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 September 30, 2016
Commission File Number 001-31539
sma02a02a01a01a01a07.jpg
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction
of incorporation or organization)
 
41-0518430
(I.R.S. Employer
Identification No.)

1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
 
80203
(Zip Code)

(303) 861-8140
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 October 26, 2016, the registrant had 86,869,269 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)
 
September 30,
2016
 
December 31,
2015
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
980,666

 
$
18

Accounts receivable
140,799

 
134,124

Derivative asset
109,818

 
367,710

Prepaid expenses and other
15,326

 
17,137

Total current assets
1,246,609

 
518,989

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
5,406,656

 
7,606,405

Less - accumulated depletion, depreciation, and amortization
(2,668,060
)
 
(3,481,836
)
Unproved oil and gas properties
177,787

 
284,538

Wells in progress
201,241

 
387,432

Oil and gas properties held for sale, net
1,109,517

 
641

Other property and equipment, net of accumulated depreciation of $41,958 and $32,956, respectively
137,553

 
153,100

Total property and equipment, net
4,364,694

 
4,950,280

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
107,029

 
120,701

Restricted cash
49,000

 
—

Other noncurrent assets
18,101

 
31,673

Total other noncurrent assets
174,130

 
152,374

Total Assets
$
5,785,433

 
$
5,621,643

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
277,571

 
$
302,517

Derivative liability
51,059

 
8

Total current liabilities
328,630

 
302,525

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
—

 
202,000

Senior Notes, net of unamortized deferred financing costs (note 5)
2,765,398

 
2,315,970

Senior Convertible Notes, net of unamortized discount and deferred financing costs (note 5)
128,925

 
—

Asset retirement obligation
66,158

 
137,284

Asset retirement obligation associated with oil and gas properties held for sale
46,290

 
241

Net Profits Plan liability
1,162

 
7,611

Deferred income taxes
453,712

 
758,279

Derivative liability
104,705

 
—

Other noncurrent liabilities
42,538

 
45,332

Total noncurrent liabilities
3,608,888

 
3,466,717

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 86,868,482 and 68,075,700, respectively
869

 
681

Additional paid-in capital
866,239

 
305,607

Retained earnings
994,969

 
1,559,515

Accumulated other comprehensive loss
(14,162
)
 
(13,402
)
Total stockholders’ equity
1,847,915

 
1,852,401

Total Liabilities and Stockholders’ Equity
$
5,785,433

 
$
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 September 30,
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Operating revenues:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
329,165


$
366,615


$
832,130


$
1,201,186

Net gain on divestiture activity (note 3)
22,388

 
2,415

 
3,413

 
38,497

Other operating revenues
1,107

 
2,121

 
2,007

 
13,548

Total operating revenues and other income
352,660


371,151


837,550


1,253,231













Operating expenses:











Oil, gas, and NGL production expense
152,524

 
184,568


445,658


554,404

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
193,966

 
243,879


619,193


680,984

Exploration
13,482

 
19,679


41,942


82,627

Impairment of proved properties
8,049

 
55,990

 
277,834

 
124,430

Abandonment and impairment of unproved properties
3,568

 
6,600

 
5,917

 
24,046

General and administrative
32,679

 
37,782


93,117


124,026

Change in Net Profits Plan liability
(8,314
)

(4,364
)

(6,449
)

(13,174
)
Derivative (gain) loss
(28,037
)
 
(212,253
)

121,086


(285,491
)
Other operating expenses
2,397

 
7,166

 
14,180

 
34,589

Total operating expenses
370,314


339,047


1,612,478


1,326,441













Income (loss) from operations
(17,654
)

32,104


(774,928
)

(73,210
)












Non-operating income (expense):











Interest expense
(47,206
)

(33,157
)

(112,329
)

(96,583
)
Gain (loss) on extinguishment of debt
—

 
—

 
15,722

 
(16,578
)
Other, net
221

 
27

 
232

 
623













Loss before income taxes
(64,639
)

(1,026
)

(871,303
)

(185,748
)
Income tax benefit
23,732

 
4,140


314,505


78,296













Net income (loss)
$
(40,907
)

$
3,114


$
(556,798
)

$
(107,452
)












Basic weighted-average common shares outstanding
78,468

 
67,961

 
71,574

 
67,638













Diluted weighted-average common shares outstanding
78,468

 
68,119

 
71,574

 
67,638













Basic net income (loss) per common share
$
(0.52
)

$
0.05


$
(7.78
)

$
(1.59
)












Diluted net income (loss) per common share
$
(0.52
)

$
0.05


$
(7.78
)

$
(1.59
)












Dividends per common share
$
0.05


$
0.05


$
0.10


$
0.10


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

4

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands)
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
 
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
Net income (loss)
$
(40,907
)
 
$
3,114

 
$
(556,798
)
 
$
(107,452
)
Other comprehensive loss, net of tax:
 
 
 
 
 
 
 
Pension liability adjustment
(255
)
 
(20
)
 
(760
)
 
(772
)
Total other comprehensive loss, net of tax
(255
)
 
(20
)
 
(760
)
 
(772
)
Total comprehensive income (loss)
$
(41,162
)
 
$
3,094

 
$
(557,558
)
 
$
(108,224
)

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

5


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



Additional Paid-in Capital



Accumulated Other Comprehensive Loss

 Total Stockholders’ Equity

Common Stock


Retained Earnings



Shares

Amount




Balances, December 31, 2015
68,075,700


$
681


$
305,607


$
1,559,515


$
(13,402
)

$
1,852,401

Net loss
—


—


—


(556,798
)

—


(556,798
)
Other comprehensive loss
—


—


—


—


(760
)

(760
)
Cash dividends, $ 0.10 per share
—


—


—


(7,748
)

—


(7,748
)
Issuance of common stock under Employee Stock Purchase Plan
140,853


1


2,353


—


—


2,354

Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
198,456


2


(2,343
)

