XNYS:SM SM Energy Co Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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

FORM 10-Q

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

For the quarterly period ended June 30, 2012
Commission File Number 001-31539
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

As of July 27, 2012, the registrant had 65,151,506 shares of common stock, $0.01 par value, outstanding.





SM ENERGY COMPANY
INDEX
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share amounts)
 
June 30,
2012
 
December 31,
2011
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
184

 
$
119,194

Accounts receivable
209,633

 
210,368

Refundable income taxes
2,603

 
5,581

Prepaid expenses and other
46,812

 
68,026

Derivative asset
69,207

 
55,813

Deferred income taxes
5,798

 
4,222

Total current assets
334,237

 
463,204

 
 
 
 
Property and equipment (successful efforts method), at cost:
 
 
 
Land
1,845

 
1,548

Proved oil and gas properties
4,869,603

 
4,378,987

Less - accumulated depletion, depreciation, and amortization
(2,034,929
)
 
(1,766,445
)
Unproved oil and gas properties
122,005

 
120,966

Wells in progress
274,690

 
273,428

Materials inventory, at lower of cost or market
12,966

 
16,537

Oil and gas properties held for sale (note 3)
60,711

 
246

Other property and equipment, net of accumulated depreciation of $20,799 in 2012 and $23,985 in 2011
120,058

 
71,369

Total property and equipment, net
3,426,949

 
3,096,636

 
 
 
 
Other noncurrent assets:
 
 
 
Derivative asset
44,270

 
31,062

Restricted cash
109,486

 
124,703

Other noncurrent assets
84,629

 
83,375

Total other noncurrent assets
238,385

 
239,140

Total Assets
$
3,999,571

 
$
3,798,980

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
460,611

 
$
456,999

Derivative liability
9,150

 
42,806

Other current liabilities
6,000

 
6,000

Total current liabilities
475,761

 
505,805

 
 
 
 
Noncurrent liabilities:
 
 
 
Long-term credit facility
61,000

 

3.50% Senior Convertible Notes, net of unamortized discount of $2,431 in 2011

 
285,069

6.625% Senior Notes Due 2019
350,000

 
350,000

6.50% Senior Notes Due 2021
350,000

 
350,000

6.50% Senior Notes Due 2023
400,000



Asset retirement obligation
89,027

 
87,167

Asset retirement obligation associated with oil and gas properties held for sale (note 3)
1,732

 
1,277

Net Profits Plan liability (note 11)
89,591

 
107,731

Deferred income taxes
596,725

 
568,263

Derivative liability
956

 
12,875

Other noncurrent liabilities
57,083

 
67,853

Total noncurrent liabilities
1,996,114

 
1,830,235

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 65,155,340 shares in 2012 and 64,145,482 shares in 2011; outstanding, net of treasury shares: 65,100,773 shares in 2012 and 64,064,415 shares in 2011
652

 
641

Additional paid-in capital
234,562

 
216,966

Treasury stock, at cost: 54,567 shares in 2012 and 81,067 shares in 2011
(1,263
)
 
(1,544
)
Retained earnings
1,299,175

 
1,251,157

Accumulated other comprehensive loss
(5,430
)
 
(4,280
)
Total stockholders' equity
1,527,696

 
1,462,940

Total Liabilities and Stockholders’ Equity
$
3,999,571

 
$
3,798,980

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

3


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Operating revenues and other income:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
312,608

 
$
333,934

 
$
675,203

 
$
610,247

Realized hedge gain (loss) (note 10)
185

 
(6,330
)
 
1,837

 
(7,705
)
Gain (loss) on divestiture activity
(24,176
)
 
30,019

 
(22,714
)
 
54,934

Marketed gas system and other operating revenue
15,803

 
20,250

 
27,517

 
35,726

Total operating revenues and other income
304,420

 
377,873

 
681,843

 
693,202

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Oil, gas, and NGL production expense
91,134

 
53,342

 
178,266

 
119,154

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
161,608

 
115,382

 
331,178

 
220,738

Exploration
22,007

 
9,603

 
40,614

 
22,315

Impairment of proved properties
38,523

 

 
38,523

 

Abandonment and impairment of unproved properties
10,707

 
1,237

 
10,849


4,316

General and administrative
31,130

 
27,310

 
59,272

 
53,171

Change in Net Profits Plan liability
(22,079
)
 
(13,984
)
 
(18,140
)
 
211

Unrealized and realized derivative (gain) loss (note 10)
(98,112
)
 
(43,876
)
 
(95,896
)
 
44,553

Marketed gas system and other operating expense
17,111

 
17,152

 
28,561

 
37,009

Total operating expenses
252,029

 
166,166

 
573,227

 
501,467

 
 
 
 
 
 
 
 
Income from operations
52,391

 
211,707

 
108,616

 
191,735

 
 
 
 
 
 
 
 
Nonoperating income (expense):
 
 
 
 
 
 
 
Interest income
5

 
227

 
75

 
355

Interest expense
(12,712
)
 
(14,550
)
 
(26,990
)
 
(24,264
)
 
 
 
 
 
 
 
 
Income before income taxes
39,684

 
197,384

 
81,701

 
167,826

Income tax expense
(14,795
)

(72,851
)

(30,476
)

(61,796
)
 
 
 
 
 
 
 
 
Net income
$
24,889

 
$
124,533

 
$
51,225

 
$
106,030

 
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
64,585

 
63,638

 
64,345

 
63,543

 
 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding
67,556

 
66,909

 
67,806

 
66,695

 
 
 
 
 
 
 
 
Basic net income per common share (note 9)
$
0.39

 
$
1.96

 
$
0.80

 
$
1.67

 
 
 
 
 
 
 
 
Diluted net income per common share (note 9)
$
0.37

 
$
1.86

 
$
0.76

 
$
1.59

 
 
 
 
 
 
 
 
Dividends per common share
$

 
$

 
$
0.05

 
$
0.05


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

4


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(in thousands)
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
 
 
2012
 
2011
 
2012
 
2011
 
 
 
 
 
 
 
 
Net income
$
24,889

 
$
124,533

 
$
51,225

 
$
106,030

 
 
 
 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Reclassification to earnings
(116
)
 
3,951

 
(1,150
)
 
4,878

Total other comprehensive income (loss), net of tax
(116
)
 
3,951

 
(1,150
)
 
4,878

 
 
 
 
 
 
 
 
Total comprehensive income
$
24,773

 
$
128,484

 
$
50,075

 
$
110,908


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

5


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
 
For the Six Months Ended June 30,
 
2012
 
2011
Cash flows from operating activities:
 
 
 
Net income
$
51,225

 
$
106,030

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
(Gain) loss on divestiture activity
22,714

 
(54,934
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
331,178

 
220,738

Exploratory dry hole expense
8,198

 
49

Impairment of proved properties
38,523

 

Abandonment and impairment of unproved properties
10,849

 
4,316

Stock-based compensation expense
12,372

 
11,837

Change in Net Profits Plan liability
(18,140
)
 
211

Unrealized derivative (gain) loss
(74,014
)
 
24,160

Amortization of debt discount and deferred financing costs
4,616

 
11,294

Deferred income taxes
30,215

 
52,241

Plugging and abandonment
(1,516
)
 
(1,430
)
Other
(867
)
 
(5,888
)
Changes in current assets and liabilities:
 
 
 
Accounts receivable
735

 
(10,370
)
Refundable income taxes
2,978

 
5,348

Prepaid expenses and other
(4,759
)
 
15,692

Accounts payable and accrued expenses
(4,019
)
 
