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EX-31.2 - EXHIBIT 31.2 - SM Energy Cosm-312certificationwpursel.htm



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, 2014
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 22, 2014, the registrant had 67,405,401 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,
2014
 
December 31,
2013
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
269

 
$
282,248

Accounts receivable
304,175

 
318,371

Derivative asset
41,295

 
21,559

Deferred income taxes
9,084

 
10,749

Prepaid expenses and other
16,782

 
14,574

Total current assets
371,605

 
647,501

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
6,789,927

 
5,637,462

Less - accumulated depletion, depreciation, and amortization
(3,045,006
)
 
(2,583,698
)
Unproved oil and gas properties
536,100

 
271,100

Wells in progress
637,584

 
279,654

Oil and gas properties held for sale net of accumulated depletion, depreciation and amortization of $22,482 and $7,390, respectively
19,883

 
19,072

Other property and equipment, net of accumulated depreciation of $35,627 and $28,775, respectively
276,953

 
236,202

Total property and equipment, net
5,215,441

 
3,859,792

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
22,510

 
30,951

Restricted cash

 
96,713

Other noncurrent assets
51,190

 
70,208

Total other noncurrent assets
73,700

 
197,872

Total Assets
$
5,660,746

 
$
4,705,165

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
664,925

 
$
606,751

Derivative liability
4,649

 
26,380

Other current liabilities

 
6,000

Total current liabilities
669,574

 
639,131

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
390,000

 

Senior Notes (note 5)
1,600,000

 
1,600,000

Asset retirement obligation
123,905

 
115,659

Asset retirement obligation associated with oil and gas properties held for sale
452

 
3,033

Net Profits Plan liability
41,705

 
56,985

Deferred income taxes
846,698

 
650,125

Derivative liability
8,243

 
4,640

Other noncurrent liabilities
28,329

 
28,771

Total noncurrent liabilities
3,039,332

 
2,459,213

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 67,393,867 and 67,078,853 shares outstanding, respectively; net of treasury shares: 67,393,867 and 67,056,441, respectively
674

 
671

Additional paid-in capital
273,783

 
257,720

Treasury stock, at cost: zero and 22,412 shares, respectively

 
(823
)
Retained earnings
1,682,273

 
1,354,669

Accumulated other comprehensive loss
(4,890
)
 
(5,416
)
Total stockholders’ equity
1,951,840

 
1,606,821

Total Liabilities and Stockholders’ Equity
$
5,660,746

 
$
4,705,165

 
 
 
 
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,
 
2014
 
2013
 
2014
 
2013
Operating revenues:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
617,207


$
601,787


$
1,894,977


$
1,605,882

Other operating revenues
1,579

 
11,320

 
31,509

 
50,765

Total operating revenues
618,786


613,107


1,926,486


1,656,647













Operating expenses:











Oil, gas, and NGL production expense
178,390


158,921


519,697


434,291

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
183,259


195,792


548,255


620,232

Exploration
34,556

 
16,280


80,161


52,335

Impairment of proved properties

 
5,935

 

 
61,706

Abandonment and impairment of unproved properties
15,522

 
3,818

 
18,487

 
8,459

General and administrative
41,696

 
33,920


114,862


101,574

Change in Net Profits Plan liability
(6,399
)

940


(15,280
)

(6,423
)
Derivative (gain) loss
(190,661
)
 
39,933


33,470


(14,685
)
Other operating expenses
5,444

 
20,084

 
19,505

 
71,192

Total operating expenses
261,807


475,623


1,319,157


1,328,681













Income from operations
356,979


137,484


607,329


327,966













Non-operating income (expense):











Interest expense
(22,621
)

(24,488
)

(70,851
)

(65,170
)
Other, net
(672
)

28


(2,493
)

64













Income before income taxes
333,686


113,024


533,985


262,860

Income tax expense
(124,748
)

(42,334
)

(199,660
)

(98,921
)












Net income
$
208,938


$
70,690


$
334,325


$
163,939













Basic weighted-average common shares outstanding
67,379

 
66,943

 
67,169

 
66,486













Diluted weighted-average common shares outstanding
68,430

 
68,253

 
68,258

 
67,969













Basic net income per common share
$
3.10


$
1.06


$
4.98


$
2.47













Diluted net income per common share
$
3.05


$
1.04


$
4.90


$
2.41













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 (UNAUDITED)
(in thousands)
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
 
2014
 
2013
 
2014
 
2013
 
 
 
 
 
 
 
 
Net income
$
208,938

 
$
70,690

 
$
334,325

 
$
163,939

Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Reclassification to earnings (1)

 
308

 

 
1,115

Pension liability adjustment
196

 

 
526

 
(3
)
Total other comprehensive income, net of tax
196

 
308

 
526

 
1,112

Total comprehensive income
$
209,134

 
$
70,998

 
$
334,851

 
$
165,051

____________________________________________
(1) Reclassification from accumulated other comprehensive loss (AOCL) related to de-designated hedges. As of December 31, 2013, all commodity derivative contracts that had been designated as cash flow hedges were settled and reclassified into earnings from AOCL.


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,
 
2014
 
2013
Cash flows from operating activities:
 
 
 
Net income
$
334,325

 
$
163,939

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
548,255

 
620,232

Exploratory dry hole expense
22,844

 
5,878

Impairment of proved properties

 
61,706

Abandonment and impairment of unproved properties
18,487

 
8,459

Stock-based compensation expense
24,568

 
25,495

Change in Net Profits Plan liability
(15,280
)
 
(6,423
)
Derivative (gain) loss
33,470

 
(14,685
)
Derivative cash settlement gain (loss)
(62,894
)
 
12,715

Amortization of deferred financing costs
4,433

 
3,914

Deferred income taxes
198,180

 
98,619

Plugging and abandonment
(6,193
)
 
(7,453
)
Other, net
(2,986
)
 
3,439

Changes in current assets and liabilities:
 
 
 
Accounts receivable
6,476

 
(45,209
)
Prepaid expenses and other
234

 
(2,461
)
Accounts payable and accrued expenses
(28,797
)
 
72,704

Net cash provided by operating activities
1,075,122

 
1,000,869

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from sale of oil and gas properties
41,868

 
20,498

Capital expenditures
(1,317,862
)
 
(1,121,355
)
Acquisition of proved and unproved oil and gas properties
(459,277
)
 