—


—


(2,341
)
Stock-based compensation expense
53,473


1


20,484


—


—


20,485

Issuance of common stock from stock offering
18,400,000


184


530,728


—


—


530,912

Equity component of 1.50% Senior Convertible Notes due 2021 issuance, net of issuance costs
—


—


38,860


—


—


38,860

Purchase of capped call transactions
—


—


(24,183
)

—


—


(24,183
)
Deferred tax liability related to integrated Senior Convertible Notes, net
—


—


(5,267
)

—


—


(5,267
)
Balances, September 30, 2016
86,868,482


$
869


$
866,239


$
994,969


$
(14,162
)

$
1,847,915


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


6

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)

 
For the Nine Months Ended September 30,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(556,798
)
 
$
(107,452
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Net gain on divestiture activity
(3,413
)
 
(38,497
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
619,193

 
680,984

Exploratory dry hole expense
(16
)
 
22,860

Impairment of proved properties
277,834

 
124,430

Abandonment and impairment of unproved properties
5,917

 
24,046

Stock-based compensation expense
20,485

 
20,492

Change in Net Profits Plan liability
(6,449
)
 
(13,174
)
Derivative (gain) loss
121,086

 
(285,491
)
Derivative settlement gain
306,234

 
387,719

Amortization of discount and deferred financing costs
5,687

 
5,803

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

Deferred income taxes
(314,770
)
 
(80,388
)
Plugging and abandonment
(5,222
)
 
(5,540
)
Other, net
(2,392
)
 
3,670

Changes in current assets and liabilities:
 
 
 
Accounts receivable
1,221

 
105,336

Prepaid expenses and other
7,652

 
587

Accounts payable and accrued expenses
(65,166
)
 
(74,247
)
Accrued derivative settlements
19,651

 
9,588

Net cash provided by operating activities
415,012

 
784,849

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
201,829

 
335,103

Capital expenditures
(492,794
)
 
(1,261,871
)
Acquisition of proved and unproved oil and gas properties
(21,853
)
 
(7,088
)
Acquisition deposit held in escrow
(49,000
)
 
—

Other, net
—

 
(990
)
Net cash used in investing activities
(361,818
)
 
(934,846
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
743,000

 
1,604,500

Repayment of credit facility
(945,000
)
 
(1,586,500
)
Debt issuance costs related to credit facility
(3,132
)
 
—

Net proceeds from Senior Notes
492,397

 
490,951

Cash paid to repurchase Senior Notes
(29,904
)
 
(350,000
)
Net proceeds from Senior Convertible Notes
166,681

 
—

Cash paid for capped call transactions
(24,109
)
 
—

Net proceeds from sale of common stock
533,266

 
3,157

Dividends paid
(3,404
)
 
(3,373
)
Net share settlement from issuance of stock awards
(2,341
)
 
(8,502
)
Other, net
—

 
(159
)
Net cash provided by financing activities
927,454

 
150,074

 
 
 
 
Net change in cash and cash equivalents
980,648

 
77

Cash and cash equivalents at beginning of period
18

 
120

Cash and cash equivalents at end of period
$
980,666

 
$
197

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

7

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)

Supplemental schedule of additional cash flow information and non-cash activities:
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
(in thousands)
Supplemental Cash Flow Information:
 
 
 
Cash paid for interest, net of capitalized interest (1)
$
88,109

 
$
88,920

Net cash (refunded) paid for income taxes
$
(4,481
)
 
$
492

 
 
 
 
Supplemental Non-Cash Investing Activities:
 
 
 
Changes in capital expenditure accruals and other
$
(1,287
)
 
$
(183,945
)
____________________________________________
(1)
Cash paid for interest, net of capitalized interest for the nine months ended September 30, 2016, does not include the $10.0 million paid to terminate a second lien facility that was no longer necessary to fund acquisition activity.

As of September 30, 2016, $23.6 million of accrued commissions and payments to Net Profits Plan participants related to divestitures were included in accounts payable and accrued expenses in the Company’s condensed consolidated balance sheets. As of September 30, 2015, there were no accrued commissions or payments to Net Profits Plan participants related to divestitures.

Additionally, dividends of approximately $4.3 million and $3.4 million were declared by the Company’s Board of Directors, but not paid, as of September 30, 2016, and 2015, respectively.

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

8

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

Note 1 - The Company and Business

SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report) in onshore North America.

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

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and the instructions to Quarterly Report on Form 10-Q and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 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 September 30, 2016, and through the filing date of this report.

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 potential 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.

9

•
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 necessary to implement the standards, evaluating the provisions of each of these standards, and assessing their potential 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 potential impact on the Company’s financial statements and disclosures.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. This guidance is to be applied using a retrospective method. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. 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 potential 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 September 30, 2016, and through the filing date of this report.

Note 3 – Assets Held for Sale, Divestitures and Acquisitions
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 on divestiture activity line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).

As of September 30, 2016, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $1.1 billion of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which primarily consists of the Company’s outside-operated Eagle Ford shale assets and all of the Company’s North Rocky Mountain assets outside of its Divide County program (referred to as “Raven/Bear Den” throughout this report). A corresponding aggregate asset retirement obligation liability of $46.3 million is separately presented. The Company expects to close these transactions by year-end or within the first quarter of 2017. There were no material assets held for sale as of December 31, 2015.


10

The following table presents income (loss) before income taxes for the three and nine months ended September 30, 2016, and 2015, of the Company’s assets held for sale as of September 30, 2016; specifically, its outside-operated Eagle Ford shale assets and Raven/Bear Den assets, each of which are considered a significant asset disposal group.

