Table of Contents

 

 

 

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, 2011

 

Commission File Number 001-31539

 

GRAPHIC

 

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)

 

Delaware

 

41-0518430

(State or other jurisdiction

of incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

1775 Sherman Street, Suite 1200, Denver, Colorado

 

80203

(Address of principal executive offices)

 

(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 x 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 x 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 x

 

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 x

 

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 26, 2011 the registrant had 63,734,209 shares of common stock, $0.01 par value, outstanding.

 

 

 



Table of Contents

 

SM ENERGY COMPANY

INDEX

 

 

 

 

PAGE

Part I.

FINANCIAL INFORMATION

 

 

 

 

 

 

Item 1.

Financial Statements (Unaudited)

 

 

 

 

 

 

 

Condensed Consolidated Balance Sheets

June 30, 2011, and December 31, 2010

3

 

 

 

 

 

 

Condensed Consolidated Statements of Operations

Three and Six Months Ended June 30, 2011, and 2010

4

 

 

 

 

 

 

Condensed Consolidated Statements of Stockholders’ Equity and Comprehensive Income

Six Months Ended June 30, 2011, and 2010

5

 

 

 

 

 

 

Condensed Consolidated Statements of Cash Flows

Six Months Ended June 30, 2011, and 2010

6

 

 

 

 

 

 

Notes to Condensed Consolidated Financial Statements

8

 

 

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

23

 

 

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

(included within the content of Item 2)

46

 

 

 

 

 

Item 4.

Controls and Procedures

46

 

 

 

 

Part II.

OTHER INFORMATION

 

 

 

 

 

 

Item 1.

Legal Proceedings

46

 

 

 

 

 

Item 1A.

Risk Factors

46

 

 

 

 

 

Item 6.

Exhibits

47

 



Table of Contents

 

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,

 

December 31,

 

 

 

2011

 

2010

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

101,080

 

$

5,077

 

Accounts receivable

 

173,557

 

163,190

 

Refundable income taxes

 

3,134

 

8,482

 

Prepaid expenses and other

 

32,281

 

45,522

 

Derivative asset

 

28,985

 

43,491

 

Deferred income taxes

 

7,086

 

8,883

 

Total current assets

 

346,123

 

274,645

 

 

 

 

 

 

 

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

 

 

 

 

 

Land

 

1,526

 

1,491

 

Proved oil and gas properties

 

3,799,844

 

3,389,158

 

Less - accumulated depletion, depreciation, and amortization

 

(1,532,670

)

(1,326,932

)

Unproved oil and gas properties

 

89,317

 

94,290

 

Wells in progress

 

245,650

 

145,327

 

Materials inventory, at lower of cost or market

 

15,915

 

22,542

 

Oil and gas properties held for sale (note 3)

 

130,077

 

86,811

 

Other property and equipment, net of accumulated depreciation of $17,550 in 2011 and $15,480 in 2010

 

61,831

 

21,365

 

 

 

2,811,490

 

2,434,052

 

 

 

 

 

 

 

Other noncurrent assets:

 

 

 

 

 

Derivative asset

 

10,624

 

18,841

 

Other noncurrent assets

 

51,656

 

16,783

 

Total other noncurrent assets

 

62,280

 

35,624

 

 

 

 

 

 

 

Total Assets

 

$

3,219,893

 

$

2,744,321

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued expenses

 

$

413,048

 

$

417,654

 

Derivative liability

 

70,100

 

82,044

 

Deposit associated with oil and gas properties held for sale

 

 

2,355

 

Total current liabilities

 

483,148

 

502,053

 

 

 

 

 

 

 

Noncurrent liabilities:

 

 

 

 

 

Long-term credit facility

 

 

48,000

 

3.50% Senior Convertible Notes, net of unamortized discount of $7,209 in 2011 and $11,827 in 2010

 

280,291

 

275,673

 

6.625% Senior Notes

 

350,000

 

 

Asset retirement obligation

 

72,273

 

69,052

 

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

 

92

 

2,119

 

Net Profits Plan liability

 

133,419

 

135,850

 

Deferred income taxes

 

496,405

 

443,135

 

Derivative liability

 

38,233

 

32,557

 

Other noncurrent liabilities

 

16,866

 

17,356

 

Total noncurrent liabilities

 

1,387,579

 

1,023,742

 

 

 

 

 

 

 

Commitments and contingencies (note 7)

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 63,764,421 shares in 2011 and 63,412,800 shares in 2010; outstanding, net of treasury shares: 63,683,354 shares in 2011 and 63,310,165 shares in 2010

 

638

 

634

 

Additional paid-in capital

 

215,704

 

191,674

 

Treasury stock, at cost: 81,067 shares in 2011 and 102,635 shares in 2010

 

(1,544

)

(423

)

Retained earnings

 

1,144,972

 

1,042,123

 

Accumulated other comprehensive loss

 

(10,604

)

(15,482

)

Total stockholders’ equity

 

1,349,166

 

1,218,526

 

 

 

 

 

 

 

Total Liabilities and Stockholders’ Equity

 

$

3,219,893

 

$

2,744,321

 

 

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

 

3



Table of Contents

 

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

 

 

 

 

For the Three Months

 

For the Six Months

 

 

 

Ended June 30,

 

Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

Operating revenues and other income:

 

 

 

 

 

 

 

 

 

Oil, gas, and NGL production revenue

 

$

333,934

 

$

175,887

 

$

610,247

 

$

388,774

 

Realized hedge gain (loss) (note 10)

 

(6,330

)

9,329

 

(7,705

)

11,924

 

Gain on divestiture activity (note 3)

 

30,019

 

7,021

 

54,934

 

127,999

 

Marketed gas system and other operating revenue

 

20,250

 

19,460

 

35,726

 

43,135

 

Total operating revenues and other income

 

377,873

 

211,697

 

693,202

 

571,832

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Oil, gas, and NGL production expense

 

53,342

 

45,168

 

119,154

 

93,508

 

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

 

115,382

 

79,770

 

220,738

 

157,535

 

Exploration

 

9,603

 

14,498

 

22,315

 

28,396

 

Abandonment and impairment of unproved properties

 

1,237

 

2,375

 

4,316

 

3,279

 

General and administrative

 

27,310

 

25,398

 

53,171

 

48,884

 

Change in Net Profits Plan liability

 

(13,984

)

(6,599

)

211

 

(33,871

)

Unrealized and realized derivative (gain) loss (note 10)

 

(43,876

)

(2,087

)

44,553

 

(9,822

)

Marketed gas system and other expense

 

17,152

 

16,385

 

37,009

 

39,383

 

Total operating expenses

 

166,166

 

174,908

 

501,467

 

327,292

 

 

 

 

 

 

 

 

 

 

 

Income from operations

 

211,707

 

36,789

 

191,735

 

244,540

 

 

 

 

 

 

 

 

 

 

 

Nonoperating income (expense):

 

 

 

 

 

 

 

 

 

Interest income

 

227

 

54

 

355

 

183

 

Interest expense

 

(14,550

)

(6,343

)

(24,264

)

(13,130

)

 

 

 

 

 

 

 

 

 

 

Income before income taxes

 

197,384

 

30,500

 

167,826

 

231,593

 

Income tax expense

 

(72,851

)

(12,432

)

(61,796

)

(87,347

)

 

 

 

 

 

 

 

 

 

 

Net income

 

$

124,533

 

$

18,068

 

$

106,030

 

$

144,246

 

 

 

 

 

 

 

 

 

 

 

Basic weighted-average common shares outstanding

 

63,638

 

62,917

 

63,543

 

62,855

 

 

 

 

 

 

 

 

 

 

 

Diluted weighted-average common shares outstanding

 

66,909

 

64,566

 

66,695

 

64,493

 

 

 

 

 

 

 

 

 

 

 

Basic net income per common share

 

$

1.96

 

$

0.29

 

$

1.67

 

$

2.29

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per common share

 

$

1.86

 

$

0.28

 

$

1.59

 

$

2.24

 

 

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

 

4



Table of Contents

 

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)

(In thousands, except share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

Additional

 

 

 

 

 

 

 

Other

 

Total

 

 

 

Common Stock

 

Paid-in

 

Treasury Stock

 

Retained

 

Comprehensive

 

Stockholders’

 

 

 

Shares

 

Amount

 

Capital

 

Shares

 

Amount

 

Earnings

 

Income (Loss)

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances, January 1, 2011

 

63,412,800

 

$

634

 

$

191,674

 

(102,635

)

$

(423

)

$

1,042,123

 

$

(15,482

)

$

1,218,526

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

106,030

 

 

106,030

 

Reclassification to earnings

 

 

 

 

 

 

 

4,878

 

4,878

 

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

110,908

 

Cash dividends, $ 0.05 per share

 

 

 

 

 

 

(3,181

)

