10-Q

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, 2015
Commission File Number 001-31539
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
 
Accelerated filer o
 
 
 
Non-accelerated filer o  
(Do not check if a smaller reporting company)
 
Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

As of October 21, 2015, the registrant had 67,974,771 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,
2015
 
December 31,
2014
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
197

 
$
120

Accounts receivable
171,067

 
322,630

Derivative asset
347,299

 
402,668

Prepaid expenses and other
19,114

 
19,625

Total current assets
537,677

 
745,043

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
7,468,331

 
7,348,436

Less - accumulated depletion, depreciation, and amortization
(3,240,109
)
 
(3,233,012
)
Unproved oil and gas properties
381,869

 
532,498

Wells in progress
452,436

 
503,734

Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $74,894 and $22,482, respectively
29,173

 
17,891

Other property and equipment, net of accumulated depreciation of $43,197 and $37,079, respectively
359,339

 
334,356

Total property and equipment, net
5,451,039

 
5,503,903

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
147,530

 
189,540

Other noncurrent assets
77,615

 
78,214

Total other noncurrent assets
225,145

 
267,754

Total Assets
$
6,213,861

 
$
6,516,700

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
361,734

 
$
640,684

Derivative liability
2,900

 
—

Deferred tax liability
120,563

 
142,976

Other current liabilities
—

 
1,000

Total current liabilities
485,197

 
784,660

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
184,000

 
166,000

Senior Notes (note 5)
2,350,000

 
2,200,000

Asset retirement obligation
118,153

 
120,867

Net Profits Plan liability
13,962

 
27,136

Deferred income taxes
833,352

 
891,681

Derivative liability
2,019

 
70

Other noncurrent liabilities
40,341

 
39,631

Total noncurrent liabilities
3,541,827

 
3,445,385

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 67,968,714 and 67,463,060, respectively
680

 
675

Additional paid-in capital
298,438

 
283,295

Retained earnings
1,899,803

 
2,013,997

Accumulated other comprehensive loss
(12,084
)
 
(11,312
)
Total stockholders’ equity
2,186,837

 
2,286,655

Total Liabilities and Stockholders’ Equity
$
6,213,861

 
$
6,516,700

 
 
 
 
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,
 
2015
 
2014
 
2015
 
2014
Operating revenues:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
366,615


$
617,207


$
1,201,186


$
1,894,977

Net gain (loss) on divestiture activity (note 3)
2,415

 
(5,432
)
 
38,497

 
52

Other operating revenues
2,121

 
7,011

 
13,548

 
31,457

Total operating revenues and other income
371,151


618,786


1,253,231


1,926,486













Operating expenses:











Oil, gas, and NGL production expense
184,568


178,390


554,404


519,697

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
243,879


183,259


680,984


548,255

Exploration
19,679

 
34,556


82,627


80,161

Impairment of proved properties
55,990

 
—

 
124,430

 
—

Abandonment and impairment of unproved properties
6,600

 
15,522

 
24,046

 
18,487

General and administrative
37,782

 
41,696


124,026


114,862

Change in Net Profits Plan liability
(4,364
)

(6,399
)

(13,174
)

(15,280
)
Derivative (gain) loss
(212,253
)
 
(190,661
)

(285,491
)

33,470

Other operating expenses
7,166

 
5,444

 
34,589

 
19,505

Total operating expenses
339,047


261,807


1,326,441


1,319,157













Income (loss) from operations
32,104


356,979


(73,210
)

607,329













Non-operating income (expense):











Other, net
27

 
(672
)
 
623

 
(2,493
)
Interest expense
(33,157
)

(22,621
)

(96,583
)

(70,851
)
Loss on extinguishment of debt
—

 
—

 
(16,578
)
 
—













Income (loss) before income taxes
(1,026
)

333,686


(185,748
)

533,985

Income tax (expense) benefit
4,140


(124,748
)

78,296


(199,660
)












Net income (loss)
$
3,114


$
208,938


$
(107,452
)

$
334,325













Basic weighted-average common shares outstanding
67,961

 
67,379

 
67,638

 
67,169













Diluted weighted-average common shares outstanding
68,119

 
68,430

 
67,638

 
68,258













Basic net income (loss) per common share
$
0.05


$
3.10


$
(1.59
)

$
4.98













Diluted net income (loss) per common share
$
0.05


$
3.05


$
(1.59
)

$
4.90













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,
 
 
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
Net income (loss)
$
3,114

 
$
208,938

 
$
(107,452
)
 
$
334,325

Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Pension liability adjustment
(20
)
 
196

 
(772
)
 
526

Total other comprehensive income (loss), net of tax
(20
)
 
196

 
(772
)
 
526

Total comprehensive income (loss)
$
3,094

 
$
209,134

 
$
(108,224
)
 
$
334,851


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

5

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

 
For the Nine Months Ended September 30,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(107,452
)
 
$
334,325

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Net gain on divestiture activity
(38,497
)
 
(52
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
680,984

 
548,255

Exploratory dry hole expense
22,860

 
22,844

Impairment of proved properties
124,430

 
—

Abandonment and impairment of unproved properties
24,046

 
18,487

Stock-based compensation expense
20,492

 
24,568

Change in Net Profits Plan liability
(13,174
)
 
(15,280
)
Derivative (gain) loss
(285,491
)
 
33,470

Derivative cash settlements
397,307

 
(62,894
)
Amortization of deferred financing costs
5,803

 
4,433

Non-cash loss on extinguishment of debt
4,123

 
—

Deferred income taxes
(80,388
)
 
198,180

Plugging and abandonment
(5,540
)
 
(6,193
)
Other, net
3,670

 
(2,934
)
Changes in current assets and liabilities:
 
 
 
Accounts receivable
105,336

 
6,476

Prepaid expenses and other
587

 
234

Accounts payable and accrued expenses
(74,247
)
 
(28,797
)
Net cash provided by operating activities
784,849

 
1,075,122

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
335,103

 
41,868

Capital expenditures
(1,261,871
)
 
(1,317,862
)
Acquisition of proved and unproved oil and gas properties
(7,088
)
 
(459,277
)
Other, net
(990
)
 
(714
)
Net cash used in investing activities
(934,846
)
 
(1,735,985
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
1,604,500

 
536,500

Repayment of credit facility
(1,586,500
)
 
(146,500
)
Net proceeds from Senior Notes
490,951

 
—

Repayment of Senior Notes
(350,000
)
 
—

Proceeds from sale of common stock
3,157

 
2,898

Dividends paid
(3,373
)
 
(3,353
)
Net share settlement from issuance of stock awards
(8,502
)
 
(10,576
)
Other, net
(159
)
 
(85
)
Net cash provided by financing activities
150,074

 
378,884

 
 
 
 
Net change in cash and cash equivalents
77

 
(281,979
)
Cash and cash equivalents at beginning of period
120

 
282,248

Cash and cash equivalents at end of period
$
197

 
$
269

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

6

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

Supplemental schedule of additional cash flow information and non-cash investing and financing activities:
 
For the Nine Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Cash paid for interest, net of capitalized interest
$
88,920

 
$
79,119

 
 
 
 
Net cash paid for income taxes
$
492

 
$
1,979


Dividends of approximately $3.4 million were declared by the Company’s Board of Directors, but not paid, as of September 30, 2015, and 2014.
    
