Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K/A

(Amendment No. #1)

 

x                Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the fiscal year ended December 31, 2009

 

Commission file number 1-9735

 

 

BERRY PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

 

DELAWARE

 

77-0079387

(State of incorporation or organization)

 

(I.R.S. Employer Identification Number)

 

1999 Broadway

Suite 3700

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

 

Registrant’s telephone number, including area code:

(303) 999- 4400

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Class A Common Stock, $0.01 par value

 

New York Stock Exchange

(including associated stock purchase rights)

 

 

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  YES x  NO o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  YES o  NO x

 

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 o NO o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  YES o  NO x

 

As of June 30, 2009, the aggregate market value of the voting and non-voting common stock held by non-affiliates was $684,959,425. As of February 1, 2010, the registrant had 50,952,786 shares of Class A Common Stock outstanding. The registrant also had 1,797,784 shares of Class B Stock outstanding on February 1, 2010 all of which are held by an affiliate of the registrant.

 

 

 



Table of Contents

 

BERRY PETROLEUM COMPANY

TABLE OF CONTENTS

 

 

 

 

Page

 

Explanatory Note

 

3

 

 

 

 

PART II

 

 

 

 

Item 8.

Financial Statements and Supplementary Data

 

4

 

Balance Sheets

 

6

 

Statements of Income

 

7

 

Statements of Comprehensive Income (Loss)

 

7

 

Statements of Shareholders’ Equity

 

8

 

Statements of Cash Flows

 

9

 

 

 

 

PART IV

 

 

 

 

Item 15.

Exhibits, Financial Statement Schedules

 

38

 

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EXPLANATORY NOTE

 

Berry Petroleum Company (the “Registrant”) is filing this Amendment No. 1 (this “Amendment”) to its Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (the “Form 10-K”).  The sole purpose of this Amendment No. 1 is to amend Item 8 of the Form 10-K to correct the presentation error in the Statement of Comprehensive Income (Loss) for the year ended December 31, 2009 and the related disclosures in Note 3 to the audited financial statements.  Comprehensive income (loss) in the Form 10-K reflected a net gain from the change in fair value of derivatives of $174.1 million, which should have been reflected as a net loss. The unrealized gains (losses) on derivatives, net of income tax, has been revised from a gain of $205.3 million to a loss of $129.3 million.  The reclassification of realized (gains) losses on derivatives included in net income, net of taxes, has been revised from a gain of $31.2 million to a gain of $44.8 million. Accordingly, this Amendment reflects comprehensive loss of approximately $120.0 million, rather than comprehensive income of $228.1 million reflected in the Form 10-K. These corrections were also included in the Company’s Form 10-Q for the period ended June 30, 2010 filed August 9, 2010.  Except to correct Item 8 of the Form 10-K as described above, no other items or disclosures in the Form 10-K have been amended, and all other information included in the Form 10-K remains unchanged.  This Amendment does not reflect events occurring after the filing of the Form 10-K or modify, amend or update any items or disclosures therein in any way other than as required to reflect the changes identified above.

 

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Item 8. Financial Statements and Supplementary Data

 

 

 

Page

Report of Independent Registered Public Accounting Firm

 

5

Balance Sheets at December 31, 2009 and 2008

 

6

Statements of Income for the Years Ended December 31, 2009, 2008 and 2007

 

7

Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2009, 2008 and 2007

 

7

Statements of Shareholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007

 

8

Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007

 

9

Notes to the Financial Statements

 

10

Supplemental Information About Oil & Gas Producing Activities (Unaudited)

 

34

 

Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.

 

4



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Shareholders of Berry Petroleum Company:

 

In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Berry Petroleum Company at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

As discussed in Note 2 to the financial statements, the Company changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008. As discussed in Note 9 to the financial statements, the Company changed the manner in which it accounts for earnings per share in 2009.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 25, 2010, except for the effects of the matter discussed in Note 17, as to which the date is August 11, 2010

 

5


 


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BERRY PETROLEUM COMPANY

Balance Sheets

December 31, 2009 and 2008

(In Thousands, Except Share Information)

 

 

 

2009

 

2008

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

5,311

 

$

240

 

Short-term investments

 

66

 

66

 

Accounts receivable, net of allowance for doubtful accounts of $38,508 and $38,511, respectively

 

74,337

 

65,873

 

Deferred income taxes

 

5,623

 

 

Fair value of derivatives

 

11,527

 

111,886

 

Prepaid expenses and other

 

6,612

 

11,015

 

Total current assets

 

103,476

 

189,080

 

Oil and gas properties (successful efforts basis), buildings and equipment, net

 

2,106,385

 

2,254,425

 

Fair value of derivatives

 

735

 

79,696

 

Other assets

 

29,539

 

19,182

 

 

 

$

2,240,135

 

$

2,542,383

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

63,096

 

$

119,221

 

Revenue and royalties payable

 

25,878

 

34,416

 

Accrued liabilities

 

29,320

 

34,566

 

Line of credit

 

 

25,300

 

Income taxes payable

 

 

187

 

Fair value of derivatives

 

33,843

 

1,445

 

Deferred income taxes

 

 

45,490

 

Total current liabilities

 

152,137

 

260,625

 

Long-term liabilities:

 

 

 

 

 

Deferred income taxes

 

237,161

 

270,323

 

Senior secured revolving credit facility

 

372,000

 

931,800

 

8¼% Senior subordinated notes due 2016

 

200,000

 

200,000

 

10¼% Senior notes due 2014, net of unamortized discount of $13,456 and $0, respectively

 

436,544

 

 

Asset retirement obligation

 

43,487

 

41,967

 

Other long-term liabilities

 

19,711

 

5,921

 

Fair value of derivatives

 

75,836

 

4,203

 

 

 

1,384,739

 

1,454,214

 

Commitments and contingencies (Note 13)

 

 

 

 

 

Shareholders’ equity:

 

 

 

 

 

Preferred stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding

 

 

 

Capital stock, $0.01 par value:

 

 

 

 

 

Class A Common Stock, 100,000,000 shares authorized; 42,952,499 shares issued and outstanding (42,782,365 in 2008)

 

430

 

427

 

Class B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and outstanding (liquidation preference of $899)

 

18

 

18

 

Capital in excess of par value

 

89,068

 

79,653

 

Accumulated other comprehensive (loss) income

 

(60,372

)

113,697

 

Retained earnings

 

674,115

 

633,749

 

Total shareholders’ equity

 

703,259

 

827,544

 

 

 

$

2,240,135

 

$

2,542,383

 

 

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

 

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BERRY PETROLEUM COMPANY

Statements of Income

Years ended December 31, 2009, 2008 and 2007

(In Thousands, Except Per Share Data)

 

 

 

2009

 

2008

 

2007

 

REVENUES

 

 

 

 

 

 

 

Sales of oil and gas

 

$

506,691

 

$

649,248

 

$

433,208

 

Sales of electricity

 

36,065

 

63,525

 

55,619

 

Gas marketing

 

22,806

 

35,750

 

 

Gain (loss) on derivatives

 

6,514

 

(213

)

13

 

Gain (loss) on sale of assets

 

826

 

(1,297

)

54,173

 

Interest and other income, net

 

1,810

 

3,504

 

4,414

 

 

 

574,712

 

750,517

 

547,427

 

EXPENSES

 

 

 

 

 

 

 

Operating costs - oil and gas production

 

156,612

 

188,758

 

130,940

 

Operating costs - electricity generation

 

31,400

 

54,891

 

45,980

 

Production taxes

 

18,144

 

26,876

 

14,651

 

Depreciation, depletion & amortization - oil and gas production

 

139,919

 

125,595

 

82,861

 

Depreciation, depletion & amortization — electricity generation

 

3,681

 

2,812

 

3,568

 

Gas marketing

 

