Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended September 30, 2010

 

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

 

For the transition period from     to     

 

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

 

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 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

 

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 October 15, 2010 the registrant had 53,032,471 shares of Class A Common Stock ($.01 par value) outstanding. The registrant also had 1,797,784 shares of Class B Stock ($.01 par value) outstanding on October 15, 2010 all of which is held by an affiliate of the registrant.

 

 

 



Table of Contents

 

BERRY PETROLEUM COMPANY

INDEX TO FORM 10-Q

September 30, 2010

 

 

 

Page

 

 

 

PART I. FINANCIAL INFORMATION

 

 

Item 1. Financial Statements

1

 

Condensed Balance Sheets at September 30, 2010 and December 31, 2009

1

 

Condensed Statements of Income (Loss) for the Three and Nine Months Ended September 30, 2010 and 2009

2

 

Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009

3

 

Condensed Statements of Shareholders’ Equity for the Nine Months Ended September 30, 2010

4

 

Notes to Condensed Financial Statements

5

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

18

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

30

 

Item 4. Controls and Procedures

33

 

 

 

PART II. OTHER INFORMATION

 

 

Item 1. Legal Proceedings

34

 

Item 1A. Risk Factors

34

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

36

 

Item 3. Defaults Upon Senior Securities

36

 

Item 4. Removed and Reserved

36

 

Item 5. Other Information

36

 

Item 6. Exhibits

36

Signatures

36

 

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BERRY PETROLEUM COMPANY

Condensed Balance Sheets

(Unaudited)

(In Thousands, Except Share Information)

 

 

 

September 30,
2010

 

December 31,
2009

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

54

 

$

5,311

 

Short-term investments

 

65

 

66

 

Accounts receivable, net of allowance for doubtful accounts of $0 and $38,508, respectively

 

84,502

 

74,337

 

Deferred income taxes

 

11,882

 

5,623

 

Derivative instruments

 

5,414

 

11,527

 

Prepaid expenses and other

 

14,854

 

6,612

 

Total current assets

 

116,771

 

103,476

 

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

 

2,409,225

 

2,106,385

 

Derivative instruments

 

3,082

 

735

 

Other assets

 

24,804

 

29,539

 

 

 

$

2,553,882

 

$

2,240,135

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

94,756

 

$

63,096

 

Revenue and royalties payable

 

28,160

 

25,878

 

Accrued liabilities

 

46,075

 

29,320

 

Derivative instruments

 

44,910

 

33,843

 

Total current liabilities

 

213,901

 

152,137

 

Long-term liabilities:

 

 

 

 

 

Deferred income taxes

 

319,279

 

237,161

 

Senior secured revolving credit facility

 

240,000

 

372,000

 

8.25% Senior subordinated notes due 2016

 

200,000

 

200,000

 

10.25% Senior notes due 2014, net of unamortized discount of $11,666 and $13,456, respectively

 

438,334

 

436,544

 

Asset retirement obligation

 

51,161

 

43,487

 

Other long-term liabilities

 

18,386

 

19,711

 

Derivative instruments

 

32,566

 

75,836

 

 

 

1,299,726

 

1,384,739

 

Shareholders’ equity:

 

 

 

 

 

Preferred stock, $.01 par value, 2,000,000 shares authorized; no shares outstanding

 

 

 

Capital stock, $.01 par value:

 

 

 

 

 

Class A Common Stock, 100,000,000 shares authorized; 53,009,221 and 42,952,499 shares issued and outstanding, respectively

 

512

 

430

 

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

 

322,600

 

89,068

 

Accumulated other comprehensive loss

 

(48,533

)

(60,372

)

Retained earnings

 

765,658

 

674,115

 

Total shareholders’ equity

 

1,040,255

 

703,259

 

 

 

$

2,553,882

 

$

2,240,135

 

 

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

 

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Table of Contents

 

BERRY PETROLEUM COMPANY

Condensed Statements of Income (Loss)

(Unaudited)

(In Thousands, Except Per Share Data)

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

REVENUES AND OTHER INCOME ITEMS

 

 

 

 

 

 

 

 

 

Sales of oil and gas

 

$

151,671

 

$

127,455

 

$

451,003

 

$

374,117

 

Sales of electricity

 

9,451

 

9,137

 

27,313

 

26,032

 

Gas marketing

 

4,918

 

5,217

 

18,194

 

17,646

 

Realized and unrealized (loss) gain on derivatives, net

 

(27,178

)

531

 

30,482

 

6,565

 

Settlement of Flying J bankruptcy claim

 

 

 

21,992

 

 

Gain on sale of assets

 

 

828

 

 

828

 

Interest and other income, net

 

362

 

287

 

2,320

 

1,375

 

 

 

139,224

 

143,455

 

551,304

 

426,563

 

EXPENSES

 

 

 

 

 

 

 

 

 

Operating costs - oil and gas production

 

46,782

 

39,195

 

140,269

 

111,317

 

Operating costs - electricity generation

 

7,220

 

6,892

 

24,729

 

22,071

 

Production taxes

 

6,215

 

3,874

 

16,484

 

14,411

 

Depreciation, depletion & amortization - oil and gas production

 

49,367

 

33,502

 

128,976

 

104,271

 

Depreciation, depletion & amortization - electricity generation

 

819

 

951

 

2,407

 

2,938

 

Gas marketing

 

4,067

 

4,633

 

16,209

 

16,149

 

General and administrative

 

12,399

 

10,686

 

38,389

 

37,143

 

Interest

 

15,586

 

14,562

 

49,373

 

35,201

 

Extinguishment of debt

 

 

329

 

 

10,823

 

Transaction costs on acquisitions

 

 

 

2,635

 

 

Dry hole, abandonment, impairment and exploration

 

586

 

69

 

2,221

 

209

 

Bad debt recovery

 

 

 

(38,508

)

 

 

 

143,041

 

114,693

 

383,184

 

354,533

 

Income (loss) before income taxes

 

(3,817

)

28,762

 

168,120

 

72,030

 

Income tax (benefit) provision

 

(794

)

10,423

 

64,450

 

24,681

 

Income (loss) from continuing operations

 

(3,023

)

18,339

 

103,670

 

47,349

 

Income (loss) from discontinued operations, net of taxes

 

 

668

 

 

(6,323

)

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(3,023

)

$

19,007

 

$

103,670

 

$

41,026

 

 

 

 

 

 

 

 

 

 

 

Basic net (loss) income from continuing operations per share

 

$

(0.06

)

$

0.41

 

$

1.94

 

$

1.04

 

Basic net income (loss) from discontinued operations per share

 

$

 

$

0.01

 

$

 

$

(0.14

)

Basic net (loss) income per share

 

$

(0.06

)

$

0.42

 

$

1.94

 

$

0.90

 

 

 

 

 

 

 

 

 

 

 

Diluted net (loss) income from continuing operations per share

 

$

(0.06

)

$

0.40

 

$

1.93

 

$

1.03

 