(2,530
)
Excess income tax benefit from the exercise of stock awards

 
(6,791
)
Net cash provided by operating activities
410,288

 
369,973

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from sale of oil and gas properties
15,410

 
97,952

Capital expenditures
(705,366
)
 
(662,372
)
Acquisition of oil and gas properties
(5,312
)
 

Other
111

 
(2,355
)
Net cash used in investing activities
(695,157
)
 
(566,775
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
802,500

 
102,000

Repayment of credit facility
(741,500
)
 
(150,000
)
Debt issuance costs related to credit facility

 
(8,525
)
Net proceeds from 6.625% Senior Notes Due 2019

 
341,435

Net proceeds from 6.50% Senior Notes Due 2023
392,336

 

Repayment of 3.50% Convertible Notes
(287,500
)
 

Proceeds from sale of common stock
2,888

 
4,929

Dividends paid
(3,208
)
 
(3,181
)
Excess income tax benefit from the exercise of stock awards

 
6,791

Other
343

 
(644
)
Net cash provided by financing activities
165,859

 
292,805

 
 
 
 
Net change in cash and cash equivalents
(119,010
)
 
96,003

Cash and cash equivalents at beginning of period
119,194

 
5,077

Cash and cash equivalents at end of period
$
184

 
$
101,080

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 Six Months Ended June 30,
 
2012
 
2011
 
(in thousands)
 
 
 
 
Cash paid for interest
$
(30,137
)
 
$
(6,378
)
 
 
 
 
Net cash refunded for income taxes
$
2,815

 
$
2,543


As of June 30, 2012, and 2011, $226.0 million, and $237.9 million, respectively, are included as additions to oil and gas properties and accounts payable and accrued expenses. These oil and gas property additions are reflected in cash used in investing activities in the periods that the payables are settled.

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

7


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

Note 1 - The Company and Business

SM Energy Company (“SM Energy” or the “Company”) is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (also referred to as “oil”, “gas”, and “NGLs” throughout the document) in onshore North America, with a current focus on oil and NGL-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, 2011 (the “2011 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring accruals that are 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 condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of June 30, 2012, through the filing date of this report.

Other Significant Accounting Policies

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the 2011 Form 10-K, and are supplemented throughout the notes to condensed consolidated financial statements in this report. It is suggested that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and notes included in the 2011 Form 10-K.

Recently Issued and Recently Adopted Accounting Standards

On January 1, 2012, the Company adopted new fair value measurement authoritative accounting guidance issued by the Financial Accounting Standards Board (the “FASB”), that clarifies the application of fair value measurement and disclosure requirements and changing particular principles and requirements for measuring fair value. For each class of assets and liabilities not measured at fair value in the Company's financial statements but for which fair value is disclosed, this guidance requires the Company to disclose the nature, characteristics, and risks of the asset or liability and the level of the fair value hierarchy within which the fair value measurement is categorized. Please refer to Note 11 - Fair Value Measurements in which the changes to the Company's financial statements resulting from the new authoritative guidance are presented.

On January 1, 2012, the Company adopted new authoritative accounting guidance issued by the FASB stating an entity that reports items of other comprehensive income has the option to present the components of comprehensive income in either one continuous financial statement, or two consecutive financial statements, including reclassification adjustments. Subsequent to the issuance of this authoritative guidance, the FASB issued additional authoritative accounting guidance that effectively deferred the requirement to present the reclassification adjustments on the face of the financial statements, as well as the requirement to present the individual components of other comprehensive income for interim periods. The adoption of this statement did not have a material impact on the Company. The Company has elected to present a separate statement of comprehensive income, including the individual components, titled Condensed Consolidated Statements of Comprehensive Income, as part of Item 1 to this report.

There are no new significant accounting standards applicable to SM Energy that have been issued but not yet adopted as of June 30, 2012.

8


Note 3 - 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 that 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 of the assets held for sale over their fair value less costs to sell. Subsequent changes to the estimated fair value less the costs to sell will impact the measurement of assets held for sale for which fair value less costs to sell is determined to be less than the carrying value of the assets.

As of June 30, 2012, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $60.7 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense. A corresponding asset retirement obligation liability of $1.7 million is separately presented. These assets held for sale include certain assets located in the Company’s Rocky Mountain region, as well as the Company’s Marcellus shale assets in Pennsylvania. The Company determined that these planned asset sales do not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

During the second quarter of 2012, the Company reclassified a portion of the assets previously held for sale as of March 31, 2012, to assets held and used, as these assets were no longer being actively marketed. The assets were measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense (“DD&A”) that would have been recognized had the assets been continuously held and used, or the fair value of the assets at the date they no longer met the criteria as held for sale. As a result of this measurement, the Company recognized $1.7 million of DD&A expense and a $28.3 million loss on unsuccessful sale of properties, which is included in gain (loss) on divestiture activity in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).

Note 4 - Income Taxes

Income tax expense for the six months ended June 30, 2012, and 2011 differs from the amounts that would be provided by applying the statutory U.S. federal income tax rate to income before income taxes as a result of the estimated effect of percentage depletion, the effect of state income taxes, uncertain tax positions, valuation allowances, and other permanent differences. The quarterly rate can also be impacted by the proportion of income earned in the reported periods.

The provision for income taxes consists of the following:

 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Current portion of income tax benefit (expense):
 
 
 
 
 
 
 
Federal
$

 
$
(2,212
)
 
$

 
$
(9,156
)
State
132

 
(224
)
 
(261
)
 
(399
)
Deferred portion of income tax expense
(14,927
)
 
(70,415
)
 
(30,215
)
 
(52,241
)
Total income tax expense
$
(14,795
)
 
$
(72,851
)
 
$
(30,476
)
 
$
(61,796
)
Effective tax rate
37.3
%
 
36.9
%
 
37.3
%
 
36.8
%

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

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 U.S. federal or state income tax examinations by these tax authorities for years before 2007. In the first quarter of 2011, the Company received a $5.5 million refund from its 2006 tax year as a result of a net operating loss carryback claim from the 2008 tax year. The Internal Revenue Service initiated an audit in the first quarter of 2012 for the 2007 and 2010 tax years.

In the third quarter of 2011, the Company completed a multi-year research and development credit study and recorded a cumulative discrete tax benefit. As of the filing date of this report, federal tax law allowing for the calculation of these credits from the Company’s increasing research activities has not been extended past December 31, 2011. For these reasons, comparable periods of 2012 and 2011 presented in this report reflect no benefit for the credit.

9



Note 5 - Long-Term Debt

The Company satisfied its obligations to exchange its outstanding $350.0 million 6.50% Senior Notes due 2021 (the “2021 Notes”) and its outstanding $350.0 million 6.625% Senior Notes due 2019 (the “2019 Notes”) for notes registered under the Securities Act of 1933, as amended (the “Securities Act”), on March 7, 2012, and on January 12, 2012, respectively. There are no subsidiary guarantors of these notes.
3.50% Senior Convertible Notes Due 2027
On April 2, 2012, the Company called for redemption all of its outstanding 3.50% Senior Convertible Notes due 2027 (the “3.50% Senior Convertible Notes”). The call for redemption resulted in note holders of $281.3 million aggregate principal amount electing to convert their notes. The Company settled the principal amount of all converted 3.50% Senior Convertible Notes in cash and the excess conversion value by issuing 864,106 shares of its common stock. The Company redeemed the remaining $6.2 million of aggregate principal amount of notes that were not converted on the redemption date at par plus accrued interest in cash. The Company used funds borrowed under its credit facility to pay the cash portion of the 3.50% Senior Convertible Notes settlement.
6.50% Senior Notes Due 2023
On June 29, 2012, the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023 (the “2023 Notes”). The 2023 Notes were issued at par and mature on January 1, 2023. The Company received net proceeds of $392.3 million after deducting fees of $7.7 million, which will be amortized as deferred financing costs over the life of the 2023 Notes. The net proceeds were used to reduce the Company’s outstanding credit facility balance.
Prior to July 1, 2015, the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principal amount of the 2023 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus accrued and unpaid interest. The Company may also redeem the 2023 Notes, in whole or in part, at any time prior to July 1, 2017, at a redemption price equal to 100 percent of the principal amount of the 2023 Notes to be redeemed, plus a specified make-whole premium and accrued and unpaid interest to the applicable redemption date. 