(62,007
)
Other, net
(714
)
 
(3,509
)
Net cash used in investing activities
(1,735,985
)
 
(1,166,373
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
536,500

 
976,500

Repayment of credit facility
(146,500
)
 
(1,288,500
)
Deferred financing costs related to credit facility

 
(3,444
)
Net proceeds from 2024 Notes

 
490,274

Proceeds from sale of common stock
2,898

 
4,450

Dividends paid
(3,353
)
 
(3,314
)
Net share settlement from issuance of stock awards
(10,576
)
 
(16,203
)
Other, net
(85
)
 
(9
)
Net cash provided by financing activities
378,884

 
159,754

 
 
 
 
Net change in cash and cash equivalents
(281,979
)
 
(5,750
)
Cash and cash equivalents at beginning of period
282,248

 
5,926

Cash and cash equivalents at end of period
$
269

 
$
176

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,
 
2014
 
2013
 
(in thousands)
Cash paid for interest, net of capitalized interest
$
79,119

 
$
59,841

 
 
 
 
Net cash paid (refunded) for income taxes
$
1,979

 
$
(259
)

Dividends of approximately $3.4 million were declared by the Company’s Board of Directors, but not paid, as of September 30, 2014. Dividends of approximately $3.3 million were declared by the Company’s Board of Directors, but not paid, as of September 30, 2013.

As of September 30, 2014, and 2013, $404.8 million and $238.7 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 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 with a fair value of $6.2 million. During the third quarter of 2013, the Company exchanged properties in its Rocky Mountain region with a fair value of $25.0 million. The cash consideration exchanged at the respective closings 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, with a current focus on oil and liquids-rich resource plays.

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. They do not include all information and notes required by GAAP for complete 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, 2013 (the “2013 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, 2014, through the filing date of this report.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in its 2013 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 2013 Form 10-K.

Recently Issued Accounting Standards

                In April 2014, the Financial Accounting Standards Board (“FASB”) issued new authoritative accounting guidance related to the recognition and presentation of discontinued operations in the financial statements.  This guidance intends to reduce the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have, or will have, a major effect on an entity’s operations and financial results.  This guidance is to be applied prospectively and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2014.  Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

                In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue from contracts with customers. This guidance is to be applied using a retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early application is not permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.
               
                In June 2014, the FASB issued new authoritative accounting guidance related to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period.  This guidance may be applied either prospectively or retrospectively and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015.  Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.


8


                In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met.  This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted.  The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

There are no other new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of September 30, 2014, and through the filing date of this report.

Note 3 – Acquisitions, Divestitures, and Assets Held for Sale
Gooseneck Prospect Acquisition

On September 24, 2014, the Company acquired approximately 61,000 net acres of proved and unproved oil and gas properties in the Company’s Gooseneck prospect area in North Dakota, along with other related equipment, contracts, records and other assets (collectively the “Assets”). Total consideration paid by the Company was $325.2 million in cash and the effective date for the acquisition was July 1, 2014.

It was determined that this acquisition met the definition of a business combination under ASC 805, Business Combinations, as it included proved properties. The Company allocated the preliminary adjusted purchase price to the acquired assets and liabilities based on fair values as of the acquisition date of September 24, 2014, as summarized in the following table. This acquisition is subject to normal post-closing adjustments, which are expected to be completed in early 2015. Refer to Note 11 - Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of acquired properties.

Purchase Price
As of September 24, 2014
 
(in thousands)
Cash consideration
$
325,230

 
 
Fair value of assets acquired:
 
Proved oil and gas properties
$
201,842

Unproved oil and gas properties
125,562

Total fair value of oil and gas properties acquired
327,404

 
 
Working capital
(61
)
Asset retirement obligation
(2,113
)
Total fair value of net assets acquired
$
325,230


Rocky Mountain Acquisitions

In addition to the Gooseneck prospect acquisition discussed above, the Company acquired other proved and unproved properties in its Rocky Mountain region during the nine months ended September 30, 2014, from multiple sellers for approximately $134.1 million in total cash consideration plus approximately 7,000 net acres of non-core assets in the Company’s Rocky Mountain region. These acquisitions are subject to normal post-closing adjustments, which are expected to be completed in late 2014 and early 2015.

Subsequent to September 30, 2014, the Company closed an acquisition of proved and unproved properties in its Gooseneck prospect area for total cash consideration of approximately $84.8 million. This acquisition is subject to normal post-closing adjustments, which are expected to be completed in early 2015.

9


Divestitures

During the second quarter of 2014, the Company divested certain non-strategic assets in the Williston Basin located in its Rocky Mountain region. Total cash proceeds received at closing (referred throughout this report as “divestiture proceeds”) were $50.2 million and the estimated net gain is $26.8 million. This divestiture is subject to normal post-closing adjustments, which are expected to be completed during the fourth quarter of 2014.

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

As of September 30, 2014, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $19.9 million of oil and gas properties held for sale, net of accumulated depletion, depreciation, and amortization expense. A corresponding asset retirement obligation liability of $0.5 million is separately presented. Assets held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. Certain assets classified as held for sale as of September 30, 2014, were written down to fair value less estimated costs to sell, which was recorded as a loss on divestiture activity and is included within the other operating revenues line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).

The Company determined that these planned asset sales do not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

Note 4 - Income Taxes

Income tax expense for the three and nine months ended September 30, 2014, and 2013, differs from the amounts 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, and other permanent differences. The quarterly rate can also be impacted by the proportional effects of forecasted net income 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,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Current portion of income tax (benefit) expense:
 
 
 
 
 
 
 
Federal
$

 
$

 
$

 
$

State
479

 
(46
)
 
1,480

 
302

Deferred portion of income tax expense
124,269

 
42,380

 
198,180

 
98,619

Total income tax expense
$
124,748

 
$
42,334

 
$
199,660

 
$
98,921

 
37.4
%
 
37.5
%
 
37.4
%
 
37.6
%

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.