Diluted net income (loss) from discontinued operations per share

 

$

 

$

0.01

 

$

 

$

(0.14

)

Diluted net (loss) income per share

 

$

(0.06

)

$

0.41

 

$

1.93

 

$

0.89

 

 

 

 

 

 

 

 

 

 

 

Dividends per share

 

$

0.075

 

$

0.075

 

$

0.225

 

$

0.225

 

 

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

 

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BERRY PETROLEUM COMPANY

Condensed Statements of Cash Flows

(Unaudited)

(In Thousands)

 

 

 

Nine months ended September 30,

 

 

 

2010

 

2009

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

103,670

 

$

41,026

 

Depreciation, depletion and amortization

 

131,383

 

109,397

 

Extinguishment of debt

 

 

10,823

 

Amortization of debt issue costs and net discount

 

6,383

 

4,891

 

Dry hole and impairment

 

1,477

 

9,643

 

Unrealized (gain) loss on derivatives

 

(8,999

)

4,796

 

Stock-based compensation expense

 

7,134

 

7,054

 

Deferred income taxes

 

67,533

 

13,546

 

Loss on sale of oil and natural gas properties

 

 

79

 

Other, net

 

 

(5,253

)

Cash paid for abandonment

 

(1,830

)

(293

)

Bad debt recovery

 

(38,508

)

 

Change in book overdraft

 

8,309

 

(20,199

)

Decrease (increase) in current assets other than cash and cash equivalents

 

19,852

 

(9,828

)

Increase (decrease) in current liabilities other than book overdraft and line of credit

 

22,117

 

(17,303

)

Net cash provided by operating activities

 

318,521

 

148,379

 

Cash flows from investing activities:

 

 

 

 

 

Exploration and development of oil and gas properties

 

(230,955

)

(94,636

)

Property acquisitions

 

(154,517

)

(11,904

)

Capitalized interest

 

(20,402

)

(21,145

)

Proceeds from sale of assets

 

 

139,796

 

Net cash (used in) provided by investing activities

 

(405,874

)

12,111

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from issuances on line of credit

 

219,200

 

323,100

 

Payments on line of credit

 

(219,200

)

(335,900

)

Proceeds from issuance of 10.25% senior notes

 

 

434,962

 

Long-term borrowings under credit facility

 

165,000

 

643,300

 

Repayments of long-term borrowings under credit facility

 

(297,000

)

(1,210,100

)

Debt issue costs

 

 

(23,857

)

Proceeds from financing obligation

 

 

18,295

 

Financing obligation

 

(257

)

 

Dividends paid

 

(12,127

)

(10,247

)

Proceeds from issuance of common stock, net

 

224,313

 

 

Proceeds from stock option exercises

 

1,762

 

601

 

Excess tax benefit and other

 

405

 

91

 

Net cash provided by (used in) financing activities

 

82,096

 

(159,755

)

 

 

 

 

 

 

Net (decrease) increase in cash and cash equivalents

 

(5,257

)

735

 

Cash and cash equivalents at beginning of year

 

5,311

 

240

 

Cash and cash equivalents at end of period

 

$

54

 

$

975

 

 

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

 

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BERRY PETROLEUM COMPANY

Condensed Statement of Shareholders’ Equity

(Unaudited)

(In Thousands, Except Per Share Data)

 

 

 

Class
A

 

Class
B

 

Capital in
Excess of Par
Value

 

Retained
Earnings

 

Accumulated
Other
Comprehensive
Income (Loss)

 

Total
Shareholders’
Equity

 

Balances at December 31, 2009

 

430

 

18

 

89,068

 

674,115

 

(60,372

)

703,259

 

Issuance of stock

 

80

 

 

224,233

 

 

 

224,313

 

Exercise of stock options

 

1

 

 

1,760

 

 

 

1,761

 

Restricted stock issued

 

1

 

 

 

 

 

1

 

Stock based compensation

 

 

 

7,134

 

 

 

7,134

 

Tax effect of stock option exercises

 

 

 

405

 

 

 

405

 

Dividends

 

 

 

 

(12,127

)

 

(12,127

)

Comprehensive income:

 

 

 

 

 

 

 

Net income

 

 

 

 

103,670

 

 

103,670

 

Net change from hedging activity

 

 

 

 

 

11,839

 

11,839

 

Total comprehensive Income

 

 

 

 

 

 

115,509

 

Balances at September 30, 2010

 

$

512

 

$

18

 

$

322,600

 

$

765,658

 

$

(48,533

)

$

1,040,255

 

 

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

 

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Berry Petroleum Company

Notes to Condensed Financial Statements

 

1.       Basis of Presentation

 

These Condensed Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial reporting.  All adjustments which are, in the opinion of management, necessary to present fairly Berry Petroleum Company’s (the Company) financial position at September 30, 2010, the results of operations for the three and nine months ended September 30, 2010 and 2009,  its cash flows for the nine months ended September 30, 2010 and 2009 and shareholders’ equity for the nine months ended September 30, 2010 have been included. Interim results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for oil and natural gas, as well as other factors.  In the course of preparing the Condensed Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and, accordingly, actual results could differ from amounts previously established.

 

The Company’s Condensed Financial Statements have been prepared on a basis consistent with the accounting principles and policies reflected in the Company’s audited financial statements as of and for the year ended December 31, 2009.  The year-end Condensed Balance Sheet was derived from audited Financial Statements included in such report, but does not include all disclosures required by GAAP.  The Company has revised comprehensive income (loss) to reflect the correction of a prior period presentation error.  The Company has concluded that the presentation error was immaterial to the previously filed financial statements. See Note 4 to the Condensed Financial Statements.

 

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 September 30, 2010 and December 31, 2009 is $24.0 million and $15.7 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

 

2.       Acquisitions and Divestitures

 

Acquisitions

 

In March 2010, the Company acquired interests in producing properties principally on 6,900 net acres in the Permian basin of West Texas (W. Texas) for $133 million, comprised of an initial purchase price of $126 million, and customary post-closing adjustments of approximately $7 million (the March Acquisition).  The March Acquisition was financed with the proceeds from the issuance of the Company’s Class A Common Stock in January 2010.  In April 2010, the Company closed on the acquisition of an additional 3,200 net acres in the Permian basin for approximately $14 million, including normal post closing adjustments (the April Acquisition and, together with the March Acquisition, the Permian Basin Acquisitions).  The Permian Basin Acquisitions included properties with total proved reserves of approximately 13 MMBOE, of which 83% were crude oil and 21% were proved developed.

 

The Permian Basin Acquisitions qualify as business combinations and, as such, the Company estimated the fair value of each property as of the acquisition date (the date on which the Company obtained control of the properties).  The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  Fair value measurements also utilize assumptions of market participants.  The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.  These assumptions represent Level 3 inputs.

 

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The following table summarizes the consideration paid to the seller and the amounts of the assets acquired and liabilities assumed in the March Acquisition.