 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Income (loss) before income taxes (1)
$
20,309

 
$
(15,132
)
 
$
(289,563
)
 
$
55,445

____________________________________________
(1) Income (loss) before income taxes reflects oil, gas, and NGL production revenue less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion, and related general and administrative expense and exploration overhead. Additionally, loss before income taxes for the nine months ended September 30, 2016, includes $269.6 million of proved property impairments, and income (loss) before income taxes for the three and nine months ended September 30, 2015, includes $17.8 million of proved property impairments.

Subsequent to September 30, 2016, the Company entered into a definitive agreement for the sale of its Raven/Bear Den assets for a gross purchase price of $785.0 million, subject to customary purchase price adjustments. This transaction is expected to close in early December 2016, with the net proceeds expected to be used to partially fund the QStar Acquisition (defined and discussed below). The closing of this divestiture is subject to the satisfaction of customary closing conditions, and there can be no assurance that this transaction will close on the expected closing date or at all.

Divestitures

During the third quarter of 2016, the Company divested certain of its Permian and Rocky Mountain assets in separate packages that were previously classified as held for sale. The Permian assets consisted of non-core properties in New Mexico and were divested for total cash received at closing, net of paid or accrued commissions and payments to Net Profits Plan participants (referred throughout this report as “net divestiture proceeds”) of $54.6 million. The Company recorded a net loss of $10.1 million related to these divested assets for the nine months ended September 30, 2016. The Rocky Mountain assets, which consisted of certain non-core properties in the Williston and Powder River Basins, were divested in two separate packages for total net divestiture proceeds of $110.6 million. The Company recorded a net gain of $16.4 million related to these divested assets for the nine months ended September 30, 2016. Certain of these sold assets were written down in the first quarter of 2016 and subsequently written up in the second quarter of 2016 based on changes in the estimated fair value less selling costs. Each of these divestitures is subject to normal post-closing adjustments, and the respective post-closings are expected to occur in the fourth quarter of 2016 or early 2017.
    
During the second quarter of 2015, the Company divested its Mid-Continent assets in separate packages for net divestiture proceeds received at closing of $310.2 million and recorded a net gain of $108.4 million for the nine months ended September 30, 2015. Final settlement of these divestitures occurred in the fourth quarter of 2015 and first quarter of 2016. In conjunction with these divestitures, the Company closed its Tulsa, Oklahoma office in 2015. Please refer to Note 12 - Exit and Disposal Costs for additional discussion.

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

Acquisitions

During the third quarter of 2016, the Company entered into a definitive purchase agreement with Rock Oil Holdings, LLC to acquire all membership interests of JPM EOC Opal, LLC, which owned proved and unproved properties in the Midland Basin, for an aggregate purchase price of $980.0 million, subject to customary purchase price adjustments (referred to throughout this report as the “Rock Oil Acquisition”). Upon executing the purchase agreement, the Company tendered a $49.0 million deposit that was held in escrow as of September 30, 2016, and reflected as restricted cash in the accompanying balance sheets.

The Rock Oil Acquisition closed on October 4, 2016, for an adjusted purchase price of $991.0 million and was funded by the Company’s recent asset divestitures, and the Company’s equity, Senior Convertible Notes, and 2026 Notes offerings during the third quarter of 2016, as defined and discussed in Note 5 - Long-Term Debt and Note 13 - Equity. This acquisition is subject to normal post-closing adjustments that are expected to occur in the fourth quarter of 2016 or early 2017. Final purchase accounting for the Rock Oil Acquisition transaction was not complete at the time this report was filed, and as such, certain disclosures required by ASC Topic

11

805, Business Combinations, have not been made herein. The Company will include this information in its 2016 Annual Report on Form 10-K.

Subsequent to September 30, 2016, the Company entered into a definitive purchase agreement with QStar LLC (“QStar”) to acquire proved and unproved properties in the Midland Basin. Additionally, the Company entered into a Ratification and Joinder Agreement (“Joinder Agreement”) with RRP-QStar, LLC (“RRP”), whereby the Company agreed to acquire RRP’s interests in the same Midland Basin assets on the same terms and conditions set forth in the agreement with QStar LLC, except as such terms are modified under the Joinder Agreement. Under these agreements, the Company agreed to purchase QStar’s and RRP’s interest in the Midland Basin assets for $1.1 billion in cash consideration, and approximately 13.4 million shares of the Company’s common stock, par value $0.01 per share, as discussed further in Note 13 - Equity. The Company intends to fund the cash portion of the transactions with proceeds from planned asset divestitures and borrowings under the credit facility. Together these transactions are referred to as the “QStar Acquisition” throughout this report and are expected to close mid-December 2016. The closing of the QStar and RRP transactions are subject to the satisfaction of customary closing conditions, and there can be no assurance that either of these transactions will close on the expected closing dates or at all.

Note 4 - Income Taxes

The income tax benefit recorded for each of the three and nine months ended September 30, 2016, and 2015, differs from the amount 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 impacts 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 September 30,
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Current portion of income tax expense (benefit):
 
 
 
 
 
 
 
Federal
$
—

 
$
—

 
$
—

 
$
—

State
24

 
(8,308
)
 
265

 
2,092

Deferred portion of income tax expense (benefit)
(23,756
)
 
4,168

 
(314,770
)
 
(80,388
)
Income tax benefit
$
(23,732
)
 
$
(4,140
)
 
$
(314,505
)
 
$
(78,296
)
Effective tax rate
36.7
%
 
403.5
%
 
36.1
%
 
42.2
%

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 Company activities among multiple state tax jurisdictions. Cumulative effects of state tax 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 2013. 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. In accordance with regulations, the Senior Convertible Notes and the capped call transactions, as defined and discussed in Note 5 - Long-Term Debt, were identified during the quarter as an integrated transaction.