As of September 30, 2015, and 2014, $141.5 million and $404.8 million, respectively, of accrued capital expenditures were included in accounts payable and accrued expenses in the Company’s condensed consolidated balance sheets. These oil and gas property additions are reflected in net cash used in investing activities in the periods during which the payables are settled.

During the second quarter of 2014, the Company exchanged properties in its Rocky Mountain region for other properties also located in its Rocky Mountain region with a fair value of $6.2 million. The amount of cash consideration paid at closing for agreed upon adjustments is reflected in the acquisition of proved and unproved oil and gas properties line item in the condensed consolidated statements of cash flows.

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

7

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

Note 1 - The Company and Business

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

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

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of SM Energy have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and the instructions to 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, 2014 (the “2014 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring accruals 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 its unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of September 30, 2015, through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in its 2014 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 2014 Form 10-K.

Recently Issued Accounting Standards

Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-01, “Income Statement – Extraordinary and Unusual Items.” This ASU simplifies income statement presentation by eliminating the concept of extraordinary items. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard.

In April 2015, the FASB issued new authoritative accounting guidance requiring debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the related debt liability. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted. In August 2015, effective upon release, the FASB issued related new authoritative accounting guidance allowing for deferred financing costs associated with line-of-credit arrangements to continue to be presented as assets. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In August 2015, the FASB issued new authoritative accounting guidance to defer the effective date of the new revenue recognition standard by one year. The new revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

Other than as disclosed above or in the 2014 Form 10-K, there are no other new accounting standards that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of September 30, 2015, and through the filing date of this report.


8

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

During the second quarter of 2015, the Company divested its Mid-Continent assets in separate transactions for total cash proceeds received at closing, which reflect aggregate gross purchase price net of closing adjustments (referred to throughout this report as “divestiture proceeds”) of $316.5 million and an estimated total net gain of $108.4 million. These assets were classified as held for sale as of March 31, 2015, and certain of these assets were written down by $30.0 million during the three months ended March 31, 2015, to reflect fair value less estimated costs to sell. This write-down is reflected in the total net estimated gain of $108.4 million discussed above. These divestitures are subject to normal post-closing adjustments expected to occur in the fourth quarter of 2015 or early 2016.

In conjunction with the Company’s efforts to divest its Mid-Continent assets, the Company previously announced the planned closure of its Tulsa, Oklahoma office in 2015, with the relocation of certain personnel to other Company offices. The Company expects to incur a total of approximately $10 million of exit and disposal costs associated with the severance, retention and relocation of employees, and other related matters, excluding the lease expenses discussed in the next paragraph. For the three and nine months ended September 30, 2015, the Company recorded $1.0 million and $9.5 million, respectively, of exit and disposal costs, the majority of which were recorded as general and administrative expense in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).

Additionally, during the third quarter of 2015, the Company vacated its office space in Tulsa. The Company has subleased a portion of the space and is currently attempting to sublease the remaining space. As of September 30, 2015, the Company is obligated to pay lease costs of approximately $5.8 million, net of expected income from office space currently subleased, which will be expensed over the duration of the lease, which expires in 2022. This obligation will decrease if the Company successfully subleases additional space.

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 decreases to the estimated fair value less the costs to sell impact the measurement of assets held for sale.

As of September 30, 2015, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $29.2 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which primarily consist of certain non-core assets in the Company’s Permian region and certain assets in exploratory areas that the Company no longer intends to explore and develop in light of the low commodity price environment. There is a corresponding asset retirement obligation liability of approximately $3.3 million for assets held for sale recorded in the asset retirement obligation liability financial statement line item in the accompanying balance sheets. For the nine months ended September 30, 2015, write-downs on certain assets held for sale totaled $98.6 million, which included the $30.0 million write-down recorded on certain Mid-Continent assets in the first quarter 2015 as discussed above. There were minimal adjustments on certain assets held for sale for the three months ended September 30, 2015. Write-downs on assets held for sale are recorded in the net gain (loss) on divestiture activity line item in the accompanying statements of operations.

Subsequent to September 30, 2015, the Company entered into a purchase and sale agreement with a buyer for the sale of certain assets held for sale as of September 30, 2015, in its Permian region. The Company expects to close this transaction in the fourth quarter of 2015 for a purchase price of approximately $26.0 million, subject to customary closing adjustments. The closing of this transaction is subject to the satisfaction of customary closing conditions, and there can be no assurance that the transaction will close on the expected closing date or at all.

The Company determined that none of the planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance.
 
Note 4 - Income Taxes

Income tax expense (benefit) for the three and nine months ended September 30, 2015, and 2014, differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, percentage depletion, research and development (“R&D”) credits,

9

and other permanent differences. The quarterly rate can also be impacted by the proportional effects of forecasted net income or loss as of each period end presented.

The provision for income taxes consists of the following:

 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Current portion of income tax expense (benefit):
 
 
 
 
 
 
 
Federal
$
—

 
$
—

 
$
—

 
$
—

State
(8,308
)
 
479

 
2,092

 
1,480

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

 
124,269

 
(80,388
)
 
198,180

Total income tax expense (benefit)
$
(4,140
)
 
$
124,748

 
$
(78,296
)
 
$
199,660

 
403.5
%
 
37.4
%
 
42.2
%
 
37.4
%

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 from Company activities among various state tax jurisdictions. Cumulative effects of state rate changes are reflected in the period legislation is enacted. The cumulative effects of Texas and North Dakota enacted rate changes are reflected in the year-to-date deferred portion of income tax expense (benefit). During the nine months ended September 30, 2015, the Company determined certain Oklahoma properties sold in the quarter ended June 30, 2015, qualified for the Oklahoma capital gain deduction which resulted in additional state tax benefit.

The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2007. During the first quarter of 2015, as a result of its R&D credit settlement with the IRS Appeals Office in late 2014, the Company recorded an additional $2.0 million net R&D credit from a claim filed on an amended return. No R&D credit was recorded in 2014. During the quarter ended September 30, 2015, the IRS initiated an audit of the SM-Mitsui Tax Partnership for 2013. The Company has a significant investment in the underlying assets of the tax partnership.