21,231

 

32,072

 

 

General and administrative

 

49,237

 

54,279

 

39,663

 

Interest

 

49,923

 

23,942

 

15,069

 

Extinguishment of debt

 

10,823

 

 

 

Dry hole, abandonment, impairment and exploration

 

5,425

 

10,543

 

8,351

 

Bad debt expense

 

 

38,665

 

 

 

 

486,395

 

558,433

 

341,083

 

Income before income taxes

 

88,317

 

192,084

 

206,344

 

Provision for income taxes

 

28,349

 

70,308

 

79,060

 

Income from continuing operations

 

59,968

 

121,776

 

127,284

 

(Loss) income from discontinued operations, net of tax

 

(5,938

)

11,753

 

2,644

 

 

 

 

 

 

 

 

 

Net income

 

$

54,030

 

$

133,529

 

$

129,928

 

 

 

 

 

 

 

 

 

Basic net income from continuing operations per share

 

1.31

 

2.70

 

2.85

 

Basic net (loss) income from discontinued operations per share

 

(0.13

)

0.26

 

0.06

 

Basic net income per share

 

$

1.18

 

$

2.96

 

$

2.91

 

 

 

 

 

 

 

 

 

Diluted net income from continuing operations per share

 

1.30

 

2.66

 

2.81

 

Diluted net (loss) income from discontinued operations per share

 

(0.13

)

0.26

 

0.06

 

Diluted net income per share

 

$

1.17

 

$

2.92

 

$

2.87

 

 

Statements of Comprehensive Income (Loss)

Years Ended December 31, 2009, 2008 and 2007

(In Thousands)

 

Net income

 

$

54,030

 

$

133,529

 

$

129,928

 

Unrealized gains (losses) on derivatives, net of income taxes of ($79,240), $96,546, and ($66,627), respectively

 

(129,287

)

157,522

 

(99,941

)

Reclassification of realized (gains) losses on derivatives included in net income, net of income taxes of ($27,447), $47,119 and ($524), respectively

 

(44,782

)

76,879

 

(786

)

Comprehensive income (loss)

 

$

(120,039

)

$

367,930

 

$

29,201

 

 

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

 

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BERRY PETROLEUM COMPANY

Statements of Shareholders’ Equity

Years Ended December 31, 2009, 2008 and 2007

(In Thousands, Except Per Share Data)

 

 

 

Class
A

 

Class
B

 

Capital in
Excess of Par
Value

 

Retained
Earnings

 

Accumulated
Other
Comprehensive
Income (Loss)

 

Shareholders’
Equity

 

Balances at January 1, 2007

 

$

421

 

$

18

 

$

50,166

 

$

397,072

 

$

(19,977

)

$

427,700

 

Stock-based compensation (484,451 shares)

 

4

 

 

12,930

 

 

 

12,934

 

Tax impact of stock option exercises

 

 

 

3,049

 

 

 

3,049

 

Deferred director fees - stock compensation

 

 

 

445

 

 

 

445

 

Cash dividends declared - $0.30 per share, including RSU dividend equivalents

 

 

 

 

(13,292

)

 

(13,292

)

Adoption of authoritative accounting guidance regarding uncertainty in income taxes

 

 

 

 

(63

)

 

(63

)

Change in fair value of derivatives

 

 

 

 

 

(100,727

)

(100,727

)

Net income

 

 

 

 

129,928

 

 

129,928

 

Balances at December 31, 2007

 

425

 

18

 

66,590

 

513,645

 

(120,704

)

459,974

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation (199,363 shares)

 

2

 

 

11,684

 

 

 

11,686

 

Tax impact of stock option exercise

 

 

 

938

 

 

 

938

 

Deferred director fees — stock compensation

 

 

 

441

 

 

 

441

 

Cash dividends declared - $0.30 per share, including RSU dividend equivalents

 

 

 

 

(13,425

)

 

(13,425

)

Change in fair value of derivatives

 

 

 

 

 

 

234,401

 

234,401

 

Net income

 

 

 

 

133,529

 

 

133,529

 

Balances at December 31, 2008

 

427

 

18

 

79,653

 

633,749

 

113,697

 

827,544

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation (170,134 shares)

 

3

 

 

6,750

 

 

 

6,753

 

Tax impact of stock option exercises

 

 

 

(98

)

 

 

(98

)

Deferred director fees - stock compensation

 

 

 

2,763

 

 

 

2,763

 

Cash dividends declared - $0.30 per share, including RSU dividend equivalents

 

 

 

 

(13,664

)

 

(13,664

)

Change in fair value of derivatives

 

 

 

 

 

(174,069

)

(174,069

)

Net income

 

 

 

 

54,030

 

 

54,030

 

Balances at December 31, 2009

 

$

430

 

$

18

 

$

89,068

 

$

674,115

 

$

(60,372

)

$

703,259

 

 

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

 

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BERRY PETROLEUM COMPANY

Statements of Cash Flows

Years Ended December 31, 2009, 2008 and 2007

(In Thousands)

 

 

 

2009

 

2008

 

2007

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income

 

$

54,030

 

$

133,529

 

$

129,928

 

Depreciation, depletion and amortization

 

145,788

 

141,049

 

97,259

 

Extinguishment of debt

 

10,823

 

 

 

Amortization of debt issuance costs and net discount

 

6,827

 

1,774

 

774

 

Dry hole and impairment

 

14,859

 

9,932

 

12,951

 

Commodity derivatives

 

247

 

(108

)

574

 

Stock-based compensation expense

 

8,626

 

9,313

 

8,200

 

Deferred income taxes

 

19,998

 

67,982

 

62,465

 

Loss (gain) on sale of asset

 

79

 

1,297

 

(54,173

)

Other, net

 

(4,016

)

(2,530

)

2,787

 

Cash paid for abandonment

 

(1,030

)

(4,607

)

(1,188

)

Allowance for bad debt

 

 

38,511

 

 

Change in book overdraft

 

(16,018

)

23,984

 

(9,400

)

(Increase) decrease in current assets other than cash, cash equivalents and short-term investments

 

(10,055

)

10,281

 

(47,876

)

(Decrease) increase in current liabilities other than line of credit

 

(17,582

)

(20,838

)

36,578

 

Net cash provided by operating activities

 

212,576

 

409,569

 

238,879

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Exploration and development of oil and gas properties

 

(134,946

)

(397,601

)

(285,267

)

Property acquisitions

 

(13,497

)

(667,996

)

(56,247

)

Capitalized interest

 

(30,107

)

(23,209

)

(18,104

)

Proceeds from sale of assets

 

139,796

 

2,037

 

72,405

 

Net cash used in investing activities

 

(38,754

)

(1,086,769

)

(287,213

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Proceeds from issuances on line of credit

 

387,700

 

404,000

 

395,150

 

Payments on line of credit

 

(413,000

)

(393,000

)

(396,850

)

Proceeds from issuance of long-term debt

 

1,090,262

 

1,708,700

 

229,300

 

Payments on long-term debt

 

(1,215,100

)

(1,021,900

)

(174,300

)

Debt issuance costs

 

(23,955

)

(11,002

)

(1

)

Financing obligation

 

18,214

 

 

 

Dividends paid

 

(13,664

)

(13,425

)

(13,292

)

Proceeds from stock option exercises

 

890

 

2,813

 

5,178

 

Excess tax (expense) benefit

 

(98

)

938

 

3,049

 

Net cash (used in) provided by financing activities

 

(168,751

)

677,124

 

48,234

 

Net increase (decrease) in cash and cash equivalents

 

5,071

 

(76

)

(100

)

Cash and cash equivalents at beginning of year

 

240

 

316

 

416

 

Cash and cash equivalents at end of year

 

$

5,311

 

$

240

 

$

316

 

Supplemental disclosures of cash flow information:

 

 

 

 

 

 

 

Interest paid, net of capitalized interest

 

$

36,854

 

$

15,708

 

$

15,841

 

Income taxes paid

 

$

8,769

 

$

13,290

 

$

6,715

 

Supplemental non-cash activity:

 

 

 

 

 

 

 

(Decrease) increase in fair value of derivatives:

 

 

 

 

 

 

 

Current (net of income taxes of ($49,914), $75,772, and ($36,562), respectively)

 

$

(81,439

)

$

123,628

 

$

(54,844

)

Non-current (net of income taxes of ($56,773), $67,893, and ($30,589), respectively)

 

(92,630

)

110,773

 

(45,883

)

Net (decrease) increase to accumulated other comprehensive (loss) income

 

$

(174,069

)

$

234,401

 

$

(100,727

)

 

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

 

9


 


Table of Contents

 

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

 

1.                                      Summary of Significant Accounting Policies

 

Description of the business

 

Berry Petroleum Company (the Company) is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. The Company has invested in cogeneration facilities which provide steam required for the extraction of heavy oil and which generates electricity for sale.