12

Note 5 - Long-Term Debt

Revolving Credit Facility

During 2016, the following amendments have been made to the Company’s Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) with its lenders:

•
On April 8, 2016, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into a Sixth Amendment to the Credit Agreement, which reduced the Company’s borrowing base to $1.25 billion. This expected reduction was primarily due to a decline in commodity prices, which resulted in a decrease in the Company’s proved reserves as of December 31, 2015. 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, this amendment revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below. The Company incurred approximately $3.1 million in deferred financing costs associated with this amendment to the Credit Agreement.
•
On August 8, 2016, the Company entered into a Seventh Amendment to the Credit Agreement to allow for capped call transactions.
•
Upon issuing the Senior Convertible Notes and 2026 Notes (as defined and discussed below) during the third quarter of 2016, the Company’s borrowing base and aggregate lender commitments were reduced from $1.25 billion to $1.1 billion.
•
On September 30, 2016, the Company entered into an Eighth Amendment to the Credit Agreement. Pursuant to the amendment, and as part of the regular, semi-annual borrowing base redetermination process, the Company’s borrowing base was increased to $1.35 billion and aggregate lender commitments increased to $1.25 billion. This increase was primarily due an increase in commodity prices and the value of the proved reserves associated with the Rock Oil Acquisition. The borrowing base increase became effective upon the closing of the Rock Oil Acquisition on October 4, 2016.

The Credit Agreement, as amended, provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019. 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 next scheduled redetermination date is April 1, 2017.
 
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. Financial covenants under the Credit Agreement require, as of the last day of each of the Company’s fiscal quarters, the Company’s (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0. The Company was in compliance with all financial and non-financial covenants under the Credit Agreement as of September 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 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 the prime rate, plus the applicable margin from the utilization table below.  Commitment fees are accrued on the unused portion of the aggregate lender commitment amount and are included in interest expense in the accompanying statements of operations. The borrowing base utilization grid under the 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
%


13

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the credit facility as of October 26, 2016, September 30, 2016, and December 31, 2015:

 
As of October 26, 2016
 
As of September 30, 2016
 
As of December 31, 2015
 
(in thousands)
Credit facility balance (1)
$
—

 
$
—

 
$
202,000

Letters of credit (2)
200

 
200

 
200

Available borrowing capacity
1,249,800

 
1,106,675

 
1,297,800

Total aggregate lender commitment amount
$
1,250,000

 
$
1,106,875

 
$
1,500,000

____________________________________________
(1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and 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.
Senior Notes
The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of September 30, 2016, and December 31, 2015, consisted of the following:

 
As of September 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

 
$
3,547

 
$
343,408

 
$
350,000

 
$
4,106

 
$
345,894

6.125% Senior Notes due 2022
561,796

 
7,274

 
554,522

 
600,000

 
8,714

 
591,286

6.50% Senior Notes due 2023
394,985

 
4,618

 
390,367

 
400,000

 
5,231

 
394,769

5.0% Senior Notes due 2024
500,000

 
6,763

 
493,237

 
500,000

 
7,455

 
492,545

5.625% Senior Notes due 2025
500,000

 
7,845

 
492,155

 
500,000

 
8,524

 
491,476

6.75% Senior Notes due 2026
500,000

 
8,291

 
491,709

 
—

 
—

 
—

Total
$
2,803,736

 
$
38,338

 
$
2,765,398

 
$
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 September 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, which resulted in a net gain on extinguishment of debt of approximately $15.7 million. 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 Senior Notes upon cash settlement.


14

2026 Notes

On September 12, 2016, the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due September 15, 2026, at par (the “2026 Notes”). The Company received net proceeds of $491.6 million after deducting paid and accrued fees of $8.4 million, which are being amortized as deferred financing costs over the life of the 2026 Notes. The net proceeds were used to partially fund the Rock Oil Acquisition that closed on October 4, 2016.

Senior Convertible Notes

On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. The Company received net proceeds of $166.7 million after deducting fees of $5.8 million, of which a portion is being amortized over the life of the Senior Convertible Notes. The net proceeds were used to partially fund the Rock Oil Acquisition that closed on October 4, 2016.

The Senior Convertible Notes mature on July 1, 2021, unless earlier repurchased or converted. Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under the following circumstances: (1) during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2016, if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (2) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price (as defined in the indenture) per $1,000 principal amount of Notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (3) upon the occurrence of specified corporate events. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time, regardless of the foregoing circumstances. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment.
    
The Company has initially elected a net-settlement method to satisfy its conversion obligation, which allows the Company to settle the principal amount of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. The Senior Convertible Notes were not convertible at the option of holders as of September 30, 2016, or through the filing date of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of September 30, 2016, did not exceed the principal amount.

In accounting for the Senior Convertible Notes at issuance, the Company allocated proceeds from the Senior Convertible Notes into debt and equity components according to the authoritative accounting guidance for convertible debt instruments that may be fully or partially settled in cash upon conversion. The initial carrying amount of the debt component, which approximates its fair value, was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25 percent. The excess of the principal amount of the Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The Company incurred transaction costs of $5.8 million relating to the issuance of the Senior Convertible Notes, which were allocated between the debt and equity components in proportion to their determined fair value amounts. The debt discount and debt issuance costs are amortized to the carrying value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Upon issuance of the Senior Convertible Notes, the Company recorded $132.3 million as long-term debt and $40.2 million as additional paid-in capital in stockholders’ equity in the accompanying balance sheets.


15

The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets, consisted of the following as of September 30, 2016:

 
As of September 30, 2016
 
(in thousands)
Principal amount of Senior Convertible Notes
$
172,500

Original debt discount due to allocation of proceeds to equity
(40,217
)
Accumulated amortization of debt discount
953

Unamortized deferred financing costs
(4,311
)
Net carrying amount
$
128,925


If the Company undergoes a fundamental change, holders of the Senior Convertible Notes may require the Company to repurchase for cash all or any portion of their notes at a fundamental change repurchase price equal to 100% of the principal amount of the Senior Convertible Notes to be repurchased, plus accrued and unpaid interest. The indenture governing the Senior Convertible Notes contains customary events of default with respect to the Senior Convertible Notes, including that upon certain events of default, the Trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Senior Convertible Notes by notice to the Company, may declare 100% of the principal and accrued and unpaid interest, if any, due and payable immediately. In case of certain events of bankruptcy, insolvency or reorganization involving the Company or a significant subsidiary, 100% of the principal and accrued and unpaid interest on the Senior Convertible Notes will automatically become due and payable.