On or after July 1, 2017, the Company may also redeem all or, from time to time, a portion of the 2023 Notes at the redemption prices set forth below, during the twelve-month period beginning on July 1 of each applicable year, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest:

2017
103.250
%
2018
102.167
%
2019
101.083
%
2020 and thereafter
100.000
%

The 2023 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 2023 Notes. The Company is subject to certain covenants under the indenture governing the 2023 Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends. However, the first $6.5 million of dividends paid each year are not restricted by this covenant. The Company was in compliance with all financial covenants under its 2023 Notes as of June 30, 2012.

Additionally, on June 29, 2012, the Company entered into a registration rights agreement that provides holders of the 2023 Notes certain registration rights under the Securities Act. Pursuant to the registration rights agreement, the Company will file an exchange offer registration statement with the Securities and Exchange Commission (“SEC”) with respect to its offer to exchange the 2023 Notes for substantially identical notes that are registered under the Securities Act. Under certain circumstances, the Company has agreed to file a shelf registration statement relating to the resale of the 2023 Notes in lieu of a registered exchange offer. If the exchange offer is not completed on or before June 29, 2013, or the shelf registration statement, if required, is not declared effective within the time periods specified in the registration rights agreement, the Company has agreed to pay additional interest with respect to the 2023 Notes in an amount not to exceed one percent of the principal amount of the 2023 Notes until the exchange offer is completed or the shelf registration statement is declared effective.

10


Note 6 - Commitments and Contingencies
Commitments
    
There have been no material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in the 2011 Form 10-K.
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.
The Company was a defendant in litigation where the plaintiffs claim an aggregate overriding royalty interest of 7.46875 percent in production from approximately 22,000 of the Company’s net acres in the Eagle Ford shale play in South Texas. The plaintiffs sought to quiet title to their claimed overriding royalty interest and to recover unpaid overriding royalty interest proceeds allegedly due. The Company believes that the claimed overriding royalty interest has been terminated under the governing agreements and the applicable law, and has contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court issued an order granting plaintiffs’ motion for summary judgment and denying the Company’s motion for summary judgment. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded damages of approximately $5.1 million, which included prejudgment interest. The District Court also awarded attorneys fees and costs to the plaintiffs. The Company appealed the District Court’s judgment and obtained a stay pending appeal that prevented the plaintiffs from executing on the judgment.

On May 23, 2012, the Fourth Court of Appeals for the State of Texas delivered its opinion in this case, which reversed the summary judgment granted to the plaintiffs by the District Court and rendered judgment that the plaintiffs take nothing. Accordingly, based on the judgment of the Fourth Court of Appeals, the plaintiffs are not entitled to their claimed aggregate 7.46875 percent overriding royalty interest, nor are they entitled to the claimed damages related to the overriding royalty interest, attorneys fees or costs. The plaintiffs have the right to petition the Supreme Court of Texas for a review of the judgment of the Fourth Court of Appeals. In the event the plaintiffs’ file such petition and review is granted by the Supreme Court of Texas, the Company will continue to contest this litigation.

Note 7 - Compensation Plans

Cash Bonus Plan

During the first six months of 2012 and 2011, the Company paid $24.0 million and $21.6 million for cash bonuses earned in the 2011 and 2010 performance years, respectively. The general and administrative expense and exploration expense line items in the accompanying statements of operations include $4.6 million and $3.7 million of accrued cash bonus plan expense attributable to the three-month periods ended June 30, 2012, and 2011, respectively, and $9.3 million and $7.5 million for the six-month periods ended June 30, 2012, and 2011, respectively, related to the respective performance year.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants Restricted Stock Units (“RSUs”) as part of its long-term equity compensation program. Each RSU represents a right to one share of the Company’s common stock to be delivered upon settlement of the award at the end of the specified vesting period. RSUs are recognized as general and administrative expense and exploration expense over the vesting period of the award.

Total expense recorded for RSUs for the three-month periods ended June 30, 2012, and 2011, was $1.4 million and $985,000, respectively, and $2.6 million and $2.0 million for the six-month periods ended June 30, 2012, and 2011, respectively. As of June 30, 2012, there was $4.9 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2014. There have been no material changes to outstanding and non-vested RSUs during the six months ended June 30, 2012.

11


Subsequent to June 30, 2012, the Company granted 365,787 RSUs as part of its regular annual long-term equity compensation program. These RSUs will vest 1/3rd on each of the next three anniversary dates of the grant. Also subsequent to June 30, 2012, the Company settled 160,484 RSUs that related to awards granted in previous years by issuing a net 111,123 shares of the Company’s common stock in accordance with the terms of the RSU awards. The remaining 49,361 shares were withheld to satisfy income and payroll tax withholding obligations that arose upon delivery of the shares underlying those RSUs.
Performance Stock Units Under the Equity Incentive Compensation Plan

The Company also grants Performance Share Units as part of its long-term equity compensation program. Performance Stock Units are structurally the same as the previously granted Performance Share Awards (collectively known as “Performance Share Units” or “PSUs”). The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times 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 measure of the Company’s TSR compared with the annualized TSRs of a group of peer companies for the measurement period. PSUs are recognized as general and administrative expense and exploration expense over the vesting period of the award.

Total expense recorded for PSUs for the three-month periods ended June 30, 2012, and 2011, was $5.2 million and $4.1 million, respectively, and $8.1 million and $8.4 million for the six-month periods ended June 30, 2012, and 2011, respectively. As of June 30, 2012, there was $16.5 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2014. There have been no material changes to outstanding and non-vested PSUs during the six months ended June 30, 2012.
Subsequent to June 30, 2012, the Company granted 314,853 PSUs as part of its regular annual long-term equity compensation program. These PSUs will vest 1/3rd on each of the next three anniversary dates of the grant. Also subsequent to June 30, 2012, the Company settled 609,714 PSUs that were granted in 2009 and earned a two times multiplier by issuing a net 812,562 shares of the Company’s common stock in accordance with the terms of the PSU awards. There were 406,866 shares withheld to satisfy income and payroll tax withholding obligations that arose 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 six months ended June 30, 2012, is presented in the following table:

 
Shares
 
Weighted-
Average
Exercise Price
 
Aggregate
 Intrinsic Value (in thousands)
 
 
 
 
 
 
Outstanding, at beginning of year
508,214

 
$
13.86

 
$
30,109

Exercised
(108,299
)
 
$
12.36

 
$
6,667

Forfeited

 
$

 
 
Outstanding, at end of quarter
399,915

 
$
14.26

 
$
13,937

Vested and exercisable, at end of quarter
399,915

 
$
14.26

 
$
13,937


As of June 30, 2012, there was no unrecognized compensation expense related to stock option awards.
Director Shares
During the six months ended June 30, 2012, and 2011, the Company issued 26,500 and 21,568 shares, respectively, of the Company’s common stock from treasury to the Company’s non-employee directors, under the Company’s Equity Incentive Compensation Plan. The Company recorded $1.1 million and $1.0 million of compensation expense related to these awards for both the three and six months ended June 30, 2012, and 2011, respectively. The Company appointed a new non-employee director on July 16, 2012, and granted him 3,986 shares of the Company’s common stock from treasury, as a pro-rata share of the Company’s annual director compensation. All shares of common stock issued to the Company’s non-employee directors are earned over a one-year service period.