 

 

 

(In thousands)

 

Consideration paid to seller:

 

 

 

Cash consideration

 

$

133,301

 

 

 

 

 

Recognized amounts of identifiable assets acquired and liabilities assumed:

 

 

 

Proved developed and undeveloped properties

 

134,546

 

Other assets acquired

 

354

 

Asset retirement obligation

 

(1,367

)

Other liabilities assumed

 

(232

)

 

 

 

 

Total identifiable net assets

 

$

133,301

 

 

The March Acquisition had an effective date of January 1, 2010, and activity from January 1, 2010 through March 4, 2010 was treated as purchase price adjustments.  The preliminary purchase price allocation included an estimate for activity between January 1, 2010 and March 4, 2010; however, actual amounts were greater than the Company’s estimate which resulted in an increase to the total cash consideration paid to the seller.  As a result, the initial $1.4 million of gain on purchase of oil and natural gas properties recorded in the first quarter of 2010 was reversed in the second quarter of 2010 to reflect the purchase price adjustments.

 

The following table summarizes the consideration paid to the seller and the amounts of the assets acquired and liabilities assumed in the April Acquisition.

 

 

 

(In thousands)

 

Consideration paid to seller:

 

 

 

Cash consideration

 

$

14,322

 

 

 

 

 

Recognized amounts of identifiable assets acquired and liabilities assumed:

 

 

 

Proved developed and undeveloped properties

 

16,264

 

Asset retirement obligation

 

(1,942

)

 

 

 

 

Total identifiable net assets

 

$

14,322

 

 

Acquisition costs of $0.0 million and $2.6 million have been recorded in the Condensed Statements of Income (Loss) under the caption Transaction costs on acquisitions in the three and nine months ended September 30, 2010, respectively.  Revenues of $8.4 million and $17.1 million generated by the acquired properties have been included in the accompanying Condensed Statements of Income (Loss) in the three and nine months ended September 30, 2010, respectively.  Earnings of $2.9 million and $5.5 million generated by the Permian Basin Acquisitions have been included in the accompanying Condensed Statements of Income (Loss) in the three and nine months ended September 30, 2010, respectively.

 

Divestitures

 

On March 3, 2009, the Company entered into an agreement to sell its assets in the Denver-Julesburg basin in Colorado (DJ basin) 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 reflected within the $6.3 million Income (loss) from discontinued operations, net of taxes, on its Condensed Statement of Income (Loss) for the nine months ended September 30, 2009.

 

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Income (loss) from discontinued operations, net of taxes, on the accompanying Condensed Statements of Income (Loss) is comprised of the following (in thousands):

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

 

$

(578

)

$

 

$

5,111

 

Total expenses

 

 

 

 

16,283

 

Loss from discontinued operations, before income taxes

 

 

(578

)

 

(11,172

)

Income tax benefit

 

 

1,246

 

 

4,849

 

Income (loss) from discontinued operations, net of taxes

 

$

 

$

668

 

$

 

$

(6,323

)

 

3.       Shareholders’ Equity

 

In January 2010, the Company issued 8 million shares of Class A Common Stock at a price of $29.25 per share. Net proceeds from this offering were $224.3 million after deducting underwriting discounts and commissions and offering expenses. The Company used the net proceeds from the offering to fund the purchase of the March Acquisition (as defined above) and to repay a portion of the outstanding borrowings under the senior secured revolving credit facility.  See Note 2 to the Condensed Financial Statements.

 

4.       Earnings per Share and Comprehensive Income (Loss)

 

Basic (loss) earnings per common share is calculated by dividing adjusted income (loss) available to common shareholders by the weighted average number of common shares outstanding during each period.  Diluted (loss) earnings per common share is calculated by dividing (loss) income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method.  When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share accordingly.

 

The two-class method of computing earnings (loss) per share is required for those entities that have participating securities. The two- class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings.  Restricted stock issued prior to January 1, 2010 under the Company’s equity incentive plans has the right to receive non-forfeitable dividends, participating on an equal basis with common stock. Restricted stock issued subsequent to January 1, 2010 under the Company’s stock incentive plans no longer has the right to receive non-forfeitable dividends.  Stock units issued to directors under the Company’s nonemployee directors deferred compensation plan also have the right to be credited with non-forfeitable dividends, participating on an equal basis with common stock.  Therefore, unvested restricted stock and stock units issued to directors issued prior to January 1, 2010 must be allocated to both common stock and these participating securities under the two-class method.  Stock options issued under the Company’s stock incentive plans do not participate in dividends.

 

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The following table shows the computation of basic and diluted earnings (loss) per share from continuing and discontinued operations for the three and nine months ended September, 2010 and 2009 (in thousands):

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

Net income (loss) from continuing operations

 

$

(3,023

)

$

18,339

 

$

103,670

 

$

47,349

 

Less: income allocable to participating securities

 

 

445

 

2,011

 

1,153

 

(Loss) income available for shareholders

 

$

(3,023

)

$

17,894

 

$

101,659

 

$

46,196

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) from discontinued operations

 

$

 

$

668

 

$

 

$

(6,323

)

Less: Income allocable to participating securities

 

 

17

 

 

 

Income (loss) from discontinued operations available for shareholders

 

$

 

$

651

 

$

 

$

(6,323

)

 

 

 

 

 

 

 

 

 

 

Basic (loss) earnings per share from continuing operations

 

$

(0.06

)

$

0.41

 

$

1.94

 

$

1.04

 

Basic earnings (loss) per share from discontinued operations

 

 

0.01

 

 

(0.14

)

Basic (loss) earnings per share

 

$

(0.06

)

$

0.42

 

$

1.94

 

$

0.90

 

 

 

 

 

 

 

 

 

 

 

Diluted (loss) earnings per share from continuing operations

 

$

(0.06

)

$

0.40

 

$

1.93

 

$

1.03

 

Diluted earnings (loss) per share from discontinued operations

 

 

0.01

 

 

(0.14

)

Diluted (loss) earnings per share

 

$

(0.06

)

$

0.41

 

1.93

 

$

0.89

 

 

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding - basic

 

53,007

 

44,633

 

52,357

 

44,607

 

Add: Dilutive effects of stock options and RSUs

 

 

303

 

386

 

189

 

Weighted average shares outstanding - dilutive

 

53,007

 

44,936

 

52,743

 

44,796

 

 

Options to purchase 2.2 million shares and 1.2 million shares were not included in the diluted earnings per share calculation for the three and nine months ended September 30, 2010, respectively, because their effect would have been anti-dilutive.  Options to purchase 1.2 million and 1.6 million shares were not included in the diluted earnings (loss) per share calculation for the three and nine months ended September 30, 2009, respectively, because their effect would have been anti-dilutive.