 

(3,181

)

Issuance of common stock under Employee Stock Purchase Plan

 

22,373

 

1

 

1,121

 

 

 

 

 

1,122

 

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings, including income tax benefit of RSUs

 

18,836

 

 

(644

)

 

 

 

 

(644

)

Sale of common stock, including income tax benefit of stock option exercises

 

310,412

 

3

 

10,595

 

 

 

 

 

10,598

 

Stock-based compensation expense

 

 

 

12,958

 

21,568

 

(1,121

)

 

 

11,837

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances, June 30, 2011

 

63,764,421

 

$

638

 

$

215,704

 

(81,067

)

$

(1,544

)

$

1,144,972

 

$

(10,604

)

$

1,349,166

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances, January 1, 2010

 

62,899,122

 

$

629

 

$

160,516

 

(126,893

)

$

(1,204

)

$

851,583

 

$

(37,954

)

$

973,570

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

144,246

 

 

144,246

 

Change in derivative instrument fair value

 

 

 

 

 

 

 

53,765

 

53,765

 

Reclassification to earnings

 

 

 

 

 

 

 

(782

)

(782

)

Minimum pension liability adjustment

 

 

 

 

 

 

 

4

 

4

 

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

197,233

 

Cash dividends, $ 0.05 per share

 

 

 

 

 

 

(3,144

)

 

(3,144

)

Issuance of common stock under Employee Stock Purchase Plan

 

27,456

 

 

799

 

 

 

 

 

799

 

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings, including income tax cost of RSUs

 

34,588

 

1

 

(545

)

 

 

 

 

(544

)

Sale of common stock, including income tax benefit of stock option exercises

 

148,902

 

1

 

3,054

 

 

 

 

 

3,055

 

Stock-based compensation expense

 

 

 

11,149

 

24,258

 

715

 

 

 

11,864

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balances, June 30, 2010

 

63,110,068

 

$

631

 

$

174,973

 

(102,635

)

$

(489

)

$

992,685

 

$

15,033

 

$

1,182,833

 

 

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

 

5



Table of Contents

 

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

 

 

 

For the Six Months

 

 

 

Ended June 30,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

106,030

 

$

144,246

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Gain on divestiture activity

 

(54,934

)

(127,999

)

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

 

220,738

 

157,535

 

Exploratory dry hole expense

 

49

 

327

 

Abandonment and impairment of unproved properties

 

4,316

 

3,279

 

Stock-based compensation expense

 

11,837

 

11,864

 

Change in Net Profits Plan liability

 

211

 

(33,871

)

Unrealized derivative (gain) loss

 

24,160

 

(9,822

)

Amortization of debt discount and deferred financing costs

 

11,294

 

6,657

 

Deferred income taxes

 

52,241

 

78,820

 

Plugging and abandonment

 

(1,430

)

(6,222

)

Other

 

(5,888

)

2,937

 

Changes in current assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(10,370

)

7,628

 

Refundable income taxes

 

5,348

 

9,558

 

Prepaid expenses and other

 

15,692

 

(148

)

Accounts payable and accrued expenses

 

(2,530

)

26,299

 

Excess income tax benefit from the exercise of stock awards

 

(6,791

)

(938

)

Net cash provided by operating activities

 

369,973

 

270,150

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Net proceeds from sale of oil and gas properties

 

97,952

 

247,998

 

Capital expenditures

 

(662,372

)

(304,627

)

Deposits to restricted cash

 

 

(19,595

)

Other

 

(2,355

)

(6,492

)

Net cash used in investing activities

 

(566,775

)

(82,716

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from credit facility

 

102,000

 

204,059

 

Repayment of credit facility

 

(150,000

)

(392,059

)

Debt issuance costs related to credit facility

 

(8,525

)

 

Net proceeds from 6.625% Senior Notes

 

341,435

 

 

Proceeds from sale of common stock

 

4,929

 

2,916

 

Dividends paid

 

(3,181

)

(3,144

)

Excess income tax benefit from the exercise of stock awards

 

6,791

 

938

 

Other

 

(644

)

(544

)

Net cash provided by (used in) financing activities

 

292,805

 

(187,834

)

 

 

 

 

 

 

Net change in cash and cash equivalents

 

96,003

 

(400

)

Cash and cash equivalents at beginning of period

 

5,077

 

10,649

 

Cash and cash equivalents at end of period

 

$

101,080

 

$

10,249

 

 

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

 

6



Table of Contents

 

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)

 

Supplemental schedule of additional cash flow information and noncash investing and financing activities:

 

 

 

For the Six Months
Ended June 30,

 

 

 

2011

 

2010

 

 

 

(In thousands)

 

 

 

 

 

 

 

Cash paid for interest

 

$

(6,378

)

$

(8,152

)

 

 

 

 

 

 

Net cash refunded for income taxes

 

$

2,543

 

$

2,392

 

 

As of June 30, 2011, and 2010, $237.9 million, and $105.4 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 consolidated financial statements.

 

7



Table of Contents

 

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, exploitation, development, and production of crude oil, natural gas, and natural gas liquids (“NGLs”) in North America, with a focus on oil and liquids-rich resource plays.

 

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

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements of SM Energy have been prepared in accordance with accounting principles generally accepted in the United States 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 generally accepted accounting principles 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, 2010,  (the “2010 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 subsequent events after the balance sheet date of June 30, 2011, 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 2010 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 2010 Form 10-K.  As discussed in Note 10 - Derivative Financial Instruments, as of January 1, 2011, the Company elected to discontinue cash flow hedge accounting on a prospective basis.

 

Recently Issued Accounting Standards

 

In May 2011, the Financial Accounting Standards Board (“FASB”) issued new fair value measurement authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value.  This guidance is effective for annual periods beginning after December 15, 2011.  The Company is currently evaluating the provisions of this guidance and assessing the impact, if any, it may have on the Company’s fair value disclosures.

 

In June 2011, the FASB issued new authoritative guidance that states an entity that reports items of other comprehensive income has the option to present the components of net income and comprehensive income in either one continuous financial statement, or two consecutive financial statements. This guidance is effective for annual periods beginning after December 15, 2011.  The Company is currently evaluating the provisions of this guidance and assessing the impact it will have on the Company’s comprehensive income disclosures.

 

Note 3 - Divestitures and Assets Held for Sale

 

Mid-Continent Divestiture

 

In June 2011, the Company completed the divestiture of certain non-strategic Constitution Field assets located in its Mid-Continent region that were classified as assets held for sale at March 31, 2011.   Total cash received, before marketing costs and Net Profits Interest Bonus Plan (“Net Profits Plan”) payments, was $35.7 million.  The final sale price is subject to post-closing adjustments and is expected to be finalized during the second half of 2011.  The estimated gain on this divestiture was approximately $28.5 million and may be impacted by the post-closing adjustments mentioned above.  The Company determined that the sale did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

 

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Table of Contents

 

Rocky Mountain Divestiture

 

In January 2011, the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain region that were classified as assets held for sale at December 31, 2010.   Total cash received, before marketing costs and Net Profits Plan payments, was $45.5 million.  The final gain on sale related to the divestiture was $27.2 million.  The Company determined that the sale did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

 

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 expense any excess of carrying value over fair value less costs to sell.  Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale for assets for which fair value is determined to be less than the carrying value of the assets.

 

As of June 30, 2011, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) include $130.1 million in book value of assets held for sale, net of accumulated depletion, depreciation and amortization and a corresponding asset retirement obligation liability is also separately presented.  The above assets held for sale and asset retirement obligation liability amounts include certain assets located in Pennsylvania and the Company’s South Texas & Gulf Coast region, including our gathering assets as described in Note 12 – Acquisition and Development Agreement.  The Company determined that these planned asset sales do not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

 

In July 2011, the Company entered into an agreement to divest its Marcellus shale assets located in Pennsylvania that were classified as held for sale at June 30, 2011, for $80.0 million in cash, subject to normal closing and post-closing adjustments.  The agreement has an effective date of April 1, 2011, and is anticipated to close in the third quarter of 2011.  The closing of this transaction is subject to the satisfaction of certain closing conditions, including the resolution of any title and environmental defects exceeding specified levels.

 

On August 2, 2011, the Company divested its operated LaSalle and Dimmitt County assets located in its South Texas & Gulf Coast region that were classified as assets held for sale at June 30, 2011.  Total cash received, before marketing costs, was $227.4 million.  The final sales price is subject to post-closing adjustments and is expected to be finalized in the fourth quarter of 2011.  The estimated gain on this divestiture is approximately $196.1 million and may be impacted by the post-closing adjustments mentioned above.

 

Note 4 - Income Taxes

 

Income tax expense for the six-month periods ended June 30, 2011, and 2010, 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 the domestic production activities deduction, percentage depletion, the effect of state income taxes, and other permanent differences.

