

 
$
437.1


DD&A expense decreased slightly for the three and six months ended June 30, 2016, compared to the same periods in 2015. The decrease in our DD&A expense was a result of the decline in our production volumes, partially offset by an increase in our DD&A rate in 2016. Please refer to the section A three-month and six-month overview of selected production and financial information, including trends above for further discussion of DD&A expense on a per BOE basis.

Exploration

The components of exploration expense are summarized as follows:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Geological and geophysical expenses
$
0.5

 
$
1.0

 
$
0.6

 
$
4.7

Exploratory dry hole
—

 
6.6

 
—

 
22.9

Overhead and other expenses
12.7

 
17.9

 
27.9

 
35.3

Total
$
13.2

 
$
25.5

 
$
28.5

 
$
62.9

Exploration expense for the three and six months ended June 30, 2016, decreased 48 percent and 55 percent, respectively, compared to the same periods in 2015, primarily due to exploratory dry holes being expensed in the first and second quarters of 2015 and reduced overhead costs due to decreased headcount. An exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole and impacts the amount of exploration expense we record. As a result of the current commodity price environment, we have reduced exploration activity and expect our exploratory dry hole, geological and geophysical, overhead and other exploration expenses to be lower in 2016 than in 2015.


34

Impairment of proved properties and abandonment and impairment of unproved properties

The following table presents our impairment of proved properties expense and abandonment and impairment of unproved properties expense for the periods presented:
    
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Impairment of proved properties
$
—

 
$
12.9

 
$
269.8

 
$
68.4

Abandonment and impairment of unproved properties
$
—

 
$
5.8

 
$
2.3

 
$
17.4


During the first quarter of 2016, we impaired proved properties, primarily in our outside-operated Eagle Ford shale program, as a result of continued commodity price declines. Additionally, we allowed certain leases to expire and impaired unproved properties we no longer intended to develop.

Proved and unproved property impairments recorded for the three and six months ended June 30, 2015, were due to commodity price declines, our decision to reduce capital invested in the development of certain prospects in our South Texas & Gulf Coast and Permian regions, and acreage we no longer intended to develop.

We expect proved property impairments to be more likely to occur in periods of declining commodity prices, and unproved property impairments to fluctuate with the timing of lease expirations, unsuccessful exploration activities, and changing economics associated with volatile commodity prices. Any amount of future impairment is difficult to predict, but based on updated commodity price assumptions as of July 27, 2016, we do not expect any material impairments in the third quarter of 2016 due to commodity price impacts. If commodity prices decline, downward revisions of proved reserves may be significant and could result in impairments in future periods. In addition to future commodity price declines, changes in drilling plans, downward engineering revisions, or unsuccessful exploration efforts may result in proved and unproved property impairments.

General and administrative
    
The following table presents our general and administrative expense for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
General and administrative
$
28.2

 
$
42.6

 
$
60.4

 
$
86.2


G&A expense decreased 34 percent and 30 percent for the three and six months ended June 30, 2016, respectively, compared with the same periods in 2015. This decrease is primarily due to lower headcount in 2016 than in 2015, and exit and disposal costs of $5.0 million and $8.5 million incurred for the three and six months ended June 30, 2015, respectively, relating to the closure of our Tulsa, Oklahoma office.
Change in Net Profits Plan liability
The following table presents the change in our Net Profits Plan liability for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Change in Net Profits Plan liability
$
3.1

 
$
(4.5
)
 
$
1.9

 
$
(8.8
)
This non-cash expense (benefit) generally relates to the change between the reporting periods in the estimated value of the associated liability resulting from settlements made or accrued during the period and changes in assumptions used for production rates, reserve quantities, commodity pricing, discount rates, and production costs. The non-cash expense for the three and six months

35

ended June 30, 2016, is a result of the increase in commodity prices during the second quarter of 2016 driving an increase in the corresponding liability as of June 30, 2016. The non-cash benefit for the three and six months ended June 30, 2015, resulted from cash payments made or accrued under the Net Profits Plan upon the divestiture of properties subject to the Net Profits Plan and the decline in commodity prices during the first half of 2015. We generally expect changes in our Net Profits Plan liability to correlate with fluctuations in commodity prices. Divestitures of properties subject to the Net Profits Plan also result in changes to the Net Profits Plan liability.