 

Basis of presentation

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

Reclassifications and error corrections

 

Included in the fourth quarter of 2009 are adjustments to correct the prior accounting for the Company’s royalties in the amount of $3.3 million, which resulted in decreasing its sales of oil and gas and increasing its royalties payable.  The year- to-date impact of the adjustment was $1.9 million.  Management concluded the impact was immaterial to the current and prior periods.

 

In March 2008, the Company determined there was an error in computing royalties payable in prior years, accumulating to $10.5 million as of December 31, 2007. The Company concluded the error was not material to any individual prior interim or annual period (or to the projected earnings for 2008) and, therefore, the error was corrected during the first quarter of 2008, with the effect of increasing sales of oil and gas by $10.5 million and reducing royalties payable.

 

Cash and cash equivalents

 

The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2009 and 2008 is $15.7 million and $31.8 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

 

Accounts receivable

 

Trade accounts receivable consist mainly of receivables from oil and gas purchases and joint interest owners on properties the Company operates.  For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.  Generally, oil and gas receivables are collected within two months.

 

Allowance for doubtful accounts

 

The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.  As of both December 31, 2009 and 2008, the Company has an allowance for doubtful accounts of $38.5 million.  The 2008 amount represents the Company’s November and December 2008 sales to BWOC.  The Company had a long-term contract to sell all of its heavy crude oil in California for approximately $8.10 below WTI with BWOC.  On December 22, 2008, Flying J, Inc. and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC each filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.  Also in December 2008, BWOC informed the Company that it was unable to receive the Company’s production.  On March 17, 2009, the Company entered into a stipulation with BWOC, terminating the contract effective as of March 16, 2009.  The Company recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC.  Of that $38.5 million due from BWOC, $11.8 million represents 20 days of December 2008 crude oil sales and an administrative claim under the bankruptcy proceedings and $26.7 million represents November and the balance of December 2008 crude oil sales which would have the same priority as other general unsecured claims.  BWOC will also be liable to the Company for damages under this contract.  While the Company also has guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, the information received from the bankruptcy proceedings to date has not provided the Company with adequate data from which to make a conclusion that any amounts will be collected.  The Company has entered into various agreements with other companies to sell its California oil production.

 

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Table of Contents

 

Discontinued operations

 

In 2009, the Company sold its DJ Basin assets, the results of operations of which, are reported as discontinued operations in the Statement of Income.

 

Income taxes and uncertain tax positions

 

Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the asset and liability method, which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. A valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods.  Income tax positions must meet a more-likely-than-not recognition threshold to be recognized, and any potential accrued interest and penalties related to the unrecognized tax benefits are recognized within income tax expense.  Uncertain tax positions are recognized in the Balance Sheet as a current or noncurrent liability, based upon the expected timing of the payment to a taxing authority.

 

Derivatives

 

The Company periodically enters into commodity derivative contracts to manage its exposure to oil and natural gas price volatility.  The Company also enters into derivative contracts to mitigate the risk of interest rate fluctuations.   The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge.  Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings.  Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, has no effect on the statement of income because changes in fair value of the derivative offsets changes in the fair value of the hedged item.   Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings.  Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.  The estimated fair value of derivative instruments requires substantial judgment.  These values are based upon, among other things, whether or not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, time to maturity and credit risk.  The values the Company reports in its financial statements changes as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond its control.

 

Prior to January 1, 2010, the Company designated most of its commodity and interest rate derivative contracts as cash flow hedges, whose unrealized fair value gains and losses were recorded to Accumulated other comprehensive loss (AOCL).  Effective January 1, 2010, the Company has elected to de-designate all of its commodity and interest rate contracts that had previously been designated as cash flow hedges as of December 31, 2009 and have elected to discontinue hedge accounting prospectively.

 

As a result, subsequent to December 31, 2009, the Company will recognize all gains and losses from prospective changes in commodity and interest rate derivative fair values immediately in earnings rather than deferring any such amounts in AOCL.  At December 31, 2009, AOCL consisted of $97 million ($60 million after tax) of unrealized losses, representing the mark-to-market value of the Company’s cash flow hedges as of the balance sheet date, less any ineffectiveness recognized.  As a result of discontinuing hedge accounting on January 1, 2010, such mark-to-market values at December 31, 2009 are frozen in AOCL as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions affect earnings.  The Company expects to reclassify into earnings from AOCL the frozen value related to de-designated commodity hedges during the next three years.

 

Oil and gas properties, buildings and equipment

 

The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.

 

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Table of Contents

 

Depletion of oil and gas producing properties is computed using the units-of-production method. Depreciation of lease and well equipment, including cogeneration facilities and other steam generation equipment and facilities, is computed using the units-of-production method or on a straight-line basis over estimated useful lives ranging from 10 to 20 years. Buildings and equipment are recorded at cost. Depreciation is provided on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Estimated residual salvage value is considered when determining depreciation, depletion and amortization (DD&A) rates.  Changes in reserves are applied on a prospective basis.

 

Interest incurred on funds borrowed to finance exploration and certain acquisition and development activities is capitalized. To qualify for interest capitalization, the costs incurred must relate to the acquisition of unproved reserves, drilling of wells to prove up the reserves and the installation of the necessary pipelines and facilities to make the property ready for production. Such capitalized interest is included in oil and gas properties, buildings and equipment. Capitalized interest is added into the depreciable base of the assets and is expensed on a units-of-production basis over the life of the respective project.

 

In accordance with authoritative guidance, the Company groups assets at the field level and periodically reviews the carrying value of its property and equipment to test whether current events or circumstances indicate such carrying value may not be recoverable. If the tests indicate that the carrying value of the asset is greater than the estimated future undiscounted cash flows to be generated by such asset, then an impairment adjustment needs to be recognized. Such adjustment consists of the amount by which the carrying value of such asset exceeds its fair value. The Company generally measures fair value by considering sale prices for similar assets or by discounting estimated future cash flows from such asset using an appropriate discount rate. Considerable management judgment is necessary to estimate the fair value of assets, and accordingly, actual results could vary significantly from such estimates. When assets are sold, the applicable costs and accumulated depreciation and depletion are removed from the accounts and any gain or loss is included in income. Expenditures for maintenance and repairs are expensed as incurred.

 

Asset retirement obligations

 

Asset retirement obligations (ARO) relate to future costs associated with plugging and abandonment of oil and gas wells, removal of equipments and facilities from leased acreage and returning such land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset.  Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

 

Accrued liabilities

 

Accrued liabilities consist primarily of accrued property taxes, accrued interest and accrued payroll costs.  Accrued property taxes were $8.3 million and $13.5 million as of December 31, 2009 and 2008, respectively.  Accrued interest was $6.9 million and $8.4 million as of December 31, 2009 and 2008, respectively.  Accrued payroll costs were $8.2 million and $8.4 million as of December 31, 2009 and 2008, respectively.

