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 March 31, 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 o 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 April 19, 2010, the registrant had 51,131,921 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 April 19, 2010 all of which is held by an affiliate of the registrant.

 

 

 



Table of Contents

 

BERRY PETROLEUM COMPANY

FIRST QUARTER 2010 FORM 10-Q

TABLE OF CONTENTS

 

 

 

Page

 

 

 

PART I. FINANCIAL INFORMATION

 

 

 

 

 

Item 1. Condensed Financial Statements

3

 

 

 

 

Unaudited Condensed Balance Sheets at March 31, 2010 and December 31, 2009

3

 

 

 

 

Unaudited Condensed Statements of Income for the Three Months Ended March 31, 2010 and 2009

4

 

 

 

 

Unaudited Condensed Statements of Comprehensive Income for the Three Months Ended March 31, 2010 and 2009

4

 

 

 

 

Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009

5

 

 

 

 

Notes to Unaudited Condensed Financial Statements

6

 

 

 

 

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

19

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

31

 

 

 

 

Item 4. Controls and Procedures

34

 

 

 

PART II. OTHER INFORMATION

 

 

 

 

 

Item 1. Legal Proceedings

35

 

 

 

 

Item 1A. Risk Factors

35

 

 

 

 

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

35

 

 

 

 

Item 3. Defaults Upon Senior Securities

35

 

 

 

 

Item 4. Removed and Reserved

35

 

 

 

 

Item 5. Other Information

35

 

 

 

 

Item 6. Exhibits

36

 

2



Table of Contents

 

BERRY PETROLEUM COMPANY

Unaudited Condensed Balance Sheets

(In Thousands, Except Share Information)

 

 

 

March 31,
2010

 

December 31,
2009

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

57

 

$

5,311

 

Short-term investments

 

65

 

66

 

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

 

84,764

 

74,337

 

Deferred income taxes

 

10,274

 

5,623

 

Fair value of derivatives

 

6,164

 

11,527

 

Prepaid expenses and other

 

10,878

 

6,612

 

Total current assets

 

112,202

 

103,476

 

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

 

2,269,848

 

2,106,385

 

Fair value of derivatives

 

2,369

 

735

 

Other assets

 

27,973

 

29,539

 

 

 

$

2,412,392

 

$

2,240,135

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

76,641

 

$

63,096

 

Revenue and royalties payable

 

16,909

 

25,878

 

Accrued liabilities

 

42,498

 

29,320

 

Fair value of derivatives

 

44,851

 

33,843

 

Total current liabilities

 

180,899

 

152,137

 

Long-term liabilities:

 

 

 

 

 

Deferred income taxes

 

251,913

 

237,161

 

Senior secured revolving credit facility

 

270,000

 

372,000

 

8¼ % Senior subordinated notes due 2016

 

200,000

 

200,000

 

10¼% Senior notes due 2014, net of unamortized discount of $12,877 and $13,456, respectively

 

437,124

 

436,544

 

Asset retirement obligation

 

46,919

 

43,487

 

Other long-term liabilities

 

20,150

 

19,711

 

Fair value of derivatives

 

57,773

 

75,836

 

 

 

1,283,879

 

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; 51,126,421 shares issued and outstanding (42,952,499 in 2009)

 

511

 

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

 

316,313

 

89,068

 

Accumulated other comprehensive loss

 

(56,972

)

(60,372

)

Retained earnings

 

687,744

 

674,115

 

Total shareholders’ equity

 

947,614

 

703,259

 

 

 

$

2,412,392

 

$

2,240,135

 

 

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

 

3



Table of Contents

 

BERRY PETROLEUM COMPANY

Unaudited Condensed Statements of Income

Three Months Ended March 31, 2010 and 2009

(In Thousands, Except Per Share Data)

 

 

 

Three months ended March 31,

 

 

 

2010

 

2009

 

REVENUES AND OTHER INCOME ITEMS

 

 

 

 

 

Sales of oil and gas

 

$

147,807

 

$

127,869

 

Sales of electricity

 

9,933

 

10,270

 

Gas marketing

 

8,272

 

7,581

 

Realized and unrealized gain on derivatives, net

 

1,603

 

37,164

 

Interest and other income, net

 

164

 

283

 

 

 

167,779

 

183,167

 

EXPENSES

 

 

 

 

 

Operating costs - oil and gas production

 

47,036

 

37,384

 

Operating costs - electricity generation

 

9,670

 

8,783

 

Production taxes

 

5,204

 

5,652

 

Depreciation, depletion & amortization - oil and gas production

 

35,907

 

36,398

 

Depreciation, depletion & amortization - electricity generation

 

795

 

959

 

Gas marketing

 

7,786

 

7,284

 

General and administrative

 