10


The Company and its subsidiaries file federal income tax returns and various state income tax returns. With certain exceptions, the Company is no longer subject to United States federal or state income tax examinations by tax authorities for years before 2007. Federal tax law allowing for the calculation of an R&D credit was enacted in 2013, which allowed the credit for the 2012 and 2013 tax years. However, the Company has not yet commissioned a study to calculate the credit for these tax years. The table above excludes the impact for any credit that could be claimed for the 2013 tax year. The Internal Revenue Service (“IRS”) initiated an audit in the first quarter of 2012 related to R&D tax credits claimed by the Company for the 2007 through 2010 tax years. On April 23, 2013, the IRS issued a Notice of Proposed Adjustment disallowing $4.6 million of R&D tax credits claimed for open tax years during the audit period. During the quarter ended September 30, 2014, the Company successfully reached an agreement with the IRS Appeals Office, which allowed the Company to claim a portion of these R&D credits and resulted in no significant adjustment.

On September 13, 2013, the United States Department of the Treasury issued the final and re-proposed tangible property regulations effective for tax years beginning January 1, 2014. The Company has determined it is materially compliant with the requirements of these regulations.

Note 5 - Long-term Debt

Revolving Credit Facility

The Company’s Fifth Amended and Restated Credit Agreement provides a maximum loan amount of $2.5 billion, current aggregate lender commitments of $1.3 billion, and a maturity date of April 12, 2018.  The borrowing base is subject to regular semi-annual redeterminations. On October 6, 2014, the lending group redetermined the Company’s borrowing base under the credit facility and increased it from $2.2 billion to $2.4 billion, with no change in the aggregate lender commitments of $1.3 billion. The borrowing base redetermination process under the credit facility considers the value of the Company’s proved oil and gas properties, as determined by the lender group. The next scheduled redetermination date is April 1, 2015. Borrowings under the facility are secured by at least 75 percent of the Company’s proved oil and gas properties. 
 
The Company must comply with certain financial and non-financial covenants under the terms of its credit facility 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 facility as of September 30, 2014, 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 Company’s credit facility as of October 22, 2014, September 30, 2014, and December 31, 2013:

 
As of October 22, 2014
 
As of September 30, 2014
 
As of December 31, 2013
 
(in thousands)
Credit facility balance
$
558,500

 
$
390,000

 
$

Letters of credit (1)
$
808

 
$
808

 
$
808

Available borrowing capacity
$
740,692

 
$
909,192

 
$
1,299,192

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

11


Senior Notes
The Senior Notes line on the accompanying balance sheets represents the outstanding principal amount of the 6.625% Senior Notes due 2019 (the “2019 Notes”), the 6.50% Senior Notes due 2021 (the “2021 Notes”), the 6.50% Senior Notes due 2023 (the “2023 Notes”), and the 5.0% Senior Notes due 2024 (the “2024 Notes” and collectively with the 2019 Notes, 2021 Notes, and 2023 Notes, the “Senior Notes”), as shown in the table below:
 
As of September 30, 2014
 
As of December 31, 2013
 
(in thousands)
2019 Notes
$
350,000

 
$
350,000

2021 Notes
350,000

 
350,000

2023 Notes
400,000

 
400,000

2024 Notes
500,000

 
500,000

Total Senior Notes
$
1,600,000

 
$
1,600,000


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 these covenants. The Company does not expect these restrictions to limit its ability to continue paying dividends at its current rate for the foreseeable future if declared by the Company’s Board of Directors. The Company was in compliance with all covenants under its Senior Notes as of September 30, 2014, and through the filing date of this report.
2024 Notes
On May 20, 2013, the Company issued $500.0 million in aggregate principal amount of 2024 Notes. The 2024 Notes were issued at par and mature on January 15, 2024. Please refer to Note 5 - Long-term Debt in the Company’s 2013 Form 10-K for additional discussion of the terms of these notes.
On May 20, 2013, the Company entered into a registration rights agreement that provided holders of the 2024 Notes certain registration rights under the Securities Act of 1933, as amended (the “Securities Act”). The Company closed its offer to exchange its 2024 Notes for notes registered under the Securities Act on June 25, 2014.

Note 6 - Commitments and Contingencies

Commitments

During the first nine months of 2014, the Company entered into drilling rig contracts with total expected commitments of $110.5 million and varying terms extending through 2016. As of September 30, 2014, the remaining expected drilling commitments totaled $72.3 million. Early termination of the remaining contracts would result in penalties totaling $42.5 million as of September 30, 2014. Subsequent to September 30, 2014, the Company entered into additional drilling rig contracts with future expected commitments totaling $24.5 million, and varying terms extending through 2016. Early termination of these contracts would result in penalties totaling $14.4 million.

During the third quarter of 2014, as part of the Gooseneck prospect acquisition described in Note 3 - Acquisitions, Divestitures, and Assets Held for Sale, the Company assumed a share of the seller’s rights and obligations under a gas purchase agreement whereby the Company is subject to certain through-put commitments extending through 2028. The Company may be required to make periodic deficiency payments for any shortfalls in delivering the minimum applicable annual volume commitment. In the event that no product is delivered in accordance with this agreement, the undiscounted aggregate deficiency payments totaled approximately $24.4 million as of September 30, 2014. Subsequent to September 30, 2014, the Company closed an acquisition resulting in an increase it its obligations under this gas purchase agreement. As of the filing date of this report, in the event that no product is delivered in accordance with this agreement, the undiscounted aggregate deficiency payments total approximately $42.6 million. The Company expects to deliver at least the minimum applicable annual volumes under this agreement.


12


Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such 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.

On April 16, 2014, the Company settled its previously disclosed litigation against Endeavour Operating Corporation (“Endeavour”). The Company, its working interest partners, and Endeavour agreed to mutually release all claims and dismiss the lawsuit in exchange for certain cash payments and other consideration paid to the Company and its working interest partners by Endeavour. The Company recorded a $10.7 million gain in the other operating revenues line item in the accompanying statements of operations in the second quarter of 2014 relating to this settlement.

On January 27, 2011, Chieftain Royalty Company (“Chieftain”) filed a Class Action Petition against the Company in the District Court of Beaver County, Oklahoma, claiming damages related to royalty payments on all of the Oklahoma oil and gas wells operated by the Company and its predecessors. These claims include breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Company removed this lawsuit to the United States District Court for the Western District of Oklahoma on February 22, 2011. The Company responded to the petition and denied the allegations. The district court did not rule on Chieftain’s motion to certify the putative class, and stayed all proceedings until the United States Court of Appeals for the Tenth Circuit issued its rulings on class certification in two similar royalty class action lawsuits. On July 9, 2013, the Tenth Circuit issued its opinions, reversing the trial courts’ grant of class certification and remanding the matters to the trial courts for those cases. The district court presiding over the Company’s case subsequently lifted its stay, and the Company now expects Chieftain to file a new motion for class certification in the first half of 2016.