Note 5 - Long-Term Debt

Revolving Credit Facility

The Company’s Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), provides a maximum loan amount of $2.5 billion, current aggregate lender commitments of $1.5 billion, and a maturity date of December 10, 2019. Effective as of October 7, 2015, the Company’s lenders decreased the borrowing base to $2.0 billion as part of the regularly scheduled semi-annual redetermination under the Credit Agreement. This expected reduction from $2.4 billion was primarily a result of the Company’s sale of its Mid-Continent assets completed in the second quarter of 2015, plus adjustments consistent with lower commodity prices. There was no change in the current aggregate lender commitments of $1.5 billion. The next redetermination date is scheduled for April 1, 2016. Borrowings under the facility are secured by mortgages on assets having a value equal to at least 75 percent of the total value of the Company’s proved oil and gas properties. 
 
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including limitations on the payment of dividends to $50.0 million per year.  The Company was in compliance with all covenants under the Credit Agreement as of September 30, 2015, and through the filing date of this report.

The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of October 21, 2015, September 30, 2015, and December 31, 2014:

 
As of October 21, 2015
 
As of September 30, 2015
 
As of December 31, 2014
 
(in thousands)
Credit facility balance
$
177,500

 
$
184,000

 
$
166,000

Letters of credit (1)
$
200

 
$
200

 
$
808

Available borrowing capacity
$
1,322,300

 
$
1,315,800

 
$
1,333,192

____________________________________________
(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.

10

Senior Notes
The Senior Notes line on the accompanying balance sheets represents the outstanding principal amount of the notes shown in the table below (the “Senior Notes”):
 
As of September 30, 2015
 
As of December 31, 2014
 
(in thousands)
6.625% Senior Notes due 2019
$
—

 
$
350,000

6.50% Senior Notes due 2021
350,000

 
350,000

6.125% Senior Notes due 2022
600,000

 
600,000

6.50% Senior Notes due 2023
400,000

 
400,000

5.0% Senior Notes due 2024
500,000

 
500,000

5.625% Senior Notes due 2025
500,000

 
—

Total Senior Notes
$
2,350,000

 
$
2,200,000


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 respective indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; provided, however, that the first $6.5 million of dividends paid each year are not restricted by this restricted payment covenant. The Company was in compliance with all covenants under its Senior Notes as of September 30, 2015, and through the filing date of this report.

2019 Notes    

On May 7, 2015, the Company commenced a cash tender offer for any and all of its outstanding 6.625% Senior Notes due 2019 (the “2019 Notes”) at a price of $1,036.88 per $1,000 of principal amount for all 2019 Notes tendered by May 20, 2015 (“Consent Payment Deadline”), and at a price of $1,006.88 per $1,000 of principal amount for all 2019 Notes properly tendered thereafter. On the Consent Payment Deadline, the Company received tenders and consents from the holders of approximately $242.9 million in aggregate principal amount, or approximately 69%, of its outstanding 2019 Notes in connection with the cash tender offer. Following its entry into the supplemental indenture dated as of May 21, 2015, to the indenture dated as of February 7, 2011, between the Company and U.S. Bank National Association, as Trustee, the Company accepted the 2019 Notes tendered as of the Consent Payment Deadline in exchange for payment of total consideration, including accrued interest, of approximately $256.2 million under the Tender Offer and Consent Solicitation. On June 5, 2015, the Company accepted $1.5 million of 2019 Notes tendered after the Consent Payment Deadline in exchange for payment of total consideration, including accrued interest, of approximately $1.6 million.

On June 22, 2015, the Company redeemed the remaining outstanding 2019 Notes at a redemption price of 103.313% of the principal amount for payment of total consideration, including accrued interest, of approximately $111.5 million.

The Company recorded a loss on extinguishment of debt related to the tender offer and redemption of its 2019 Notes of approximately $16.6 million for the quarter ended June 30, 2015. This amount includes approximately $12.5 million associated with the premium paid for the tender offer and redemption of the 2019 Notes and approximately $4.1 million related to the acceleration of unamortized deferred financing costs.

2025 Notes

On May 21, 2015, the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 (the “2025 Notes”) to certain underwriters in a public offering registered under the Securities Act of 1933, as amended (the “Securities Act”). The 2025 Notes were issued at par and mature on June 1, 2025. The Company received net proceeds of approximately $491.0 million after deducting fees of $9.0 million, which are being amortized as deferred financing costs over the life of the 2025 Notes. The net proceeds were used to fund the consideration paid to the tendering holders of the 2019 Notes and to redeem the remaining un-tendered 2019 Notes, as well as repay outstanding borrowings under the Credit Agreement and for general corporate purposes.

11

Prior to June 1, 2018, the Company may redeem, on one or more occasions, up to 35% of the aggregate principal amount of the 2025 Notes with the net cash proceeds of certain equity offerings at a redemption price of 105.625% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2025 Notes, in whole or in part, at any time after June 1, 2018, and prior to June 1, 2020, at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed, plus a specified make-whole premium and accrued and unpaid interest to the applicable redemption date. 
    
On or after June 1, 2020, the Company may also redeem all or, from time to time during the twelve-month period beginning on June 1 of each applicable year, a portion of the 2025 Notes at the redemption prices set forth below expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest:

2020
102.813
%
2021
101.875
%
2022
100.938
%
2023 and thereafter
100.000
%

2022 Notes

The Company completed its offer to exchange its 6.125% Senior Notes due 2022 for notes registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), on July 10, 2015.

Note 6 - Commitments and Contingencies

Commitments

There were no material changes in commitments during the first nine months of 2015, except as further discussed below. Please refer to Note 6 - Commitments and Contingencies in the Company’s 2014 Form 10-K for additional discussion.

In light of the low commodity price environment, the Company curtailed drilling activity during the first nine months of 2015. For the three and nine months ended September 30, 2015, the Company incurred drilling rig termination fees of $2.2 million and $8.1 million, respectively, which are recorded in the other operating expenses line item in the accompanying statements of operations.

During the third quarter of 2015, the Company entered into an amendment to a gas gathering agreement whereby the Company is subject to certain gathering throughput commitments for five years upon the expansion of the existing third party gathering system. The Company may be required to make periodic deficiency payments for any shortfalls in delivering the minimum annual volume commitment. In the event that no product is delivered in accordance with this agreement, the aggregate undiscounted deficiency payments beginning in 2017 and extending through 2022 would be approximately $142.7 million as of September 30, 2015. As of the filing date of this report, the Company does not expect to incur any material shortfalls.

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 estimable. 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. At September 30, 2015, the Company had $4.6 million accrued for estimated exposure related to claims for payment of royalties on certain Federal and Indian leases. Although the Company believes that it has properly estimated its exposure with respect to the various contracts, laws and regulations, administrative rulings, and interpretations thereof, adjustments could be required as new interpretations and regulations arise.


12

Note 7 - Compensation Plans

Performance Share Units Under the Equity Incentive Compensation Plan

The Company grants performance share units (“PSUs”) to eligible employees as a part of its long-term equity compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0% to 200% of the number of PSUs awarded and is determined based on certain performance criteria over a three-year measurement period. The performance criteria for the PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. Compensation expense for PSUs is recognized within general and administrative and exploration expense over the vesting periods of the respective awards.