 

Revenue recognition

 

Revenues associated with sales of crude oil, natural gas, electricity and natural gas marketing are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. Revenues from crude oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of its net working interest (entitlement method).  Revenues are derived from gas marketing sales which represent excess capacity on the Rockies Express pipeline which the Company uses to market natural gas for its working interest partners.

 

Electricity cost allocation

 

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation.  Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine that would otherwise be wasted, to produce steam. Such cogeneration operations produce electricity and steam. The Company allocates steam costs to its oil and gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. Electricity used in oil and gas operations is allocated at cost. A portion of the capital costs of the cogeneration facilities is allocated to DD&A-oil and gas production. 

 

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Table of Contents

 

Electricity consumption included in oil and gas operating costs for the years ended December 31, 2009, 2008 and 2007 was $2.8 million, $5.8 million and $5.0 million, respectively.

 

Transportation costs

 

Transportation costs, consisting primarily of natural gas transportation costs, are included in either “Operating costs - oil and gas production” or “Operating costs - electricity generation,” as applicable. Natural gas transportation costs included in Operating costs - oil and gas production were $15.2 million, $9.5 million and $1.2 million for 2009, 2008 and 2007, respectively.  Natural gas transportation costs included in Operating costs - electricity generation were $2.8 million, $7.2 million and $6.7 million for 2009, 2008 and 2007, respectively. Additionally, the transportation costs in Uinta were $0.2 million, $0.2 million and $1.4 million in 2009, 2008 and 2007, respectively.

 

Stock-based compensation

 

The Company recognizes the grant date fair value of stock options and other stock based compensation issued in the statement of income.  Expense is recognized on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award).

 

Earnings (loss) per share

 

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period.  Under the treasury stock method, diluted earnings (loss) per share is computed by dividing net earnings (loss) adjusted for the effects of potential common shares.

 

Related party transactions

 

In December 2007, the Company accepted a tender issued by Bakersfield Fuel & Oil Company (BFO) to purchase all of its shares in BFO for $2.9 million. These proceeds are reflected in the “Proceeds from sale of assets” line on the Statements of Cash Flows and in the “Gain on sale of assets” line on the Statements of Income. Mr. Thomas Jamieson is a Director of Berry Petroleum Company and a director and the controlling stockholder of BFO. The tender was made to all shareholders of BFO other than Mr. Jamieson and his affiliates. The Corporate Governance and Nominating Committee, with input from the Audit Committee, approved this transaction.

 

Equity method investments

 

The Company owns interests in two entities which serve to gather and transport natural gas in the Company’s Lake Canyon and Brundage Canyon fields. The Company owns less than 50% interest in both entities and these interests are accounted for using the equity method.  The Company’s net investment in these entities is included under the caption “Other assets” on its Balance Sheet.

 

Impact of recently issued accounting standard updates

 

In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-06 “Improving Disclosures about Fair Value Measurements.”   The ASU amends previously issued authoritative guidance and requires new disclosures and clarifies existing disclosures and is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the rollforward activity in Level 3 fair value measurements.  Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years.  As this requires only additional disclosures, the guidance will have no impact on the Company’s financial position or results of operations.

 

2.                                      Fair Value Measurement

 

In September 2006, authoritative guidance was issued that defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Company adopted this guidance as of January 1, 2008 for all financial and nonfinancial assets and liabilities recognized or disclosed at fair value on a recurring basis.  The Company has also adopted the authoritative guidance as it relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis as of January 1, 2009 pursuant to the authoritative guidance issued by the FASB in February 2008.  The adoption of the authoritative guidance did not have a material impact on the financial statements for the years ended December 31, 2009 or 2008.

 

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Table of Contents

 

The authoritative guidance establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

 

A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy.  Oil swaps, natural gas swaps and interest rate swaps are valued using internal models which are based on active market data and are classified within Level 2 of the valuation hierarchy. Derivatives that are valued based upon models with significant unobservable market inputs (primarily volatility), and that are normally traded less actively are classified within Level 3 of the valuation hierarchy. The Company determines the value of option contracts utilizing industry-standard option pricing models based on inputs that are either readily available in public markets, can be derived from information available in publicly quoted markets, or are quoted by financial institutions that trade these contracts. In situations where the Company obtains inputs via quotes from financial institutions, it verifies the reasonableness of these quotes via similar quotes from another financial institution as of each date for which financial statements are prepared. The Company also considers counterparty credit risk and its own credit risk in its determination of all estimated fair values. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds.  Level 3 derivatives include oil collars, natural gas collars and natural gas basis swaps.

 

The following tables set forth by level within the fair value hierarchy the Company’s assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2009 and 2008.

 

Assets and liabilities measured at fair value on a recurring basis

 

December 31, 2009 (in
millions)

 

Total carrying value on the
Balance Sheet

 

Level 2

 

Level 3

 

 

 

 

 

 

 

 

 

Commodity derivative liability

 

$

(88.5

)

$

(62.5

)

$

(26.0

)

Interest rate swaps liability

 

(8.9

)

(8.9

)

 

Total liabilities at fair value

 

$

(97.4

)

$

(71.4

)

$

(26.0

)

 

December 31, 2008 (in
millions)

 

Total carrying value on the
Balance Sheet

 

Level 2

 

Level 3

 

 

 

 

 

 

 

 

 

Commodity derivative asset

 

198.4

 

25.9

 

172.5

 

Interest rate swaps liability

 

(12.5

)

(12.5

)

 

Total assets at fair value

 

185.9

 

13.4

 

172.5

 

 

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Table of Contents

 

Changes in Level 3 fair value measurements

 

The table below includes a rollforward of the Balance Sheet amounts (including the change in fair value) for financial instruments classified by us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).

 

(in millions)

 

Twelve months ended
December 31, 2009

 

Twelve months ended
December 31, 2008

 

 

 

 

 

 

 

Fair value asset (liability), beginning of period

 

$

172.5

 

$

(194.3

)

Total realized and unrealized (losses) gains included in Gain (loss) on derivatives

 

(1.0

)

0.4

 

Purchases, sales and settlements, net

 

(200.9

)

366.4

 

Transfers in and/or out of Level 3

 

3.4

 

 

Fair value (liability) asset, end of period

 

(26.0

)

172.5

 

 

 

 

 

 

 

Total unrealized (losses) gains included in income related to financial assets and liabilities still on the balance sheet at December 31, 2009 and 2008

 

$

(0.1

)

$

 

 

The $3.4 million of transfers out of Level 3 for the year ended December 31, 2009 represent crude oil collars that were converted to crude oil swaps during the first quarter of 2009.

 

For further discussion related to the Company’s derivatives see Note 3 to the financial statements.

 

Fair Market Value of Financial Instruments

 

The Company used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Company’s credit facilities approximated fair value, because the interest rates on the credit facilities are variable. The fair values of the 8.25 % senior subordinated notes due 2016 and the 10.25 % senior notes due 2014 were estimated based on quoted market prices. The fair values of the Company’s derivative instruments and other investments are discussed above.