This case involves complex legal issues and uncertainties; a potentially large class of plaintiffs, and a large number of related producing properties, lease agreements and wells; and an alleged class period commencing in 1988 and spanning the entire producing life of the wells. Because the proceedings are in the early stages, with discovery yet to be completed, the Company is unable to estimate what impact, if any, the action will have on its financial condition, results of operations, or cash flows. The Company is still evaluating the claims, but believes that it has properly paid royalties under Oklahoma law and has and will continue to vigorously defend this case. On December 30, 2013, the Company sold a substantial portion of the assets that were subject to this matter and the buyer assumed any such liabilities related to such properties.

Note 7 - Compensation Plans

Cash Bonus Plan

During the first nine months of 2014 and 2013, the Company paid $41.7 million and $16.0 million, respectively, for cash bonuses earned during the 2013 and 2012 performance years, respectively. The general and administrative (“G&A”) expense and exploration expense line items in the accompanying statements of operations include $6.2 million and $5.8 million of accrued cash bonus plan expense for the three months ended September 30, 2014, and 2013, respectively, and $19.0 million and $16.7 million of accrued cash bonus plan expense for the nine months ended September 30, 2014, and 2013, respectively, related to the respective performance years.

Non-qualified Deferred Compensation Plan

In January 2014, the Company established a non-qualified deferred compensation (“NQDC”) plan intended to provide plan participants with the ability to plan for income tax events and the opportunity to receive a benefit for matching contributions in excess of Internal Revenue Code (“IRC”) limits applicable to the Company’s 401(k) plan. The NQDC plan is designed to allow employee participants to defer a portion of base salary and cash bonuses paid pursuant to the Company’s cash bonus plan and director participants to defer a portion of the cash retainer paid to directors. Each year, participating employees may elect to defer (i) between 0% and 50% of their base salary and (ii) between 0% and 100% of the cash bonus paid pursuant to the cash bonus plan, and participating directors may elect to defer between 0% and 100% of their cash retainer. The NQDC plan requires the Company to make contributions for each eligible employee equal to 100% of the deferred amount for such employee, limited to 6% of such employee’s base salary and cash bonus. Each eligible employee’s interest in contributions made by the Company will vest 40% after the second year of such employee’s service to the Company, and 20% per year thereafter. A participant’s account will be distributed based upon the participant’s payment election made at the time of deferral. A participant may elect to have distributions made in lump sum or in

13


annual installments ranging for a period from 1 to 10 years. Participants in the NQDC plan are currently limited to the Company’s officers and directors.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants restricted stock units (“RSUs”) as part of its equity compensation program. Each RSU represents a right to one share of the Company’s common stock to be delivered upon settlement of the award at the end of the specified vesting period. Expense associated with RSUs is recognized as G&A expense and exploration expense over the vesting period of the award.

Total expense recorded for RSUs for the three months ended September 30, 2014, and 2013, was $4.8 million and $3.7 million, respectively, and $10.5 million and $10.0 million for the nine months ended September 30, 2014, and 2013, respectively. As of September 30, 2014, there was $26.7 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2017.

A summary of the status and activity of non-vested RSUs for the nine-month period ended September 30, 2014, is presented in the following table:

 
RSUs
 
Weighted-Average
 Grant-Date
Fair Value
Non-vested at beginning of year
580,431

 
$
57.05

Granted
233,601

 
$
84.11

Vested
(250,601
)
 
$
58.09

Forfeited
(32,736
)
 
$
59.07

Non-vested at end of quarter
530,695

 
$
68.34

The fair value of the RSUs granted during the first nine months of 2014 was $19.6 million. These RSUs will vest 1/3rd on each of the next three anniversary dates of the grant. During the first nine months of 2014, the Company settled 250,601 RSUs that related to awards granted in previous years. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company issued 169,835 net shares of common stock. The remaining 80,766 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those RSUs.
Performance Share Units Under the Equity Incentive Compensation Plan

The Company grants performance share units (“PSUs”) as part of its 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 the Company’s performance 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 measurement period and the relative performance of the Company’s TSR compared with the annualized TSRs of a group of peer companies for the measurement period. Expense associated with PSUs is recognized as G&A expense and exploration expense over the vesting period of the award.

Total expense recorded for PSUs for the three months ended September 30, 2014, and 2013, was $4.8 million and $3.5 million, respectively, and $11.6 million and $13.2 million for the nine months ended September 30, 2014, and 2013, respectively. As of September 30, 2014, there was $24.7 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2017.


14


A summary of the status and activity of non-vested PSUs for the nine-month period ended September 30, 2014, is presented in the following table:
 
PSUs (1)
 
Weighted-Average
 Grant-Date
Fair Value
Non-vested at beginning of year
572,469

 
$
66.07

Granted
202,404

 
$
94.66

Vested
(115,784
)
 
$
59.30

Forfeited
(129,491
)
 
$
87.21

Non-vested at end of quarter
529,598

 
$
73.31

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

The fair value of the PSUs granted during the first nine months of 2014 was $19.2 million. These PSUs will vest on the third anniversary of the date of the grant. During the first nine months of 2014, the Company settled PSUs that were granted in 2011, which earned a 0.55 times multiplier, by issuing a net 85,121 shares of the Company’s common stock in accordance with the terms of the PSU awards. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company withheld 45,042 shares to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs.

Stock Option Grants Under the Equity Incentive Compensation Plan

A summary of activity associated with the Company’s Stock Option Plan for the nine months ended September 30, 2014, is presented in the following table:
 
Shares
 
Weighted-
Average
Exercise Price
 
Aggregate
 Intrinsic Value (in thousands)
Outstanding, at beginning of year
39,088

 
$
20.87

 
$
2,433

Exercised
(19,544
)
 
$
20.87

 
$
1,237

Forfeited

 
$

 
$

Outstanding, at end of quarter
19,544

 
$
20.87

 
$
1,117

Vested and exercisable, at end of quarter
19,544

 
$
20.87

 
$
1,117


As of September 30, 2014, there was no unrecognized compensation expense related to stock option awards.
Director Shares
During the nine months ended September 30, 2014 and 2013, the Company issued 27,677 and 28,169 shares, respectively, of its common stock to its non-employee directors, under the Company’s Equity Incentive Compensation Plan.  The Company recorded $196,000 of compensation expense related to these awards for the three months ended September 30, 2014, and no compensation expense related to these awards for the three months ended September 30, 2013. The Company recorded $1.4 million and $1.4 million of compensation expense related to these awards for the nine months ended September 30, 2014, and 2013, 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 by the director, in which case that director's shares vest immediately.