12


Employee Stock Purchase Plan
Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. The Company had 1.3 million shares available for issuance under the ESPP as of June 30, 2012. There were 37,124 and 22,373 shares issued under the ESPP during the second quarters of 2012 and 2011, 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 Net Profits Interest Bonus Plan (“Net Profits Plan”) that have been recorded as either general and administrative expense or exploration expense are presented in the table below:

 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
General and administrative expense
$
3,682

 
$
5,261

 
$
8,094

 
$
10,591

Exploration expense
493

 
585

 
1,018

 
1,062

Total
$
4,175

 
$
5,846

 
$
9,112

 
$
11,653


Additionally, the Company accrued or made cash payments under the Net Profits Plan of $1.4 million and $2.0 million for the three-month periods ended June 30, 2012, and 2011, respectively, and $1.7 million and $6.3 million for the six-month periods ended June 30, 2012, and 2011, respectively, as a result of divestiture proceeds. These cash payments are accounted for as a reduction in the gain (loss) on divestiture activity in the accompanying statements of operations.

The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative expense. The amount that would be allocated to exploration expense is minimal in comparison. Over time, less of the amount distributed relates to prospective exploration efforts as more of the amount distributed is paid to employees that have terminated employment and do not provide ongoing exploration support to the Company.

Note 8 - Pension Benefits

Pension Plans

The Company has a non-contributory pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan”).


13


Components of Net Periodic Benefit Cost for Both Pension Plans

The following table presents the components of the net periodic benefit cost for both the Qualified Pension Plan and the Nonqualified Pension Plan:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Service cost
$
1,515

 
$
1,052

 
$
2,465

 
$
1,900

Interest cost
393

 
312

 
689

 
592

Expected return on plan assets that reduces periodic pension costs
(352
)
 
(281
)
 
(572
)
 
(440
)
Amortization of prior service costs
9

 

 
9

 

Amortization of net actuarial loss
293

 
111

 
394

 
202

Net periodic benefit cost
$
1,858

 
$
1,194

 
$
2,985

 
$
2,254


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

Contributions

The Company is required to contribute a total of $5.4 million to its Qualified Pension Plan for the 2012 plan year. The Company has contributed $4.6 million of such amount as of June 30, 2012.

Note 9 - Earnings per Share

Basic net income per common share is calculated by dividing net income available to common shareholders 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 options, unvested RSUs, contingent PSUs, and shares into which the 3.50% Senior Convertible Notes were convertible.

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 zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 - Compensation Plans under the heading Performance Stock Units Under the Equity Incentive Compensation Plan.

The Company called for redemption the 3.50% Senior Convertible Notes on April 2, 2012, and the majority of the then outstanding holders of the 3.50% Senior Convertible Notes elected to convert their notes. The Company issued 864,106 common shares upon conversion and these shares were included in the calculation of basic weighted-average common shares outstanding for the three and six months ended June 30, 2012. Please refer to Note 5 - Long-Term Debt for additional discussion. Prior to calling the notes for redemption, the Company’s 3.50% Senior Convertible Notes had a net-share settlement right giving the Company the option to irrevocably elect, by notice to the trustee under the indenture for the notes, to settle the Company’s obligation, in the event that holders of the notes elect to convert all or a portion of their notes, by delivering cash in an amount equal to each $1,000 principal amount of notes surrendered for conversion and, if applicable, at the Company’s option, shares of common stock or cash, or any combination of common stock and cash, for the amount of conversion value in excess of the principal amount. Prior to the settlement of the Company’s 3.50% Senior Convertible Notes, potentially dilutive shares associated with this conversion feature were accounted for using the treasury stock method when shares of the Company’s common stock traded at an average closing price that exceeded the $54.42 conversion price. Shares of the Company’s common stock traded at an average closing price exceeding the conversion price for the three and six month periods ended June 30, 2012, and 2011, making them dilutive for those periods. The diluted net income per share calculations for the three-month and six-month periods ended June 30, 2012, were adjusted on a weighted basis for the conversion of the 3.50% Senior Convertible Notes.

14



The treasury stock method is used to measure the dilutive impact of unvested RSUs, contingent PSUs, in-the-money stock options, and 3.50% Senior Convertible Notes.

The following table sets forth the calculations of basic and diluted earnings per share:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands, except per share amounts)
Net income
$
24,889

 
$
124,533

 
$
51,225

 
$
106,030

Basic weighted-average common shares outstanding
64,585

 
63,638

 
64,345

 
63,543

Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs
2,149

 
2,182

 
2,182

 
2,161

Add: dilutive effect of 3.50% Senior Convertible Notes
822

 
1,089

 
1,279

 
991

Diluted weighted-average common shares outstanding
67,556

 
66,909

 
67,806

 
66,695

Basic net income per common share
$
0.39

 
$
1.96

 
$
0.80

 
$
1.67

Diluted net income per common share
$
0.37

 
$
1.86

 
$
0.76

 
$
1.59


Note 10 - Derivative Financial Instruments

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. The Company’s derivative contracts include swap and collar arrangements for oil, gas, and NGLs. As of June 30, 2012, the Company had commodity derivative contracts through the first quarter of 2015 for a total of 9.1 million Bbls of anticipated oil production, 80.0 million MMBtu of anticipated gas production, and 1.8 million Bbls of anticipated NGL production. Subsequent to June 30, 2012, the Company executed swaps on 2.5 million Bbls of oil from September 2012 through June 2015.

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 $103.4 million and $31.2 million at June 30, 2012, and December 31, 2011, respectively.

Discontinuance of Cash Flow Hedge Accounting

Prior to January 1, 2011, the Company designated its commodity derivative contracts as cash flow hedges, for which unrealized changes in fair value were recorded to accumulated other comprehensive income (loss) (“AOCIL”), to the extent the hedges were effective. As of January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010. As a result, subsequent to December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCIL. The Company had no derivatives designated as cash flow hedges for the three-month and six-month periods ended June 30, 2012, and 2011, and as such, no ineffectiveness was recognized in earnings for the respective periods.

As a result of discontinuing hedge accounting on January 1, 2011, such fair values at December 31, 2010, were frozen in AOCIL as of the de-designation date and are reclassified into earnings as the original derivative transactions settle. As of June 30, 2012, AOCIL included immaterial net unrealized gains, net of income tax, on commodity derivative contracts that had been previously designated as cash flow hedges. The Company expects to reclassify into earnings from AOCIL after-tax net gains of $451,000 related to de-designated commodity derivative contracts during the next twelve months. Please refer to Note 11 - Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques.