 

 

 

Carrying
Amount

 

Estimated
Fair Value

 

(in millions)

 

As of December 31, 2009

 

 

 

 

 

 

 

Line of credit

 

$

 

$

 

Senior secured revolving credit facility

 

372

 

372

 

8.25 % Senior subordinated notes due 2016

 

200

 

196

 

10.25% Senior notes due 2014

 

437

 

487

 

 

 

$

1,009

 

$

1,055

 

 

 

 

Carrying
Amount

 

Estimated
Fair Value

 

(in millions)

 

As of December 31, 2008

 

 

 

 

 

 

 

Line of credit

 

$

25

 

$

25

 

Senior secured revolving credit facility

 

932

 

932

 

8.25 % Senior subordinated notes due 2016

 

200

 

116

 

 

 

$

1,157

 

$

1,073

 

 

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Table of Contents

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

 

In December 2009, subsequent to the approval of the Company’s capital budget, the Company recorded a $4.2 million impairment charge related to the write down of a drilling rig to its fair value.  Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operational costs, and a risk-adjusted discount rate.  The fair value measurement was based on Level 3 inputs.  The fair value of the drilling rig on December 31, 2009 was $3.3 million.

 

3.                                      Hedging

 

To minimize the effect of a downturn in oil and gas prices and protect the Company’s profitability and the economics of its development plans, the Company enters into crude oil and natural gas hedge contracts from time to time. The terms of contracts depend on various factors, including management’s view of future crude oil and natural gas prices, acquisition economics on purchased assets and future financial commitments. This price hedging program is designed to moderate the effects of a severe crude oil and natural gas price downturn while allowing us to participate in some commodity price increases. The Company benefits from lower natural gas pricing as it is a consumer of natural gas in its California operations.  In the Rocky Mountains and E. Texas the Company benefits from higher natural gas pricing. The Company has hedged, and may hedge in the future, both natural gas purchases and sales as determined appropriate by management.  Management regularly monitors the crude oil and natural gas markets and financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate in accordance with policy established by its Board of Directors.  Currently, the hedges are in the form of swaps and collars.  However, the Company may use a variety of hedge instruments in the future to hedge WTI or the index gas price.  The Company also utilizes interest rate derivatives to protect against changes in interest rates on its floating rate debt.

 

At December 31, 2009, the net fair value derivative liability was $97.4 million as compared to a net fair value asset of $185.9 million at December 31, 2008 which reflects changes in commodity prices and interest rates. Based on NYMEX strip pricing as of December 31, 2009, the Company expects to make hedge payments under the existing derivatives of $21.7 million during the next twelve months.

 

At December 31, 2009, AOCL consisted of $(60.4) million, net of tax, of unrealized losses from crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at December 31, 2009, less any ineffectiveness recognized.  As a result of discontinuing hedge accounting on January 1, 2010, such mark-to-market values at December 31, 2009 are frozen in AOCL as of the de-designation date and will be reclassified into earnings in the same period that the forecasted transactions impact earnings.

 

The related cash flow impact of all of the Company’s hedges is reflected in cash flows from operating activities.

 

The Company presents its derivative assets and liabilities on its Balance Sheets on a net basis.  The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with a counterparty to a derivative contract.  The Company uses these agreements to manage and reduce its potential counterparty credit risk.

 

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Table of Contents

 

The following table disaggregates the Company’s net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to master netting arrangements.  Finally, the Company identifies the line items on its Balance Sheets in which these fair value amounts are included.  The gross asset and liability values in the table below are segregated between those derivatives designated in qualifying hedge accounting relationships and those not designated in hedge accounting relationships.  The Company uses the end of period accounting designation to determine the classification for each derivative position.

 

 

 

As of December 31, 2009

 

 

 

Derivative Assets

 

Derivative Liabilities

 

(in millions)

 

Balance Sheet
Location

 

Fair Value

 

Balance Sheet Location

 

Fair Value

 

Commodity — Oil

 

Current assets

 

$

14.2

 

Current liability

 

$

30.8

 

Commodity — Natural Gas

 

Current assets

 

1.3

 

 

 

 

 

Commodity — Oil

 

 

 

 

 

Long term liabilities

 

74.1

 

Commodity — Natural Gas

 

Long term assets

 

0.4

 

 

 

 

 

Commodity — Natural Gas

 

Current liability

 

0.2

 

 

 

 

 

Commodity — Natural Gas

 

Long term liabilities

 

1.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate contracts

 

Long term assets

 

0.3

 

Current assets

 

3.5

 

Interest rate contracts

 

 

 

 

 

Current liabilities

 

2.7

 

Interest rate contracts

 

 

 

 

 

Long term liabilities

 

3.0

 

Total derivatives designated as hedging instruments under authoritative guidance

 

 

 

17.6

 

 

 

114.1

 

Commodity — Natural Gas

 

 

 

 

Current assets

 

0.4

 

Commodity — Natural Gas

 

 

 

 

Current liabilities

 

0.5

 

Total derivatives not designated as hedging instruments under authoritative guidance

 

 

 

 

 

 

0.9

 

Total Derivatives

 

 

 

$

17.6

 

 

 

$

115.0

 

 

The tables below summarize the Statement of Income impacts of the Company’s derivative instruments before tax for the twelve months ending December 31, 2009 (in millions):

 

Derivatives cash
flow hedging
relationships

 

Amount of Gain
(Loss) Recognized
in AOCL on
Derivative

(Effective portion)

 

Location of Gain
(Loss) Reclassified
from AOCL into
Income (Effective
Portion)

 

Amount of Gain
(Loss)
Reclassified from
AOCL into
Income (Effective
Portion)

 

Location of Gain (loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)

 

Amount of Gain (Loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)

 

Commodity - Oil

 

$

(219.3

)

Sales of oil and gas

 

$

53.9

 

Sales of oil and gas

 

$

 

Commodity - Natural Gas

 

12.9

 

Sales of oil and gas

 

25.4

 

Gain (loss) on derivatives

 

(0.6

)

Interest rate

 

(2.7

)

Interest expense

 

(7.0

)

Gain (loss) on derivatives

 

 

Total

 

$

(209.1

)

 

 

$

72.3

 

 

 

$

(0.6

)

 

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Table of Contents

 

Amount of Gain or (Loss) Recognized in Income on Derivatives not designated as Hedging Instruments under authoritative guidance as of twelve months ending December 31, 2009:

 

Derivatives not designated as
Hedging Instruments under
authoritative guidance

 

Location of Gain (Loss) Recognized
in Income on Derivative

 

Amount of Gain (Loss)
Recognized in Income on
Derivatives not designated as
Hedging Instruments under
authoritative guidance

 

 

 

 

 

 

 

Commodity — Oil

 

Gain (loss) on derivatives

 

$

(6.7

)

Commodity - Natural Gas

 

Gain (loss) on derivatives

 

(0.5

)

Commodity - Natural Gas

 

(Loss) income from discontinued operations, net of taxes

 

(0.5

)

Total Derivatives

 

 

 

$

(7.7

)

 

During the first quarter of 2009, the Company converted oil collars for 6,000 Bbl/D for the full year 2010 into swaps for the same volumes with swap prices ranging from $61.00 to $64.80.

 

The Company generally utilizes NYMEX WTI based derivatives to hedge cash flows from its California oil sales.  The Company’s oil sales contracts with multiple refiners are primarily based on the field posting prices.  There is a high correlation between WTI and the field posting prices which allowed us to utilize hedge accounting.  As there is a ready market for the Company’s crude oil in California, the Company does not believe the loss of any particular contract impacts the probability that its hedged forecasted transactions will occur.  The Company generally hedges its natural gas at the basis location that corresponds to the forecasted sale.