Total compensation expense recorded for PSUs for the three months ended September 30, 2015, and 2014, was $2.4 million and $4.8 million, respectively, and $7.4 million and $11.6 million for the nine months ended September 30, 2015, and 2014, respectively. As of September 30, 2015, there was $21.3 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2018.

A summary of the status and activity of non-vested PSUs for the nine months ended September 30, 2015, is presented in the following table:
 
PSUs (1)
 
Weighted-Average
 Grant-Date
Fair Value
Non-vested at beginning of year
433,660

 
$
73.63

Granted
320,753

 
$
45.34

Vested
(75,353
)
 
$
51.59

Forfeited
(47,787
)
 
$
74.42

Non-vested at end of quarter
631,273

 
$
61.83

____________________________________________
(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 first nine months of 2015, the Company granted 320,753 PSUs with a fair value of $14.5 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 the first nine months of 2015, the Company settled PSUs that were granted in 2012, which earned a 1.0 times multiplier, by issuing 188,279 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, 100,683 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 within general and administrative expense and exploration expense over the vesting periods of the award.

Total compensation expense recorded for RSUs was $4.1 million and $4.8 million for the three months ended September 30, 2015, and 2014, respectively, and $9.9 million and $10.5 million for the nine months ended September 30, 2015, and 2014, respectively. As of September 30, 2015, there was $22.7 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2018.


13

A summary of the status and activity of non-vested RSUs for the nine months ended September 30, 2015, is presented in the following table:

 
RSUs
 
Weighted-Average
 Grant-Date
Fair Value
Non-vested at beginning of year
515,724

 
$
68.29

Granted
356,246

 
$
43.72

Vested
(267,244
)
 
$
63.43

Forfeited
(41,330
)
 
$
68.63

Non-vested at end of quarter
563,396

 
$
55.04


During the first nine months of 2015, the Company granted 356,246 RSUs with a fair value of $15.6 million as part of its regular annual long-term equity compensation program. These RSUs will vest one-third of the total grant on each of the next three anniversaries of the date of the grant. Also, during the first nine months of 2015, the Company settled 267,244 RSUs that related to awards granted in previous years. 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, the Company issued 181,187 net shares of common stock. The remaining 86,057 shares were withheld to satisfy income and payroll tax withholding obligations that arose upon delivery of the shares underlying those RSUs.

Director Shares

During the first nine months of 2015 and 2014, the Company issued 37,950 and 27,677 shares, respectively, of its common stock to its non-employee directors, under the Company’s Equity Incentive Compensation Plan.  The Company recorded approximately $271,000 and $196,000 of compensation expense related to these awards for the three months ended September 30, 2015 and 2014, respectively. The Company recorded $1.4 million of compensation expense related to these awards for the nine months ended September 30, 2015, and 2014, respectively.

All shares of common stock issued to the Company’s non-employee directors are earned over the one-year service period following the date of grant, unless five years of service has been provided to the Company by the director, in which case that director’s shares vest upon the earlier of the completion of the one-year service period or the director retiring from the Board of Directors.
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% 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, as amended (“IRC”). The Company had approximately 1.1 million shares available for issuance under the ESPP as of September 30, 2015. There were 96,285 and 35,249 shares issued under the ESPP during the nine months ended September 30, 2015, and 2014, respectively. 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 Company’s Net Profits Plan totaled $410,000 and $2.6 million for the three months ended September 30, 2015, and 2014, respectively, and $3.6 million and $8.1 million for the nine months ended September 30, 2015, and 2014, respectively, the majority of which were recorded as general and administrative expense within the accompanying statements of operations.
Additionally, the Company accrued or made cash payments under the Net Profits Plan of $3.8 million and $8.3 million for the nine months ended September 30, 2015, and 2014, respectively, as a result of the divestitures of properties subject to the Net Profits Plan. These cash payments are accounted for as a reduction in the net gain (loss) on divestiture activity line item in the accompanying statements of operations.
The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit

14

in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative expense. As time has passed, the amount distributed relating to prospective exploration efforts has become insignificant as more is paid to employees that have terminated employment and do not provide ongoing exploration support to the Company.
Note 8 - Pension Benefits

Pension Plans

The Company has a non-contributory pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). During the third quarter of 2015, the Company announced to its employees that it intends to freeze the Pension Plans to new participants, effective December 31, 2015. Employees currently participating in the Pension Plans 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,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Service cost
$
1,989

 
$
1,584

 
$
5,963

 
$
4,752

Interest cost
624

 
548

 
1,872

 
1,643

Expected return on plan assets that reduces periodic pension costs
(546
)
 
(494
)
 
(1,637
)
 
(1,483
)
Amortization of prior service costs
4

 
4

 
13

 
13

Amortization of net actuarial loss
371

 
172

 
1,114

 
516

Net periodic benefit cost
$
2,442

 
$
1,814

 
$
7,325

 
$
5,441


Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants.

Contributions

The Company contributed $6.4 million to the Pension Plans during the nine months ended September 30, 2015.

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 Company’s 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 in-the-money outstanding stock options. The treasury stock method is used to measure the dilutive impact of these stock awards. All remaining stock options were exercised during the year ended December 31, 2014, and therefore, were only dilutive for the three and nine months ended September 30, 2014.


15

PSUs represent the right to receive, upon settlement of the PSUs after completion of the three-year performance period, a number of shares of the Company’s common stock that may range from 0% to 200% of 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. For additional discussion on PSUs, please refer to Note 7 - Compensation Plans under the heading Performance Share Units Under the Equity Incentive Compensation Plan.

When there is a loss from continuing operations, as was the case for 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. For the nine months ended September 30, 2015, weighted-average anti-dilutive securities related to unvested RSUs and contingent PSUs totaled approximately 380,000 shares, respectively.

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,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per share amounts)
Net income (loss)
$
3,114

 
$
208,938

 
$
(107,452
)
 
$
334,325

Basic weighted-average common shares outstanding
67,961

 
67,379

 
67,638

 
67,169

Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs
158

 
1,051

 
—

 
1,089

Diluted weighted-average common shares outstanding
68,119

 
68,430

 
67,638

 
68,258

Basic net income (loss) per common share
$
0.05

 
$
3.10

 
$
(1.59
)
 
$
4.98

Diluted net income (loss) per common share
$
0.05

 
$
3.05

 
$
(1.59
)
 
$
4.90


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 include swap and collar arrangements for oil, gas, and NGLs.
    
As of September 30, 2015, the Company had commodity derivative contracts outstanding through the second quarter of 2020 for a total of 7.6 million Bbls of oil production, 190.4 million MMBtu of gas production, and 13.7 million Bbls of NGL production. Subsequent to September 30, 2015, the Company entered into one derivative contract through the third quarter of 2016 for 886,000 Bbls of NGL production with a contract price of $20.16 per Bbl. This subsequent derivative contract for propane production is based on Oil Price Information Service (“OPIS”) Propane Mont Belvieu Non-TET.