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of September 30, 2016, and through the filing date of this report.

Capped Call Transactions

In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The aggregate cost of the capped call transactions was approximately $24.2 million. The capped call transactions are generally expected to reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock, as measured under the terms of the capped call transactions (“market price per share”), is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible Notes and is subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the Senior Convertible Notes. The cap price of the capped call transactions will initially be $60.00 per share, and is subject to certain adjustments under the terms of the capped call transactions. If, however, the market price per share exceeds the cap price of the capped call transactions, there would be dilution and/or there would not be an offset of such potential cash payments, in each case, to the extent that such market price per share exceeds the cap price of the capped call transactions.

The Company evaluated the capped call transactions under authoritative accounting guidance and determined that they should be accounted for as separate transactions and classified as equity instruments with no recurring fair value measurement recorded.

Note 6 - Commitments and Contingencies

Commitments

There were no material changes in commitments during the first nine months 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 in the Company’s operated Eagle Ford shale program. 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 become effective upon the constructed pipeline becoming operational, which is expected to be in the fourth quarter of 2016.
 

16

During 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 nine months ended September 30, 2016, the Company incurred $1.1 million and $8.7 million, respectively, of expenses 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 nine months ended September 30, 2015, the Company incurred drilling rig termination and standby fees of $2.2 million and $8.1 million, respectively. As of September 30, 2016, the Company had drilling rig commitments totaling $20.0 million through 2018. Early termination of these contracts as of September 30, 2016, would result in termination penalties of $15.1 million, which would be in lieu of paying the remaining $20.0 million commitment. Additionally, the Company entered into drilling rig agreements to begin operating two rigs in the Midland Basin in the fourth quarter of 2016, neither of which has a material long-term commitment.

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 September 30, 2016, the Company is committed to deliver 290 Bcf of natural gas and 38 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 $333.2 million at September 30, 2016. However, because the Company owns a 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 $235.2 million if the $333.2 million shortfall payment was required. The Company’s outside-operated Eagle Ford shale assets, subject to this commitment and other material throughput commitments, are held for sale as of September 30, 2016.

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 September 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 1,556 Bcf of natural gas, 69 MMBbl of crude oil, and 13 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 $235.2 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 and water disposal 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 September 30, 2016, the Company had $2.7 million accrued for estimated exposure related to potential claims for payment of royalties on certain Federal 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.


17

Note 7 - Compensation Plans

Equity Incentive Compensation Plan

As of September 30, 2016, 5.5 million shares of common stock remained available for grant under the Company’s 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 primarily 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 September 30, 2016, and 2015, was $2.3 million and $2.4 million, respectively, and $8.2 million and $7.4 million for the nine months ended September 30, 2016, and 2015, respectively. As of September 30, 2016, there was $18.9 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2019.

A summary of the status and activity of non-vested PSUs for the nine months ended September 30, 2016, is presented in the following table:
 
PSUs (1)
 
Weighted-Average
 Grant-Date
Fair Value
Non-vested at beginning of year
626,328

 
$
61.81

Granted
447,971

 
$
26.56

Vested
(129,422
)
 
$
64.19

Forfeited
(99,414
)
 
$
57.43

Non-vested at end of quarter
845,463

 
$
43.29

____________________________________________
(1) 
The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero to two.

During the nine months ended September 30, 2016, the Company granted 447,971 PSUs with a fair value of $11.9 million as part of its regular annual long-term equity compensation program. These PSUs will fully vest on the third anniversary of the date of the grant. Also, during this period, the Company settled PSUs that were granted in 2013, which earned a 0.2 times multiplier, by issuing 30,061 net shares of the Company’s common stock in accordance with the terms of the respective PSU awards. The Company and the majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Incentive Compensation Plan and individual award agreements. As a result, 14,809 shares were withheld to satisfy income and payroll tax withholding obligations that arose upon delivery of the shares underlying the 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 primarily within general and administrative expense and exploration expense over the vesting periods of the award.

Total compensation expense recorded for RSUs was $2.8 million and $4.1 million for the three months ended September 30, 2016, and 2015, respectively, and $9.3 million and $9.9 million for the nine months ended September 30, 2016, and 2015, respectively. As of September 30, 2016, there was $17.8 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2019.


18

A summary of the status and activity of non-vested RSUs for the nine months ended September 30, 2016, is presented in the following table:

 
RSUs
 
Weighted-Average
 Grant-Date
Fair Value
Non-vested at beginning of year
543,737

 
$
55.01

Granted
417,065

 
$
28.08

Vested
(240,233
)
 
$
58.08

Forfeited
(79,393
)
 
$
46.32

Non-vested at end of quarter
641,176

 
$
37.42


During the nine months ended September 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, during the nine months ended September 30, 2016, the Company released 240,233 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 168,395 net shares of common stock. The remaining 71,838 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 nine months ended September 30, 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 compensation expense of $1.2 million and $1.4 million, respectively.