 

While the Company designates the majority of its hedges as cash flow hedges, it has not elected hedge accounting on certain of its crude oil and natural gas hedges.  During the twelve months ended December 31, 2009, the Company recorded $6.5 million under the caption “Gain (loss) on derivatives” related to hedges for which it either did not elect hedge accounting or which no longer qualified for hedge accounting.  In conjunction with the sale of the DJ basin assets, during the first quarter of 2009, the Company concluded that the forecasted transaction in certain of its hedging relationships was not probable of occurring.  As such, the Company reclassified a gain of $14.3 million from AOCL to the Statement of Income under the caption “Gain (loss) on derivatives.”  “Gain (loss) on derivatives” includes a loss for cash settlements of $7.6 million and a gain for the change in fair value of $0.3 million on hedges for which the Company has not elected hedge accounting. Additionally, a portion of the change in fair value for hedges that was designated as cash flow hedges may impact the Company’s income as the sales price is not perfectly correlated with the Company’s hedges.  The Company recognized an unrealized net loss of $0.5 million on the Statement of Income under the caption “Gain (loss) on derivatives” for the twelve months ended December 31, 2009, respectively, as a result of ineffectiveness.  During the first quarter of 2009, the Company entered into natural gas derivatives on behalf of the purchaser of its DJ assets.  The Company did not elect hedge accounting for these hedges and recorded an unrealized net loss of $0.5 million on the Statement of Income under the caption “(Loss) income from discontinued operations, net of taxes.”

 

The Company’s hedge contracts have been executed primarily with counterparties that are party to its senior secured revolving credit facility.

 

Neither the Company nor its counterparties are required to post collateral in connection with its derivative positions and netting agreements are in place with each of the Company’s counterparties allowing the Company to offset its commodity derivative asset and liability positions.  The credit rating of each of these counterparties was AA-/Aa2, or better as of December 31, 2009.  The Company’s derivatives are held with a small number of counterparties and as of December 31, 2009, the Company’s largest three counterparties accounted for 76% of the value of its total derivative positions.

 

As of December 31, 2009, the Company had the following commodity hedges:

 

 

 

2010

 

2011

 

2012

 

Oil Bbl/D:

 

14,930

 

9,020

 

3,000

 

Natural Gas MMBtu/D:

 

19,000

 

10,000

 

10,000

 

 

For further discussion related to the fair value of the Company’s derivatives see Note 2 to the financial statements.

 

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4.                                      Asset Retirement Obligations (AROs)

 

The following table summarizes the change in abandonment obligation for the years ended December 31 (in thousands):

 

 

 

2009

 

2008

 

Beginning balance at January 1

 

$

41,967

 

$

36,426

 

Liabilities incurred

 

1,407

 

4,686

 

Liabilities settled

 

(1,030

)

(4,607

)

Disposition of assets

 

(2,752

)

 

Revisions in estimated liabilities

 

 

2,006

 

Accretion expense

 

3,895

 

3,456

 

Ending balance at December 31

 

$

43,487

 

$

41,967

 

 

The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

 

5.                                      Acquisitions and Divestitures

 

During the twelve months ended December 31, 2009, the Company completed acquisitions totaling $13.5 million. In June 2009, the Company acquired property near McKittrick, California, the deep rights to one of the leases in its Darco property in E. Texas, and additional interests in its Piceance Garden Gulch assets.

 

On July 17, 2009, the Company completed the financing of its E. Texas gas gathering system for $18.4 million in cash.  The Company entered into concurrent long-term gas gathering agreements for the E. Texas production which contained an embedded lease.  The transaction was treated as a financing obligation.  Accordingly, the net book value of the property of $16.7 million will be depreciated over the remaining useful life of the asset and the cash received of $18.4 million was recorded as a financing obligation.  A portion of future payments will be recorded as gathering expense, a portion as interest expense and the balance as a reduction in the financing obligation.  There is no minimum payment required under these agreements.

 

On March 3, 2009, the Company entered into an agreement to sell its DJ basin assets and related hedges for $154 million before customary closing adjustments. The closing date of the sale of the assets was April 1, 2009.  The Company recorded a pre-tax impairment loss of $9.6 million related to the sale, which is aggregated within the $5.9 million “(Loss) income from discontinued operations, net of taxes” on its Statement of Income for the twelve months ended December 31, 2009.

 

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(Loss) income from discontinued operations, net of tax on the accompanying statements of income is comprised of the following (in thousands):

 

 

 

For the Twelve Months Ended
December 31,

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Oil and gas revenue

 

$

5,396

 

48,729

 

$

34,192

 

Loss on sale of asset

 

(908

)

 

 

Other revenue

 

623

 

2,072

 

1,851

 

Total revenue

 

5,111

 

50,801

 

36,043

 

 

 

 

 

 

 

 

 

Operating expenses

 

2,576

 

11,340

 

10,279

 

Production taxes

 

195

 

3,023

 

2,564

 

DD&A

 

2,188

 

12,642

 

10,829

 

General and administrative

 

388

 

1,074

 

547

 

Interest expense

 

815

 

2,267

 

2,218

 

Commodity derivatives

 

484

 

145

 

13

 

Dry hole, abandonment, impairment and exploration

 

9,637

 

1,772

 

5,306

 

Total expenses

 

16,283

 

32,263

 

31,756

 

 

 

 

 

 

 

 

 

(Loss) income from discontinued operations, before income taxes

 

(11,172

)

18,538

 

4,287

 

Income tax (benefit) expense

 

(5,234

)

6,785

 

1,643

 

(Loss) income from discontinued operations

 

$

(5,938

)

11,753

 

$

2,644

 

 

On July 15, 2008, the Company acquired a 100% working interest in natural gas producing properties on 4,500 net acres in Limestone and Harrison counties in E. Texas for approximately $668 million, including post closing adjustments of $46 million.

 

The unaudited pro forma results presented below for the years ended December 31, 2008 and 2007 have been prepared to give effect to the E. Texas Acquisition on the Company’s results of operations under the purchase method of accounting as if it had been consummated at the beginning of each of the periods presented.  The unaudited pro forma results do not purport to represent the results of operations that actually would have occurred on such date or to project the Company’s results of operations for any future date or period.  The pro forma results set forth below also gives effect to (1) the presentation as discontinued operations of the Company’s DJ Basin assets, which were sold on April 1, 2009, and (2) the Company’s implementation of authoritative guidance on determining whether instruments granted in share-based payment transactions are participating securities, which requires the revision of prior period basic and diluted earning per share data.

 

 

 

Year Ended
December 31,
2008

 

Year Ended
December 31,
2007

 

Pro forma revenue

 

$

797,261

 

$

581,138

 

Pro forma income from operations

 

$

197,196

 

$

162,733

 

Pro forma net income

 

$

125,917

 

$

103,333

 

Pro forma basic earnings per share

 

$

2.79

 

$

2.34

 

Pro forma diluted earnings per share

 

$

2.75

 

$

2.30

 

 

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The following is a calculation and allocation of purchase price to the E. Texas Acquisition assets and liabilities based on their relative fair values, as determined by the valuation of proved reserves and related assets as of the acquisition date:

 

Purchase price (in thousands):

 

As of
December 31, 2008

 

Original purchase price

 

$

622,356

 

 

 

 

 

Closing adjustments for property costs, and operating expenses in excess of revenues between the effective date and closing date

 

45,506

 

 

 

 

 

Total purchase price allocation

 

$

667,862

 

 

 

 

 

Allocation of purchase price (in thousands):

 

 

 

 

 

 

 

Oil and natural gas properties

 

$

651,659

(i)

Pipeline

 

17,277

 

Tax receivable

 

1,476

 

 

 

 

 

Total assets acquired

 

670,412

 

 

 

 

 

Current liabilities

 

(1,195

)(ii)

Asset retirement obligation

 

(1,355

)

 

 

 

 

Net assets acquired

 

$

667,862

 

 


(i)  Determined by reserve analysis.

(ii)  Accrual for royalties payable.

 

In May 2007, the Company sold its non-core West Montalvo assets in Ventura County, California. The sale proceeds were approximately $61 million and the Company recognized a $52 million pretax gain on the sale, including post closing adjustments. In the fourth quarter of 2007 the Company completed the sale of a portion of its Tri-State acreage for $1.4 million.