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 agreements, the Company receives the difference between an index price and the floor price if the index price is below the floor price.  The Company pays the difference between the 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.


16

The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of September 30, 2015:

Oil Contracts

Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(Bbls)
 
(per Bbl)
Fourth quarter 2015
 
1,137,000

 
$
90.15

2016
 
5,570,000

 
$
88.01

All oil swaps
 
6,707,000

 
 

Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(Bbls)
 
(per Bbl)
 
(per Bbl)
Fourth quarter 2015
 
869,000

 
$
85.00

 
$
92.19

All oil collars
 
869,000

 
 
 
 

Gas Contracts

Gas Swaps
Contract Period
 
Volumes
 
Weighted-Average
 Contract Price
 
 
(MMBtu)
 
(per MMBtu)
Fourth quarter 2015
 
12,499,000

 
$
4.01

2016
 
80,186,000

 
$
3.61

2017
 
37,527,000

 
$
4.09

2018
 
30,606,000

 
$
4.27

2019
 
24,415,000

 
$
4.34

All gas swaps*
 
185,233,000

 
 

*Gas swaps are comprised of IF El Paso Permian (2%), IF HSC (95%), IF NGPL TXOK (1%), and IF NNG Ventura (2%).

Gas Collars
Contract Period
 
Volumes
 
Weighted-
Average Floor
Price
 
Weighted-
Average Ceiling
Price
 
 
(MMBtu)
 
(per MMBtu)
 
(per MMBtu)
Fourth quarter 2015
 
5,157,000

 
$
3.99

 
$
4.29

All gas collars*
 
5,157,000

 
 
 
 

*Gas collars are comprised of IF El Paso Permian (6%), IF HSC (89%), and IF NNG Ventura (5%).

17

NGL Contracts

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
 
 
(Bbls)
(per Bbl)
 
(Bbls)
(per Bbl)
 
(Bbls)
(per Bbl)
 
(Bbls)
(per Bbl)
Fourth quarter 2015
 
—

$
—

 
941,000

$
19.60

 
322,000

$
24.90

 
276,000

$
25.30

2016
 
3,193,000

$
8.47

 
2,746,000

$
19.09

 
273,000

$
25.62

 
233,000

$
25.87

2017
 
2,271,000

$
9.16

 
—

$
—

 
—

$
—

 
—

$
—

2018
 
1,671,000

$
10.65

 
—

$
—

 
—

$
—

 
—

$
—

2019
 
1,200,000

$
10.92

 
—

$
—

 
—

$
—

 
—

$
—

2020
 
539,000

$
11.13

 
—

$
—

 
—

$
—

 
—

$
—

Total NGL swaps
 
8,874,000

 
 
3,687,000

 
 
595,000

 
 
509,000

 

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 $489.9 million as of September 30, 2015, and a net asset of $592.1 million as of December 31, 2014.

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

 
As of September 30, 2015
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
347,299

 
Current liabilities
 
$
2,900

Commodity contracts
Noncurrent assets
 
147,530

 
Noncurrent liabilities
 
2,019

Derivatives not designated as hedging instruments
 
 
$
494,829

 
 
 
$
4,919


 
As of December 31, 2014
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
402,668

 
Current liabilities
 
$
—

Commodity contracts
Noncurrent assets
 
189,540

 
Noncurrent liabilities
 
70

Derivatives not designated as hedging instruments
 
 
$
592,208

 
 
 
$
70


Offsetting of Derivative Assets and Liabilities

As of September 30, 2015, and December 31, 2014, all derivative instruments held by the Company were subject to master netting arrangements by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.  

18

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts:
 
 
Derivative Assets
 
Derivative Liabilities
 
 
As of
 
As of
Offsetting of Derivative Assets and Liabilities
 
September 30,
2015
 
December 31, 2014
 
September 30,
2015
 
December 31, 2014
 
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
 
$
494,829

 
$
592,208

 
$
(4,919
)
 
$
(70
)
Amounts not offset in the accompanying balance sheets
 
(4,919
)
 
(70
)
 
4,919

 
70

Net amounts
 
$
489,910

 
$
592,138

 
$
—

 
$
—

    
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,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Derivative settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
(90,493
)
 
$
517

 
$
(270,622
)
 
$
27,435

Gas contracts (1)
(19,167
)
 
1,687

 
(92,279
)
 
28,563

NGL contracts
(4,035
)
 
(1,930
)
 
(24,818
)
 
6,896

Total derivative settlement (gain) loss (2)
$
(113,695
)

$
274


$
(387,719
)

$
62,894

 
 
 
 
 
 
 
 
Total derivative (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
(131,728
)
 
$
(140,912
)
 
$
(138,839
)
 
$
(15,367
)
Gas contracts
(66,538
)
 
(41,352
)
 
(142,807
)
 
46,263

NGL contracts
(13,987
)
 
(8,397
)
 
(3,845
)
 
2,574

Total derivative (gain) loss (3)
$
(212,253
)

$
(190,661
)

$
(285,491
)

$
33,470

____________________________________________
(1)  
Natural gas derivative settlements for the nine months ended September 30, 2015, include a $15.3 million gain recorded in the second quarter of 2015 on the early settlement of futures contracts as a result of divesting of the Company’s Mid-Continent assets.
(2) 
Total derivative settlement (gain) loss is reported net of the change in accrued settlements between periods in the derivative cash settlements line item on the condensed consolidated statements of cash flows within net cash provided by operating activities.
(3) 
Total derivative (gain) loss is reported in the derivative (gain) loss line item on the condensed consolidated statements of cash flows within net cash provided by operating activities.

Credit Related Contingent Features

As of September 30, 2015, 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 Company’s obligations under its derivative contracts are secured by mortgages on assets having a value equal to at least 75 percent of the total value of the Company’s proved oil and gas properties. 


19

Note 11 - Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
•
Level 1 – quoted prices in active markets for identical assets or liabilities
•
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
•
Level 3 – significant inputs to the valuation model are unobservable
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of September 30, 2015:


Level 1

Level 2

Level 3

(in thousands)
Assets:








Derivatives (1)
$
—


$
494,829


$
—

Proved oil and gas properties (2)
$
—


$
—


$
56,849

Oil and gas properties held for sale (2)
$
—

 
$
—

 
$
3,376

Liabilities:








Derivatives (1)
$
—


$
4,919


$
—

Net Profits Plan (1)
$
—


$
—


$
13,962

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

The following is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the hierarchy as of December 31, 2014:

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

 
$
592,208

 
$
—

Proved oil and gas properties (2)
$
—

 
$
—

 
$
33,423

Oil and gas properties held for sale (2)
$
—

 
$
—

 
$
17,891

Liabilities:
 
 
 
 
 
Derivatives (1)
$
—

 
$
70

 
$
—

Net Profits Plan (1)
$
—

 
$
—

 
$
27,136

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

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.