Beginning with the awards granted in 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 of 1986, as amended (“IRC”). The Company had 808,854 shares available for issuance under the ESPP as of September 30, 2016. There were 140,853 and 96,285 shares issued under the ESPP during the nine months ended September 30, 2016, and 2015, respectively, and the Company received $2.4 million and $3.2 million, respectively, in cash through payroll deductions. The Company recorded compensation expense of $1.7 million in each of the nine months ended September 30, 2016, and 2015. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Net Profits Plan

Cash payments made or accrued under the Net Profits Plan for the nine months ended September 30, 2016, totaled $26.8 million, which included accrued payments of $21.6 million resulting from the divestitures of properties subject to the Net Profits Plan in the third quarter of 2016. Payments related to divested properties are accounted for as a reduction in the net gain on divestiture activity line item in the accompanying statement of operations. Cash payments made or accrued under the Net Profits Plan for the nine months ended September 30, 2015, totaled $7.4 million, which included payments of $3.8 million resulting from the divestitures of the Company’s Mid-Continent properties subject to the Net Profits Plan in the second quarter of 2015.

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

19

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 September 30,
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Service cost
$
2,050

 
$
1,989

 
$
6,150

 
$
5,963

Interest cost
727

 
624

 
2,181

 
1,872

Expected return on plan assets that reduces periodic pension cost
(559
)
 
(546
)
 
(1,677
)
 
(1,637
)
Amortization of prior service cost
4

 
4

 
13

 
13

Amortization of net actuarial loss
396

 
371

 
1,187

 
1,114

Net periodic benefit cost
$
2,618

 
$
2,442

 
$
7,854

 
$
7,325


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 $11.0 million to the Pension Plans during the nine months ended September 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, contingent PSUs, and shares into which the Senior Convertible Notes are convertible. The treasury stock method is used to measure the dilutive impact of these stock awards and the Senior Convertible Notes.

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.

On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which allows the Company to settle the principal amount of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. However, the Company has not made this a formal legal irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business conditions warrant. For accounting purposes, the treasury stock method is used to measure the potential dilutive impact of shares associated with this conversion feature. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the three months ended September 30, 2016. In connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions are not reflected in diluted net income per share as they will always be anti-dilutive. Please refer to Note 5 - Long-Term Debt for additional discussion.


20

When the Company recognizes a loss from continuing operations, as was the case for the three and nine months ended September 30, 2016, and the nine months ended September 30, 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 for the periods presented:
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Weighted-average common shares excluded from diluted earnings per share due to their anti-dilutive effect:
 
 
 
 
 
 
 
Unvested RSUs and contingent PSUs
506

 
—

 
193

 
380


The following table sets forth the calculations of basic and diluted earnings per share:
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except per share amounts)
Net income (loss)
$
(40,907
)
 
$
3,114

 
$
(556,798
)
 
$
(107,452
)
Basic weighted-average common shares outstanding
78,468

 
67,961

 
71,574

 
67,638

Add: dilutive effect of unvested RSUs and contingent PSUs
—

 
158

 
—

 
—

Diluted weighted-average common shares outstanding
78,468

 
68,119

 
71,574

 
67,638

Basic net income (loss) per common share
$
(0.52
)
 
$
0.05

 
$
(7.78
)
 
$
(1.59
)
Diluted net income (loss) per common share
$
(0.52
)
 
$
0.05

 
$
(7.78
)
 
$
(1.59
)
Subsequent to September 30, 2016, the Company entered into definitive purchase agreements for the QStar Acquisition expected to close in mid-December 2016, which will be partially funded by a private issuance of approximately 13.4 million shares of common stock. Please refer to Note 13 - Equity for additional discussion.

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 September 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.


21

Subsequent to September 30, 2016, the Company entered into derivative fixed price swap contracts through the first quarter of 2019 for a total of 5.4 million MMBtu of gas production at contract prices ranging from $3.15 to $3.46 per MMBtu, and derivative fixed price swap contracts through the fourth quarter of 2019 for 4.1 million Bbls of NGL production at contract prices ranging from $13.02 per Bbl to $47.67 per Bbl. Additionally, subsequent to September 30, 2016, the Company entered into derivative collar contracts through the fourth quarter of 2019 for a total of 3.3 million Bbls of oil production with contract floor prices of $50.00 per Bbl and contract ceiling prices ranging from $58.18 to $61.55 per Bbl.

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

Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(MBbls)
 
(per Bbl)
Fourth quarter 2016
 
2,249

 
$
59.03

2017
 
5,612

 
$
46.46

Total
 
7,861

 
 

Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(MBbls)
 
(per Bbl)
 
(per Bbl)
Fourth quarter 2016
 
881

 
$
40.00

 
$
51.52

2017
 
2,463

 
$
45.00

 
$
54.09

Total
 
3,344

 
 
 
 

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)
Fourth quarter 2016
 
26,700

 
$
3.34

 
—

 
$
—

 
26,700

2017
 
99,549

 
$
3.94

 
—

 
$
—

 
99,549

2018
 
57,970

 
$
3.70

 
(30,606
)
 
$
4.27

 
27,364

2019
 
24,415

 
$
4.34

 
(24,415
)
 
$
4.34

 
—

Total*
 
208,634

 
 
 
(55,021
)
 
 
 
153,613

*Total net volumes of natural gas swaps are comprised of IF El Paso Permian (1%), IF HSC (96%), and IF NNG Ventura (3%).


22

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)
Fourth quarter 2016
 
687

$
8.71

 
792

$
18.53

 
226

$
22.91

 
182

$
23.25

2017
 
3,062

$
8.92

 
1,530

$
20.78

 
—

$
—

 
—

$
—

2018
 
2,435

$
10.18

 
593

$
21.60

 
—

$
—

 
—

$
—

2019
 
1,200

$
10.92

 
—

$
—

 
—

$
—

 
—

$
—

2020
 
539

$
11.13

 
—

$
—

 
—

$
—

 
—

$
—

Total
 
7,923

 
 
2,915

 
 
226

 
 
182

 

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net asset of $61.1 million as of September 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 September 30, 2016
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
109,818

 
Current liabilities
 
$
51,059

Commodity contracts
Noncurrent assets
 
107,029

 
Noncurrent liabilities
 
104,705

Derivatives not designated as hedging instruments
 
 
$
216,847

 
 
 
$
155,764


 
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 September 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.  