15


Employee Stock Purchase Plan
Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The Company had 1.2 million shares available for issuance under the ESPP as of September 30, 2014. The Company issued 35,249 and 44,437 shares under the ESPP during the first nine months of 2014 and 2013, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.
Net Profits Interest Bonus Plan

Cash payments made or accrued under the Company’s Net Profits Interest Bonus Plan (“Net Profits Plan”) that have been recorded as either G&A expense or exploration expense are presented in the table below:

 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
General and administrative expense
$
2,487

 
$
4,302

 
$
7,451

 
$
11,531

Exploration expense
162

 
329

 
644

 
1,026

Total
$
2,649

 
$
4,631

 
$
8,095

 
$
12,557

    
Additionally, the Company accrued or made cash payments under the Net Profits Plan of $8.3 million and $2.6 million for the nine months ended September 30, 2014, and 2013, respectively, as a result of divestiture proceeds. These cash payments are accounted for as a reduction in gain on divestiture activity included within the other operating revenues line in the accompanying statements of operations.

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”).

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,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Service cost
$
1,584

 
$
1,572

 
$
4,752

 
$
4,718

Interest cost
548

 
407

 
1,643

 
1,220

Expected return on plan assets that reduces periodic pension costs
(494
)
 
(384
)
 
(1,483
)
 
(1,153
)
Amortization of prior service costs
4

 
4

 
13

 
13

Amortization of net actuarial loss
172

 
306

 
516

 
917

Net periodic benefit cost
$
1,814

 
$
1,905

 
$
5,441

 
$
5,715


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.


16


Contributions

The Company contributed $5.3 million to the Pension Plans during the nine month period ended September 30, 2014.

Note 9 - Earnings per Share

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

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.

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,
 
2014
 
2013
 
2014
 
2013
 
(in thousands, except per share amounts)
Net income
$
208,938

 
$
70,690

 
$
334,325

 
$
163,939

Basic weighted-average common shares outstanding
67,379

 
66,943

 
67,169

 
66,486

Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs
1,051

 
1,310

 
1,089

 
1,483

Diluted weighted-average common shares outstanding
68,430

 
68,253

 
68,258

 
67,969

Basic net income per common share
$
3.10

 
$
1.06

 
$
4.98

 
$
2.47

Diluted net income per common share
$
3.05

 
$
1.04

 
$
4.90

 
$
2.41


Note 10 - Derivative Financial Instruments

Summary of Oil, Gas, and NGL Derivative Contracts in Place
    
The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivative contracts include swap and costless collar arrangements for oil, gas, and NGLs.
    
As of September 30, 2014, the Company had commodity derivative contracts outstanding through the second quarter of 2018 for a total of 17.6 million Bbls of oil production, 164.1 million MMBtu of gas production, and 1.8 million Bbls of NGL production.
    
In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference.  For collar 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.

17


The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of September 30, 2014:

Oil Contracts

Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(Bbls)
 
(per Bbl)
Fourth quarter 2014
 
2,016,000

 
$
96.01

2015
 
5,741,000

 
$
91.14

2016
 
5,570,000

 
$
88.01

All oil swaps
 
13,327,000

 
 

Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(Bbls)
 
(per Bbl)
 
(per Bbl)
Fourth quarter 2014
 
923,000

 
$
85.00

 
$
102.63

2015
 
3,366,000

 
$
85.00

 
$
94.25

All oil collars
 
4,289,000

 
 
 
 

Gas Contracts

Gas Swaps
Contract Period
 
Volumes
 
Weighted-Average
 Contract Price
 
 
(MMBtu)
 
(per MMBtu)
Fourth quarter 2014
 
22,014,000

 
$
4.02

2015
 
57,943,000

 
$
4.04

2016
 
37,472,000

 
$
4.17

2017
 
23,430,000

 
$
4.21

2018
 
10,200,000

 
$
4.31

All gas swaps*
 
151,059,000

 
 

*Gas swaps are comprised of IF El Paso Permian (4%), IF HSC (83%), IF NGPL TXOK (2%), IF NNG Ventura (2%), IF Enable East (8%), and IF CIG (1%).

Gas Collars
Contract Period
 
Volumes
 
Weighted-
Average Floor
Price
 
Weighted-
Average Ceiling
Price
 
 
(MMBtu)
 
(per MMBtu)
 
(per MMBtu)
2015
 
13,002,000

 
$
3.98

 
$
4.30

All gas collars*
 
13,002,000

 
 
 
 

*Gas collars are comprised of IF El Paso Permian (4%), IF HSC (80%), IF NNG Ventura (8%), and IF Enable East (8%).

18


NGL Contracts

NGL Swaps
Contract Period
 
Volumes
 
Weighted-Average
 Contract Price
 
 
(Bbls)
 
(per Bbl)
Fourth quarter 2014
 
980,000

 
$
61.69

2015
 
781,000

 
$
55.42

All NGL swaps*
 
1,761,000

 
 

*NGL swaps are comprised of Oil Price Information System (“OPIS”) Mont Belvieu LDH Propane (67%) and OPIS Mont Belvieu NON-LDH Natural Gasoline (33%).

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 $50.9 million and net asset of $21.5 million as of September 30, 2014, and December 31, 2013, respectively.

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

 
As of September 30, 2014
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
41,295

 
Current liabilities
 
$
4,649

Commodity contracts
Noncurrent assets
 
22,510

 
Noncurrent liabilities
 
8,243

Derivatives not designated as hedging instruments
 
 
$
63,805

 
 
 
$
12,892


 
As of December 31, 2013
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
21,559

 
Current liabilities
 
$
26,380

Commodity contracts
Noncurrent assets
 
30,951

 
Noncurrent liabilities
 
4,640

Derivatives not designated as hedging instruments
 
 
$
52,510

 
 
 
$
31,020


Offsetting of Derivative Assets and Liabilities

As of September 30, 2014, and December 31, 2013, all derivative instruments held by the Company were subject to enforceable 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 settlements that occur 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.
 