20

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

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

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

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

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

Net Profits Plan

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

The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. The calculation of this liability is a significant management estimate. A discount rate of 12 percent is used to calculate this liability and is intended to represent the Company’s best estimate of the present value of expected future payments under the Net Profits Plan.

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

If the commodity prices used in the calculation changed by five percent, the liability recorded at September 30, 2015, would differ by approximately $1.5 million. A one percent increase or decrease in the discount rate would result in a change of approximately $500,000. Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated.


21

No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates.
    
The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs:
 
For the Nine Months Ended September 30, 2015
 
(in thousands)
Beginning balance
$
27,136

Net decrease in liability (1)
(5,749
)
Net settlements (1) (2)
(7,425
)
Transfers in (out) of Level 3
—

Ending balance
$
13,962


____________________________________________
(1) 
Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.
(2) 
Settlements represent cash payments made or accrued under the Net Profits Plan. The amount in the table includes cash payments made or accrued under the Net Profits Plan of $3.8 million for the nine months ended September 30, 2015, 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 measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of September 30, 2015, or December 31, 2014, as they are recorded at historical value.

 
As of September 30, 2015
 
As of December 31, 2014
 
(in thousands)
6.625% Senior Notes due 2019
$
—

 
$
350,018

6.50% Senior Notes due 2021
$
336,658

 
$
343,000

6.125% Senior Notes due 2022
$
552,000

 
$
556,500

6.50% Senior Notes due 2023
$
374,000

 
$
379,000

5.0% Senior Notes due 2024
$
423,750

 
$
435,000

5.625% Senior Notes due 2025
$
430,000

 
$
—


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.


22

Proved and Unproved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is based on the best information available and was estimated to be 12 percent as of September 30, 2015, and December 31, 2014. The Company believes the discount rate is representative of current market conditions and takes into account estimates of future cash payments, 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 New York Mercantile Exchange (“NYMEX”) strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. The Company recorded impairment of proved oil and gas properties expense of $56.0 million and $124.4 million for the three and nine months ended September 30, 2015, respectively, due to continued declines in commodity strip prices since year-end 2014, the Company’s decision to reduce capital invested in the development of certain prospects in its South Texas & Gulf Coast and Permian regions, and a decline in performance of non-core assets. Proved properties measured at fair value within the accompanying balance sheets totaled $56.8 million as of September 30, 2015. As of December 31, 2014, proved oil and gas properties measured at fair value totaled $33.4 million.

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable.  To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. The Company recorded abandonment and impairment of unproved oil and gas properties expense of $6.6 million and $24.0 million for the three and nine months ended September 30, 2015, respectively, related to acreage the Company no longer intended to develop. Unproved properties measured at fair value were written down to zero in the accompanying balance sheets as of September 30, 2015, and December 31, 2014.
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. For the nine months ended September 30, 2015, write-downs on certain assets held for sale totaled $98.6 million. There were minimal adjustments on certain assets held for sale for the three months ended September 30, 2015. These write-downs are included within the net gain (loss) on divestiture activity line item on the accompanying statements of operations. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale.

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.

Note 12 - Suspended Well Costs

For the nine months ended September 30, 2015, the Company charged $21.1 million of exploratory well costs to exploration expense related to two unsuccessful exploratory wells that were capitalized as of December 31, 2014. None of the costs were capitalized for a period greater than one year as of December 31, 2014, or at the time the wells were determined to be unsuccessful.


23

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

This management’s discussion and analysis contains forward-looking statements. Refer to Cautionary Information About Forward-Looking Statements at the end of this item for an explanation of these types of statements.

Overview of the Company, Highlights, and Outlook

General Overview

We are an independent energy company engaged in the production of oil, gas, and NGLs in onshore North America. Our strategic objective is to 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 seek to maximize the value of our assets through industry leading technology application and outstanding operational execution. We focus on achieving high full-cycle economic returns on our investments and maintaining a simple, strong balance sheet through a conservative approach to leverage.

We currently have development positions in the Eagle Ford shale, Bakken/Three Forks and Permian Basin resource plays that are the focus of our capital investment programs. We also have delineation and exploration programs in the Powder River Basin and in east Texas.

In the third quarter of 2015, we had the following financial and operational results:

•
Average net daily production for the three months ended September 30, 2015, was 49.1 MBbls of oil, 471.1 MMcf of gas, and 46.8 MBbls of NGLs, for a quarterly equivalent daily production rate of 174.5 MBOE, compared with 142.5 MBOE for the same period in 2014. Please see additional discussion below under Production Results.

•
We recorded net income of $3.1 million, or $0.05 per diluted share, for the three months ended September 30, 2015, compared to net income of $208.9 million, or $3.05 per diluted share, for the three months ended September 30, 2014. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2015, and 2014, below for additional discussion regarding the components of net income (loss).
 
•
Costs incurred for oil and gas property acquisitions and exploration and development activities for the three months ended September 30, 2015, totaled $286.6 million. The majority of our drilling and completion costs incurred during this period were in our Eagle Ford shale and Bakken/Three Forks programs. Total costs incurred for the same period in 2014 were $1.0 billion, including the acquisition of approximately $367.6 million of proved and unproved properties in our Gooseneck prospect area and in the Powder River Basin. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program.

•
Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2015, was $259.4 million, compared to $406.2 million for the same period in 2014. 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.

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 contracts paying us various industry posted prices, adjusted for basis differentials. We are paid the average of the daily settlement price for the respective posted prices for the period in which the product is sold, adjusted for quality, transportation, American Petroleum Institute (“API”) gravity, and location differentials. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative settlements, unless otherwise indicated.


24

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the second and third quarters of 2015, as well as the third quarter of 2014:

 
For the Three Months Ended
 
September 30, 2015
 
June 30, 2015
 
September 30, 2014
Crude Oil (per Bbl):
 
 
 
 
 
Average daily NYMEX price
$
46.48

 
$
57.85

 
$
97.60

Realized price, before the effect of derivative settlements
$
40.03

 
$
51.45

 
$
86.56

Effect of derivative settlements
$
20.02

 
$
14.53

 
$
(0.12
)
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Average daily NYMEX price (per MMBtu)
$
2.75

 
$
2.73

 
$
3.94

Realized price, before the effect of derivative settlements (per Mcf)
$
2.77

 
$
2.53

 
$
4.49

Effect of derivative settlements (per Mcf) (1)
$
0.45

 
$
0.88

 
$
(0.05
)
 
 
 
 
 
 
Natural Gas Liquids (per Bbl):(2)
 
 
 
 
 
Average daily OPIS price
$
18.22

 
$
20.79

 
$
39.37

Realized price, before the effect of derivative settlements
$
15.18

 
$
16.85

 
$
34.86

Effect of derivative settlements
$
0.94

 
$
—

 
$
0.61

____________________________________________
(1)
Natural gas derivative settlements for the three months ended June 30, 2015, includes a $15.3 million gain on the early settlement of futures contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015, increasing the effect of derivative settlements by $0.35 per Mcf.
(2)  
Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
    
While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products. 