    

15


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

 
As of June 30, 2012
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity Contracts
Current Assets
 
$
69,207

 
Current Liabilities
 
$
9,150

Commodity Contracts
Noncurrent Assets
 
44,270

 
Noncurrent Liabilities
 
956

Derivatives not designated as hedging instruments
 
 
$
113,477

 
 
 
$
10,106


 
As of December 31, 2011
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity Contracts
Current Assets
 
$
55,813

 
Current Liabilities
 
$
42,806

Commodity Contracts
Noncurrent Assets
 
31,062

 
Noncurrent Liabilities
 
12,875

Derivatives not designated as hedging instruments
 
 
$
86,875

 
 
 
$
55,681


    
The following table summarizes the components of unrealized and realized derivative (gain) loss presented in the accompanying statements of operations:

 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Cash settlement (gain) loss:
 
 
 
 
 
 
 
Oil contracts
$
2,371

 
$
10,633

 
$
10,670

 
$
17,363

Gas contracts
(16,252
)
 
(590
)
 
(31,464
)
 
(2,317
)
NGL contracts
(2,565
)
 
3,933

 
(1,088
)
 
5,347

Total cash settlement (gain) loss
$
(16,446
)
 
$
13,976

 
$
(21,882
)
 
$
20,393

 
 
 
 
 
 
 
 
Unrealized (gain) loss on change in fair value:
 
 
 
 
 
 
 
Oil contracts
$
(92,774
)
 
$
(51,216
)
 
$
(63,283
)
 
$
16,151

Gas contracts
29,867

 
(6,681
)
 
12,233

 
(2,421
)
NGL contracts
(18,759
)
 
45

 
(22,964
)
 
10,430

Total net unrealized (gain) loss on change in fair value
$
(81,666
)

$
(57,852
)

$
(74,014
)

$
24,160

Total unrealized and realized derivative (gain) loss
$
(98,112
)
 
$
(43,876
)
 
$
(95,896
)
 
$
44,553

    
The following table summarizes the effect of derivative instruments on AOCIL and the accompanying statements of operations (net of income tax):

 
 
 
Location in
Consolidated
Statements of
Operations
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
Derivatives
 
 
2012
 
2011
 
2012
 
2011
 
 
 
 
 
(in thousands)
Amount reclassified from AOCIL
Commodity Contracts
 
Realized hedge gain (loss)
 
$
(116
)
 
$
3,951

 
$
(1,150
)
 
$
4,878



16


The Company realized a net hedge gain of $185,000 and a net hedge loss of $6.3 million for the three months ended June 30, 2012, and 2011, respectively, and a net hedge gain of $1.8 million and a net hedge loss of $7.7 million from its commodity derivative contracts for the six months ended June 30, 2012, and 2011, respectively, shown net of income tax in the table above. Realized hedge gains and losses are comprised of settlements on commodity derivative contracts that were previously designated as cash flow hedges and are reported in the total operating revenues and other income section of the accompanying statements of operations. 

Credit Related Contingent Features

As of June 30, 2012, and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility syndicate. The Company’s obligations under its credit facility and derivative contracts are secured by liens on substantially all of the Company’s proved oil and gas properties.

Convertible Note Derivative Instruments

The contingent interest provision of the 3.50% Senior Convertible Notes was an embedded derivative instrument. The fair value of this derivative was determined to be immaterial as of December 31, 2011. The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-Term Debt for additional discussion.

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 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 where they are classified within the hierarchy as of June 30, 2012:

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

 
$
113,477

 
$

  Proved oil and gas properties (2)
$

 
$

 
$
79,543

  Unproved oil and gas properties (2)
$

 
$

 
$
15,650

Liabilities:
 
 
 
 
 
Derivatives (1)
$

 
$
10,106

 
$

Net Profits Plan (1)
$

 
$

 
$
89,591

(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.

    

17


The following is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the hierarchy as of December 31, 2011:

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

 
$
86,875

 
$

Proved oil and gas properties (2)
$

 
$

 
$
139,992

Unproved oil and gas properties (2)
$

 
$

 
$
15,809

Liabilities:
 
 
 
 
 
Derivatives (1)
$

 
$
55,681

 
$

Net Profits Plan (1)
$

 
$

 
$
107,731


(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.

Both financial and non-financial assets and liabilities are categorized within the 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 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. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may ask 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 bank syndicate.

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 accounting authoritative 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.


18


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. For those pools currently in payout, a discount rate of 12 percent is used to calculate this liability. A discount rate of 15 percent is used to calculate the liability for pools that have not reached payout. These rates are intended to represent the 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 the overall market conditions, which are continually evaluated to consider 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 crude oil, gas, and NGL commodity markets.

If the commodity prices used in the calculation changed by five percent, the liability recorded at June 30, 2012, would differ by approximately $8 million. A one percent increase or decrease in the discount rate would result in a change of approximately $4 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 the 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 Net Profits Plan liability measured at fair value using Level 3 inputs:
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Beginning balance
$
111,670

 
$
147,403

 
$
107,731

 
$
135,850

Net increase (decrease) in liability (1)
(16,473
)
 
(6,092
)
 
(7,311
)
 
18,193

Net settlements (1)(2)(3)
(5,606
)
 
(7,892
)
 
(10,829
)
 
(20,624
)
Transfers in (out) of Level 3

 

 

 

Ending balance
$
89,591

 
$
133,419

 
$
89,591

 
$
133,419

_____________________ ___ __
(1)
Net changes in the 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 relating to divestiture proceeds of $1.4 million and $2.0 million for the three months ended June 30, 2012, and 2011, respectively, and $1.7 million and $6.3 million for the six months ended June 30, 2012, and 2011, respectively.
(3)
During the first quarter of 2011, the Company elected to settle several Net Profits Plan pools associated with the acquisition of Nance Petroleum Corporation in 1999, through an aggregate $2.6 million cash payment. As a result, the Company reduced its Net Profits Plan liability by that amount. There was no impact on the accompanying statements of operations for the three-month or six-month periods ended June 30, 2011, related to these settlements. 


19


Long-term Debt

The 2019 Notes and 2021 Notes are valued using Level 1 inputs based on quoted secondary market trading prices. The estimated fair value of the 2019 Notes and the 2021 Notes as of June 30, 2012, was approximately $360 million and $356 million, respectively, and as of December 31, 2011, was approximately $359 million and $360 million, respectively.

The 2023 Notes are valued using Level 2 inputs based on bond valuation prices obtained from a third party source. The price is generated by qualitative algorithms that use direct market observations, such as recent sales, bid and ask prices from brokers, dealers, buy side firms, and other market inputs. The estimated fair value of these notes was approximately $403 million as of June 30, 2012. In accordance with the registration rights agreement discussed in Note 5 - Long-Term Debt, the Company is required to register the 2023 Notes within one year of issuance. Upon registration and subsequent trading, the notes will be valued using Level 1 inputs.

The estimated fair value of the 3.50% Senior Convertible Notes was approximately $394 million as of December 31, 2011. The estimated fair value of the embedded contingent interest derivative was immaterial as of December 31, 2011. The 3.50% Senior Convertible Notes were valued using Level 1 inputs, based on quoted secondary market trading prices. The 3.50% Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-Term Debt for additional discussion.

Proved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication 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 for the quarter ended June 30, 2012, and the year ended December 31, 2011. Management 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. The prices for NGLs are forecasted using the Oil Price Information System Mont Belvieu (“OPIS”) pricing, adjusted for basis differentials, for the first five years. At the end of the first five years, a flat terminal price is used for each commodity stream. Future operating costs are also adjusted as deemed appropriate for these estimates.

As a result of asset write-downs, discussed in Note 13 - Impairment of Proved and Unproved Properties and Note 3 - Assets Held for Sale, the proved oil and gas properties measured at fair value within the accompanying balance sheets were $79.5 million at June 30, 2012, and $140.0 million at December 31, 2011.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. 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 to measure the fair value of unproved properties.
As a result of asset write-downs, discussed in Note 13 - Impairment of Proved and Unproved Properties, unproved oil and gas properties measured at fair value within the accompanying balance sheets were $15.7 million at June 30, 2012, and $15.8 million at December 31, 2011.