19


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, 2014
 
December 31, 2013
 
September 30, 2014
 
December 31, 2013
 
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
 
$
63,805

 
$
52,510

 
$
(12,892
)
 
$
(31,020
)
Amounts not offset in the accompanying balance sheets
 
(12,744
)
 
(30,652
)
 
12,744

 
30,652

Net amounts
 
$
51,061

 
$
21,858

 
$
(148
)
 
$
(368
)
    
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,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Derivative cash settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
517

 
$
13,538

 
27,435

 
$
13,786

Gas contracts
1,687

 
(11,019
)
 
28,563

 
(18,752
)
NGL contracts
(1,930
)
 
(1,231
)
 
6,896

 
(7,749
)
Total derivative cash settlement (gain) loss(1)
274


1,288


62,894


(12,715
)
 
 
 
 
 
 
 
 
Derivative (gain) loss:
 
 
 
 
 
 
 
Oil contracts
(141,429
)
 
30,488

 
(42,802
)
 
8,233

Gas contracts
(43,039
)
 
(2,264
)
 
17,700

 
(12,462
)
NGL contracts
(6,467
)
 
10,421

 
(4,322
)
 
2,259

Total derivative (gain) loss (2)
$
(190,661
)

$
39,933


$
33,470


$
(14,685
)
____________________________________________
(1) 
Total derivative cash settlement (gain) loss is reported in the derivative cash settlement gain (loss) line item on the condensed consolidated statements of cash flows within net cash provided by operating activities.
(2) 
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, 2014, 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 liens on at least 75 percent of the Company’s proved oil and gas properties.


20


Note 11 - Fair Value Measurements

The Company follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fair value. That authoritative accounting 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 is a listing of the Company’s assets and liabilities that are measured at fair value and their classification within the fair value hierarchy as of September 30, 2014:


Level 1

Level 2

Level 3

(in thousands)
Assets:








Derivatives (1)
$


$
63,805


$

Proved oil and gas properties (2)
$


$


$
9,443

Unproved oil and gas properties (2)
$


$


$
43,252

Oil and gas properties held for sale (2)
$


$


$
17,952

Liabilities:








Derivatives (1)
$


$
12,892


$

Net Profits Plan (1)
$


$


$
41,705

Asset retirement obligation (2)
$


$


$
923

Asset retirement obligation associated with oil and gas properties held for sale (2)
$


$


$
452

____________________________________________
(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 or liability 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 and their classification within the fair value hierarchy as of December 31, 2013:

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

 
$
52,510

 
$

Proved oil and gas properties (2)
$

 
$

 
$
62,178

Unproved oil and gas properties (2)
$

 
$

 
$
3,280

Oil and gas properties held for sale (2)
$

 
$

 
$
650

Liabilities:
 
 
 
 
 
Derivatives (1)
$

 
$
31,020

 
$

Net Profits Plan (1)
$

 
$

 
$
56,985

____________________________________________
(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 or liability that is measured at fair value on a nonrecurring basis.


21


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

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration the 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. These 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 liability position with a counterparty. 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 approach, 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 derivatives 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.


22


If the commodity prices used in the calculation changed by five percent, the liability recorded at September 30, 2014, would differ by approximately $4 million. A one percent increase or decrease in the discount rate would result in a change of approximately $2 million. 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.

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 on 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, 2014
 
(in thousands)
Beginning balance
$
56,985

Net increase in liability (1)
1,156

Net settlements (1) (2)
(16,436
)
Transfers in (out) of Level 3

Ending balance
$
41,705


____________________________________________
(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 Company accrued or made cash payments under the Net Profits Plan of $8.3 million as a result of divestitures during the nine months ended September 30, 2014.

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, 2014, or December 31, 2013, as they are recorded at historical value.

 
As of September 30, 2014
 
As of December 31, 2013
 
(in thousands)
2019 Notes
$
364,000

 
$
374,290

2021 Notes
$
371,875

 
$
373,625

2023 Notes
$
415,500

 
$
422,000

2024 Notes
$
492,500

 
$
475,315


As of September 30, 2014, the Company had $390.0 million of floating-rate debt outstanding. The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating and based on prevailing market rates.


23


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 that 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, 2014, and December 31, 2013. The Company believes that 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 forecasted 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 forecasted 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. Proved 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 utilizes the income valuation technique discussed above.

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. 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.
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 and are subject to change. Refer to Note 3 - Acquisitions, Divestiture, and Assets Held for Sale for additional information on the fair value of assets acquired during the nine months ended September 30, 2014.

Asset Retirement Obligations

The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

24


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

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

Overview of the Company, Highlights, and Outlook

General Overview

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, oil-focused plays in the Powder River Basin and Permian Basin, and a position in an emerging play in East Texas. We have built a portfolio of onshore properties in the contiguous United States primarily through early entry into existing and emerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production and reserves growth. By entering these plays early, we believe we can capture larger resource potential at a lower cost.

Our principal business strategy is to focus on the early capture of resource plays in order to create and then enhance value for our stockholders while maintaining a strong balance sheet. We strive to leverage industry-leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have identified potential value through these efforts, our goal is to develop such potential through top-tier operational and project execution, and as appropriate, high-grade our portfolio by selectively divesting assets. We regularly examine our portfolio for opportunities to improve the quality of our asset base in order to optimize our returns and preserve our financial strength.

In the third quarter of 2014, we had the following financial and operational results:

Average net daily production for the three months ended September 30, 2014, was 43.5 MBbls of oil, 386.5 MMcf of gas, and 34.6 MBbls of NGLs, for a quarterly equivalent daily production rate of 142.5 MBOE, compared with 138.8 MBOE for the same period in 2013. Please see additional discussion below under Production Results.

Net income for the three months ended September 30, 2014, was $208.9 million, or $3.05 per diluted share, compared to net income for the three months ended September 30, 2013, of $70.7 million, or $1.04 per diluted share. The increase in net income in the current period is largely driven by an increase in the fair value of commodity derivative contracts. Please refer to the Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2014, and 2013 below for additional discussion regarding the components of net income.
 