Derivative (gain) loss

The following table presents our derivative (gain) loss for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Derivative (gain) loss
$
163.4

 
$
80.9

 
$
149.1

 
$
(73.2
)

We recognized a derivative loss for the three and six months ended June 30, 2016. Contracts settled during the three months ended June 30, 2016, had a fair value of $114.7 million at March 31, 2016, and settled for $101.7 million, which resulted in a $13.0 million loss during the second quarter of 2016. Additionally, we recorded a $150.4 million decrease during the three months ended June 30, 2016, in the fair value of contracts settling subsequent to June 30, 2016. We recognized a $15.8 million gain on first quarter 2016 settlements, partially offset by a $1.6 million mark-to-market loss recorded on remaining contracts as of March 31, 2016.

We recognized a derivative loss for the three months ended June 30, 2015. Contracts settled during the three months ended June 30, 2015, had a fair value of $133.1 million at March 31, 2015, and settled for $112.8 million, which resulted in a $20.3 million loss during the second quarter of 2015. Included in these settlements was a $15.3 million gain on the early settlement of future contracts resulting from the divestiture of our Mid-Continent assets during the second quarter of 2015. Additionally, we recorded a $60.6 million decrease during the three months ended June 30, 2015, in the fair value of contracts settling subsequent to June 30, 2015. We recognized a $13.5 million gain on first quarter 2015 settlements and a $140.7 million mark-to-market gain on remaining contracts as of March 31, 2015.

Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information.
    
Other operating expenses

The following table presents our other operating expenses for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Other operating expenses
$
4.9

 
$
10.3

 
$
11.8

 
$
27.4


Other operating expenses for the three and six months ended June 30, 2016, consists primarily of drilling rig termination and standby fees of $2.6 million and $7.6 million, respectively. This compares to drilling rig termination and standby fees of $2.7 million and $5.9 million recorded for the three and six months ended June 30, 2015, respectively. Additionally, we recorded $4.7 million related to estimated claims for payment of royalties on certain Federal and Indian leases during the three months ended June 30, 2015. These estimated claims were slightly reduced during the six months ended June 30, 2016. Please refer to Note 6 - Commitments and Contingencies in Part I, Item I of this report for additional information. The remaining decrease is largely due to the sale of our Mid-Continent gas assets in the second quarter of 2015, which eliminated all marketed gas volumes and all marketed gas system expenses.


36

Gain (loss) on extinguishment of debt

The following table presents our gain (loss) on extinguishment of debt for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Gain (loss) on extinguishment of debt
$
—

 
$
(16.6
)
 
$
15.7

 
$
(16.6
)

During the first quarter of 2016, we recorded a $15.7 million net gain on the early extinguishment of a portion of our 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023, which includes approximately $16.4 million associated with the discount realized upon repurchase, slightly offset by approximately $700,000 related to the acceleration of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional information.

For the three and six months ended June 30, 2015, we recorded a $16.6 million loss on the early extinguishment of our 6.625% Senior Notes due 2019, which includes approximately $12.5 million associated with the premium paid for the tender offer and redemption of the notes and approximately $4.1 million for the acceleration of unamortized deferred financing costs.

Income tax benefit

The following table presents our income tax benefit and effective tax rate for the periods presented:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions, except tax rate)
Income tax benefit
$
95.9

 
$
40.7

 
$
290.8

 
$
74.2

Effective tax rate
36.2
%
 
41.4
%
 
36.0
%
 
40.1
%

The decrease in the effective tax rate for the three and six months ended June 30, 2016, compared to the same periods in 2015, resulted from discrete benefits realized from finalization of an R&D credit claim in the first quarter of 2015 and enacted state rate changes in Texas and North Dakota in the second quarter of 2015. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion service commitments to maintain the flexibility to adjust our activity and capital expenditures in periods of prolonged weak commodity prices or to respond should commodity prices recover.