23

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts:
 
 
Derivative Assets
 
Derivative Liabilities
 
 
As of
 
As of
Offsetting of Derivative Assets and Liabilities
 
September 30, 2016
 
December 31, 2015
 
September 30, 2016
 
December 31, 2015
 
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
 
$
216,847

 
$
488,411

 
$
(155,764
)
 
$
(8
)
Amounts not offset in the accompanying balance sheets
 
(136,358
)
 
(8
)
 
136,358

 
8

Net amounts
 
$
80,489

 
$
488,403

 
$
(19,406
)
 
$
—

    
The following table summarizes the components of the derivative (gain) loss presented in the accompanying statements of operations:
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Derivative settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
(49,241
)
 
$
(90,493
)
 
$
(221,397
)
 
$
(270,622
)
Gas contracts (1)
(10,096
)
 
(19,167
)
 
(82,588
)
 
(92,279
)
NGL contracts
1,841

 
(4,035
)
 
(2,249
)
 
(24,818
)
Total derivative settlement gain
$
(57,496
)

$
(113,695
)

$
(306,234
)

$
(387,719
)
 
 
 
 
 
 
 
 
Total derivative (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
(733
)
 
$
(131,728
)
 
$
49,608

 
$
(138,839
)
Gas contracts
(14,006
)
 
(66,538
)
 
24,460

 
(142,807
)
NGL contracts
(13,298
)
 
(13,987
)
 
47,018

 
(3,845
)
Total derivative (gain) loss:
$
(28,037
)

$
(212,253
)

$
121,086


$
(285,491
)
____________________________________________
(1)  
Natural gas derivative settlements for the nine months ended September 30, 2015, include a $15.3 million gain on the early settlement of future contracts as a result of divesting the Company’s Mid-Continent assets during the second quarter of 2015.

Credit Related Contingent Features

As of September 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 Sixth Amendment to the Credit Agreement 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.
 

24

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 summarizes the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of September 30, 2016:



Level 1

Level 2

Level 3

(in thousands)
Assets:








Derivatives (1)
$
—


$
216,847


$
—

Liabilities:








Derivatives (1)
$
—


$
155,764


$
—

Net Profits Plan (1)
$
—


$
—


$
1,162

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

The following table summarizes the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 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.


25

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.

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 $124.8 million as of December 31, 2015. None of the Company’s property and equipment, net, was measured at fair value in the accompanying balance sheets as of September 30, 2016.
    
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 September 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 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. Impairments on proved properties during the nine months ended September 30, 2016, totaled $277.8 million and related primarily to the decline in proved and risk-adjusted probable and possible reserve expected cash flows for the Company’s outside-operated Eagle Ford shale 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 and 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,

26

and estimated reserve values. Abandonment and impairment expense on unproved properties was $5.9 million for the nine months ended September 30, 2016, and $78.6 million for the year ended December 31, 2015. In both periods, 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 no longer intended to develop and made the subsequent decision to sell.

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. There were no assets held for sale recorded at fair value as of September 30, 2016, or December 31, 2015. Please refer to Note 3 – Assets Held for Sale, Divestitures and Acquisitions.

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.

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 using a discount rate of 10 percent, and is intended to represent the Company’s best estimate of the present value of expected future payments under the Net Profits Plan. The estimate is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. Pricing assumptions used are five one-year strip prices with the fifth year’s pricing then carried out indefinitely with adjustments made 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 estimate is volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets. Due to divestitures of assets subject to the Net Profits Plan in recent years, the liability has been significantly reduced.


27

The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs:
 
For the Nine Months Ended September 30, 2016
 
(in thousands)
Beginning balance
$
7,611

Net increase in liability (1)
20,389

Net settlements (1) (2)
(26,838
)
Transfers in (out) of Level 3
—

Ending balance
$
1,162


____________________________________________
(1) 
Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item in the accompanying statements of operations.
(2) 
Settlements represent cash payments made or accrued under the Net Profits Plan. The amount in the table includes cash payments made or accrued under the Net Profits Plan of $21.6 million for the nine months ended September 30, 2016, as a result of the divestitures of properties subject to the Net Profits Plan.

Long-Term Debt
The following table reflects the fair value of the Senior Notes and Senior Convertible Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes and Senior Convertible Notes were not presented at fair value on the accompanying balance sheets as of September 30, 2016, or December 31, 2015, as they were recorded at carrying value, net of any unamortized discount and 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 and the bifurcation of the Senior Convertible Notes.

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

 
$
354,761

 
$
350,000

 
$
262,938

6.125% Senior Notes due 2022
$
561,796

 
$
567,414

 
$
600,000

 
$
440,250

6.50% Senior Notes due 2023
$
394,985

 
$
400,910

 
$
400,000

 
$
296,000

5.0% Senior Notes due 2024
$
500,000

 
$
472,220

 
$
500,000

 
$
334,065

5.625% Senior Notes due 2025
$
500,000

 
$
470,000

 
$
500,000

 
$
326,875

6.75% Senior Notes due 2026
$
500,000

 
$
506,250

 
$
—

 
$
—

1.50% Senior Convertible Notes due 2021
$
172,500

 
$
210,990

 
$
—

 
$
—


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.