13,835

 

13,294

 

Interest expense

 

17,447

 

10,050

 

Transaction costs on acquisitions, net of gain

 

727

 

 

Dry hole, abandonment, impairment and exploration

 

1,369

 

122

 

 

 

139,776

 

119,926

 

Income before income taxes

 

28,003

 

63,241

 

Provision for income taxes

 

10,334

 

21,462

 

Income from continuing operations

 

17,669

 

41,779

 

Loss from discontinued operations, net of taxes

 

 

(6,781

)

 

 

 

 

 

 

Net income

 

$

17,669

 

$

34,998

 

 

 

 

 

 

 

Basic net income from continuing operations per share

 

$

0.34

 

$

0.92

 

Basic net loss from discontinued operations per share

 

$

 

$

(0.15

)

Basic net income per share

 

$

0.34

 

$

0.77

 

 

 

 

 

 

 

Diluted net income from continuing operations per share

 

$

0.34

 

$

0.92

 

Diluted net loss from discontinued operations per share

 

$

 

$

(0.15

)

Diluted net income per share

 

$

0.34

 

$

0.77

 

 

 

 

 

 

 

Dividends per share

 

$

0.075

 

$

0.075

 

 

Unaudited Condensed Statements of Comprehensive Income

Three Months Ended March 31, 2010 and 2009

(In Thousands)

 

Net income

 

$

17,669

 

$

34,998

 

Unrealized gains on derivatives, net of income taxes of $0 and $48,160, respectively

 

 

78,577

 

Reclassification of realized gains on derivatives included in net income, net of income tax benefits of $2,084 and $17,788, respectively

 

(3,400

)

(29,022

)

Comprehensive income

 

$

14,269

 

$

84,553

 

 

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

 

4



Table of Contents

 

BERRY PETROLEUM COMPANY

Unaudited Condensed Statements of Cash Flows

Three Months Ended March 31, 2010 and 2009

(In Thousands)

 

 

 

Three months ended March 31,

 

 

 

2010

 

2009

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

17,669

 

$

34,998

 

Depreciation, depletion and amortization

 

36,702

 

39,545

 

Amortization of debt issue costs and net discount

 

2,098

 

1,088

 

Gain on purchase of oil and natural gas properties

 

(1,358

)

 

Dry hole and impairment

 

1,207

 

9,643

 

Unrealized loss (gain) on derivatives

 

2,476

 

(22,842

)

Stock-based compensation expense

 

3,031

 

2,988

 

Deferred income taxes

 

8,548

 

21,059

 

Other, net

 

 

(5,040

)

Cash paid for abandonment

 

(22

)

(112

)

Change in book overdraft

 

(1,377

)

(23,510

)

Increase in current assets other than cash and cash equivalents

 

(14,179

)

(12,933

)

Increase (decrease) in current liabilities other than book overdraft, line of credit and fair value of derivatives

 

8,720

 

(36,755

)

Net cash provided by operating activities

 

63,515

 

8,129

 

Cash flows from investing activities:

 

 

 

 

 

Exploration and development of oil and gas properties

 

(47,958

)

(50,181

)

Property acquisitions

 

(132,515

)

(1,173

)

Capitalized interest

 

(5,967

)

(5,312

)

Deposits on asset sales

 

 

14,000

 

Deposits on potential property acquisitions

 

(500

)

 

Net cash used in investing activities

 

(186,940

)

(42,666

)

Cash flows from financing activities:

 

 

 

 

 

Proceeds from issuances on line of credit

 

76,100

 

147,800

 

Payments on line of credit

 

(76,100

)

(173,100

)

Long-term borrowings under credit facility

 

125,000

 

159,600

 

Repayments of long-term borrowings under credit facility

 

(227,000

)

(92,000

)

Debt issue costs

 

 

(4,538

)

Financing obligation

 

(83

)

 

Dividends paid

 

(4,040

)

(3,416

)

Proceeds from issuance of common stock, net

 

224,337

 

 

Proceeds from stock option exercises

 

75

 

 

Excess tax benefit and other

 

(118

)

 

Net cash provided by financing activities

 

118,171

 

34,346

 

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(5,254

)

(191

)

Cash and cash equivalents at beginning of year

 

5,311

 

240

 

Cash and cash equivalents at end of period

 

$

57

 

$

49

 

 

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

 

5



Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

1.                      Basis of Presentation

 

These unaudited Condensed Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (GAAP) for interim financial reporting.   All adjustments which are, in the opinion of management, necessary for a fair statement of Berry Petroleum Company’s (the Company) financial position at March 31, 2010 and December 31, 2009 and results of operations and accumulated other comprehensive loss (AOCL) for the three months ended March 31, 2010 and 2009, and its cash flows for the three months ended March 31, 2010 and 2009 have been included. In the opinion of management, all adjustments, which are of a normal recurring nature, have been made which are necessary for a fair presentation of the financial position. 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 initially established.