 

The provision for income taxes consists of the following:

 

 

 

For the Three Months
Ended June 30,

 

For the Six Months
Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(in thousands)

 

Current portion of income tax (expense) benefit:

 

 

 

 

 

 

 

 

 

Federal

 

$

(2,212

)

$

1,759

 

$

(9,156

)

$

(8,216

)

State

 

(224

)

21

 

(399

)

(311

)

Deferred portion of income tax (expense)

 

(70,415

)

(14,212

)

(52,241

)

(78,820

)

Total income tax (expense)

 

$

(72,851

)

$

(12,432

)

$

(61,796

)

$

(87,347

)

Effective tax rate

 

36.9

%

40.8

%

36.8

%

37.7

%

 

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.  The cumulative effects of state rate changes are reflected in the period legislation is enacted.  Changes in the effective tax rate between periods also occur due to estimates for the domestic production activities deduction, percentage depletion, and for potential permanent state tax items that affect the presented periods differently due to oil and gas price variability and the impact of non-core asset sales. The quarterly rate can also be impacted by the proportion of income earned in reported periods.

 

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Table of Contents

 

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states.  With few 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 the anticipated $5.5 million refund from its 2006 tax year as a result of a net operating loss carryback claim from the 2008 tax year.  In the fourth quarter of 2010, the Internal Revenue Service initiated an audit of the Company for the 2009 tax year.   The audit was concluded in the second quarter of 2011 with a $110,000 decrease to the total 2005 refund claim of $25 million.  A quick refund claim of $22.9 million from 2005 was received in the third quarter of 2010.  The Company’s remaining refundable income tax balance at June 30, 2011, includes the remaining $2 million 2005 amount.

 

Note 5 - Long-Term Debt

 

Revolving Credit Facility

 

The Company executed a Fourth Amended and Restated Credit Agreement on May 27, 2011.  This amended revolving credit facility replaced the Company’s previous facility.  The Company incurred $8.5 million of deferred financing costs in association with the amended credit facility.  Borrowings under the facility are secured by substantially all of the Company’s proved oil and gas properties.  The credit facility has a maximum loan amount of $2.5 billion, with current aggregate lender commitments of $1.0 billion, and a maturity date of May 27, 2016.  The borrowing base under the credit facility as of the filing date of this report is $1.3 billion, and is subject to regular semi-annual redeterminations.  The borrowing base redetermination process considers the value of the Company’s oil and gas properties and other assets, as determined by the bank syndicate.

 

The Company must comply with certain financial and non-financial covenants under the terms of its credit facility agreement, including the limitation of the Company’s dividends to no more than $50.0 million per year.  The Company was in compliance with all financial and non-financial covenants under the credit facility as of June 30, 2011, and through the filing date of this report.  Interest and commitment fees are accrued based on the borrowing base utilization grid below.  Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternative Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table below.  Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).

 

Borrowing Base Utilization Grid

 

Borrowing Base Utilization Percentage

 

<25%

 

³25% <50%

 

³50% <75%

 

³75% <90%

 

³90%

 

Eurodollar Loans

 

1.500

%

1.750

%

2.000

%

2.250

%

2.500

%

ABR Loans or Swingline Loans

 

0.500

%

0.750

%

1.000

%

1.250

%

1.500

%

Commitment Fee Rate

 

0.375

%

0.375

%

0.500

%

0.500

%

0.500

%

 

The Company had no outstanding borrowings under its credit facility as of June 30, 2011.  The Company had $48.0 million of outstanding borrowings under its previous credit facility as of December 31, 2010.  The Company had $999.4 million available borrowing capacity under this facility as of June 30, 2011.  The Company had $629.5 million available borrowing capacity under its previous facility as of December 31, 2010, when the aggregate commitment amount was $678.0 million.  The Company has two letters of credit outstanding for a total of $608,000 as of June 30, 2011.  The Company had a single letter of credit outstanding in the amount of $483,000 at December 31, 2010.  These letters of credit reduce the amount available under the commitment amount on a dollar-for-dollar basis.

 

6.625% Senior Notes Due 2019

 

On February 7, 2011, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes Due 2019 (the “6.625% Senior Notes”).  The 6.625% Senior Notes were issued at par and mature on February 15, 2019.  The Company received net proceeds of approximately $341.4 million after deducting fees of approximately $8.6 million, which will be amortized as deferred financing costs over the life of the 6.625% Senior Notes.  The net proceeds were used to repay all borrowings under the Company’s credit facility, with the remainder to be used for the Company’s ongoing capital expenditure program and general corporate purposes.

 

Prior to February 15, 2014, the Company may redeem up to 35 percent of the aggregate principal amount of the 6.625% Senior Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount thereof, plus accrued and unpaid interest.  The Company may redeem the 6.625% Senior Notes, in whole or part, at any time prior to February 15, 2015, at a redemption price equal to 100% of the principal amount, plus a specified make whole premium and accrued and unpaid interest.

 

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Table of Contents

 

The Company may also redeem all or, from time to time, a portion of the 6.625% Senior Notes on or after February 15, 2015, at the prices set forth below, expressed as a percentage of the principal amount redeemed, plus accrued and unpaid interest:

 

2015

 

103.313

%

2016

 

101.656

%

2017 and thereafter

 

100.000

%

 

The 6.625% Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt.  There are no subsidiary guarantors of the 6.625% Senior Notes.  The Company is subject to certain covenants under its 6.625% Senior Notes that limit incurring additional indebtedness, issuing preferred stock, and making restricted payments in excess of specified amounts.  The restricted payment covenant limits the payment of dividends on the Company’s common stock, provided however, the Company may pay dividends of up to $6.5 million for any given year during the eight-year term of the notes.  The Company is in compliance with all covenants under its 6.625% Senior Notes as of June 30, 2011, and through the filing date of this report.

 

Additionally, on February 7, 2011, the Company entered into a registration rights agreement that provides holders of the 6.625% Senior Notes certain registration rights for the 6.625% Senior Notes under the Securities Act of 1933, as amended (the “Securities Act”).  Pursuant to the registration rights agreement, the Company will file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) with respect to an offer to exchange the 6.625% Senior Notes for substantially identical notes that are registered under the Securities Act.  Under certain circumstances, in lieu of a registered exchange offer, the Company has agreed to file a shelf registration statement relating to the resale of the 6.625% Senior Notes.  If the exchange offer is not completed on or before February 7, 2012, or the shelf registration statement, if required, is not declared effective within the time periods specified in the registration rights agreement, then the Company has agreed to pay additional interest with respect to the 6.625% Senior Notes in an amount not to exceed one percent of the principal amount of the 6.625% Senior Notes until the exchange offer is completed or the shelf registration statement is declared effective.

 

3.50% Senior Convertible Notes Due 2027

 

On April 4, 2007, the Company issued $287.5 million in aggregate principal amount of 3.50% Senior Convertible Notes Due 2027 (the “3.50% Senior Convertible Notes”).  The 3.50% Senior Convertible Notes mature on April 1, 2027, unless converted prior to maturity, redeemed, or purchased by the Company.

 

Holders of the 3.50% Senior Convertible Notes may elect to surrender all or a portion of their notes for conversion under certain circumstances, including during a calendar quarter if the closing price of the Company’s common stock was more than 130 percent of the conversion price of $54.42 per share for at least 20 trading days in the 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter.  As of December 31, 2010, the 3.50% Senior Convertible Notes were not convertible.  The closing price of the Company’s common stock was more than the conversion trigger price of $70.75 per share for at least 20 trading days in the 30 consecutive trading days ending on the last trading day during the first quarter of 2011.  Therefore the holders of the 3.50% Senior Convertible Notes had the right to convert all or a portion of their notes during the second quarter of 2011.  If holders elect to convert all or a portion of their notes during a calendar quarter that they are eligible to do so, they will receive cash, shares of the Company’s common stock, or any combination thereof as may be elected by the Company under the indenture for the 3.50% Senior Convertible Notes.  No holders elected to convert their notes during the second quarter of 2011.  The closing price of the Company’s common stock was not more than the conversion trigger price of $70.75 per share for at least 20 trading days in the 30 consecutive trading days ending on the last trading day in the second quarter of 2011.  Therefore, the 3.50% Senior Convertible Notes will not be convertible during the third quarter of 2011.

 

Note 6 - Earnings per Share

 

Basic net income per common share of stock is calculated by dividing net income available to common stockholders by the basic weighted-average common shares outstanding for the respective period.  The Company’s earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

 

Diluted net income per common share of stock is calculated by dividing adjusted net income by the number of diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for this calculation consist of unvested restricted stock units (“RSUs”), in-the-money outstanding options to purchase the Company’s common stock, contingent Performance Share Awards (“PSAs”), and shares into which the 3.50% Senior Convertible Notes are convertible.