Note 12 - Exit and Disposal Costs

In the third quarter of 2016, the Company conducted a company-wide reduction in workforce and announced plans to close the Company’s Billings, Montana regional office and relocate certain employees to the Company’s corporate office in Denver, Colorado or other Company offices. This decision was made in an effort to reduce future costs and better position the Company for efficient growth in response to prolonged commodity price weakness. The Company expects to incur approximately $8 million of exit and disposal costs related to termination benefits, relocation of certain employees, and other related matters, excluding lease expenses discussed in the next paragraph, all of which will be included in general and administrative expense in the accompanying statements of operations. The majority of these costs are expected to be recorded in 2016 with the remaining costs recorded in early 2017. The Company incurred $2.9 million of exit and disposal costs during the three months ended September 30, 2016.
Additionally, during the third quarter of 2016, the Company announced plans to vacate its office space in Billings, Montana effective November 1, 2016. As of September 30, 2016, the Company was obligated to pay lease costs of approximately $6.5 million over the remaining lease term. Subsequent to September 30, 2016, the Company and its lessor executed an agreement to terminate this lease effective November 11, 2016, and pay a fee of $3.2 million in lieu of the $6.5 million in lease costs.
In conjunction with its Mid-Continent divestitures in 2015, the Company closed its Tulsa, Oklahoma office and incurred $1.0 million and $9.5 million of exit and disposal costs included in general and administrative expense in the accompanying statements of operations for the three and nine months ended September 30, 2015, respectively. The remaining exit and disposal costs were incurred in the fourth quarter of 2015, with the exception of lease expenses discussed in the next paragraph.

Additionally, the Company vacated its office space in Tulsa during the third quarter of 2015 and subsequently subleased its space. As of September 30, 2016, the Company is obligated to pay lease costs of approximately $3.8 million, net of expected income from office space subleased, which will be expensed over the remaining duration of the lease, which expires in 2022.

Note 13 - Equity
On August 12, 2016, the Company completed an underwritten public offering of 18.4 million shares of its common stock at an offering price of $30.00 per share. Net proceeds from the offering totaled $530.9 million, after deducting underwriting discounts and commissions and offering expenses, which the Company used to partially fund the Rock Oil Acquisition that closed subsequent to September 30, 2016. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the Securities and Exchange Commission.
Subsequent to September 30, 2016, the Company announced the QStar Acquisition, discussed in Note 3 – Assets Held for Sale, Divestitures and Acquisitions. The Company plans to partially fund the acquisition through a private issuance of $500.0 million of the Company’s common stock to the sellers based on the volume-weighted average price for the 30 days prior to the execution of the definitive purchase agreements for the QStar Acquisition of $37.35 per share, or approximately 13.4 million shares.


28

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.

During 2016, we have focused our capital investments on our development positions in the Permian Basin, Eagle Ford shale, and Bakken/Three Forks resource plays. Subsequent to September 30, 2016, we announced:

•
closing the Rock Oil Acquisition in the Midland Basin;

•
entering into the QStar Acquisition agreements in the Midland Basin; and

•
entering into an agreement to sell our Raven/Bear Den and other assets in the Williston Basin.
    
We have outlined a straight-forward strategy to focus on expanding our Tier 1 assets in the Permian Basin and developing these assets along with our operated Eagle Ford shale assets. As part of this strategy, we will continue to core up our portfolio, so that we can concentrate our investment dollars in our highest return programs and bring that value forward through accelerated development activity.

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

•
Average net daily production for the three months ended September 30, 2016, was 47.2 MBbls of oil, 403.0 MMcf of gas, and 39.5 MBbls of NGLs, for a quarterly equivalent daily production rate of 153.9 MBOE, compared with 174.5 MBOE for the same period in 2015. Please see additional discussion below under Production Results.

•
We recorded a net loss of $40.9 million, or $0.52 per diluted share, for the three months ended September 30, 2016, compared with net income of $3.1 million, or $0.05 per diluted share, for the three months ended September 30, 2015. Please refer to Comparison of Financial Results and Trends Between the Three Months and Nine Months Ended September 30, 2016, and 2015, below for additional discussion regarding the components of net income (loss) for each period.
 
•
Costs incurred for oil and gas property acquisitions, exploration and development activities for the three months ended September 30, 2016, totaled $156.5 million, compared with $286.6 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 September 30, 2016 totaled $158.1 million, compared with $235.3 million for the same period in 2015.

•
Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2016, was $205.1 million, compared with $259.4 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 income (loss) and net cash provided by operating activities to adjusted EBITDAX.


29

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.

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

 
For the Three Months Ended
 
September 30, 2016
 
June 30, 2016
 
September 30, 2015
Crude Oil (per Bbl):
 
 
 
 
 
Average NYMEX contract monthly price
$
44.94

 
$
45.59

 
$
46.48

Realized price, before the effect of derivative settlements
$
38.81

 
$
39.38

 
$
40.03

Effect of oil derivative settlements
$
11.34

 
$
17.59

 
$
20.02

 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Average NYMEX monthly settle price (per MMBtu)
$
2.81

 
$
1.95

 
$
2.75

Realized price, before the effect of derivative settlements (per Mcf)
$
2.71

 
$
1.79

 
$
2.77

Effect of natural gas derivative settlements (per Mcf)
$
0.27

 
$
0.81

 
$
0.45

 
 
 
 
 
 
NGLs (per Bbl): 
 
 
 
 
 
Average OPIS price (1)
$
19.74

 
$
20.04

 
$
18.22

Realized price, before the effect of derivative settlements
$
16.58

 
$
16.12

 
$
15.18

Effect of NGL derivative settlements
$
(0.51
)
 
$
(0.51
)
 
$
0.94

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

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. Oil markets continue to be unstable as a result of over-supply. While we have realized production declines in the United States, declines elsewhere in the world are required to balance the market.

Natural gas pricing increased during the third quarter of 2016, largely as a result of demand growth from gas fired power generation and exports exceeding prior expectations. 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.

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 reduced supply and demand increases across all commodities.


30

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 October 26, 2016, and September 30, 2016:

 
As of October 26, 2016
 
As of September 30, 2016
NYMEX WTI oil (per Bbl)
$
51.78

 
$
50.76

NYMEX Henry Hub gas (per MMBtu)
$
3.05

 
$
3.07

OPIS NGLs (per Bbl)
$
23.23