Sources of Cash

We currently expect our 2016 capital program to be primarily funded by cash flows from operations, with any remaining cash needs to be funded by borrowings under our credit facility and proceeds received from the divestiture of properties. See Credit Facility below for a discussion of our most recent borrowing base redetermination. Although we anticipate cash flows from these sources will be sufficient to fund our expected 2016 capital program, we may also elect to access the capital markets, depending on prevailing market conditions. From time to time, we may enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. During the first quarter of 2016, our credit ratings were downgraded by two major rating agencies. These downgrades and any future downgrades may make it more difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. During the first half of 2016, cash received from the settlement of commodity derivative contracts provided a significant positive source of cash, which is reflected in net cash provided by operating activities in our accompanying condensed consolidated statements of cash flows. The fair

37

value of our commodity derivative contracts was a net asset of $90.5 million at June 30, 2016, of which $62.2 million relates to contracts expected to settle in the second half of 2016. As our derivative contracts settle in future periods, and if commodity prices remain at current levels or decline further, our future cash flows from operations will be negatively impacted. Please refer to Note 10 – Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts. Decreases in commodity prices have limited our industry’s access to capital markets. Our credit facility borrowing base could be further reduced as a result of lower commodity prices, divestitures of proved properties, or newly issued debt.

Proposals to reform the Internal Revenue Code of 1986, as amended, which include eliminating or reducing current tax deductions for intangible drilling costs, depreciation of equipment acquisition costs, the domestic production activities deduction, percentage depletion, and other deductions that reduce our taxable income, continue to circulate. We expect that future legislation modifying or eliminating these deductions would reduce net operating cash flows over time, thereby reducing funding available for our exploration and development capital programs, as well as funding available to our peers in the industry for similar programs. If enacted, these reductions in available deductions could have a significant adverse effect on drilling in the United States for a number of years.

Credit Facility

Our Amended Credit Agreement provides for a maximum loan amount of $2.5 billion and a maturity date of December 10, 2019. Pursuant to the most recent amendment, and as part of our regular semi-annual redetermination, our borrowing base and the current aggregate lender commitments were both reduced to $1.25 billion during the second quarter of 2016. This expected reduction was primarily a result of the decrease in our proved reserves as of December 31, 2015, resulting from the continued decline in commodity prices. We do not expect to be negatively impacted by the reduction in our borrowing base and aggregate lender commitments, as we currently plan to spend within adjusted EBITDAX during 2016 and believe the revised amounts will be sufficient to meet our anticipated liquidity and operating needs. No individual bank that is a party to our Amended Credit Agreement represents more than 10 percent of the lender commitments. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under our Amended Credit Agreement as of July 27, 2016, and June 30, 2016, and Credit Agreement as of December 31, 2015.

We must comply with certain financial and non-financial covenants under the terms of the Amended Credit Agreement, including covenants limiting dividend payments and requiring us to maintain certain financial ratios, as defined by the Amended Credit Agreement. As of June 30, 2016, financial covenants under the Amended Credit Agreement require, as of the last day of each of our fiscal quarters, our (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. We were in compliance with all financial and non-financial covenants under the Amended Credit Agreement as of June 30, 2016, and through the filing date of this report. Please refer to the caption Non-GAAP Financial Measures below for the calculation of adjusted EBITDAX, and a reconciliation of adjusted EBITDAX to net loss and to net cash provided by operating activities.
  
Our daily weighted-average credit facility debt balance was approximately $312.1 million and $282.1 million for the three and six months ended June 30, 2016, respectively. Our daily weighted-average credit facility debt balance was approximately $330.0 million and $321.8 million for the three and six months ended June 30, 2015, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, and the amount of our capital expenditures all impact the amount we have borrowed under our credit facility.