 

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Table of Contents

 

The PSAs represent the right to receive, upon settlement of the PSAs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSAs granted on the award date.  The number of potentially dilutive shares related to PSAs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period.  For additional discussion on PSAs, please refer to Note 8 - Compensation Plans under the heading Performance Share Awards Under the Equity Incentive Compensation Plan.

 

The Company’s 3.50% Senior Convertible Notes have a net-share settlement right whereby the Company has the option to irrevocably elect, by notice to the trustee under the indenture for the notes, to settle the Company’s obligation to deliver shares of the Company’s common stock, 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.  For accounting purposes, the treasury stock method is used to measure the potentially dilutive impact of shares associated with this conversion feature.  Shares of the Company’s common stock traded at an average closing price exceeding the $54.42 conversion price for the three-month and six-month periods ended June 30, 2011.  The 3.50% Senior Convertible Notes had a dilutive impact for the three-month and six-month periods ended June 30, 2011, as calculated in the basic and diluted earnings per share table below.  The 3.50% Senior Convertible Notes were not dilutive for the three-month and six-month periods ended June 30, 2010.

 

The treasury stock method is used to measure the dilutive impact of unvested RSUs, contingent PSAs, and in-the-money stock options, as calculated in the basic and diluted earnings per share table below.

 

The following table sets forth the calculation of basic and diluted earnings per share:

 

 

 

For the Three Months
Ended June 30,

 

For the Six Months
Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

124,533

 

$

18,068

 

$

106,030

 

$

144,246

 

Basic weighted-average common shares outstanding

 

63,638

 

62,917

 

63,543

 

62,855

 

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

 

2,182

 

1,649

 

2,161

 

1,638

 

Add: dilutive effect of 3.50% Senior Convertible Notes

 

1,089

 

 

991

 

 

Diluted weighted-average common shares outstanding

 

66,909

 

64,566

 

66,695

 

64,493

 

Basic net income per common share

 

$

1.96

 

$

0.29

 

$

1.67

 

$

2.29

 

Diluted net income per common share

 

$

1.86

 

$

0.28

 

$

1.59

 

$

2.24

 

 

Note 7 - Commitments and Contingencies

 

During the second quarter of 2011, the Company entered into two natural gas gathering and services agreements whereby it is subject to certain natural gas gathering through-put commitments for up to ten years pursuant to each contract.  The Company may be required to make periodic deficiency payments for any shortfalls in delivering the minimum applicable annual or semi-annual volume commitments.  In the event that no gas is delivered pursuant to the agreements, the aggregate deficiency payments will total approximately $729.4 million.  If a shortfall in the minimum volume commitment arises, the Company can arrange for third party gas to be delivered into the applicable gathering system and applied to the Company’s minimum commitment.

 

During the first quarter of 2011, the Company entered into a hydraulic fracturing services contract.  The total commitment is $180.0 million over a two-year term commencing January 1, 2011.  However, the Company’s liability in the event of early termination of this contract is not to exceed $24.0 million.

 

The Company is subject to litigation and claims that have arisen in the ordinary course of its business.  The Company accrues for such items when a liability is probable and the amount can be reasonably estimated.  The Company currently has no such accruals.  In the opinion of management, any adverse results in any such pending litigation and claims will not have a material effect on the results of operations, the financial position, or cash flows of the Company.

 

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Table of Contents

 

The Company is currently 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 seek to quiet title to their claimed overriding royalty interest and seek the recovery of unpaid overriding royalty interest proceeds allegedly due.  The Texas District Court has issued an order granting plaintiffs’ motion for summary judgment, but the Company believes that the summary judgment order is incorrect under the governing agreements and applicable law, and the Company intends to appeal and continue to contest the litigation.  In July 2011, the court entered judgment awarding the plaintiffs damages of approximately $5.2 million.  If the plaintiffs were to ultimately prevail, the overriding royalty interest would reduce the Company’s net revenue interest in the affected acreage.  The Company does not currently believe that an unfavorable ultimate outcome is probable, nor that if the plaintiffs prevail there would be a material effect on the financial position of the Company.  Based on the Company’s current view of the facts and circumstances of the case, no accrual has been made for any loss.

 

Note 8 - Compensation Plans

 

Cash Bonus Plan

 

During the first quarters of 2011 and 2010, the Company paid $21.6 million and $7.7 million for cash bonuses earned in the 2010 and 2009 performance years, respectively.  Within the general and administrative expense and exploration expense line items in the accompanying statements of operations was $3.7 million and $2.9 million of accrued cash bonus plan expense related to the specific performance year for the three-month periods ended June 30, 2011, and 2010, respectively, and $7.5 million and $6.0 million for the six-month periods ended June 30, 2011, and 2010, respectively.

 

Performance Share Awards Under the Equity Incentive Compensation Plan

 

PSAs are the primary form of long-term equity incentive compensation for the Company.  The PSA factor is based on the Company’s performance after completion of a three-year performance period.  The performance criteria for the PSAs are based on a combination of the Company’s annualized total shareholder return (“TSR”) for the performance period and the relative measure of the Company’s TSR compared with the annualized TSR of an index comprised of certain peer companies for the performance period.  In addition, there are separate employment service vesting provisions.  PSAs are recognized as general and administrative and exploration expense over the vesting period of the award.

 

Total stock-based compensation expense related to PSAs for the three-month periods ended June 30, 2011, and 2010, was $4.1 million and $3.8 million, respectively, and $8.4 million and $7.4 million for the six-month periods ended June 30, 2011, and 2010, respectively.  As of June 30, 2011, there was $13.6 million of total unrecognized compensation expense related to unvested PSAs that is being amortized through 2013.

 

A summary of the status and activity of PSAs for the six-month period ended June 30, 2011, is presented in the following table:

 

 

 

 

 

Weighted-

 

 

 

 

 

Average Grant-

 

 

 

PSAs

 

Date Fair Value

 

Non-vested, at January 1, 2011

 

1,110,666

 

$

39.48

 

Granted

 

 

$

 

Vested (1)

 

(7,682

)

$

36.69

 

Forfeited

 

(23,289

)

$

39.41

 

Non-vested, at June 30, 2011

 

1,079,695

 

$

39.50

 

 


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

 

Subsequent to June 30, 2011, the Company granted 234,308 Performance Stock Units (“PSUs”), which are structurally the same as previously granted PSAs, as part of its regular annual compensation process.  These PSUs will vest 1/7th on July 1, 2012, 2/7ths on July 1, 2013, and 4/7ths on July 1, 2014.  Also subsequent to June 30, 2011, the Company settled 305,351 PSAs that relate to awards granted in 2008 through the issuance of shares of the Company’s common stock in accordance with the terms of the PSA awards.

 

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Table of Contents

 

Restricted Stock Units Under the Equity Incentive Compensation Plan

 

An RSU represents a right to receive one share of the Company’s common stock to be delivered upon settlement of the RSU when it vests.  Total RSU compensation expense for the three-month periods ended June 30, 2011, and 2010, was $985,000 and $1.7 million, respectively, and $2.0 million and $3.5 million for the six-month periods ended June 30, 2011, and 2010, respectively.  As of June 30, 2011, there was $4.5 million of total unrecognized compensation expense related to unvested RSU awards that is being amortized through 2013.

 

During the first half of 2011, the Company settled 27,714 RSUs that relate to awards granted in 2008 through the issuance of shares of the Company’s common stock in accordance with the terms of the RSU awards.  As a result, the Company issued a net of 18,836 shares of common stock associated with these grants.  The remaining 8,878 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those RSUs.

 

A summary of the status and activity of RSUs for the six-month period ended June 30, 2011, is presented in the following table:

 

 

 

 

 

Weighted-Average

 

 

 

 

 

Grant-Date

 

 

 

RSUs

 

Fair Value

 

Non-vested, at January 1, 2011

 

333,359

 

$

31.16

 

Granted

 

8,287

 

$

60.33

 

Vested

 

(27,714

)

$

37.84

 

Forfeited

 

(6,638

)

$

29.88

 

Non-vested, at June 30, 2011

 

307,294

 

$

31.37

 

 

Subsequent to June 30, 2011, the Company granted 78,165 RSUs, as part of its regular annual compensation process.  These RSUs will vest 1/7th on July 1, 2012, 2/7ths on July 1, 2013, and 4/7ths on July 1, 2014.  Also subsequent to June 30, 2011, the Company settled 77,602 RSUs that relate to awards granted in 2010 and 2009 through the issuance of shares of the Company’s common stock in accordance with the terms of the RSU awards.