Costs incurred for oil and gas property acquisitions and exploration and development activities for the three months ended September 30, 2014, totaled $1.0 billion. The majority of our drilling and completion costs incurred during this period were in our Eagle Ford shale and Bakken/Three Forks programs. Additionally, we acquired approximately $367.6 million of proved and unproved properties in our Gooseneck prospect area and the Powder River Basin during the third quarter of 2014. Total costs incurred for the same period in 2013 were $438.1 million. 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, 2014, was $406.2 million, compared to $410.4 million for the same period in 2013. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our GAAP net income and net cash provided by operating activities to adjusted EBITDAX.


25


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 and condensate are sold using contracts paying us various industry posted prices, most commonly NYMEX West Texas Intermediate (“WTI”). 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. Substantially all of our oil production in our South Texas & Gulf Coast region is condensate. 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 cash settlements, unless otherwise indicated.

The following table summarizes commodity price data, as well as the effects of derivative cash settlements as further discussed under the caption Derivative Activity below, for the second and third quarters of 2014, as well as the third quarter of 2013:

 
For the Three Months Ended
 
September 30, 2014
 
June 30, 2014
 
September 30, 2013
Crude Oil (per Bbl):
 
 
 
 
 
Average daily NYMEX price
$
97.60

 
$
103.06

 
$
105.82

Realized price, before the effects of derivative cash settlements
$
86.56

 
$
91.78

 
$
96.44

Effects of derivative cash settlements
$
(0.12
)
 
$
(5.18
)
 
$
(3.66
)
 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Average daily NYMEX price (per MMBtu)
$
3.94

 
$
4.59

 
$
3.55

Realized price, before the effects of derivatives cash settlements (per Mcf)
$
4.49

 
$
4.87

 
$
3.81

Effects of derivative cash settlements (per Mcf)
$
(0.05
)
 
$
(0.36
)
 
$
0.29

 
 
 
 
 
 
Natural Gas Liquids (per Bbl):
 
 
 
 
 
Average daily OPIS price
$
39.37

 
$
41.21

 
$
40.23

Realized price, before the effects of derivative cash settlements
$
34.86

 
$
35.61

 
$
34.01

Effects of derivative cash settlements
$
0.61

 
$
(0.02
)
 
$
0.49

____________________________________________
Note: 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 could affect the price of oil. Concerns about lower forecasted levels of global economic growth combined with ample supply, particularly from producing countries in the Organization of Petroleum Exporting Countries (“OPEC”), have negatively impacted oil prices in recent weeks. The supply of NGLs in the United States is expected to continue to grow in the near term as a result of the number of industry participants targeting projects that produce these products. If demand does not keep pace with anticipated growth in NGL supply, prices could be negatively impacted. The prices of several NGL products correlate to the price of oil and accordingly are likely to directionally follow that market. Gas prices have been under sustained downward pressure due to high levels of supply in recent years, particularly in the Northeast United States. Longer term, we anticipate natural gas prices will remain near current levels. 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 22, 2014, and September 30, 2014:


26


 
As of October 22, 2014
 
As of September 30, 2014
NYMEX WTI oil (per Bbl)
$
79.31

 
$
88.68

NYMEX Henry Hub gas (per MMBtu)
$
3.68

 
$
4.01

OPIS NGLs (per Bbl)
$
32.44

 
$
37.75


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 future operations and have partially reduced our exposure to volatility in commodity prices.  Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil, gas, and NGL 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 for additional information regarding our oil, gas, and NGL derivatives.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) included provisions requiring over-the-counter derivative transactions to be cleared through clearinghouses and traded on exchanges. On July 10, 2012, the Commodity Futures Trading Commission (“CFTC”) and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms that determine what types of transactions will be subject to regulation under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers compliance dates for a number of other final Dodd-Frank Act rules, including new rules proposed by the CFTC governing margin requirements for uncleared swaps entered into by non-bank swap entities, and new rules proposed by U.S. banking regulators regarding margin requirements for uncleared swaps entered into by bank swap entities. The ultimate effect of these new rules on our business and any additional regulations is currently uncertain. Under CFTC rules we believe our derivative activity qualifies for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk entered into by entities predominantly engaged in non-financial activity from the mandatory swap clearing requirement. However, we are not certain whether the provisions of the final rules and regulations will exempt us from the requirements to post margin in connection with commodity price risk management activities. Final rules and regulations on major provisions of the legislation, such as new margin requirements, are to be established through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules and regulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use to manage our financial risks related to volatility in oil, gas, and NGL commodity prices.

Third Quarter 2014 Highlights and Outlook for the Remainder of 2014

Operational Activities. During the third quarter of 2014, we operated between four and five drilling rigs supported by two frac spreads in our operated Eagle Ford shale program in South Texas. We primarily focused on pad drilling in the northern portion of our acreage position, where there is a higher liquids contribution to our product mix. This year, our development program has shifted to utilizing longer laterals and completions with higher sand loading. Early results from these enhanced completions suggest significantly improved well performance. In the third quarter, production declined due to required shut-ins of producing wells during offset well completions. We believe we have secured the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our current development plans.
In our outside operated Eagle Ford shale program, the operator began the third quarter of 2014 running nine drilling rigs and dropped two rigs during the quarter. The operator expects to run seven rigs for the remainder of 2014. During the second quarter of 2014, the remainder of our carry under our Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd. (the “Acquisition and Development Agreement”), was expended. Accordingly, we accrued our full share of drilling and completion costs for this program in the third quarter of 2014.

We have an ongoing exploration program to acquire leasehold and test concepts in new plays. In 2014, we are evaluating an emerging new venture play in East Texas. We are currently constructing a gathering system to allow for longer-term production tests on wells that we have drilled and completed. We expect this system to be completed in the fourth quarter of 2014.