Materials Inventory

Materials inventory is valued at the lower of cost or market. The Company uses Level 2 inputs to measure the fair value of materials inventory, which is primarily comprised of tubular goods. The Company uses third party market quotes and compares the quotes to the book value of the materials inventory. If the book value exceeds the quoted market price, the Company reduces the book value to the market price. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing materials inventory. There were no materials inventories measured at fair value in the accompanying balance sheets at June 30, 2012, or December 31, 2011.


20


Asset Retirement Obligations

The income valuation technique is utilized by the Company 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. There were no asset retirement obligations measured at fair value in the accompanying balance sheets at June 30, 2012, or December 31, 2011.

Note 12 - Acquisition and Development Agreement

In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd. (the “Acquisition and Development Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to the Company’s remaining interest in these assets following the closing of the transaction, until Mitsui has expended an aggregate $680.0 million on behalf of the Company. Based on the Company’s forecast of the operator’s drilling plans, it will take three to four years to fully utilize the carry. The Acquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining ten percent of drilling and completion costs for the affected acreage.

As of June 30, 2012, the Company held $109.5 million of contractually restricted cash payments from Mitsui, which will be used solely for development operations and accordingly are classified as non-current assets in the accompanying balance sheets. The Company has recorded a corresponding liability equal to the restricted cash balance. The portion of the liability related to development operations expected to occur within the next year is recorded in accounts payable and accrued expenses within the accompanying balance sheets. The portion of the liability related to development operations expected to occur more than one year in the future is recorded in other noncurrent liabilities within the accompanying balance sheets as of June 30, 2012. There was no net impact on the accompanying condensed consolidated statement of cash flows as restricted cash was offset against the corresponding liability in investing activities. Of the $680.0 million carry amount, $128.3 million had been spent as of June 30, 2012.

Note 13 - Impairment of Proved and Unproved Properties
    
Proved Properties    

During the first half of 2012, the Company recorded proved property impairments of $38.5 million related to its Haynesville shale assets, due to a decline in natural gas prices. There were no proved property impairments recorded during the first half of 2011.

Unproved Properties

During the first half of 2012, the Company recorded abandonment and impairment of unproved properties expense of $10.8 million, the majority of which related to acreage we no longer intend to develop within the Rocky Mountain region. During the first half of 2011, the Company recorded abandonment and impairment of unproved properties expense of $4.3 million associated with lease expirations in the Mid-Continent region.


21


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, as well as meaningful positions in the Granite Wash, the Haynesville, and Woodford shale resource plays, and the Permian Basin. We have built a portfolio of onshore properties in the contiguous United States primarily through early entrance 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 reserve growth.
Our principal business strategy is focused on the early capture of resource plays in order to create and then enhance value for our shareholders, 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, mitigate our risks by selectively divesting portions of certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to maximize our returns and preserve our financial strength.

In the second quarter of 2012, we had the following financial and operational results:

Average daily production for the three months ended June 30, 2012, was 25.9 MBbls of oil, 309.2 MMcf of gas, and 15.2 MBbls of NGLs, for an average equivalent production rate of 555.7 MMCFE per day, compared with 436.9 MMCFE per day for the same period in 2011. Please see additional discussion below under the caption Production Results.

Net income for the three months ended June 30, 2012, was $24.9 million, or $0.37 per diluted share, compared to net income for the three months ended June 30, 2011, of $124.5 million or $1.86 per diluted share. Please refer to Note 9 - Earnings per Share in Part I, Item 1 of this report for additional discussion of the impact the conversion of our 3.50% Senior Convertible Notes had on our earnings per share calculation and to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2012, and 2011 for additional discussion regarding the components of net income.
 
Costs incurred for oil and gas producing activities for the three months ended June 30, 2012, were $407.7 million, compared with $352.2 million for the same period in 2011. Please see additional discussion below under the caption Costs Incurred in Oil and Gas Producing Activities.

EBITDAX, a non-GAAP financial measure, for the three months ended June 30, 2012, was $213.7 million, compared with $242.4 million for the same period in 2011. Please refer to the caption Non-GAAP Financial Measures below for additional discussion, including a reconciliation from GAAP net income to EBITDAX.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. We sell the majority of our gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the high 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 either the average of the NYMEX West Texas Intermediate (“WTI”) daily settlement price or the average of alternative posted prices for the periods in which the product is produced, adjusted for quality, transportation, and location differentials.


22


The following table summarizes commodity price data for the first and second quarters of 2012, as well as the second quarter of 2011:

 
For the Three Months Ended
 
June 30, 2012
 
March 31, 2012
 
June 30, 2011
Crude Oil (per Bbl):
 
 
 
 
 
Average NYMEX price
$
93.30

 
$
102.99

 
$
102.28

Realized price
$
82.52

 
$
90.67

 
$
97.51

 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Average NYMEX price (per MMBtu)
$
2.28

 
$
2.44

 
$
4.36

Realized price (per Mcf)
$
2.34

 
$
2.90

 
$
4.63

 
 
 
 
 
 
Natural Gas Liquids (per Bbl):
 
 
 
 
 
Average OPIS price
$
43.71

 
$
54.15

 
$
61.62

Realized price
$
37.79

 
$
44.67

 
$
54.02

Note: Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 6% Isobutane, 11% Normal Butane, 14% Natural Gasoline and 32% Propane for all periods presented.
    
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 likely 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 could affect the price of oil. The supply of NGLs in the U.S. is expected to grow in the near term as a result of the number of industry participants targeting projects that produce these products. The pace of NGL production is growing faster than the capacity to process or consume NGLs, which will likely negatively impact pricing in the near term. The prices of several of the specific NGL products correlate to the price of oil and accordingly are likely to directionally follow that market. Gas prices have been under downward pressure due to current market oversupply resulting from high levels of drilling activity, high levels of gas in storage, an unusually mild winter in the United States, and tepid economic growth. The 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed above) as of June 30, 2012, were $87.14 per Bbl of oil, $3.29 per MMBtu of gas, and $37.26 per Bbl of NGLs, respectively. Comparable prices as of July 27, 2012, were $91.63 per Bbl of oil, $3.41 per MMBtu of gas, and $40.02 per Bbl of NGLs, respectively.
While changes in 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. Our realized prices shown in the table above do not include the impact of cash settlements from derivative contracts, which is consistent with all prior periods reported.

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 level 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 of Part I, Item 1 of this report for additional information regarding our oil, gas, and NGL derivatives, and the caption, Summary of Oil, Gas, and NGL Derivative Contracts in Place, below.