 

Stock Option Grants Under Prior Stock Option Plans

 

The following table summarizes stock option activity for the six months ended June 30, 2011:

 

 

 

 

 

Weighted-

 

 

 

 

 

 

 

Average

 

Aggregate

 

 

 

Options

 

Exercise Price

 

Intrinsic Value

 

 

 

 

 

 

 

 

 

Outstanding, January 1, 2011

 

920,765

 

$

13.11

 

$

42,192,057

 

Exercised

 

(310,412

)

$

12.26

 

 

 

Forfeited

 

 

$

 

 

 

Outstanding, June 30, 2011

 

610,353

 

$

13.54

 

$

36,586,971

 

Vested and exercisable, June 30, 2011

 

610,353

 

$

13.54

 

$

36,586,971

 

 

As of June 30, 2011, there was no unrecognized compensation expense related to stock option awards.

 

Director Shares

 

During the six months ended June 30, 2011, and 2010, the Company issued 21,568 and 24,258 shares, respectively, of the Company’s common stock from treasury to the Company’s non-employee directors.  The shares were issued pursuant to the Company’s Equity Incentive Compensation Plan.  The Company recorded $1.0 million and $690,000 of compensation expense for the three-month periods ended June 30, 2011, and 2010, respectively, and $1.0 million and $715,000 for the six-month periods ended June 30, 2011, and 2010, respectively.

 

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Table of Contents

 

Employee Stock Purchase Plan

 

Under the Company’s Employee Stock Purchase Plan (the “ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation.  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.   Shares issued under the ESPP, on or after July 1, 2011, have no restriction period.  The ESPP is intended to qualify under Section 423 of the Internal Revenue Code.  The Company has set aside 2,000,000 shares of its common stock to be available for issuance under the ESPP, of which 1,392,954 shares are available for issuance as of June 30, 2011.  There were 22,373 and 27,456 shares issued under the ESPP during the first half of 2011 and 2010, respectively, with a six month restriction period.  The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

 

Net Profits Plan

 

Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during a year were designated within a specific pool.  Key employees recommended by senior management and designated as participants by the Compensation Committee of the Company’s Board of Directors (“Board”) and employed by the Company on the last day of that year became entitled to payments under the Net Profits Plan after the Company had received net cash flows returning 100 percent of all costs associated with that pool.  Thereafter, ten percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually.  The portion of net cash flows from a pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the ten percent level.  In December 2007, the Board discontinued the creation of new pools under the Net Profits Plan.  As a result, the 2007 Net Profits Plan pool was the last pool established by the Company.

 

Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below:

 

 

 

For the Three Months
Ended June 30,

 

For the Six Months
Ended June 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(in thousands)

 

General and administrative expense

 

$

5,261

 

$

5,381

 

$

10,591

 

$

12,315

 

Exploration expense

 

585

 

667

 

1,062

 

1,258

 

Total

 

$

5,846

 

$

6,048

 

$

11,653

 

$

13,573

 

 

Additionally, the Company accrued or made cash payments under the Net Profits Plan of $2.0 million and $1.9 million for the three months ended June 30, 2011, and 2010, respectively, and $6.3 million and $20.1 million for the six months ended June 30, 2011, and 2010, respectively, as a result of divestiture proceeds.  The cash payments are accounted for as a reduction of the gain 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 did allocate 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 benefit would predominately be allocated to general and administrative expense.  The amount that would be allocated to exploration expense is minimal in comparison.  As time progresses, less of the distributions relate to prospective exploration efforts as more of the distributions are made to employees that have terminated employment and do not provide ongoing exploration support to the Company.

 

Note 9 - 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”).

 

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Components of Net Periodic Benefit Cost for Both 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,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(in thousands)

 

Service cost

 

$

1,052

 

$

848

 

$

1,900

 

$

1,696

 

Interest cost

 

312

 

280

 

592

 

560

 

Expected return on plan assets

 

(281

)

(159

)

(440

)

(318

)

Amortization of net actuarial loss

 

111

 

91

 

202

 

182

 

Net periodic benefit cost

 

$

1,194

 

$

1,060

 

$

2,254

 

$

2,120

 

 

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 ten percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.

 

Contributions

 

The Company is currently required to contribute $6.3 million to its Qualified Pension Plan.  The Company has made $3.6 million in 2011 contributions as of June 30, 2011.

 

Note 10 - Derivative Financial Instruments

 

To mitigate a portion of the exposure to potentially adverse market changes in oil, natural gas, and NGL prices and the associated impact on cash flows, the Company has entered into various derivative commodity contracts.  The Company’s derivative contracts in place include swap and collar arrangements for oil, natural gas, and NGLs.  As of June 30, 2011, and through the filing date of this report, the Company has commodity derivative contracts in place through the first quarter of 2014 for a total of approximately 8 MMBbls of anticipated crude oil production, 45 million MMBtu of anticipated natural gas production, and 1 MMBbls of anticipated NGL production.

 

The Company’s oil, natural gas, and NGL derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities.  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 pertinent 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, natural gas, and NGL derivative markets are highly active.  The fair value of oil, natural gas, and NGL commodity derivative contracts was a net liability of $68.7 million and $52.3 million at June 30, 2011, and December 31, 2010, respectively.

 

Discontinuance of Cash Flow Hedge Accounting

 

Prior to January 1, 2011, the Company designated its commodity derivative contracts as cash flow hedges, whose 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.

 

At December 31, 2010, accumulated other comprehensive loss (“AOCL”) included $18.6 million ($11.8 million, net of income tax) of unrealized losses, representing the change in fair value of the Company’s open commodity derivative contracts designated as cash flow hedges as of that balance sheet date, less any ineffectiveness recognized.  As a result of discontinuing hedge accounting on January 1, 2011, such fair values at December 31, 2010 were frozen in AOCL as of the de-designation date and reclassified into earnings as the original derivative transactions settle.  During the six months ended June 30, 2011, $7.7 million ($4.9 million, net of income tax) of derivative losses relating to de-designated commodity hedges were reclassified from AOCL into earnings.  As of June 30, 2011, AOCL included $10.9 million ($6.9 million, net of income tax) of unrealized losses on commodity

 

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derivative contracts that had been previously designated as cash flow hedges.  The Company expects to reclassify into earnings from AOCL after-tax net losses of $6.9 million related to de-designated commodity derivative contracts during the next twelve months.

 

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

 

 

 

As of June 30, 2011

 

 

 

Derivative Assets

 

Derivative Liabilities

 

 

 

Balance Sheet
Classification

 

Fair Value

 

Balance Sheet
Classification

 

Fair Value

 

 

 

(in thousands)

 

Commodity Contracts

 

Current Assets

 

$

28,985

 

Current Liabilities

 

$

(70,100

)

Commodity Contracts

 

Noncurrent Assets

 

10,624

 

Noncurrent Liabilities

 

(38,233

)

Derivatives not designated as hedging instruments

 

 

 

$

39,609

 

 

 

$

(108,333

)

 

 

 

As of December 31, 2010

 

 

 

Derivative Assets

 

Derivative Liabilities

 

 

 

Balance Sheet
Classification

 

Fair Value

 

Balance Sheet
Classification

 

Fair Value

 

 

 

(in thousands)

 

Commodity Contracts

 

Current Assets

 

$

43,491

 

Current Liabilities

 

$

(82,044

)

Commodity Contracts

 

Noncurrent Assets

 

18,841

 

Noncurrent Liabilities

 

(32,557

)

Derivatives designated as hedging instruments

 

 

 

$

62,332

 

 

 

$

(114,601

)

 

The following table summarizes the unrealized and realized gain and loss from derivative cash settlements and changes in fair value of derivative contracts as presented in the accompanying statements of operations.

 

 

 

For the Three

 

For the Six

 

 

 

Months Ended

 

Months Ended

 

 

 

June 30, 2011

 

June 30, 2011

 

 

 

(in thousands)

 

Cash settlement (gain) and loss:

 

 

 

 

 

Oil contracts

 

$

10,633

 

$

17,363

 

Natural gas contracts

 

(590

)

(2,317

)

NGL contracts

 

3,933

 

5,347

 

Total cash settlement loss

 

$

13,976

 

$

20,393

 

 

 

 

 

 

 

Unrealized (gain) loss on changes in fair value:

 

 

 

 

 

Oil contracts

 

$

(51,216

)

$

16,151

 

Natural gas contracts

 

(6,681

)

(2,421

)

NGL contracts

 

45

 

10,430

 

Total net unrealized (gain) loss on change in fair value

 

$

(57,852

)

$

24,160

 

Total unrealized and realized derivative (gain) loss

 

$

(43,876

)

$

44,553

 

 

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

 

 

 

 

 

Location on
Consolidated
Statement of

 

For the Three Months
Ended June 30,

 

For the Six Months
Ended June 30,

 

 

 

Derivatives

 

Operations

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

(in thousands)

 

Amount of (gain) loss reclassified from AOCIL to realized hedge gain (loss)

 

Commodity Contracts

 

Realized hedge gain (loss)

 

$

3,951

 

$

1,163

 

$

4,878

 

$

(782

)

 

The realized net hedge loss for the three-month and six-month periods ended June 30, 2011, is comprised of realized cash settlements on commodity derivative contracts that were previously designated as cash flow hedges, whereas the realized net hedge gain (loss) for the three-month and six-month periods ended June 30, 2010, is comprised of realized cash settlements on all commodity derivative contracts.  Realized hedge gains or losses from the settlement of oil, natural gas, and NGL derivatives previously designated as cash flow hedges are reported in the total operating revenues and other income section of the accompanying statements of operations.  The Company realized a net hedge loss of $6.3 million and a net hedge gain of $9.3 million from its oil, natural gas, and NGL derivative contracts for the three months ended June 30, 2011, and 2010, respectively, and a net loss of $7.7 million and a net gain of $11.9 million from its oil, natural gas, and NGL derivative contracts for the six months ended June 30, 2011, and 2010, respectively.