We expect future prices for oil, gas, and NGLs to be volatile.  In addition to supply and demand fundamentals, as a global commodity, the price of oil will continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East.  The relative strength of the U.S. dollar compared to other currencies also affects the price of oil.  Oil prices have remained under downward pressure in recent months due to slower forecasted global economic growth combined with excess global supply.  In response to lower oil prices at the end of 2014 and the first three quarters of 2015, industry participants have significantly cut capital spending, which we expect will result in lower supply.  Gas prices also remain under downward pressure as supply has exceeded demand, resulting in higher levels of gas in storage compared to 2014 and compared to the 5-year average.  Excess supply of ethane and propane with higher volumes in storage than historical averages has resulted in a further drop in pricing for those products in recent months.  Changes to existing laws and regulations pertaining to the ability to export oil, gas, and NGLs also have the potential to impact the prices for these commodities. 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 21, 2015, and September 30, 2015:

 
As of October 21, 2015
 
As of September 30, 2015
NYMEX WTI oil (per Bbl)
$
48.31

 
$
48.15

NYMEX Henry Hub gas (per MMBtu)
$
2.68

 
$
2.75

OPIS NGLs (per Bbl)
$
18.64

 
$
19.45


25

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

Third Quarter 2015 Highlights and Outlook for the Remainder of 2015

Operational Activities. 2015 has been a year of transition as the broader oil and gas industry adjusts to lower oil prices. We scaled back activity during the first three quarters of 2015 by reducing the number of active drilling rigs and deferring the completion of certain drilled wells. We have realized significant drilling and completion cost reductions during 2015 as our service providers have responded to this commodity price decline. Our goal is to be well positioned in the current commodity price environment as we enter 2016, with a focus on maintaining a strong balance sheet and strong liquidity. Going forward, we intend to incur capital expenditures near adjusted EBITDAX levels in order to minimize increases in total debt, while having the strength and flexibility to adapt should industry conditions change.

We expect our capital program for 2015 to be approximately $1.28 billion. For the nine months ended September 30, 2015, we incurred approximately $1.10 billion for exploration and development activities, net of proved and unproved property acquisitions, estimated asset retirement obligations, and capitalized interest. Please refer to the caption titled Costs Incurred in Oil and Gas Producing Activities below.

Throughout the third quarter of 2015, we operated four drilling rigs in our operated Eagle Ford shale program in south Texas, and we plan to maintain a four rig program for the remainder of the year. Beginning in 2014 and continuing into 2015, our development program shifted to utilizing longer laterals and completions with higher sand loadings. Results from these enhanced completion techniques suggest improved well performance. As of September 30, 2015, in our operated Eagle Ford shale program, we have 64 gross and net wells that have been drilled but not completed. We expect this inventory to increase in the fourth quarter. We continue to test well and completion design and spacing and the prospectivity of the Upper Eagle Ford on our acreage.
In our non-operated Eagle Ford shale program, the operator started the third quarter of 2015 operating five drilling rigs and released three rigs during the quarter. We expect the operator to continue running two rigs for the remainder of the year.
In our Bakken/Three Forks program, we began the third quarter of 2015 operating four drilling rigs. We released two rigs during the third quarter and expect to keep the remaining two rigs operating throughout the rest of the year. We continue to focus most of our activity in Divide County, North Dakota, where we are developing the Three Forks and Bakken intervals. As of September 30, 2015, in our operated Bakken/Three Forks program, we have drilled but not completed 47 gross wells (39 net). We plan on slowing down completion activities during the winter and expect to increase activity again towards the end of the first quarter of 2016. We are monitoring the results of various tests, including completion optimizations and down-spacing of both our operated and non-operated properties in this area.
In our Permian development program, we released our last operated rig during the second quarter of 2015. A large portion of our leasehold position in this region is held by production. In the first quarter of 2016, we expect to return to developing the Wolfcamp and Spraberry intervals on our Sweetie Peck property in Upton County, Texas.
Given the current commodity price environment, we have curtailed activity in our delineation and exploration programs. We have reduced our activity in the Powder River Basin in Wyoming and in east Texas to focus on preserving our more prospective acreage positions. In our Powder River Basin program, we operated one rig during the third quarter and expect to continue operating one rig for the remainder of the year. In east Texas, we are monitoring the performance of exploratory wells previously drilled and completed.
    
We will continue to evaluate our rig count throughout the remainder of 2015 and into next year as we respond to commodity price changes and reduced costs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion concerning how we intend to fund our remaining 2015 capital program.

26

Production Results. The table below provides a regional breakdown of our production for the third quarter of 2015:
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Permian
 
Total (1)
 
 
 
 
 
 
 
 
Oil (MMBbl)
1.8

 
2.3

 
0.4

 
4.5

Gas (Bcf)
39.7

 
2.3

 
1.3

 
43.3

NGLs (MMBbl)
4.2

 
0.1

 
—

 
4.3

Equivalent (MMBOE)
12.6

 
2.8

 
0.6

 
16.1

Avg. daily equivalents (MBOE/d)
137.0

 
30.6

 
6.9

 
174.5

Relative percentage
78
%
 
18
%
 
4
%
 
100
%
____________________________________________
(1) Amounts may not calculate due to rounding.

Production increased for the three months ended September 30, 2015, compared to the same period in 2014, driven primarily by the continued development of our Eagle Ford shale and Bakken/Three Forks programs. In our operated Eagle Ford shale and Bakken/Three Forks programs for the three months ended September 30, 2015, we completed nine gross and net wells and 12 gross wells (11 net), respectively. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2015, and 2014 and A three-month and nine-month overview of selected production and financial information, including trends below for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
 
For the Three Months Ended September 30, 2015
 
(in millions)
Development costs (1)
$
253.9

Exploration costs
28.0

Acquisitions
 
Proved properties
0.3

Unproved properties (2)
4.4

Total, including asset retirement obligations (3)
$
286.6

____________________________________________
(1) Includes facility costs of $10.8 million and support facility allocations of $0.8 million for the three months ended September 30, 2015.
(2) Includes $0.9 million of unproved properties acquired as part of proved property acquisitions for the three months ended September 30, 2015. The remaining balance is leasing activity.
(3) Includes amounts relating to estimated asset retirement obligations of $2.9 million and capitalized interest of $5.2 million for the three months ended September 30, 2015.

Costs incurred in oil and gas producing activities, excluding proved and unproved property acquisitions, estimated asset retirement obligations, capitalized interest, and support facility allocations, for the three months ended September 30, 2015, totaled approximately $276.5 million. The majority of costs incurred for oil and gas producing activities during the third quarter of 2015 were in the development of our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Production Results above for discussion on completion activity during the third quarter, in addition to Third Quarter 2015 Highlights and Outlook for the Remainder of 2015 above for discussion on wells that have been drilled during 2015, but not completed as of September 30, 2015. Additionally, please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital expenditure program.