 

Comprehensive Income (Loss)

 

Comprehensive income (loss) is a term used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders’ equity instead of net income (loss).  The components of other comprehensive income (loss) were as follows:

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

(in millions)

 

2010

 

2009 (1)

 

2010

 

2009 (1)

 

Net income (loss)

 

$

(3,023

)

$

19,007

 

$

103,670

 

$

41,026

 

Unrealized gains (losses) on derivatives, net of income taxes of $0, $2,026, $0 and ($49,746), respectively

 

 

3,306

 

 

(81,166

)

Reclassifications of realized (gains) losses, net of income taxes of $2,694, ($1,403), $7,283 and ($30,487), respectively

 

4,395

 

(2,289

)

11,839

 

(49,741

)

Comprehensive income (loss)

 

$

1,372

 

$

20,024

 

$

115,509

 

$

(89,881

)

 


(1) The Company revised comprehensive income (loss) to reflect the correction of a prior period presentation error.  The table below summarizes the changes:

 

 

 

For the Three Months Ended
September 30, 2009

 

For the Nine Months Ended
September 30, 2009

 

 

 

As Previously
Reported

 

As Revised

 

As Previously
Reported

 

As Revised

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

19,007

 

$

19,007

 

$

41,026

 

$

41,026

 

Unrealized gains (losses) on derivatives, net of income taxes

 

(563

)

3,306

 

169,966

 

(81,166

)

Reclassification of realized (gains) losses, net of income taxes

 

(454

)

(2,289

)

(39,059

)

(49,741

)

Comprehensive income (loss)

 

$

17,990

 

$

20,024

 

$

171,933

 

$

(89,881

)

 

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Table of Contents

 

5.                      Asset Retirement Obligation (ARO)

 

The following table summarizes the change in the ARO for the nine months ended September 30 (in thousands):

 

 

 

2010

 

2009

 

Beginning balance at January 1

 

$

43,487

 

$

41,967

 

Liabilities incurred

 

2,825

 

1,407

 

Liabilities settled

 

(1,830

)

(293

)

Liabilities assumed

 

3,309

 

 

Disposition of assets

 

 

(2,751

)

Accretion expense

 

3,370

 

2,899

 

Ending balance at September 30

 

$

51,161

 

$

43,229

 

 

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.

 

6.                    Debt Obligations

 

Short-term line of credit

 

Borrowings under the Company’s senior secured money market line of credit (the Secured Line of Credit) may be up to $30 million for a maximum of 30 days.  The Secured Line of Credit may be terminated at any time upon written notice by either the Company or the lender.

 

There were no outstanding borrowings on the Secured Line of Credit at September 30, 2010 or December 31, 2009.  Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1.4%.

 

Senior secured revolving credit facility

 

As of September 30, 2010, the Company’s senior secured revolving credit facility (the Agreement) has a 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:

 

2010

 

Thereafter

 

to Sep 2010

 

Mar 2011

 

Sep 2011

 

Thereafter

 

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 or loss.

 

The Agreement also contains a current ratio covenant which, as defined, must be at least 1.0.  The total outstanding debt at September 30, 2010 under the Agreement, as amended, and the Secured Line of Credit was $240 million and $24 million in letters of credit have been issued under the facility, leaving $674 million in borrowing capacity available under the Agreement.  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.

 

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 semi-annually 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 Condensed Balance Sheet at their amortized cost. The

 

9



Table of Contents

 

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.

 

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 Condensed 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 $125 million Notes.

 

The $125 million Notes and the $325 million Notes are treated as a single series of debt securities and are carried on the Condensed 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 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 Agreement contains restrictive covenants as described above.  Under the Company’s Notes and Sub 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 September 30, 2010.

 

 

 

As of September 30, 2010

 

Current Ratio (Not less than 1.0)

 

4.65

 

Total Funded Debt Ratio to EBITDAX (Not greater than 4.50)

 

2.38

 

Interest Coverage Ratio (Not less than 2.5)

 

4.40

 

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

 

0.69

 

 

The weighted average interest rate on the Company’s total outstanding borrowings was 7.7% and 7.0% at September 30, 2010 and December 31, 2009, respectively.

 

7.         Fair Value Measurements

 

The authoritative guidance for fair value measurements 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. The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. Oil swaps, natural gas swaps and interest rate swaps are valued using models which are based on active market data and are classified within Level 2 of the fair value 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. Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  The fair value of all derivative instruments are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services, and the Company has made no adjustments to the obtained prices.  The pricing services publish observable market information from multiple brokers and exchanges.  No proprietary models are used by the pricing services for the inputs.  All valuations were compared against counterparty valuations to verify the reasonableness of prices. 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 Company recognizes transfers between levels at the end of the reporting period for which the transfer has occurred.

 

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Table of Contents

 

The following tables set forth by level within the fair value hierarchy the Company’s net derivative assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2010 and December 31, 2009.

 

Assets and liabilities measured at fair value on a recurring basis

 

September 30, 2010 (in millions)

 

Total carrying value
on the Condensed Balance Sheet

 

Level 2

 

Level 3

 

 

 

 

 

 

 

 

 

Commodity derivatives liability, net

 

$

(57.2

)

$

(15.7

)

$

(41.5

)

Interest rate derivatives liability, net

 

(11.8

)

(11.8

)

 

Total derivative liabilities, net at fair value

 

$

(69.0

)

$

(27.5

)

$

(41.5

)

 

 

 

 

 

 

 

 

December 31, 2009 (in millions)

 

Total carrying value on the
Condensed Balance Sheet

 

Level 2

 

Level 3

 

 

 

 

 

 

 

 

 

Commodity derivatives liability, net

 

$

(88.5

)

$

(62.5

)

$

(26.0

)

Interest rate derivatives liability, net

 

(8.9

)

(8.9

)

 

Total derivative liabilities, net at fair value

 

$

(97.4

)

$

(71.4

)

$

(26.0

)

 

Changes in Level 3 fair value measurements

 

The table below includes a rollforward of the Condensed Balance Sheet amounts (including the change in fair value) for financial instruments classified by the Company within Level 3 of the fair value hierarchy. When a determination is made to classify a financial instrument within Level 3 of the fair value 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).

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

(in millions)

 

2010

 

2009

 

2010

 

2009

 

Fair value (liability) asset, beginning of period

 

$

(4.0

)

$

43.1

 

$

(26.0

)

$

172.5

 

Total realized and unrealized gains (losses)

 

 

 

 

 

 

 

 

 

Realized and unrealized (loss) gain included in income

 

(25.6

)

14.1

 

16.3

 

55.6

 

Unrealized (loss) gain included in accumulated other comprehensive loss

 

 

(10.4

)

 

(142.2

)

Purchases, sales and settlements, net

 

(11.9

)

(14.2

)

(31.8

)

(56.7

)

Transfers into and/or out of Level 3

 

 

 

 

3.4

 

Fair value (liability) asset, end of period

 

$

(41.5

)

$

32.6

 

$

(41.5

)

$

32.6

 

 

 

 

 

 

 

 

 

 

 

Total unrealized (loss) gain included in income related to financial assets and liabilities still on the Condensed Balance Sheet at September 30, 2010 and 2009

 

$

(37.5

)

$

(0.2

)

$

(15.5

)

$

(1.2

)

 

The $3.4 million of transfers out of Level 3 for the nine months ended September 30, 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 8 to the Condensed Financial Statements.