 

As noted above, effective 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, and as such no new gains or losses are deferred in AOCIL at June 30, 2011.  The following table details the effect of derivative instruments on AOCIL and the balance sheets (net of income tax):

 

 

 

Derivatives

 

Location on
Consolidated
Balance
Sheets

 

For the Six Months
Ended June 30, 2010

 

For the Year Ended
December 31, 2010

 

 

 

 

 

 

 

(in thousands)

 

Amount of gain on derivatives recognized in AOCIL during the period (effective portion)

 

Commodity Contracts

 

AOCIL

 

$

53,765

 

$

16,811

 

 

The Company has no derivatives designated as cash flow hedges at June 30, 2011.  The following table details the ineffective portion of derivative instruments classified as cash flow hedges on the accompanying statements of operations for the three-month and six-month periods ended June 30, 2010.

 

 

 

Location on
Consolidated

 

Gain Recognized in
Earnings
(Ineffective Portion)

 

Derivatives Qualifying as
Cash Flow Hedges

 

Statements of
Operations

 

For the Three Months
Ended June 30, 2010

 

For the Six Months
Ended June 30, 2010

 

 

 

 

 

(in thousands)

 

Commodity contracts

 

Unrealized and realized derivative (gain) loss

 

$

(2,087

)

$

(9,822

)

 

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Table of Contents

 

Credit Related Contingent Features

 

As of June 30, 2011, and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility bank syndicate.  The Company’s credit facility is secured by liens on substantially all of the Company’s proved oil and gas assets; therefore such counterparties do not currently require the Company to post collateral in instances where the Company is in a liability position under its derivative instruments.  No collateral was posted as of June 30, 2011, or through the filing date of this report.

 

Convertible Note Derivative Instruments

 

The contingent interest provision of the 3.50% Senior Convertible Notes is an embedded derivative instrument.  As of June 30, 2011, and December 31, 2010, the fair value of this derivative was determined to be immaterial.

 

Note 11 - Fair Value Measurements

 

The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value.  That 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 and 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 financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of June 30, 2011:

 

 

 

 

Level 1

 

Level 2

 

Level 3

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

Derivatives

 

$

 

$

39,609

 

$

 

Liabilities:

 

 

 

 

 

 

 

Derivatives

 

$

 

$

108,333

 

$

 

Net Profits Plan

 

$

 

$

 

$

133,419

 

 

The following is a listing of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2010:

 

 

 

Level 1

 

Level 2

 

Level 3

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

Derivatives

 

$

 

$

62,332

 

$

 

Liabilities:

 

 

 

 

 

 

 

Derivatives

 

$

 

$

114,601

 

$

 

Net Profits Plan

 

$

 

$

 

$

135,850

 

 

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.  There were no nonfinancial assets or liabilities measured at fair value on a nonrecurring basis at June 30, 2011, or December 31, 2010.

 

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Table of Contents

 

Derivatives

 

The Company uses Level 2 inputs to measure the fair value of oil, natural 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.

 

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 SM Energy’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.

 

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 and gas 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 vice versa.

 

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, and the discount rates used in the calculations.  The Company continually evaluates the assumptions used in this calculation in order to consider the current market environment for oil and gas prices, costs, discount rates, and overall market conditions.  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, natural gas, and NGL commodity markets.

 

If the commodity prices used in the calculation changed by five percent, the liability recorded at June 30, 2011, would differ by approximately $10 million.  A one percentage point increase in the discount rate would decrease the liability by approximately $6 million whereas a one percentage point decrease in the discount rate would increase the liability by approximately $7 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.

 

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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,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(in thousands)

 

Beginning balance

 

$

147,403

 

$

143,019

 

$

135,850

 

$

170,291

 

Net increase (decrease) in liability (a)

 

(6,092

)

1,318

 

18,193

 

(218

)

Net settlements (a)(b)(c)

 

(7,892

)

(7,917

)

(20,624

)

(33,653

)

Transfers in (out) of Level 3

 

 

 

 

 

Ending balance

 

$

133,419

 

$

136,420

 

$

133,419

 

$

136,420

 

 


(a)          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.

(b)         Settlements represent cash payments made or accrued under the Net Profits Plan.  Settlements made under the Net Profits Plan of $2.0 million and $1.9 million for the three months ended June 30, 2011, and 2010, respectively, and $6.3 million and $20.1 million for the six months ended June 30, 2011, and 2010, respectively, resulted from divestiture proceeds.

(c)          During the first quarter of 2011, the Company made the decision to cash out several Net Profits Plan pools associated with the acquisition of Nance Petroleum Corporation in 1999, through a $2.6 million direct payment.  As a result, the Company reduced its Net Profits Plan liability by that amount.  There is no impact on the accompanying statements of operations for the three-month or six-month periods ended June 30, 2011, related to these settlements.

 

3.50% Senior Convertible Notes

 

Based on the secondary market trading price of the 3.50% Senior Convertible Notes, the estimated fair value of the notes was approximately $406 million and $351 million as of June 30, 2011, and December 31, 2010, respectively.  The fair value of the embedded contingent interest derivative on the 3.50% Senior Convertible Notes was zero as of June 30, 2011, and December 31, 2010.

 

6.625% Senior Notes

 

Based on the secondary market trading price of the 6.625% Senior Notes, the estimated fair value of the notes was approximately $357 million as of June 30, 2011.

 

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 exceeds the sum of the undiscounted cash flows.  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 a significant management estimate based on the best information available and estimated to be 12 percent for the six months ended June 30, 2011.  Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk.  The price forecast is based on New York Mercantile Exchange (“NYMEX”) strip pricing, adjusted for basis differentials, for the first five years.  Future operating costs are also adjusted as deemed appropriate for these estimates.

 

There were no proved oil and gas properties measured at fair value within the accompanying balance sheets at June 30, 2011, or December 31, 2010.

 

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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 inventory measured at fair value within the accompanying balance sheets at June 30, 2011, or December 31, 2010.

 

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 to the undiscounted expected abandonment cash flows.  The credit-adjusted risk-free rate takes into account the Company’s credit risk, the time value of money, and the current economic state.  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 within the accompanying balance sheets at June 30, 2011, or December 31, 2010.

 

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

 

Note 12 - Acquisition and Development Agreement

 

In June 2011, the Company entered into an Acquisition and Development Agreement (the “Agreement”) with Mitsui  E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd.  Pursuant to the Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick and Webb Counties, Texas.  The transaction also provides for the conveyance of one-half of the Company’s ownership in related gathering assets for reimbursement of 50 percent of costs incurred on those assets at the time of closing.  The effective date of the transfer of the assets will be March 1, 2011.  The transaction is expected to close in the third quarter of 2011, subject to the satisfaction of closing conditions, including the receipt of certain consents and the resolution of title and environmental defects exceeding specified levels.  In return for the assets transferred, Mitsui has agreed to pay, or carry, 90 percent of certain drilling and completion costs on behalf of the Company and expenses for the affected acreage following the closing of the transaction until Mitsui has expended an aggregate $680.0 million on behalf of the Company, which is estimated to take three to four years based on the operator’s announced drilling plans.  Mitsui will also reimburse the Company for its share of capital expenditures and other costs, net of revenues, related to the period from March 1, 2011, until closing.  The Company will apply these reimbursed costs to the remaining ten percent of the Company’s drilling and completion costs for the affected acreage.

 

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Table of Contents

 

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, exploitation, development, and production of crude oil, natural 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, Haynesville shale, and Woodford shale resource plays.   We have built a portfolio of onshore properties in the contiguous United States with reserves, development drilling opportunities, and unconventional resource prospects, typically through the early entrance into existing and emerging resource plays.  We believe this approach allows for stable and predictable production and reserves growth. Furthermore, by entering these plays early, we believe that we can capture larger resource potential at lower costs.