23


The following table presents a reconciliation from our realized price to our adjusted price for the commodities indicated, including the effects of derivative cash settlements for the first and second quarters of 2012, as well as the second quarter of 2011:

 
For the Three Months Ended
 
June 30, 2012
 
March 31, 2012
 
June 30, 2011
Crude Oil (per Bbl):
 
 
 
 
 
Realized price
$
82.52

 
$
90.67

 
$
97.51

Less the effects of derivative cash settlements
(2.00
)
 
(4.32
)
 
(13.11
)
Adjusted price, including the effects of derivative cash settlements
$
80.52

 
$
86.35

 
$
84.40

 
 
 
 
 
 
Natural Gas (per Mcf):
 
 
 
 
 
Realized price
$
2.34

 
$
2.90

 
$
4.63

Add the effects of derivative cash settlements
0.68

 
0.70

 
0.38

Adjusted price, including the effects of derivative cash settlements
$
3.02

 
$
3.60

 
$
5.01

 
 
 
 
 
 
Natural Gas Liquids (per Bbl):
 
 
 
 
 
Realized price
$
37.79

 
$
44.67

 
$
54.02

Add (less) the effects of derivative cash settlements
1.65

 
(1.69
)
 
(6.53
)
Adjusted price, including the effects of derivative cash settlements
$
39.44

 
$
42.98

 
$
47.49


The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) included provisions requiring over-the-counter derivative transactions to be executed through an exchange or centrally cleared. On July 10, 2012, the Commodities Futures Trading Commission (“CFTC”) and the SEC adopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms and determine what types of transactions will be subject to heightened scrutiny 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 on our business of these new rules and any additional regulations is currently uncertain. Of particular concern to us is whether the provisions of the final rules and regulations will allow us to qualify as a non-financial, commercial end user exempt 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

Second Quarter 2012 Highlights

Operational Activities. We operated an average of 16 drilling rigs during the second quarter of 2012. The primary focus of our operated drilling activity this year has been on oil and NGL-rich gas projects. We also participated in non-operated drilling activity primarily in oil and NGL-rich plays.
In our Eagle Ford shale program in South Texas, we operated six drilling rigs throughout the second quarter of 2012. We focused our drilling in areas with higher BTU gas content and condensate yields. We believe we have sufficiently secured the requisite services, such as gas pipeline takeaway capacity and drilling and completion services, to support our current development plans. We will continue to explore additional arrangements to facilitate the future growth of our operated program. During the quarter, we began to experience challenges with our third-party operated mid-stream gathering system due to delays in the installation of tank batteries and a lack of sufficient compression, which constrained our production volumes in this program. In our non-operated Eagle Ford program, the operator had nine drilling rigs running during the second quarter of 2012. We expect the majority of our non-operated Eagle Ford drilling program to be funded over the next three to four years by our previously announced Acquisition and Development Agreement with Mitsui.
During the second quarter, we operated three drilling rigs in our Bakken/Three Forks program in the North Dakota portion of the Williston Basin focusing on our Gooseneck, Raven, and Bear Den prospects. In the southern portion of our Rocky Mountain region, we operated one rig testing various formations in the Powder River Basin of Wyoming as part of a continued delineation effort.

24


Effective January 1, 2012, we combined our ArkLaTex region into our Mid-Continent region, based in Tulsa, Oklahoma, for operational and reporting purposes. During the second quarter of 2012, we operated three drilling rigs in our Granite Wash program in western Oklahoma and the Texas Panhandle, focusing primarily on the Marmaton washes due to their higher oil and NGL contributions. Essentially all of our acreage position in this play is held by production. We completed our operated Haynesville shale program earlier in the year after reaching held by production status on substantially all of our acreage.
We operated three drilling rigs in our Permian region in the second quarter of 2012. One rig was focused on testing the Mississippian limestone formation in the northeast Midland Basin, where we have approximately 65,000 net acres. The second rig was focused on the Bone Spring formation in New Mexico. The third rig operated in the northern Permian Basin and focused on testing various shale targets.
Production Results. The table below provides a regional breakdown of our second quarter 2012 production:
 
South Texas & Gulf Coast
 
Mid-Continent
 
Permian
 
Rocky Mountain
 
Total (1)
Second quarter 2012 production:
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
0.7

 
0.1

 
0.3

 
1.3

 
2.4

Gas (Bcf)
12.8

 
13.4

 
0.8

 
1.1

 
28.1

NGLs (MMBbl)
1.3

 
0.1

 

 

 
1.4

Equivalent (BCFE)
24.4

 
14.6

 
2.7

 
8.9

 
50.6

Avg. daily equivalents (MMCFE/d)
268.4

 
160.7

 
29.1

 
97.5

 
555.7

Relative percentage
48
%
 
29
%
 
5
%
 
18
%
 
100
%
_____________________________________________
(1) Totals may not add due to rounding.

For the second quarter of 2012, our production was led by our South Texas & Gulf Coast region driven by our focus on the development of our Eagle Ford shale operated and non-operated programs. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2012, and 2011 for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
 
For the Three Months Ended June 30, 2012
 
(in millions)
Development costs
$
311.9

Facility costs
12.0

Exploration costs
60.5

Acquisitions:
 
Proved properties
5.3

Leasing activity
18.0

Total, including asset retirement obligations
$
407.7

The majority of costs incurred for oil and gas producing activities during 2012 were spent on the development of 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 fund our capital program.
3.50% Senior Convertible Notes. In April 2012, we called for redemption of our outstanding 3.50% Senior Convertible Notes. We settled the principal amount of all converted 3.50% Senior Convertible Notes in cash with the excess value settled in shares of common stock. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional information.
2023 Notes. On June 29, 2012, we issued $400.0 million in aggregate principal amount of 2023 Notes. The notes were issued at par and mature on January 1, 2023. We received net proceeds of $392.3 million from this issuance, which we used to pay down outstanding borrowings under our credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional information.

25


Marketing of Properties. During the second quarter of 2012, we began to remarket our Marcellus shale assets located in Pennsylvania and to market certain assets located in our Rocky Mountain region. Please refer to Note 3 - Assets Held for Sale in Part I, Item 1 of this report, as well as Legal Proceedings in Part II, Item 1 of this report for additional information.
Impairment of Properties. In the second quarter of 2012, we recorded proved property impairments of $38.5 million related to our Haynesville shale assets due to low natural gas prices.
 
Unsuccessful Sale of Properties. During the second quarter of 2012, we reclassified assets located in our Rocky Mountain region previously classified as held for sale as of March 31, 2012, to assets held and used, as these assets were no longer being actively marketed, which resulted in a $28.3 million loss. Please refer to Note 3 - Assets Held for Sale in Part I, Item 1 of this report for additional discussion.
Equity Compensation. Subsequent to June 30, 2012, we granted 365,787 RSUs and 314,853 PSUs pursuant to our long-term equity incentive program. Also subsequent to June 30, 2012, we issued 923,685 shares of our common stock to settle PSU and RSU awards granted in previous years. Please refer to Note 7 - Compensation Plans in Part I, Item 1 of this report for additional discussion.
First Six Months 2012 Highlights
Production Results. The table below provides a regional breakdown of our first half of 2012 production:
 
South Texas & Gulf Coast
 
Mid-Continent
 
Permian
 
Rocky Mountain
 
Total (1)
First six months of 2012 production:
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
1.4

 
0.2

 
0.6

 
2.6

 
4.9

Gas (Bcf)
25.7

 
27.3

 
1.5

 
2.3

 
56.8

NGLs (MMBbl)
2.3

 
0.2

 

 

 
2.5

Equivalent (BCFE)
48.3

 
29.6

 
5.3

 
18.1

 
101.3

Avg. daily equivalents (MMCFE/d)
265.3

 
162.7

 
28.9

 
99.5

 
556.4

Relative percentage
48
%
 
29
%
 
5
%
 
18
%
 
100
%
_____________________________________________
(1) Totals may not add due to rounding.