 

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Table of Contents

 

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 and could be at similar rates today. 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.

 

 

 

As of September 30, 2010

 

(in millions)

 

Carrying
Amount

 

Estimated
Fair Value

 

 

 

 

 

 

 

Line of credit

 

$

 

$

 

Senior secured revolving credit facility

 

240

 

240

 

8.25% Senior subordinated notes due 2016

 

200

 

207

 

10.25% Senior notes due 2014

 

438

 

493

 

 

 

$

878

 

$

940

 

 

 

 

As of December 31, 2009

 

(in millions)

 

Carrying
Amount

 

Estimated
Fair Value

 

 

 

 

 

 

 

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

 

 

8.                      Derivative Instruments

 

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable, economic cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices received for a portion of the Company’s oil and natural gas production.   The terms of the 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.  The Company periodically enters into interest rate derivative agreements to protect against changes in interest rates on its floating rate debt.  For further discussion related to the fair value of the Company’s derivatives see Note 7 to the Condensed Financial Statements.

 

As of September 30, 2010, the Company had the following commodity derivatives:

 

 

 

2010

 

2011

 

2012

 

2013

 

Oil Bbl/D:

 

15,930

 

15,520

 

10,000

 

4,000

 

Natural Gas MMBtu/D:

 

19,000

 

15,000

 

15,000

 

 

 

The Company entered into the following crude oil two-way collars during the nine months ended September 30, 2010:

 

 

 

Average

 

 

 

 

 

Barrels

 

Floor/Ceiling

 

Term

 

Per Day

 

Prices

 

Full year 2010

 

500

 

$75.00/$93.95

 

Full year 2010

 

500

 

$75.00/$94.45

 

Full year 2011

 

500

 

$75.00/$100.75

 

Full year 2011

 

500

 

$75.00/$101.15

 

Full year 2011

 

1,000

 

$75.00/$91.25

 

Full year 2012

 

500

 

$75.00/$105.00

 

Full year 2012

 

500

 

$75.00/$106.00

 

Full year 2012

 

1,000

 

$75.00/$95.00

 

 

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Table of Contents

 

The Company entered into the following crude oil three-way collars during the nine months ended September 30, 2010:

 

 

 

Average

 

 

 

 

 

Barrels

 

Floor/Swap/Ceiling

 

Term

 

Per Day

 

Prices

 

Full year 2011

 

1,000

 

$60.00 / $80.00 / $101.00

 

Full year 2011

 

1,000

 

$55.00 / $75.00 / $91.63

 

Full year 2011

 

500

 

$65.00 / $85.00 / $97.25

 

Full year 2011

 

1,000

 

$69.70 / $85.00 / $100.0

 

Full year 2011

 

1,000

 

$70.00 / $86.85 / $100.00

 

Full year 2012

 

1,000

 

$69.70 / $85.00 / $100.00

 

Full year 2012

 

1,000

 

$70.00 / $86.85 / $100.00

 

Full year 2012

 

1,000

 

$60.00 / $80.00 / $120.00

 

Full year 2012

 

1,000

 

$60.00 / $80.00 / $96.92

 

Full year 2012

 

1,000

 

$65.00 / $85.00 / $97.25

 

Full year 2013

 

1,000

 

$60.00 / $80.00 / $103.30

 

Full year 2013

 

1,000

 

$70.00 / $86.85/ $100.00

 

Full year 2013

 

1,000

 

$69.70 / $85.00 / $100.00

 

Full year 2013

 

1,000

 

$65.00 / $85.00 / $97.25

 

 

The Company entered into the following natural gas swaps during the nine months ended September 30, 2010:

 

 

 

Average

 

 

 

 

 

MMBtus

 

Swap

 

Term

 

Per Day

 

Prices

 

Full year 2011

 

5,000

 

$

5.50

 

Full year 2012

 

5,000

 

$

5.75

 

 

Discontinuance of cash flow hedge accounting

 

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 elected to de-designate all of its commodity and interest rate derivative contracts that had been previously designated as cash flow hedges as of December 31, 2009.  As a result, subsequent to December 31, 2009, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCL.

 

At December 31, 2009, AOCL consisted of $97.4 million, ($60.4 million, net of tax) of unrealized losses, representing the change in the fair value of the Company’s open commodity and interest rate 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, 2010, such fair values at December 31, 2009 are frozen in AOCL as of the de-designation date and reclassified into earnings as the original hedge transactions settle.  During the three and nine months ended September 30, 2010, $7.1 million ($4.4 million, net of tax) and $19.1 million ($11.8 million, net of tax), respectively, of amortization of AOCL relating to de-designated commodity and interest rate hedges were reclassified from AOCL into earnings.  As of September 30, 2010, AOCL consisted of $78.3 million ($48.5 million, net of tax) of unrealized losses on commodity and interest rate 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 $33.4 million related to de-designated commodity and interest rate derivative contracts during the next twelve months.

 

At September 30, 2010, the net fair value derivative liability was $69.0 million as compared to a net fair value derivative liability of $97.4 million at December 31, 2009 which reflects changes in commodity prices and interest rates. Based on NYMEX futures pricing as of September 30, 2010, the Company expects to make net payments under the existing derivatives of $30.9 million during the next twelve months.

 

The Company presents its derivative assets and liabilities on its Condensed Balance Sheets on a net basis, 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.  The related cash flow impact of all of the Company’s derivatives is reflected in cash flows from operating activities.

 

13



Table of Contents

 

The following tables detail the fair value of derivatives recorded on the Company’s Condensed Balance Sheets, by category:

 

 

 

As of September 30, 2010

 

 

 

Derivative Assets

 

Derivative Liabilities

 

(in millions)

 

Balance Sheet
Classification

 

Fair Value

 

Balance Sheet
Classification

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Total derivatives designated as hedging instruments

 

 

 

$

 

 

 

$

 

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

 

Commodity

 

Derivative assets

 

$

6.2

 

Derivative assets

 

$

 

Commodity

 

Derivative liabilities

 

 

Derivative liabilities

 

38.7

 

Interest rate

 

Derivative assets

 

 

Derivative assets

 

0.8

 

Interest rate

 

Derivative liabilities

 

 

Derivative liabilities

 

6.2

 

Long term:

 

 

 

 

 

 

 

 

 

Commodity

 

Derivative assets

 

3.6

 

Derivative assets

 

 

Commodity

 

Derivative liabilities

 

 

Derivative liabilities

 

28.3

 

Interest rate

 

Derivative assets

 

 

Derivative assets

 

0.5

 

Interest rate

 

Derivative liabilities

 

 

Derivative liabilities

 

4.3

 

Total derivatives not designated as hedging instruments

 

 

 

$

9.8

 

 

 

$

78.8

 

Total derivatives

 

 

 

$

9.8

 

 

 