Weighted-Average Interest Rates

Our weighted-average interest rates include paid and accrued interest, fees on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-average borrowing rates include paid and accrued interest only.


38

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the three and six months ended June 30, 2016, and 2015:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Weighted-average interest rate
5.9
%
 
5.9
%
 
5.9
%
 
6.0
%
Weighted-average borrowing rate
5.5
%
 
5.5
%
 
5.5
%
 
5.5
%

Our weighted-average interest rates and weighted-average borrowing rates in 2016 and 2015 have been impacted by the timing of Senior Notes issuances and redemption, the average balance on our revolving credit facility, and the fees paid on the unused portion of our aggregate commitment. The rates disclosed in the above table for the six months ended June 30, 2016, do not reflect the approximate $16.4 million associated with the discount realized upon repurchase of certain of our Senior Notes during the first quarter of 2016, or the approximate $700,000 related to the acceleration of unamortized deferred financing costs expensed upon repurchase. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. The rates disclosed in the above table for the three and six months ended June 30, 2015, do not reflect the approximate $12.5 million premium paid for the tender offer and redemption of the 2019 Notes or the approximate $4.1 million of unamortized deferred financing costs expensed upon extinguishment of these notes.

Uses of Cash
 
We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of operating and G&A costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the acquisition, exploration, and development of oil and gas properties are the primary use of our capital resources. In the first half of 2016, we spent $363.3 million in capital expenditures and in acquiring proved and unproved oil and gas properties. This amount differs from the costs incurred amount, which is accrual-based and includes asset retirement obligation, geological and geophysical expenses, and exploration overhead amounts.
The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing, and financing activities, and our ability to assimilate acquisitions and execute our drilling program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results of our operated and outside-operated exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.
We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions including covenants in our Amended Credit Agreement, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. During the six months ended June 30, 2016, we repurchased a portion of our 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023, in open market transactions, at a discount, resulting in a $15.7 million net gain on extinguishment of debt. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
As of the filing date of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Amended Credit Agreement, the indentures governing our Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. We currently do not plan to repurchase any outstanding shares during 2016.


39

Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2016, and 2015

The following tables present changes in cash flows between the six months ended June 30, 2016, and 2015, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our condensed consolidated statements of cash flows in Part I, Item 1 of this report.

Operating Activities
 
For the Six Months Ended June 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
2016
 
2015
 
 
 
(in millions)
 
 
Net cash provided by operating activities
$
256.9

 
$
549.5

 
$
(292.6
)
 
(53
)%

Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, including derivative cash settlements, decreased $393.0 million for the six months ended June 30, 2016, compared to the same period in 2015, as a result of the decline in both production volumes and realized commodity prices. Cash paid for LOE, excluding ad valorem tax expense, decreased $29.4 million for the six months ended June 30, 2016, compared to the same period in 2015, due to a decrease in production volumes and lower service provider costs. Additionally, during the six months ended June 30, 2015, we paid $12.5 million associated with the premium for the tender offer and redemption of the 6.625% Senior Notes due 2019.

Investing activities
 
For the Six Months Ended June 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
2016
 
2015
 
 
 
(in millions)
 
 
Net cash used in investing activities
$
(351.3
)
 
$
(646.7
)
 
$
295.4

 
46
%

Net cash used in investing activities decreased for the six months ended June 30, 2016, compared to the same period in 2015. Capital expenditures for the six months ended June 30, 2016, decreased $628.6 million, or 65 percent, compared to the same period in 2015. Drilling, completion, and facilities capital expenditures decreased approximately 55 percent for the six months ended June 30, 2016, as compared to the same period in 2015, as a result of a reduced operated rig count, fewer well completions, and lower service provider costs. Additionally, we paid a significant amount of year-end 2014 accrued payables during the first half of 2015. We acquired $17.8 million of primarily unproved properties in the Midland Basin during the six months ended June 30, 2016, compared to $6.6 million of proved and unproved property acquisitions in our Gooseneck prospect area in the same period in 2015. Net proceeds from the sale of oil and gas properties decreased $322.0 million for the six months ended June 30, 2016, compared to the same period in 2015, primarily due to the divestiture of our Mid-Continent assets during the second quarter of 2015.