For the first half of 2012, our production was led by our South Texas & Gulf Coast region due to our focus on the development of our Eagle Ford shale operated and non-operated programs. Please refer to Comparison of Financial Results and Trends Between the Six Months Ended June 30, 2012, and 2011 for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
 
For the Six Months Ended June 30, 2012
 
(in millions)
Development costs
$
598.5

Facility costs
23.2

Exploration costs
106.5

Acquisitions
 
Proved properties
5.3

Leasing activity
42.2

Total, including asset retirement obligations
$
775.7

 
Outlook for the Remainder of 2012

Our capital program for 2012 is expected to be approximately $1.5 billion, of which $1.1 billion to $1.2 billion will be focused on drilling and completion activities. Approximately 85 percent of our drilling budget has been allocated to our operated properties, and over 95 percent of our allocated drilling and completion capital for 2012 is expected to be directed to oil and NGL-rich projects.

26



In 2012, we now plan to invest between $520 million and $570 million of drilling and completion capital in our operated Eagle Ford shale program, which represents a decrease of approximately $130 million from our previous guidance of $650 million to $700 million of drilling and completion capital allocated for the program. The decrease in expected capital investment is primarily driven by the deferral of a number of completions as a result of midstream gathering constraints we began experiencing in the second quarter of 2012. We are currently operating six drilling rigs in this program, three of which are pod drilling while the remainder will drill wells throughout our acreage position to satisfy leasehold obligations. We expect to drop one operated rig later in the year. Aside from the drilling necessary to satisfy leasehold obligations throughout our position, we expect to focus our drilling on the northern portion of our acreage position which has higher condensate and NGL yields. For the remainder of 2012, we plan to continue testing our well design and acreage spacing assumptions in order to determine the ultimate development spacing and to optimize the well performance and capital efficiency of our operated acreage.
 
In our non-operated Eagle Ford shale program, the operator is currently operating nine drilling rigs and one spudder rig. Based on the operator’s stated plans, our expectation is that the number of rigs will remain relatively constant throughout the year. Mitsui is obligated to carry the majority of the drilling and completion costs of our non-operated drilling activity through 2012 and, as such, we expect to deploy minimal capital related to drilling in this program. Costs that are not associated with drilling or completion activities, such as infrastructure construction, are not carried by Mitsui, and accordingly we will be responsible for our proportionate share of these costs. During the second quarter, the operator increased the amount of expected capital to be expended on infrastructure expansion, which is a cost not carried by Mitsui.
 
We plan to invest between $160 million and $185 million of our capital budget in our operated Bakken/Three Forks program in the North Dakota portion of the Williston Basin in 2012. We added a fourth drilling rig in this program at the end of the second quarter. Our plan with these rigs is to drill sufficient acreage to hold our Raven and Gooseneck prospects through production and to begin infill drilling in our Bear Den prospect, which is held by production.

In our Granite Wash program, we are currently running three drilling rigs focused on the liquids-rich Marmaton washes. As most of this acreage position is held by production, we expect to drop one of the three rigs that we operate in the program during the second half of 2012 as part of a reallocation of capital throughout our development program. We have allocated approximately $50 million to $60 million to this program, a decrease of approximately $10 million from our previous guidance of $60 million to $70 million.

We have allocated $95 million to $105 million on our operated Permian program, which is focused on three projects in our Permian region, each of which is in a different stage of maturity in our delineation and development process. Beginning in the third quarter, we added a fourth rig in our Permian region, which is focused on the Mississippian limestone in the northeastern Midland Basin.
 
We plan to invest the remainder of our allocated drilling and completion capital for 2012 on our outside operated and other operated programs. The outside operated capital primarily consists of our non-operated Bakken/Three Forks program as well as our non-operated Granite Wash program. We currently have $150 million to $200 million allocated to this program, which represents an increase from our previous guidance of approximately $50 million from our previous guidance, primarily due to an increase in the amount allocated to our non-operated Bakken/Three Forks program. For 2012, we budgeted $60 million to $80 million on our other operated activities which includes first half activity in our Haynesville shale program as well as activity planned for the year in our Powder River Basin program.

Please refer to Overview of Liquidity and Capital Resources for additional discussion regarding how we intend to fund our 2012 capital program.


27


Financial Results of Operations and Additional Comparative Data

The table below provides information regarding selected production and financial information for the quarter ended June 30, 2012, and the immediately preceding three quarters. Additional details of per MCFE costs are presented later in this section.

 
For the Three Months Ended
 
June 30,
 
March 31,
 
December 31,
 
September 30,
 
2012
 
2012
 
2011
 
2011
 
(in millions, except for production data)
Production (BCFE)
50.6

 
50.7

 
51.3

 
42.5

Oil, gas, and NGL production revenue
$
312.6

 
$
362.6

 
$
397.0

 
$
325.2

Realized hedge gain (loss)
$
0.2

 
$
1.7

 
$
(6.2
)
 
$
(6.8
)
Gain (loss) on divestiture activity
$
(24.2
)
 
$
1.5

 
$
(25.0
)
 
$
190.7

Lease operating expense
$
46.1

 
$
39.4

 
$
43.5

 
$
40.0

Transportation costs
$
30.3

 
$
28.6

 
$
30.7

 
$
23.9

Production taxes
$
14.7

 
$
19.1

 
$
19.0

 
$
13.8

DD&A
$
161.6

 
$
169.6

 
$
167.3

 
$
123.1

Exploration
$
22.0

 
$
18.6

 
$
20.0

 
$
11.3

Impairment of proved properties
$
38.5

 
$

 
$
170.5

 
$
48.5

Abandonment and impairment of unproved properties
$
10.7

 
$
0.1

 
$
3.1

 
$

General and administrative
$
31.1

 
$
28.1

 
$
35.6

 
$
29.8

Change in Net Profits Plan liability
$
(22.1
)
 
$
3.9

 
$
(0.8
)
 
$
(24.9
)
Unrealized and realized derivative (gain) loss
$
(98.1
)
 
$
2.2

 
$
46.8

 
$
(128.4
)
Net income (loss)
$
24.9

 
$
26.3

 
$
(120.7
)
 
$
230.1


Selected Performance Metrics:

 
For the Three Months Ended
 
June 30,
 
March 31,
 
December 31,
 
September 30,
 
2012
 
2012
 
2011
 
2011
Average net daily production equivalent (MMCFE per day)
555.7

 
557.0

 
557.9

 
462.1

Lease operating expense (per MCFE)
$
0.91

 
$
0.78

 
$
0.85

 
$
0.94

Transportation costs (per MCFE)
$
0.60

 
$
0.56

 
$
0.60

 
$
0.56

Production taxes as a percent of oil, gas, and NGL production revenue
4.7
%
 
5.3
%
 
4.8
%
 
4.3
%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per MCFE)
$
3.20

 
$
3.35

 
$
3.26

 
$
2.89

General and administrative (per MCFE)
$
0.62

 
$
0.56

 
$
0.69

 
$
0.70



28


A three-month and six-month overview of selected production and financial information, including trends:
 
For the Three Months Ended June 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
For the Six Months Ended June 30,
 
Amount Change Between Periods
 
Percent Change Between Periods
 
2012
 
2011
 
 
2012
 
2011
 
Net production volumes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
2.4

 
1.9

 
0.5

 
27
 %
 
4.9

 
3.6

 
1.2

 
34
 %
Gas (Bcf)
28.1

 
23.9

 
4.2

 
18
 %
 
56.8

 
45.6

 
11.1

 
24
 %
NGLs (MMBbl)
1.4

 
0.8

 
0.6

 
75
 %
 
2.5

 
1.4

 
1.1

 
81
 %
Equivalent (BCFE)
50.6

 
39.8

 
10.8

 
27
 %
 
101.3

 
75.9

 
25.4

 
33
 %
Average net daily production
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbl per day)
25.9

 
20.4

 
5.6

 
27
 %
 
26.7

 
20.1