 

Our business strategy is to increase net asset value through attractive oil and gas investment activity, while maintaining a conservative capital structure and optimizing capital expenditures.  We focus our efforts on the exploration for and development of onshore, lower-risk resource plays in North America.  We believe our inventory of resource plays is well suited for growing reserves and production due to its predictable geology and lower-risk profile.  Furthermore, our assets produce significant volumes of oil and NGLs that limit our exposure to the current lower natural gas price environment.  Our strategy is based on the following:

 

·                  leveraging our core competencies in replicating resource play success in the drilling, completion, and development of oil, natural gas, and NGL reserves;

 

·                  focusing on resource plays with low-risk geology and high liquids content;

 

·                  exploiting our legacy assets and optimizing our asset base;

 

·                  selectively acquiring leasehold positions in new and emerging resource plays; and

 

·                  maintaining a strong balance sheet while funding the growth of our business.

 

In the second quarter of 2011 we had the following financial and operational results:

 

·                  Our average daily production for the three months ended June 30, 2011, was 20.4 MBbls of oil, 262.7 MMcf of gas, and 8.7 MBbls of NGLs, for a record average equivalent production rate of 436.9 MMCFE per day, compared with 276.4 MMCFE per day for the same period in 2010.  Please see additional discussion below under the caption Production Results.

 

·                  We recorded net income for the three months ended June 30, 2011, of $124.5 million or $1.86 per diluted share compared to net income for the three months ended June 30, 2010, of $18.1 million or $0.28 per diluted share.

 

·                  Costs incurred for oil and gas producing activities for the three months ended June 30, 2011, were $352.2 million, compared with $189.3 million for the same period in 2010.  Please see additional discussion below under the caption Cost Incurred.

 

Oil, Gas, and NGL Prices

 

Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, natural gas, and NGL production, which can fluctuate dramatically.  Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2011, and 2010 and Comparison of Financial Results and Trends Between the Six Months Ended June 30, 2011, and 2010 for the realized price tables for the respective periods.   Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head.  As a result, we historically reported realized prices for our natural gas production for periods through December 31, 2010, that were higher than industry benchmarks due to the price uplift associated with incremental value contained in the higher BTU content of our gas production stream.  Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product.  Projected rapid production growth from our rich gas assets with plant product sales contracts necessitated a change in our production volume reporting.  Prior period production volumes, revenues, and prices have not been reclassified to conform to the

 

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current presentation given the immateriality of the NGL volumes produced in prior periods.  We sell the majority of our natural gas under contracts that use first-of-the-month index pricing, which means that gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced.  For assets where high BTU gas is sold at the wellhead, we also receive additional value for the higher energy content contained in the gas stream.  Our NGL production is generally sold using contracts that pay us the monthly average of the posted Oil Price Information Service Mont Belvieu daily settlement prices, adjusting for processing, transportation, and location differentials.  Our crude oil and condensate are sold using contracts that pay us either the average of the NYMEX 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.

 

The following table is a summary of commodity price data for the second quarters of 2011 and 2010 and the first quarter of 2011:

 

 

 

For the Three Months Ended

 

 

 

June 30, 2011

 

March 31, 2011

 

June 30, 2010

 

Crude Oil (per Bbl):

 

 

 

 

 

 

 

Average NYMEX price

 

$

102.28

 

$

94.46

 

$

77.88

 

Realized price

 

$

97.51

 

$

85.79

 

$

70.92

 

 

 

 

 

 

 

 

 

Natural Gas (per Mcf):

 

 

 

 

 

 

 

Average NYMEX price

 

$

4.36

 

$

4.18

 

$

4.33

 

Realized price

 

$

4.63

 

$

4.35

 

$

4.54

 

 

 

 

 

 

 

 

 

Natural Gas Liquids (per Bbl):

 

 

 

 

 

 

 

Average OPIS price

 

$

61.62

 

$

56.28

 

$

 

Realized price

 

$

54.02

 

$

46.65

 

$

 

 


Note:  Prior year NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the volumes in prior periods.  Please refer to additional discussion above.

 

We expect future prices for oil, gas, and NGLs to be volatile.  In addition to supply and demand fundamentals, the relative strength of the U.S. dollar will likely continue to impact crude oil prices.  Historically, NGL prices have trended and correlated with the price for crude oil.  The supply of NGLs is expected to grow in the near term as a result of a number of industry participants targeting projects that produce these products, which could increase supplies and negatively impact future pricing.   Natural gas prices are facing downward pressure as a result of excess supply resulting from high levels of drilling activity across the country.  The 12-month strip prices for NYMEX WTI crude oil, NYMEX Henry Hub natural gas, and OPIS NGLs as of June 30, 2011, were $98.03 per Bbl, $4.65 per MMBTU, and $57.86 per Bbl, respectively.  Comparable prices as of July 26, 2011, were $101.65 per Bbl, $4.57 per MMBTU, and $ 61.12 per Bbl, respectively.

 

While changes in quoted NYMEX oil and natural gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the price we receive is 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 Activities

 

We use financial derivative instruments as part of our financial risk management program.  We have a Board-approved 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 the derivative contracts we have in place, we believe we have established a base cash flow stream for our future operations and partially reduced our exposure to volatility in commodity prices.  Our use of collars for a portion of the derivatives allows us to participate in upward movements in oil, gas, and NGL prices while also setting a price floor for a portion of our production.  Please see Note 10 — Derivative Financial Instruments of Part I, Item 1 of this report for additional information regarding our oil, gas, and NGL derivatives, and see the caption, Summary of Oil, Gas, and NGL Derivative Contracts in Place, later in this section.

 

As of January 1, 2011, we elected to de-designate all commodity derivative contracts that had previously been designated as cash flow hedges as of December 31, 2010, and to discontinue hedge accounting prospectively.  Accordingly, beginning January 1, 2011, all of our derivative contracts are stated at fair value each quarter with changes in fair value resulting in gains and losses, which are recognized immediately in earnings.  For the three months ended June 30, 2011, realized cash settlements from our commodity risk management program for oil, natural gas, and NGLs were ($24.3) million, $9.1 million, and ($5.2) million,

 

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respectively.  For the six months ended June 30, 2011, realized cash settlements from our commodity risk management program for oil, natural gas, and NGLs were ($43.4) million, $24.0 million, and ($8.7) million, respectively.

 

The following table is a reconciliation from our realized prices to our adjusted price for the commodities indicated, including the effects of derivative cash settlements for the second quarters of 2011 and 2010 and the first quarter of 2011:

 

 

 

For the Three Months Ended

 

 

 

June 30,

 

March 31,

 

June 30,

 

 

 

2011

 

2011

 

2010

 

Crude Oil (per Bbl):

 

 

 

 

 

 

 

Realized price

 

$

97.51

 

$

85.79

 

$

70.92

 

Less the effects of derivative cash settlements

 

(13.11

)

(10.72

)

(5.75

)

Adjusted price, including the effects of derivative cash settlements

 

$

84.40

 

$

75.07

 

$

65.17

 

 

 

 

 

 

 

 

 

Natural Gas (per Mcf):

 

 

 

 

 

 

 

Realized price

 

$

4.63

 

$

4.35

 

$

4.54

 

Plus the effects of derivative cash settlements

 

0.38

 

0.69

 

1.05

 

Adjusted price, including the effects of derivative cash settlements

 

$

5.01

 

$

5.04

 

$

5.59

 

 

 

 

 

 

 

 

 

Natural Gas Liquids (per Bbl):

 

 

 

 

 

 

 

Realized price

 

$

54.02

 

$

46.65

 

$

 

Less the effects of derivative cash settlements

 

(6.53

)

(5.76

)

 

Adjusted price, including the effects of derivative cash settlements

 

$

47.49

 

$

40.89

 

$

 

 


Note:  Prior year NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the volumes in prior periods.  Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices.

 

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law.  This financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed through an exchange or centrally cleared.  The Dodd-Frank Act requires the Commodities Futures Trading Commission (the “CFTC”), the SEC, and other regulators to establish rules and regulations to implement the new legislation.  The CFTC has proposed new rules governing margin requirements for uncleared swaps entered into by non-bank swap entities, and U.S. banking regulators have proposed new rules regarding margin requirements for uncleared swaps entered into by bank swap entities.  The ultimate effect of the proposed new rules and any additional regulations on our business 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 2011 Highlights

 

Operational activities.  We operated an average of 11 drilling rigs company-wide during the second quarter of 2011.  The focus of our operated drilling activity this year has been on oil and NGL-rich gas programs and selected natural gas projects of potential strategic importance to us.  We have also participated in higher levels of outside-operated activity in oil and NGL-rich gas plays.