Financing activities
 
For the Six Months Ended June 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
2016
 
2015
 
 
 
(in millions)
 
 
Net cash provided by financing activities
$
94.4

 
$
97.2

 
$
(2.8
)
 
(3
)%

We paid $29.9 million in the six months ended June 30, 2016, for the repurchase of a portion of the principal amount of our 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023. We received $491.6 million of net proceeds from the issuance of our 2025 Notes in the second quarter of 2015. These proceeds were primarily used for the tender and redemption of the principal amount of $350.0 million of our 2019 Notes. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. We had net borrowings under our credit facility of $128.5 million during the six months ended June 30, 2016, compared to repayments of $44.0 million during the six months ended June 30, 2015.


40

Interest Rate Risk

We are exposed to market risk due to the floating interest rate on our revolving credit facility. Our Amended Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the credit facility’s fair market value, but will not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value, but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes, but can impact their fair market values. As of June 30, 2016, our fixed-rate debt and floating-rate debt outstanding totaled $2.3 billion and $330.5 million, respectively. The carrying amount of our floating rate debt at June 30, 2016, approximated its fair value. Assuming a constant floating-rate debt level of $330.5 million, the before-tax cash flow impact resulting from a 100 basis point change would be $3.3 million over a 12-month period. Please refer to Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair value of our Senior Notes.
    
Commodity Price Risk
    
The prices we receive for our oil, gas, and NGL production directly impact our revenue, overall profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to wide fluctuations in response to changes in supply and demand and other factors. The markets for oil, gas, and NGLs have been volatile, especially over the last year, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on our production for the six months ended June 30, 2016, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $26.7 million, $13.6 million, and $9.9 million, respectively.

We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity prices. Based on our derivative contracts in place for the six months ended June 30, 2016, a 10 percent decrease in the contract settlement prices, would have increased our oil, gas, and NGL derivative settlement gain by approximately $14.2 million, $8.7 million, and $6.9 million, respectively.

Off-Balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions in 2016.

Critical Accounting Policies and Estimates

Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2015 Form 10-K for discussion of our accounting policies and estimates.

New Accounting Pronouncements

Please refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards under Part I, Item 1 of this report for new accounting matters.


41

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, other non-operating income or expense, income taxes, depletion, depreciation, amortization, and accretion expense, exploration expense, impairments, non-cash stock-based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, and gains and losses on divestitures. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Amended Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in Part I, Item 1 of this report. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our credit facility provides a material source of liquidity for us. Under the terms of our Amended Credit Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of senior secured debt to adjusted EBITDAX and a minimum permitted ratio of interest to adjusted EBITDAX, we will be in default, an event that would prevent us from borrowing under our credit facility and would therefore materially limit our sources of liquidity.  In addition, if we default under our credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing our outstanding Senior Notes would be entitled to exercise all of their remedies for a default.
 


42

The following table provides reconciliations of our net loss and net cash provided by operating activities to adjusted EBITDAX for the periods presented:

For the Three Months Ended June 30,
 
For the Six Months Ended June 30,

2016
 
2015
 
2016

2015

(in thousands)
Net loss (GAAP)
$
(168,681
)
 
$
(57,508
)
 
$
(515,891
)
 
$
(110,566
)
Interest expense
34,035

 
30,779

 
65,123

 
63,426

Interest income
(5
)
 
(25
)
 
(11
)
 
(596
)
Income tax benefit
(95,898
)
 
(40,703
)
 
(290,773
)
 