$

78.8

 

 

 

 

As of December 31, 2009

 

 

 

Derivative Assets

 

Derivative Liabilities

 

(in millions)

 

Balance Sheet
Classification

 

Fair Value

 

Balance Sheet
Classification

 

Fair Value

 

Current:

 

 

 

 

 

 

 

 

 

Commodity

 

Derivative assets

 

$

15.5

 

Derivative assets

 

$

 

Commodity

 

Derivative liabilities

 

0.2

 

Derivative liabilities

 

30.8

 

Interest Rate

 

Derivative assets

 

 

Derivative assets

 

3.5

 

Interest Rate

 

Derivative liabilities

 

 

Derivative liabilities

 

2.7

 

Long term:

 

 

 

 

 

 

 

 

 

Commodity

 

Derivative assets

 

0.4

 

Derivative assets

 

 

Commodity

 

Derivative liabilities

 

1.2

 

Derivative liabilities

 

74.1

 

Interest rate

 

Derivative assets

 

0.3

 

Derivative assets

 

 

Interest rate

 

Derivative liabilities

 

 

Derivative liabilities

 

3.0

 

Total derivatives designated as hedging instruments

 

 

 

$

17.6

 

 

 

$

114.1

 

Current:

 

 

 

 

 

 

 

 

 

Commodity

 

 

 

$

 

Derivative assets

 

$

0.4

 

Commodity

 

 

 

 

Derivative liabilities

 

0.5

 

Total derivatives not designated as hedging instruments

 

 

 

$

 

 

 

$

0.9

 

Total derivatives

 

 

 

$

17.6

 

 

 

$

115.0

 

 

The tables below summarize the location and the amount of derivative instrument gains (losses) before income taxes reported in the Condensed Statements of Income (Loss) for the periods indicated (in millions):

 

 

 

Location of Gain (Loss)

 

Three months ended
September 30

 

Nine months ended
September 30,

 

Derivatives cash flow hedging relationships

 

Recognized in Income

 

2010

 

2009

 

2010

 

2009

 

Commodity

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) recognized in AOCL (effective portion)

 

Accumulated other comprehensive (loss)

 

$

 

$

9.3

 

$

 

$

(128.9

)

(Loss) gain reclassified from AOCL into income (effective portion)

 

Sales of oil and gas

 

(5.2

)

5.6

 

(12.1

)

84.7

 

(Loss) recognized in income (ineffective Portion)

 

Realized and unrealized (loss) gain on derivatives, net

 

 

(0.6

)

 

(0.2

)

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

 

 

 

 

 

 

 

 

 

 

(Loss) gain recognized in AOCL (effective portion)

 

Accumulated other comprehensive (loss)

 

$

 

$

(4.5

)

$

 

$

(2.4

)

(Loss) gain reclassified from AOCL into income (effective portion)

 

Interest

 

(1.9

)

(1.9

)

(7.0

)

(4.4

)

Gain (Loss) recognized in income (ineffective portion)

 

Realized and unrealized (loss) gain on derivatives, net

 

 

0.1

 

 

(0.2

)

 

Amount of gain or (loss) recognized in income on derivatives not designated as hedging instruments under authoritative guidance for the periods indicated (in millions):

 

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Derivatives not designated as Hedging

 

Location of Gain (Loss)

 

Three Months ended
September 30,

 

Nine Months ended
September 30,

 

Instruments under authoritative guidance

 

Recognized in Income

 

2010

 

2009

 

2010

 

2009

 

Commodity

 

Realized and unrealized gain (loss) on derivatives, net

 

$

(24.8

)

$

1.1

 

$

38.9

 

$

(7.2

)

Commodity

 

Loss from discontinued operations, net of taxes

 

 

 

 

(0.5

)

Interest Rates

 

Realized and unrealized gain (loss) on derivatives, net

 

(2.4

)

 

(8.4

)

 

 

Credit risk

 

The Company does not require collateral or other security from counterparties to support derivative instruments. However, the agreements with those counterparties typically contain netting provisions such that if a default occurs, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contract with the amount due from the defaulting party. As a result of the netting provisions the Company’s maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that the Company would have incurred if all counterparties to its derivative contracts failed to perform at September 30, 2010 was $8.5 million.  The credit rating of each of the counterparties was AA-/Aa3, or better, as of September 30, 2010.  As of September 30, 2010, the Company’s largest three counterparties accounted for 78% of the value of its total derivative positions.

 

As of September 30, 2010, the counterparties to the Company’s commodity derivative contracts consist of nine financial institutions. The Company’s counterparties or their affiliates are generally also lenders under the Company’s senior revolving credit facility. As a result, the counterparties to the Company’s derivative agreements share in the collateral supporting the Company’s senior secured revolving credit facility. The Company is not generally required to post additional collateral under derivative agreements.

 

Certain of the Company’s derivative agreements contain provisions that require cross defaults and acceleration of those instruments to any material debt. If the Company was to default on any of its material debt agreements, it would be a violation of these provisions, and the counterparties to the derivative instruments could request immediate payment on derivative instruments that are in a net liability position at that time. As of September 30, 2010, the Company was in a net liability position with six of the counterparties to the Company’s derivative instruments, totaling $77.5 million.

 

9.                    Dry hole, abandonment, impairment and exploration

 

During the three and nine months ended September 30, 2010, the Company incurred dry hole, abandonment, impairment and exploration expense of $0.6 million and $2.2 million, respectively, which was primarily a result of a mechanical failure encountered on one well in the Piceance basin.  The well was abandoned in favor of drilling a replacement well from the same well pad.  During the three and nine months ended September 30, 2009, the Company  incurred dry hole, abandonment, impairment and exploration expense of $0.1 million and $0.2 million, respectively.

 

10.               Income Taxes

 

The effective income tax rate for the three months ended September 30, 2010 and 2009 was 20.8% and 36.2%, respectively.  The effective income tax rate was 38.3% and 34.3% for the nine months ended September 30, 2010 and 2009, respectively.  The decrease in the effective tax rate in the third quarter of 2010 compared to the third quarter of 2009 is due a to one-time charge recorded in 2010 for actual tax return results and the relative weight of the one-time charge to the third quarter 2010 pre-tax loss.  The increase in the effective tax rate for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 is due to a one-time reduction in the overall state deferred tax rate in 2009 and to a one-time reduction in uncertain tax positions in 2009.  The 2009 state tax rate reduction relates to acquisitions made in lower tax jurisdictions that reduced total future state tax obligations.  The Company’s estimated annual effective tax rate varies from the 35% federal statutory rate due to the effects of state income taxes and estimated permanent differences.

 

As of September 30, 2010, the Company had a gross liability for uncertain tax benefits of $5.3 million all of which, if recognized, would affect the effective tax rate. There were no significant changes to the calculation since December 31, 2009. 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 $0.8 million and $0.7 million of interest related to its uncertain tax positions as of September 30, 2010 and December 31, 2009, respectively.