27


In our Bakken/Three Forks program, we operated three drilling rigs during the third quarter of 2014 focusing on infill drilling of our Raven/Bear Den and Gooseneck prospects in the North Dakota portion of the Williston Basin. We are monitoring the results of various well and completion designs and down-spacing tests of both our operated and non-operated properties and testing the Bakken interval on our Gooseneck and Stateline acreage. During the third quarter of 2014, we completed our acquisition of additional Gooseneck assets and paid $325.2 million at closing, net of normal closing adjustments. We expect to increase rig activity in our Bakken/Three Forks program in the fourth quarter of 2014.
In our Powder River Basin program in Wyoming, we have been accelerating activity and expanding our acreage position through acquisitions from multiple sellers during the nine months ending September 30, 2014. We operated three drilling rigs during the third quarter, and we plan to add a fourth operated drilling rig in the fourth quarter of 2014.
In our Permian program, we operated two drilling rigs during the third quarter of 2014 focused on horizontal testing and development of the Wolfcamp B interval in our Sweetie Peck prospect. In our Buffalo prospect in Gaines and Dawson Counties, Texas, we are monitoring the results of a recently completed Wolfcamp D test well. In the fourth quarter of 2014, we plan to test the Lower Spraberry in both our Sweetie Peck and Buffalo prospects.

Please refer to Overview of Liquidity and Capital Resources below for additional discussion regarding how we intend to fund our 2014 capital program.
Production Results. The table below provides a regional breakdown of our production for the third quarter of 2014:
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Permian
 
Mid-Continent
 
Total (1)
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
1.7

 
1.8

 
0.5

 

 
4.0

Gas (Bcf)
28.0

 
1.7

 
1.1

 
4.7

 
35.6

NGLs (MMBbl)
3.2

 

 

 

 
3.2

Equivalent (MMBOE)
9.5

 
2.1

 
0.7

 
0.8

 
13.1

Avg. daily equivalents (MBOE/d)
103.6

 
22.8

 
7.3

 
8.8

 
142.5

Relative percentage
73
%
 
16
%
 
5
%
 
6
%
 
100
%
____________________________________________
(1) Totals may not add due to rounding.

Production increased for the three months ended September 30, 2014, compared to the same period in 2013, driven primarily by the continued development of our operated and non-operated Eagle Ford shale programs in our South Texas & Gulf Coast region. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2014, and 2013 below for additional discussion on production.

Rocky Mountain Acquisitions. In the third quarter of 2014, we closed multiple transactions to acquire proved and unproved properties in our Gooseneck prospect area and the Powder River Basin for a total of approximately $360.7 million. These acquisitions are subject to normal post-closing adjustments, which are expected to be completed during late 2014 and early 2015.
Subsequent Events. Subsequent to September 30, 2014, as a result of our regularly scheduled semi-annual borrowing base redetermination, the lending group increased our borrowing base under our credit facility from $2.2 billion to $2.4 billion with no change in the aggregate lender commitment amount of $1.3 billion. Additionally, we acquired proved and unproved properties in our Gooseneck prospect area for total cash consideration of $84.8 million. This acquisition is subject to normal post-closing adjustments.
   

28


First Nine Months of 2014 Highlights
Production Results. The table below provides a regional breakdown of our production for the first nine months of 2014:
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Permian
 
Mid-Continent
 
Total (1)
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
5.0

 
5.1

 
1.4

 

 
11.6

Gas (Bcf)
86.7

 
4.7

 
3.2

 
14.4

 
109.1

NGLs (MMBbl)
9.1

 

 

 
0.1

 
9.2

Equivalent (MMBOE)
28.5

 
6.0

 
2.0

 
2.5

 
39.0

Avg. daily equivalents (MBOE/d)
104.5

 
21.8

 
7.2

 
9.2

 
142.7

Relative percentage
73
%
 
15
%
 
5
%
 
7
%
 
100
%
_____________________________________________
(1) Totals may not add due to rounding.

Please refer to Third Quarter 2014 Highlights and Outlook for the Remainder of 2014 above and Comparison of Financial Results and Trends Between the Nine Months Ended September 30, 2014, and 2013 below for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. For the nine months ended September 30, 2014, we incurred $2.0 billion in costs related to oil and gas property acquisitions and exploration and development activities, including both capitalized and expensed amounts. This amount includes a combined $472.6 million of proved and unproved property acquisitions in the Gooseneck prospect area and the Powder River Basin. The majority of drilling and completion costs incurred during this period were in our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program.
Rocky Mountain Divestiture. In the second quarter of 2014, we completed the divestiture of certain non-strategic assets in the Williston Basin for $50.2 million of total divestiture proceeds. The estimated net gain on this divestiture is $26.8 million. This divestiture is subject to normal post-closing adjustments, which are expected to be completed during the fourth quarter of 2014.


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,
 
2014
 
2014
 
2014
 
2013
 
(in millions, except for production data)
Production (MMBOE)
13.1

 
13.4

 
12.5

 
13.2

Oil, gas, and NGL production revenue
$
617.2

 
$
654.7

 
$
623.1

 
$
593.7

Lease operating expense
$
66.5

 
$
62.8

 
$
57.0

 
$
61.1

Transportation costs
$
81.5

 
$
83.0

 
$
79.2

 
$
75.0

Production taxes
$
30.4

 
$
31.8

 
$
27.5

 
$
26.7

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
183.3

 
$
187.8

 
$
177.2

 
$
202.6

Exploration
$
34.6

 
$
24.3

 
$
21.3

 
$
21.8

General and administrative
$
41.7

 
$
38.1

 
$
35.1

 
$
48.0

Net income
$
208.9

 
$
59.8

 
$
65.6

 
$
7.0


Selected Performance Metrics:

 
For the Three Months Ended
 
September 30,
 
June 30,
 
March 31,
 
December 31,
 
2014
 
2014
 
2014
 
2013
Average net daily production equivalent (MBOE/d)
142.5

 
147.0

 
138.6

 
143.8

Lease operating expense (per BOE)
$
5.07

 
$
4.69

 
$
4.58

 
$
4.62

Transportation costs (per BOE)
$
6.22

 
$
6.20

 
$
6.35

 
$
5.67

Production taxes as a percent of oil, gas, and NGL production revenue
4.9
%
 
4.9
%
 
4.4
%
 
4.5
%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
$
13.97

 
$
14.03

 
$
14.21

 
$
15.31

General and administrative (per BOE)
$
3.18

 
$
2.85

 
$
2.81

 
$
3.63

____________________________________________
Note: Amounts may not recalculate 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
 
2014
 
2013
 
 
2014
 
2013
 
Net production volumes (1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
4.0

 
3.8

 
0.2

 
5
 %
 
11.6

 
10.2

 
1.4

 
13
 %
Gas (Bcf)