 

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We had four drilling rigs running in our operated Eagle Ford shale program in South Texas at the end of the second quarter 2011, up from three at the end of the first quarter.  We focused our drilling in areas with higher BTU gas content and higher condensate yields.  We continue to test different ways to complete these wells with the objective of optimizing future development potential.  During the second quarter, we entered into two separate transactions to divest or sell down portions of our Eagle Ford shale position in order to lock in returns and provide funds to further develop the program.  The first transaction involved all of our operated acreage in LaSalle County, Texas, along with a small adjoining block of acreage in Dimmit County, Texas.  This transaction closed on August 2, 2011, before certain adjustments, at which time we received $227.4 million in cash proceeds.  As part of this transaction, we also assigned a small portion of our committed takeaway capacity to serve these assets.  The second transaction involves an agreement for the transfer of a 12.5 percent working interest in our non-operated acreage in exchange for a 90 percent carry of our drilling and completion costs in the same acreage for an amount not to exceed $680.0 million.  This agreement also provides for the divestiture of one-half of our interest in the gathering assets that service the non-operated program in exchange for reimbursement of 50 percent of our costs on those assets.  This transaction is expected to close in the third quarter of 2011, subject to the satisfaction of closing conditions, including the receipt of certain consents and the resolution of title and environmental defects exceeding specified levels.  After completing these two transactions, we will have approximately 150,000 operated net acres and 46,000 non-operated net acres in the Eagle Ford shale play.  With respect to infrastructure, we entered into a transaction during the quarter to sell gathering assets in the Eagle Ford shale play for $25.4 million and concurrently entered into a gas gathering agreement where we dedicated all production from certain portions of our operated Eagle Ford assets to be gathered, compressed, and treated by the same counterparty on a fee basis.  During the quarter, we also entered into firm transportation agreements that will increase our pipeline capacity to approximately 460 MMCF per day of gross wet gas by the second half of 2014.  Please refer to Note 7 - Commitments and Contingencies in Part I, Item 1 of this report for additional discussion concerning these agreements.  On our outside-operated Eagle Ford acreage, the operator continued to increase activity throughout the first half of 2011.  During the second quarter, our partner operated ten drilling rigs and it is our belief the activity will increase to 12 rigs by the end of 2011.

 

We operated two drilling rigs in the Williston Basin throughout the second quarter of 2011, both of which focused on Bakken and Three Forks drilling in our Raven and Gooseneck prospects in North Dakota.  Our drilling results in these prospects have continued to meet or exceed our expectations throughout the first half of 2011.  Consistent with other operators in the area, flooding and other weather-related issues limited our access to certain assets during the quarter.  While drilling and completion activity was disrupted to some extent, our production operations were not significantly impacted.  Elsewhere in the Rocky Mountain region, we continued to test the Niobrara formation in southern Wyoming with one drilling rig.  We drilled an additional three test wells in southeastern Wyoming in the first half of 2011 in the South Silo field where we have approximately 26,000 net acres.  In addition, we have been adding acreage with Niobrara potential in the Powder River Basin and we now have 63,000 acres in the basin.

 

In our operated horizontal Haynesville shale program in our ArkLaTex region, we operated two rigs in San Augustine County, Texas during the second quarter of 2011.  Our leasehold acreage of approximately 33,000 net acres is prospective for both the Haynesville shale and the Bossier shale, and recent Haynesville well results continue to be highly encouraging.  Our focus will be on holding this acreage through production to ensure we are in a position to benefit from any natural gas price increase in the future.

 

In our Mid-Continent region, we operated one to two rigs in our operated Granite Wash program in the Texas Panhandle and western Oklahoma during the second quarter of 2011 to test and delineate our acreage in the play.  We have approximately 34,000 net acres in the Granite Wash, which are held by production.

 

Our Permian region operated a one rig program during the second quarter of 2011, splitting its focus on the testing of Wolfberry down spacing and drilling Mississippian targets as part of our exploration effort.

 

Production Results.  The table below provides the regional breakdown of our second quarter 2011 production:

 

 

 

Mid-
Continent

 

ArkLaTex

 

South Texas
& Gulf Coast

 

Permian

 

Rocky
Mountain

 

Total (1)

 

Second Quarter 2011 Production:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

 

109.6

 

17.8

 

605.7

 

320.6

 

799.1

 

1,852.8

 

Gas (MMcf)

 

7,682.7

 

7,745.0

 

6,668.8

 

924.1

 

885.5

 

23,906.1

 

NGLs (MBbl)

 

17.3

 

18.9

 

741.5

 

4.3

 

7.7

 

789.6

 

Equivalent (MMCFE)

 

8,444.1

 

7,964.9

 

14,752.0

 

2,873.4

 

5,726.1

 

39,760.4

 

Avg. Daily Equivalents (MMCFE)

 

92.8

 

87.5

 

162.1

 

31.6

 

62.9

 

436.9

 

Relative percentage

 

21

%

20

%

37

%

7

%

15

%

100

%

 


(1) Totals may not add due to rounding.

 

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For the second quarter of 2011, our production was led by our South Texas & Gulf Coast region due to the ongoing drilling activities in our Eagle Ford shale program.  Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2011, and 2010, for additional discussion on production.

 

Costs Incurred. The following table sets forth the costs incurred for our oil and gas activities for the second quarter of 2011.

 

 

 

For the Three Months

 

 

 

Ended June 30, 2011

 

 

 

(in thousands)

 

 

 

 

 

Development costs

 

$

263,937

 

Facility costs

 

28,927

 

Exploration costs

 

50,198

 

Acquisitions of unproved properties

 

9,098

 

Total, including asset retirement obligations

 

$

352,160

 

 

Our capital and exploration activities reflect higher cash flows provided by operating activities, divestiture proceeds, and proceeds from the issuance of our 6.625% Senior Notes.

 

Credit Facility. We executed a $2.5 billion Fourth Amended and Restated Credit Agreement on May 27, 2011.  The initial borrowing base for the facility has been set at $1.3 billion and the initial commitment amount is $1.0 billion.  Please refer to Overview of Liquidity and Capital Resources below for additional discussion.

 

Acquisition and Development Agreement. In June 2011, we entered into an Acquisition and Development Agreement for the transfer of a 12.5 percent working interest in certain oil and gas assets, representing approximately 39,000 net acres, in Dimmit, LaSalle, Maverick and Webb Counties, Texas.  The agreement also provides for the conveyance of one-half of our ownership in certain related gathering assets for reimbursement of 50 percent of costs incurred on those assets.  The transaction is expected to close in the third quarter of 2011, subject to the satisfaction of closing conditions, including the receipt of certain consents and the resolution of title and environmental defects exceeding specified levels.  Under the terms of the agreement, the counterparty has agreed to pay, or carry, 90 percent of our drilling and completion costs on the subject acreage following the closing of the transaction until the counterparty has expended an aggregate $680.0 million on our behalf, which is estimated to take three to four years.  The counterparty will also reimburse us for its share of capital expenditures and other costs, net of revenues, related to the period from March 1, 2011, until closing.  We will apply these reimbursed costs to the remaining ten percent of our drilling and completion costs for the affected acreage.

 

Mid-Continent Divestiture.  In June 2011, we completed the divestiture of certain non-strategic Constitution Field assets located in our Mid-Continent region that were classified as assets held for sale at March 31, 2011.   Total cash received, before marketing costs and Net Profits Plan payments, was $35.7 million.  The final sale price is subject to post-closing adjustments and is expected to be finalized during the second half of 2011.  The estimated gain on this divestiture was approximately $28.5 million, and may be impacted by the post-closing adjustments mentioned above.

 

Eagle Ford Divestiture. During the quarter we entered into an agreement to divest certain operated Eagle Ford shale assets located in our South Texas & Gulf Coast region.  This position is comprised of our entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of our operated acreage in Dimmit County, Texas.  These assets were classified as assets held for sale at June 30, 2011.  Subsequent to quarter end, we closed this transaction.  Total cash received, before marketing costs, was $227.4 million.  The final sales price is subject to post-closing adjustments and is expected to be finalized in the fourth quarter of 2011.  The estimated gain on this divestiture is approximately $196.1 million, and may be impacted by the post-closing adjustments mentioned above.

 

Marcellus Divestiture. Subsequent to June 30, 2011, we entered into an agreement to divest all of our Marcellus shale assets located in Pennsylvania that were classified as assets held for sale at June 30, 2011, for $80.0 million in cash, subject to normal closing and post-closing adjustments.  The agreement has an effective date of April 1, 2011, and is anticipated to close in the third quarter of 2011.  The closing of this transaction is subject to the satisfaction of certain closing conditions, including the resolution of title and environmental defects exceeding specified levels.

 

Equity Compensation. Subsequent to June 30, 2011, we granted 234,308 PSUs and 78,165 RSUs pursuant to our long term incentive program.  Please refer to Note 8 - Compensation Plans within Part I, Item 1 of this report for additional discussion.

 

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First Six Months 2011 Highlights

 

Production Results. The table below provides the regional breakdown of our first half of 2011 production.

 

 

 

Mid-