 

 

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11.               Bad Debt Recovery

 

The Company recognized $38.5 million in bad debt expense in the year ended December 31, 2008 related to Flying J, Inc., its wholly owned subsidiary Big West Oil, LLC and its wholly owned subsidiary Big West of California, LLC (BWOC) filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code on December 22, 2008.  On July 6, 2010, the Joint Plan of Reorganization of Flying J, Inc., BWOC, Big West Oil, LLC, Big West Transportation, LLC and Longhorn Partners Pipeline, L.P. was confirmed under Chapter 11 of the United State Bankruptcy Code.  Additionally, on July 6, 2010, the United States Bankruptcy Court approved and confirmed that certain June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J Inc. and certain of its affiliates (collectively Flying J), regarding the resolution of the Company’s claim in Flying J’s pending bankruptcy.  Pursuant to the Stipulation, each of the Company and Flying J agreed that the total amount owed to the Company by Flying J was $60.5 million and, as a result, the Company received $60.5 million in cash on July 23, 2010.  In the quarter ended September 30, 2010, the Company recorded a settlement of its Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.

 

12.               Commitments and Contingencies

 

The Company’s contractual obligations not included in its Condensed Balance Sheet as of September 30, 2010 (except Long-term debt and Asset retirement obligation) are as follows (in millions):

 

 

 

Total

 

2010

 

2011

 

2012

 

2013

 

2014

 

Thereafter

 

Long-term debt and interest

 

$

1,170.6

 

$

17.2

 

$

68.8

 

$

306.0

 

$

62.6

 

$

485.7

 

$

230.3

 

Asset retirement obligation

 

51.2

 

0.9

 

2.9

 

2.9

 

2.8

 

2.8

 

38.9

 

Operating lease obligations

 

15.1

 

0.7

 

2.7

 

2.7

 

2.7

 

2.6

 

3.7

 

Drilling and rig obligations

 

27.7

 

3.0

 

24.7

 

 

 

 

 

Firm natural gas transportation contracts

 

121.7

 

4.9

 

19.7

 

17.6

 

15.7

 

14.8

 

49.0

 

Total

 

$

1,386.3

 

$

26.7

 

$

118.8

 

$

329.2

 

$

83.8

 

$

505.9

 

$

321.9

 

 

Operating leases

 

The Company leases corporate and field offices in California, Colorado and Texas. Rent expense with respect to its lease commitments was $0.5 million for both the three months ended September 30, 2010 and 2009, and was $1.6 million for both the nine months ended September 30, 2010 and 2009.

 

In 2006, the Company purchased a corporate aircraft which was subsequently sold and contracted under a ten year operating lease beginning December 2006.

 

Drilling obligations

 

Included in the table above are the Company’s contractual obligations on its Piceance assets in Colorado.  The Company must spud an additional 87 wells of its original 120 wells commitment by February 2011 to avoid penalties of $0.2 million per well not drilled.  Satisfying this commitment and further developing these assets depends on Piceance infrastructure and access, drilling resources, including capital availability, and other factors, all of which will be further evaluated throughout the remainder of 2010.

 

Firm natural gas transportation

 

In July 2009, the Company closed on 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.  There is no minimum payment required under these agreements.   For the three months ended September 30, 2010 and 2009, the Company incurred $1.8 million and $1.0 million, respectively, under the agreements.  For the nine months ended September 30, 2010 and 2009, the Company incurred $4.6 million and $1.0 million, respectively, under the agreements.

 

In June 2009, the Company amended its natural gas firm transportation agreement with Enbridge Pipelines providing for transportation of its gas from Tex-OK to Orange County, Florida (Zone 1).  The agreement provides for minimum volume of 25,000 MMBtu/d and a maximum volume of 55,000 MMBtu/D.

 

The Company has long-term firm transportation contracts that total 35,000 MMBtu/D on the Rockies Express (REX) pipeline for gas production in the Piceance basin.  The Company pays a demand charge for this capacity and its own production did not completely fill that capacity. To maximize the utilization of its firm transportation, the Company bought its working interest partners’ share of the gas produced in the Piceance basin at the market rate for that area and used its excess transportation to move this gas to

 

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Table of Contents

 

the sales point. The pre-tax net of our gas marketing revenue and our gas marketing expense in the Condensed Statements of Income (Loss) for the three months ended September 30, 2010 and 2009 is $0.9 million and $0.6 million, respectively. The pre-tax net of our gas marketing revenue and our gas marketing expense in the Condensed Statements of Income (Loss) for the nine months ended September 30, 2010 and 2009 is $2.0 million and $1.5 million.

 

Berry has signed firm transportation service agreements with El Paso Corporation for an average total of 35,000 MMBtu/D of firm transportation on the proposed Ruby Pipeline from Opal, WY to Malin, OR.  The expectation is that the project will proceed and be in service in 2011.

 

Other commitments

 

The Company is a party to a crude oil sales contract through June 30, 2013 with a refiner for the purchase of a minimum of 5,000 Bbl/D of its Uinta light crude oil.  Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI.  While the contractual differentials under this contract may be less favorable at times than the posted differential, demand for the Company’s 40 degree black wax (light) crude oil can vary seasonally and this contract provides a stable outlet for the Company’s crude oil. Gross oil production from the Company’s Uinta properties averaged approximately 3,040 Bbl/D in the first nine months of 2010.

 

The Company has no material accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in substantial costs incurred. The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material effect on its financial position, results of operations or liquidity.

 

Certain of the Company’s royalty payment calculations are being disputed.  The Company believes that its royalty calculations are in accordance with applicable leases and other agreements.  However, the disputed amounts that the Company may be required to pay are up to approximately $6 million.

 

In July 2009, the Company received a notice of proposed civil penalty from the Bureau of Land Management (BLM) related to the Company’s alleged non-compliance during 2007 with regulations relating to the operation and position of certain valves in its Uinta basin operations.  The proposed civil penalty was $69.6 million and reflects the theoretical maximum penalty amount under applicable regulations, absent mitigating factors.  In 2007 the Company immediately remediated the instances of non-compliance, cooperated fully with the BLM’s investigation and the Company believes no production was lost, all royalties were paid and there was no harm to the environment. Due to the above mitigating factors, among others, the Company believes this matter will be resolved by the payment of a penalty that will not exceed $2.1 million.  The Company recorded $2.1 million in general and administrative expense in the second quarter of 2009.

 

On October 7, 2010, the Company executed agreements with PG&E, which, if approved by the California Public Utilities Commission (CPUC), will extend the power contracts for its 18MW and 38MW facilities until June 30, 2011.  The electricity sales contracts with Edison for our Placerita facility will continue in effect until the CPUC approves and makes available replacement standard form Qualifying Facilities (QF) contracts.  Such contracts are the subject of a settlement agreement dated October 8, 2010 among the three California public utilities, two consumer representative groups and three parties that represent the interests of the majority of the cogeneration facilities in the state, including the Company, that if adopted by the CPUC would resolve numerous issues including the issue of new or extended contracts for QF’s such as the Company.  A ruling on the settlement is expected later in 2010 or early 2011; however, the current contracts could terminate earlier under certain limited circumstances.