 

6.                                      Oil and Gas Properties, Buildings and Equipment

 

Oil and gas properties, buildings and equipment consist of the following at December 31 (in thousands):

 

 

 

2009

 

2008

 

Oil and gas:

 

 

 

 

 

Proved properties:

 

 

 

 

 

Producing properties, including intangible drilling costs

 

$

1,892,340

 

$

1,820,609

 

Lease and well equipment (1)

 

513,961

 

663,610

 

 

 

2,406,301

 

2,484,219

 

Unproved properties

 

 

 

 

 

Properties, including intangible drilling costs

 

267,303

 

255,412

 

 

 

2,673,604

 

2,739,631

 

Less accumulated depreciation, depletion and amortization

 

583,077

 

509,277

 

 

 

2,090,527

 

2,230,354

 

Commercial and other:

 

 

 

 

 

Land

 

66

 

810

 

Drilling rigs and equipment

 

5,333

 

13,166

 

Buildings and improvements

 

5,911

 

6,274

 

Machinery and equipment

 

26,608

 

22,767

 

 

 

37,918

 

43,017

 

Less accumulated depreciation

 

22,060

 

18,946

 

 

 

15,858

 

24,071

 

 

 

$

2,106,385

 

$

2,254,425

 

 


(1) Includes cogeneration facility costs.

 

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Suspended Well Costs

 

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period of greater than one year since the completion of drilling (in thousands, except number of projects):

 

 

 

2009

 

2008

 

2007

 

Capitalized exploratory well costs that have been capitalized for a period of one year or less

 

$

 

$

 

$

6,826

 

Capitalized exploratory well costs that have been capitalized for a period greater than one year

 

 

 

 

Balance at December 31

 

$

 

$

 

$

6,826

 

 

 

 

 

 

 

 

 

Number of projects that have exploratory well costs that have been capitalized for a period of greater than one year

 

 

 

 

 

The following table reflects the net changes in capitalized exploratory well costs (in thousands):

 

 

 

2009

 

2008

 

2007

 

Beginning balance at January 1

 

$

 

$

6,826

 

$

89

 

Additions to capitalized exploratory well costs pending the determination of proved reserves

 

 

 

6,826

 

Reclassifications to wells, facilities and equipment based on the determination of proved reserves

 

 

(6,826

)

 

Capitalized exploratory well costs charged to expense

 

 

 

(89

)

Ending balance at December 31

 

$

 

$

 

$

6,826

 

 

Dry hole, abandonment, impairment and exploration

 

In 2009 the Company had dry hole, abandonment and impairment charges of $5.2 million primarily due to a $4.2 million impairment charge related to the write-down of a rig to its fair market value (see Note 2 Fair Value Measurement).  The Company incurred exploration costs in 2009 of $0.2 million compared to $0.6 million in 2008 and $0.6 million in 2007.  These costs consist primarily of geological and geophysical costs.

 

In 2008 the Company had dry hole, abandonment, impairment and exploration charges of $10.5 million consisting primarily of $7.3 million for technical difficulties that were encountered on five wells in the Piceance basin before reaching total depth.  These holes were abandoned in favor of drilling to the same bottom hole location by drilling new wells.  Due to the release of its rigs the Company performed an impairment test which resulted in $2.4 million of impairment costs resulting from the impairment of one rig.

 

In 2007 the Company had dry hole, abandonment, impairment and exploration charges of $8.4 million that consisted primarily of a $3.3 million impairment of its Coyote Flats prospect to reflect its fair value in conjunction with the preparation of its year end reserve estimates, a $2.9 million writedown of its Bakken properties which were sold in September 2007, geological and geophysical costs of $0.6 million and other dry hole charges of $1.6 million.

 

7.                                      Debt Obligations

 

Short-term lines of credit

 

In 2005, the Company completed an unsecured uncommitted money market line of credit (Line of Credit). Borrowings under the Line of Credit may be up to $30 million for a maximum of 30 days.  The Line of Credit may be terminated at any time upon written notice by either the Company or the lender.  In conjunction with the amendment to the Company’s senior secured credit facility, on July 15, 2008, the Line of Credit was collateralized by oil and natural gas properties representing at least 80% of the present value of the Company’s proved reserves.

 

At December 31, 2009 and 2008, the outstanding balance under this Line of Credit was zero and $25.3 million, respectively.  Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1.4%.  The weighted average interest rate on outstanding borrowings on the Line of Credit at December 31, 2009 and 2008 was 0% and 1.4%, respectively.

 

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Senior secured revolving credit facility

 

The Company’s senior secured revolving credit facility (the Agreement) has a current borrowing base and lender commitments of $938 million. The LIBOR and prime rate margins are between 2.25% and 3.0% based on the ratio of credit outstanding to the borrowing base and the annual commitment fee on the unused portion of the credit facility is 0.50%.

 

Covenants under the Agreement are as follows:

 

Total funded debt to EBITDAX (1) ratio not greater than:

 

Senior secured debt to EBITDAX ratio not greater than:

 

2009

 

2010

 

Thereafter

 

to Sep 2010

 

Mar 2011

 

Sep 2011

 

Thereafter

 

4.75

 

4.50

 

4.00

 

3.75

 

3.50

 

3.25

 

3.0

 

 


(1) Net income before interest expense, income tax expense, depreciation and amortization expense, exploration expense and non-cash items of income.

 

The write off of $38.5 million to bad debt expense associated with the bankruptcy of BWOC is excluded from the calculation of EBITDAX, per the Agreement.

 

The Agreement contains a current ratio covenant which, as defined, must be at least 1.0.  The total outstanding debt at December 31, 2009 under the Agreement, as amended, and the Line of Credit was $372 million and zero, respectively, and $4 million in letters of credit have been issued under the facility, leaving $562 million in borrowing capacity available.  The maximum amount available is subject to semi-annual redeterminations of the borrowing base, based on the value of the Company’s proved oil and gas reserves, in April and October of each year in accordance with the lenders’ customary procedures and practices.  Both the Company and the banks have the bilateral right to one additional redetermination each year.  The Agreement is collateralized by oil and natural gas properties representing at least 80% of the present value of the Company’s proved reserves.

 

Second Lien Term Loan

 

On April 27, 2009 the Company completed a $140 million second lien term loan, with lenders from among its current lending group, with a maturity of January 16, 2013.  The Company paid off the second lien term loan on May 29, 2009 from the proceeds of the issuance of its 10.25% senior notes due 2014, and wrote off $7.2 million in deferred loan fees for the year ended December 31, 2009.

 

10.25% senior notes due 2014

 

On May 27, 2009, the Company issued in a public offering $325 million principal amount of 10.25% senior notes due 2014 ($325 million Notes).  Interest on the $325 million Notes is paid semiannually in June and December of each year.  The $325 million Notes were issued at a discount to par value of 93.546%, and are carried on the balance sheet at their amortized cost. The deferred costs of approximately $9.5 million associated with the issuance of this debt are being amortized over the five year life of the $325 million Notes.  Pursuant to the terms of the Company’s senior secured revolving credit facility, the issuance of the $325 million Notes automatically reduced its borrowing base by 25 cents per dollar of Notes issued, or approximately $81 million.  The Company wrote off $3.3 million of deferred loan fees during the second quarter of 2009 as a result of the decrease in its borrowing base.

 

On August 13, 2009, the Company issued in a public offering an additional $125 million principal amount of  its 10.25% senior notes due 2014 ($125 million notes and, together with the $325 million notes, the Notes).  The $125 million Notes were issued at a premium to par value of 104.75%, and are carried on the balance sheet at their amortized cost. The deferred costs of approximately $1.9 million associated with the issuance of this debt are being amortized over the five year life of the Notes.  Pursuant to the terms of the Company’s senior secured revolving credit facility, the issuance of the $125 million Notes automatically reduced its borrowing base by 25 cents per dollar of notes issued, or approximately $31 million.  The Company wrote off $0.3 million of deferred loan fees during the third quarter of 2009 as a result of the decrease in its borrowing base.