Equity Compensation.  During the third quarter of 2015, we granted 356,246 RSUs and 320,753 PSUs under our long-term equity incentive program. Additionally, we issued 369,466 shares of our common stock to settle PSU and RSU awards granted in previous years. Please refer to Note 7 - Compensation Plans in Part I, Item 1 of this report for additional discussion.

27

Subsequent Events. Subsequent to September 30, 2015, our lenders under the Credit Agreement decreased our borrowing base to $2.0 billion as part of the regularly scheduled semi-annual redetermination. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. Additionally, we entered into a purchase and sale agreement with a buyer for the sale of certain assets held for sale as of September 30, 2015, in our Permian region. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale in Part I, Item 1 of this report for additional discussion.
    
First Nine Months of 2015 Highlights

Production Results. The table below provides a regional breakdown of our production for the first nine months of 2015:
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Permian
 
Mid-Continent
 
Total (1)
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
6.2

 
7.1

 
1.5

 
—

 
14.8

Gas (Bcf)
113.2

 
6.6

 
4.0

 
9.7

 
133.5

NGLs (MMBbl)
12.0

 
0.2

 
—

 
—

 
12.2

Equivalent (MMBOE)
37.0

 
8.5

 
2.2

 
1.7

 
49.3

Avg. daily equivalents (MBOE/d)
135.5

 
31.1

 
7.9

 
6.1

 
180.6

Relative percentage
75
%
 
17
%
 
4
%
 
4
%
 
100
%
____________________________________________
(1) Amounts may not calculate due to rounding.

In our operated Eagle Ford shale and Bakken/Three Forks programs for the nine months ended September 30, 2015, we completed 51 gross and net wells and 31 gross wells (27 net), respectively. Please refer to Third Quarter 2015 Highlights and Outlook for the Remainder of 2015 above and Comparison of Financial Results and Trends Between the Nine Months Ended September 30, 2015, and 2014 as well as A three-month and nine-month overview of selected production and financial information, including trends below for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
 
For the Nine Months Ended September 30, 2015
 
(in millions)
Development costs (1)
$
1,008.1

Exploration costs
108.2

Acquisitions
 
Proved properties
9.2

Unproved properties (2)
14.8

Total, including asset retirement obligations (3)
$
1,140.3

____________________________________________
(1) Includes facility costs of $65.1 million and support facility allocations of $4.9 million for the nine months ended September 30, 2015.
(2) Includes $0.9 million of unproved properties acquired as part of proved property acquisitions for the nine months ended September 30, 2015. The remaining balance is leasing activity.
(3) Includes amounts relating to estimated asset retirement obligations of $11.6 million and capitalized interest of $18.1 million for the nine months ended September 30, 2015.


28

Costs incurred in oil and gas producing activities, excluding proved and unproved property acquisitions, estimated asset retirement obligations, capitalized interest, and support facility allocation amounts disclosed above for the nine months ended September 30, 2015, totaled approximately $1.10 billion. Please refer to Production Results above for discussion on completion activity for the year to date, in addition to Third Quarter 2015 Highlights and Outlook for the Remainder of 2015 above for discussion on wells that have been drilled during 2015, but not completed as of September 30, 2015. Additionally, please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital expenditure program.

Mid-Continent Divestitures. During the second quarter of 2015, we completed the divestiture of our Mid-Continent assets in separate transactions for total divestiture proceeds of $316.5 million, with an estimated net gain of $108.4 million. These divestitures are subject to normal post-closing adjustments. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale in Part I, Item 1 of this report for additional information.

2025 Notes. On May 21, 2015, we issued $500.0 million in aggregate principal amount of 2025 Notes. The notes were issued at par and mature on June 1, 2025. We received net proceeds of $491.0 million from this issuance, which we used to fund the consideration paid to the tendering holders of the 2019 Notes and to redeem the remaining un-tendered 2019 Notes, as well as repay outstanding borrowings under our credit facility and for general corporate purposes. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional information.


29

Financial Results of Operations and Additional Comparative Data

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

 
For the Three Months Ended
 
September 30,
 
June 30,
 
March 31,
 
December 31,
 
2015
 
2015
 
2015
 
2014
 
(in millions, except for production data)
Production (MMBOE)
16.1

 
16.5

 
16.8

 
16.2

Oil, gas, and NGL production revenue
$
366.6

 
$
441.3

 
$
393.3

 
$
586.6

Oil, gas, and NGL production expense
$
184.6

 
$
173.7

 
$
196.2

 
$
196.2

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
243.9

 
$
219.7

 
$
217.4

 
$
219.3

Exploration
$
19.7

 
$
25.5

 
$
37.4

 
$
49.7

General and administrative
$
37.8

 
$
42.6

 
$
43.6

 
$
52.2

Net income (loss)
$
3.1

 
$
(57.5
)
 
$
(53.1
)
 
$
331.7

____________________________________________
Note: Amounts may not calculate due to rounding.

Selected Performance Metrics:

 
For the Three Months Ended
 
September 30,
 
June 30,
 
March 31,
 
December 31,
 
2015
 
2015
 
2015
 
2014
Average net daily production equivalent (MBOE/d)
174.5

 
181.0

 
186.4

 
175.8

Lease operating expense (per BOE)
$
3.86

 
$
3.26

 
$
3.96

 
$
4.29

Transportation costs (per BOE)
$
6.27

 
$
5.64

 
$
6.08

 
$
5.77

Production taxes as a percent of oil, gas, and NGL production revenue
4.2
%
 
5.2
%
 
4.8
%
 
4.7
%
Ad valorem tax expense (per BOE)
$
0.40

 
$
0.25

 
$
0.52

 
$
0.37

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
$
15.19

 
$
13.34

 
$
12.96

 
$
13.56

General and administrative (per BOE)
$
2.35

 
$
2.59

 
$
2.60

 
$
3.23

____________________________________________
Note: Amounts may not calculate due to rounding.

30

A three-month and nine-month overview of selected production and financial information, including trends:
 
For the Three Months Ended September 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
For the Nine Months Ended September 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
2015
 
2014
 
 
2015
 
2014
 
Net production volumes (1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
4.5

 
4.0

 
0.5

 
13
 %
 
14.8

 
11.6

 
3.3

 
28
 %
Gas (Bcf)
43.3

 
35.6

 
7.8

 
22
 %
 
133.5

 
109.1

 
24.4

 
22
 %
NGLs (MMBbl)
4.3

 
3.2

 
1.1

 
35
 %
 
12.2

 
9.2

 
3.0

 
32
 %
Equivalent (MMBOE)
16.1

 
13.1

 
2.9

 
22
 %
 
49.3

 
39.0

 
10.3

 
27
 %
Average net daily production (1)