(74,156
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
211,020

 
219,704

 
425,227

 
437,105

Exploration (1)
11,402

 
23,768

 
25,013

 
59,500

Impairment of proved properties
—

 
12,914

 
269,785

 
68,440

Abandonment and impairment of unproved properties
38

 
5,819

 
2,349

 
17,446

Stock-based compensation expense
7,047

 
7,191

 
13,915

 
13,215

Derivative (gain) loss
163,351

 
80,929

 
149,123

 
(73,238
)
Derivative settlement gain (2)
101,710

 
112,795

 
248,738

 
274,024

Change in Net Profits Plan liability
3,125

 
(4,476
)
 
1,865

 
(8,810
)
Net (gain) loss on divestiture activity
(50,046
)
 
(71,884
)
 
18,975

 
(36,082
)
(Gain) loss on extinguishment of debt
—

 
16,578

 
(15,722
)
 
16,578

Other, net
—

 
1,406

 
1,692

 
2,856

Adjusted EBITDAX (Non-GAAP)
217,098


337,287

 
399,408


649,142

Interest expense
(34,035
)

(30,779
)
 
(65,123
)

(63,426
)
Interest income
5


25

 
11


596

Income tax benefit
95,898


40,703

 
290,773


74,156

Exploration (1)
(11,402
)

(23,768
)
 
(25,013
)

(59,500
)
Exploratory dry hole expense
(5
)

6,621

 
(24
)

22,896

Amortization of deferred financing costs
2,850


1,935

 
1,930


3,892

Deferred income taxes
(95,975
)

(50,829
)
 
(291,014
)

(84,556
)
Plugging and abandonment
(2,112
)

(961
)
 
(2,716
)

(3,386
)
Loss on extinguishment of debt
—


(12,455
)

—


(12,455
)
Other, net
548

 
(3,336
)
 
(1,016
)
 
(3,290
)
Changes in current assets and liabilities
(34,273
)

1,143

 
(50,343
)

25,439

Net cash provided by operating activities (GAAP)
$
138,597


$
265,586

 
$
256,873


$
549,508

____________________________________________
(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.
(2) Natural gas derivative settlements for the three and six months ended June 30, 2015, include a $15.3 million gain on the early settlement of future contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015.


43

Cautionary Information about Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:

•
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
•
our outlook on future oil, gas, and NGL prices, well costs, and service costs;
•
the drilling of wells and other exploration and development activities and plans, as well as possible acquisitions;
•
the possible divestiture or farm-down of, or joint venture relating to, certain properties;
•
proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates;
•
future oil, gas, and NGL production estimates;
•
cash flows, anticipated liquidity, and the future repayment of debt;
•
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and
•
other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Some of these risks are described in the Risk Factors section in Part I, Item 1A of our 2015 Form 10-K, and include such factors as:
•
the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;
•
weakness in economic conditions and uncertainty in financial markets;
•
our ability to replace reserves in order to sustain production;
•
our ability to raise the substantial amount of capital required to develop and/or replace our reserves;
•
our ability to compete against competitors that have greater financial, technical, and human resources;
•
our ability to attract and retain key personnel;
•
the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;
•
the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;
•
the possibility that exploration and development drilling may not result in commercially producible reserves;

44

•
our limited control over activities on outside-operated properties;

•
our reliance on the skill and expertise of third-party service providers on our operated properties;

•
the possibility that title to properties in which we have an interest may be defective;

•
the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;
•
the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;
•
the uncertainties associated with enhanced recovery methods;
•
our commodity derivative contracts may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;
•
the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;
•
our ability to deliver necessary quantities of natural gas or crude oil to contractual counterparties;
•
price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;
•
the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility;
•
the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;
•
the possibility that covenants in our debt agreements may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions, or lead to the accelerated payment of our debt;
•
operating and environmental risks and hazards that could result in substantial losses;
•
the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities;
•
our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;
•
complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;
•
the availability and capacity of gathering, transportation, processing, and/or refining facilities;
•
our ability to sell and/or receive market prices for our oil, gas, and NGLs;
•
new technologies may cause our current exploration and drilling methods to become obsolete;
•
the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and