 

The $125 million Notes and the previously issued $325 million Notes are treated as a single series of debt securities and are carried on the balance sheet at their combined amortized cost.

 

8.25% senior subordinated notes due 2016

 

In 2006, the Company issued in a public offering $200 million of 8.25% senior subordinated notes due 2016 (the Sub notes).  Interest on the Sub notes is paid semiannually in May and November of each year.   The deferred costs of

 

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approximately $5.2 million associated with the issuance of this debt are being amortized over the ten year life of the Sub notes.

 

Financial Covenants

 

The senior secured revolving credit facility contains restrictive covenants as described above.  Under the Company’s senior subordinated and senior unsecured notes as long as the interest coverage ratio (as defined) is greater than 2.5 times, the Company may incur additional debt.  The Company was in compliance with all of these covenants as of December 31, 2009.

 

 

 

As of
December 31, 2009

 

Current Ratio (Not less than 1.0)

 

5.5

 

Total Funded Debt Ratio to EBITDAX (Not greater than 4.75)

 

3.3

 

Interest Coverage Ratio (Not less than 2.5)

 

4.2

 

Senior Secured Debt Ratio to EBITDAX (Not greater than 3.75)

 

1.2

 

 

The weighted average interest rate on the Company’s total outstanding borrowings was 7.0% and 4.9% at December 31, 2009 and 2008, respectively.

 

8.                                      Income Taxes

 

The continuing operations provision for income taxes consists of the following (in thousands):

 

 

 

2009

 

2008

 

2007

 

Current:

 

 

 

 

 

 

 

Federal

 

$

2,388

 

$

2,991

 

$

12,676

 

State

 

(198

)

5,285

 

5,191

 

 

 

2,190

 

8,276

 

17,867

 

Deferred:

 

 

 

 

 

 

 

Federal

 

28,221

 

56,919

 

52,235

 

State

 

(2,062

)

5,113

 

8,958

 

 

 

26,159

 

62,032

 

61,193

 

Total

 

$

28,349

 

$

70,308

 

$

79,060

 

 

The following table summarizes the components of the total deferred tax assets and liabilities. The components of the net deferred tax liability consist of the following at December 31 (in thousands):

 

 

 

2009

 

2008

 

Deferred tax asset:

 

 

 

 

 

Federal benefit of state taxes

 

$

6,064

 

$

11,082

 

Credit carryforwards

 

27,729

 

33,636

 

Stock option costs

 

11,091

 

9,089

 

Derivatives

 

42,218

 

2,282

 

Bad debt expense

 

15,605

 

15,936

 

Other, net

 

1,807

 

4,312

 

 

 

104,514

 

76,337

 

Deferred tax liability:

 

 

 

 

 

Depreciation and depletion

 

(330,836

)

(319,349

)

Derivatives

 

(5,216

)

(72,801

)

 

 

(336,052

)

(392,150

)

Net deferred tax liability

 

$

(231,538

)

$

(315,813

)

 

At December 31, 2009, the Company’s net deferred tax assets and liabilities were recorded as a current asset of $5.6 million and a long-term liability of $237.2 million. At December 31, 2008, the Company’s net deferred tax assets and liabilities were recorded as a current liability of $45.5 million and a long-term liability of $270.3 million.

 

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Table of Contents

 

Reconciliation of the continuing operations statutory federal income tax rate to the effective income tax rate follows:

 

 

 

2009

 

2008

 

2007

 

Tax computed at statutory federal rate

 

35

%

35

%

35

%

State income taxes, net of federal benefit

 

4

 

3

 

5

 

Deferred state rate impact

 

(4

)

(1

)

 

Net impact to uncertain tax positions

 

(2

)

 

 

Other

 

(1

)

(1

)

(2

)

Effective tax rate

 

32

%

36

%

38

%

 

The Company has approximately $14 million of federal and $15 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2024 and 2016 for federal and California purposes, respectively.

 

In June 2006, the FASB issued authoritative guidance on accounting for uncertainty in income taxes. The guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. The Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. There is also guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires additional disclosures.

 

As of December 31, 2009, the Company had a gross liability for uncertain tax benefits of $6.1 million of which $5.2 million, if recognized, would affect the effective tax rate. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. The Company had accrued approximately $0.7 million and $1.2 million of interest related to its uncertain tax positions as of December 31, 2009 and 2008, respectively.

 

For the year ended December 31, 2009 the Company recognized a net benefit of approximately $4.0 million to the Statements of Income due to audit settlements and the closure of certain federal and state tax years and uncertain tax positions accruals, net of interest expense, of approximately $0.8 million.

 

For the year ended December 31, 2008 the Company recognized a net benefit of approximately $1.6 million to the Statements of Income due to the closure of certain federal and state tax years, offset by additional uncertain tax position accruals net of interest expense of approximately $1.9 million.

 

For the year ended December 31, 2007 the Company recognized a net benefit of approximately $0.6 million to the Statements of Income due to the closure of certain federal and state tax years, offset by additional uncertain tax position accruals net of interest expense of approximately $0.2 million.

 

The following table illustrates changes in the gross unrecognized tax benefits (in millions):

 

 

 

2009

 

2008

 

2007

 

Unrecognized tax benefits at January 1

 

$

12.0

 

$

12.0

 

$

14.6

 

(Decreases) increases for positions taken in current year

 

(0.1

)

1.2

 

0.5

 

(Decreases) increases for positions taken in a prior year

 

(1.3

)

0.3

 

(0.3

)

Decreases for settlements with taxing authorities

 

(3.6

)

 

 

Decreases for lapses in the applicable statute of limitations

 

(0.9

)

(1.5

)

(2.8

)

Unrecognized tax benefits at December 31

 

$

6.1

 

$

12.0

 

$

12.0

 

 

As of December 31, 2009, the Company remains subject to examination in the following major tax jurisdictions for the tax years indicated below:

 

Jurisdiction:

 

Tax Years Subject to Exam:

 

Federal

 

2005 – 2008

 

California

 

2005 – 2008

 

Colorado

 

2005 – 2008

 

Utah

 

2005 – 2008

 

 

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9.             Earnings Per Share

 

In June 2008, the FASB issued authoritative guidance, which clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the earnings allocation in computing basic earnings per share under the two-class method.  All prior period earnings per share data presented were adjusted retrospectively to conform with the provisions of the guidance which is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years.

 

The following table shows the computation of basic and diluted net (loss) income per share from continuing and discontinued operations for the years ended December 31, (in thousands):

 

 

 

2009

 

2008

 

2007

 

Net income from continuing operations

 

$

59,968

 

$

121,776

 

$

127,284

 

Less: Income allocable to participating securities

 

1,460

 

1,752

 

1,494

 

Income available for shareholders

 

$

58,508

 

$

120,024

 

$

125,790

 

 

 

 

 

 

 

 

 

Net (loss) income from discontinued operations

 

$

(5,938

)

$

11,753

 

$

2,644

 

Less: Income allocable to participating securities

 

 

173

 

32

 

Loss (income) from discontinued operations available for shareholders

 

$

(5,938

)

$

11,580

 

$

2,612

 

 

 

 

 

 

 

 

 

Basic earnings per share from continuing operations

 

$

1.31

 

$

2.70

 

$

2.85

 

Basic (loss) earnings per share from discontinued operations

 

(0.13

)

.26

 

.06

 

Basic earnings per share

 

$

1.18

 

$

2.96

 

$

2.91

 

 

 

 

 

 

 

 

 

Dilutive earnings per share from continuing operations

 

$

1.30

 

$

2.66

 

$

2.81

 

Dilutive (loss) earnings per share from discontinued operations

 

(0.13

)

.26

 

.06