 

13.  Subsequent Event

 

On October 22, 2010, the Company entered into an agreement with a group of private sellers to acquire the interests in producing properties principally in the Wolfberry trend in West Texas for approximately $175 million in cash.  The effective date of the transaction is October 1, 2010.  The acquisition is expected to close in the fourth quarter of 2010, subject to certain closing conditions.

 

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Table of Contents

 

Berry Petroleum Company

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

 

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and the results of operations during the periods included in the accompanying Condensed Financial Statements.  You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited Financial Statements for the year ended December 31, 2009 included in our Annual Report on Form 10-K, as amended, and the Condensed Financial Statements included elsewhere herein.

 

The profitability of our operations in any particular accounting period will be directly related to the realized prices of oil, gas and electricity sold, the type and volume of oil and gas produced and electricity generated and the results of development, exploitation, acquisition, exploration and hedging activities. The realized prices for natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will be predominantly influenced by global supply and demand. The aggregate amount of oil and gas produced may fluctuate based on the success of development and exploitation of oil and gas reserves pursuant to current reservoir management. We benefit from lower natural gas prices as we are a consumer of natural gas in our California operations. In the Rocky Mountains and E. Texas we benefit from higher natural gas pricing. The cost of natural gas used in our steaming operations and electrical generation, production rates, labor, equipment costs, maintenance expenses, and production taxes are expected to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period based on the foregoing principal factors, among others.

 

Notable Third Quarter Items.

 

·                  Achieved production averaging 33,870 BOE/D, comprised of 64% crude oil, up 3% from the second quarter of 2010

·                  Received approval from the California Division of Oil, Gas and Geothermal Resources for the next phase of development of our diatomite asset

·                  Executed a one year crude oil purchase contract with ExxonMobil Oil Corporation for the sale of all the oil production from our Midway Sunset Field

·                  Executed a three rig drilling program in the Permian basin and increased production to 1,340 BOE/D, up 30% from the second quarter of 2010

·                  Determined that McKittrick 21Z cyclic development is economic and plan to expand development in 2011

·                  Generated discretionary cash flow (1) of $95 million

 

Notable Items and Expectations for the Fourth Quarter and Full Year 2010.

 

·                  Entered into an agreement with a group of private sellers to acquire their interests in producing properties principally in the Wolfberry trend in West Texas

·                  Planning to run a two rig drilling development program in the diatomite for the remainder of 2010

·                  Anticipating 2010 average production between 32,250 and 33,000 BOE/D, an 8% to 10% increase over 2009

·                  Expecting 2010 development capital between $290 million and $310 million to be fully funded from operating cash flow

·                  Expecting 2011 development capital between $375 million and $425 million at $75 WTI, primarily focused on the development of our oil assets

·                  Anticipating average 2011 production between 37,000 and 39,000 BOE/D

 


(1) Discretionary cash flow is considered a non-GAAP performance measure and reference should be made to “Reconciliation of Non-GAAP Measures” at the end of this Item 2 for further explanation of this performance measure, as well as a reconciliation to the most directly comparable GAAP measure.

 

Results of Operations.

 

In the third quarter of 2010, we reported a net loss from continuing operations of $3.0 million, or $0.6 per diluted share, and net cash flows from operations of $183.7 million. Net loss from continuing operations includes a $23.6 million loss on derivatives as a result of non-cash changes in fair values and amortization of frozen fair values.

 

During the first nine months of 2010, we reported net income from continuing operations of $103.7 million, or $1.93 per diluted share, and net cash flows from operations was $318.5 million.  Net income from continuing operations includes a $6.4 million gain on derivatives as result of non-cash changes in fair values and amortization of frozen fair values and a $37.3 million Flying J settlement,

 

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Table of Contents

 

offset by $1.0 million of dry hole costs and $1.6 million of transaction related costs related to the acquisition of certain properties in the Permian basin, as discussed below.

 

Acquisitions.

 

Permian Basin Acquisitions.  Through April, 2010, we acquired interests in producing properties principally in the Permian basin of West Texas from private sellers for approximately $147 million, including normal post closing adjustments.  These properties are located primarily within the Wolfberry play and production from these properties is approximately 1,700 BOED at present. 

 

With the acquisitions announced on October 25, 2010, we have accumulated approximately 19,350 net acres in the Wolfberry trend.  The acquisitions in 2010 will provide a five-year drilling inventory in the Permian basin with approximately 400 locations based on 40-acre spacing with an additional 400 potential locations based on 20-acre spacing.

 

Revenues.

 

Approximately 82% of our revenues are generated through the sale of oil and natural gas production under either negotiated contracts or spot gas purchase contracts at market prices. Approximately 5% of our revenues are derived from electricity sales from cogeneration facilities which supply approximately 28% of our steam requirement for use in our California thermal heavy oil operations.  We have invested in these facilities for the purpose of lowering our steam costs, which are significant in the production of heavy crude oil. Approximately 3% of our revenues are derived from gas marketing sales which represent our excess capacity on the Rockies Express pipeline which we use to market natural gas purchased from our working interest partners.

 

The following results from continuing operations are in millions (except per share data) for the three and nine month periods ended:

 

 

 

Three months ended,

 

Nine months ended,

 

 

 

September 30,
2010

 

September 30,
2009

 

June 30,
2010

 

September 30,
2010

 

September 30,
2009

 

Sales of oil

 

$

123

 

$

109

 

$

125

 

$

369

 

$

311

 

Sales of gas

 

29

 

18

 

27

 

82

 

63

 

Total sales of oil and gas

 

$

152

 

$

127

 

$

152

 

$

451

 

$

374

 

Sales of electricity

 

9

 

9

 

8

 

27

 

26

 

Gas marketing

 

5

 

5

 

5

 

18

 

18

 

Realized and unrealized (loss) gain on derivatives, net

 

(27

)

1

 

56

 

31

 

7

 

Settlement on Flying J bankruptcy claim

 

 

 

22

 

22

 

 

Interest and other income, net

 

 

1

 

1

 

2

 

2

 

Total revenues and other income

 

$

139

 

$

143

 

$

244

 

$

551

 

$

427

 

Net income (loss) from continuing operations

 

$

(3

)

$

18

 

$

89

 

$

104

 

$

47

 

Diluted (loss) earnings per share from continuing operations

 

$

(0.06

)

$

0.40

 

$

1.64

 

$

1.93

 

$

1.03

 

 

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Table of Contents

 

Operating Data. The following table is for the three months ended:

 

 

 

September 30,
2010

 

%

 

September 30,
2009

 

%

 

June 30,
2010

 

%

 

Heavy oil production (Bbl/D)

 

16,722

 

49

 

16,780

 

59

 

17,492

 

54

 

Light oil production (Bbl/D)

 

5,049

 

15

 </