•
litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.
We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing date of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under Interest Rate Risk and Commodity Price Risk in Item 2 above and is incorporated herein by reference. Please also refer to the information under Interest Rate Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2015 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that is designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
 
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls were effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes during the second quarter of 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

There have been no material changes to the legal proceedings as previously disclosed in our 2015 Form 10-K, under Part I, Item 3. See Note 6 - Commitments and Contingencies, in Part I, Item 1 of this report, for additional discussion.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2015 Form 10-K.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c)    The following table provides information about purchases by the Company or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the quarter ended June 30, 2016, of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act:

PURCHASES OF EQUITY SECURITIES BY ISSUER
AND AFFILIATED PURCHASERS

Period
(a)



Total Number of Shares Purchased (1)
(b)



Weighted Average Price Paid per Share
(c)

Total Number of Shares Purchased as Part of Publicly Announced Program
(d)

Maximum Number of Shares that May Yet Be Purchased Under the Program (2)
04/01/16 - 04/30/16
371

$
25.48

—

3,072,184

05/01/16 - 05/31/16
644

$
30.72

—

3,072,184

06/01/16 - 06/30/16
38

$
33.92

—

3,072,184

Total:
1,053

$
28.99

—

3,072,184

____________________________________________
(1) 
All shares purchased in the second quarter of 2016 offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under our Equity Incentive Compensation Plan.
(2) 
In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to up to 6,000,000 shares as of the effective date of the resolution. Accordingly, as of the date of this filing, we may repurchase up to 3,072,184 shares of common stock on a prospective basis, subject to the approval of our Board of Directors. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Amended Credit Agreement, the indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time.

Our payment of cash dividends to our stockholders is subject to covenants under the terms of our Amended Credit Agreement that limit our annual dividend payments to no more than $50.0 million per year. We are also subject to certain covenants under the indentures governing our Senior Notes that restrict certain payments, including dividends; provided, however, that the first $6.5 million of dividends paid each year are not restricted by these covenants. We do not anticipate that these restrictions will limit our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.


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ITEM 6. EXHIBITS

The following exhibits are filed or furnished with or incorporated by reference into this report:

Exhibit
 
Description
3.1
 
Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
3.2
 
Amended and Restated Bylaws of SM Energy Company, effective as of December 15, 2015 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on December 21, 2015, and incorporated herein by reference)
4.1†
 
Equity Incentive Compensation Plan, amended and restated effective as of May 24, 2016 (filed as Exhibit 4.3 to the registrant’s Form S-8 filed on June 30, 2016)
10.1*†
 
Performance Stock Unit Award Agreement as of July 1, 2016
10.2*†
 
Restricted Stock Unit Award Agreement as of July 1, 2016
10.3*†
 
Non-Employee Director Restricted Stock Award Agreement as of May 25, 2016
12.1*
 
Computation of Ratio of Earnings to Fixed Charges
31.1*
 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2*
 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1**
 
Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
101.INS*
 
XBRL Instance Document
101.SCH*
 
XBRL Schema Document
101.CAL*
 
XBRL Calculation Linkbase Document
101.LAB*
 
XBRL Label Linkbase Document
101.PRE*
 
XBRL Presentation Linkbase Document
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
_____________________________________
 
*
Filed with this report.
 
**
Furnished with this report.
 
†
Exhibit constitutes a management contract or compensatory plan or agreement.



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SIGNATURES

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

 
SM ENERGY COMPANY
 
 
 
August 3, 2016
By:
/s/ JAVAN D. OTTOSON
 
 
Javan D. Ottoson
 
 
President and Chief Executive Officer
 
 
(Principal Executive Officer)
 
 
 
August 3, 2016
By:
/s/ A. WADE PURSELL
 
 
A. Wade Pursell
 
 
Executive Vice President and Chief Financial Officer
 
 
(Principal Financial Officer)
 
 
 
August 3, 2016
By:
/s/ MARK T. SOLOMON
 
 
Mark T. Solomon
 
 
Vice President - Controller and Assistant Secretary
 
 
(Principal Accounting Officer)


50