 

The unaudited Condensed Financial Statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2009 Financial Statements.  For a more complete understanding of the Company’s operations, financial position and accounting policies, the Unaudited Condensed Financial Statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 previously filed with the SEC. The year-end Condensed Balance Sheet was derived from audited Financial Statements, but does not include all disclosures required by GAAP.

 

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 March 31, 2010 and December 31, 2009 is $14.4 million and $15.7 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

 

2.                      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. These models are 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

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

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

 

Assets and liabilities measured at fair value on a recurring basis

 

March 31, 2010 (in millions)

 

Total carrying value on the
Condensed Balance Sheet

 

Level 2

 

Level 3

 

 

 

 

 

 

 

 

 

Commodity derivatives liability

 

$

(83.7

)

$

(49.2

)

$

(34.5

)

Interest rate derivatives liability

 

(10.4

)

(10.4

)

 

Total derivative liabilities at fair value

 

$

(94.1

)

$

(59.6

)

$

(34.5

)

 

December 31, 2009 (in millions)

 

Total carrying value on the
Condensed Balance Sheet

 

Level 2

 

Level 3

 

 

 

 

 

 

 

 

 

Commodity derivatives liability

 

$

(88.5

)

$

(62.5

)

$

(26.0

)

Interest rate derivatives liability

 

(8.9

)

(8.9

)

 

Total derivative liabilities 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).

 

(in millions)

 

Three months ended
March 31, 2010

 

Three months ended
March 31, 2009

 

 

 

 

 

 

 

Fair value (liability) asset, beginning of period

 

$

(26.0

)

$

172.5

 

Total realized and unrealized gains included in Realized and unrealized gain on derivatives

 

(1.4

)

(22.9

)

Purchases, sales and settlements, net

 

(7.1

)

(15.5

)

Transfers in and/or out of Level 3

 

 

3.4

 

Fair value (liability) asset, end of period

 

$

(34.5

)

$

137.5

 

 

 

 

 

 

 

Total unrealized (losses) gains included in income related to financial assets and liabilities still on the Condensed Balance Sheet at March 31, 2010 and 2009

 

$

(8.4

)

$

22.8

 

 

The $3.4 million of transfers out of Level 3 for the three months ended March 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 Condensed Financial Statements.

 

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Table of Contents

 

Berry Petroleum Company

Notes to Unaudited 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.

 

 

 

As of March 31, 2010

 

(in millions)

 

Carrying
Amount

 

Estimated
Fair Value

 

 

 

 

 

 

 

Senior secured revolving credit facility

 

$

270

 

$

270

 

8.25% Senior subordinated notes due 2016

 

200

 

202

 

10.25% Senior notes due 2014

 

437

 

495

 

 

 

$

907

 

$

967

 

 

 

 

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

 

 

3.                      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 in an attempt to normalize the mix of fixed and floating interest rates within its debt portfolio.

 

The Company’s derivative 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 derivative asset and liability positions.  The credit rating of each of these counterparties was AA-/Aa3, or better as of March 31, 2010.  As of March 31, 2010, the Company’s largest three counterparties accounted for 74% of the value of its total derivative positions.

 

As of March 31, 2010, the Company had the following commodity derivatives:

 

 

 

2010

 

2011

 

2012

 

Oil Bbl/D:

 

15,930

 

11,020

 

5,000

 

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 Condensed Financial Statements.

 

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Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

The Company entered into the following crude oil collars during the three months ended March 31, 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

 

 

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 AOCL.  Effective January 1, 2010, however, 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 months ended March 31, 2010, $5.5 million ($3.4 million, net of tax) of derivative losses relating to de-designated commodity and interest rate hedges were reclassified from AOCL into earnings.  As of March 31, 2010, AOCL consisted of $91.9 million ($57.0 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 $22.7 million related to de-designated commodity and interest rate derivative contracts during the next twelve months.

 

At March 31, 2010, the net fair value derivative liability was $94.1 million as compared to a net fair value liability of $97.4 million at December 31, 2009 which reflects changes in commodity prices and interest rates. Based on NYMEX strip pricing as of March 31, 2010, the Company expects to make payments under the existing derivatives of $35.3 million during the next twelve months.

 

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

 

The Company presents its derivative assets and liabilities on its Condensed 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.

 

9



Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

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 Condensed 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.

 

 

 

As of March 31, 2010

 

 

 

Derivative Assets

 

Derivative Liabilities

 

(in millions)

 

Balance Sheet
Classification

 

Fair Value

 

Balance Sheet
Classification

 

Fair Value

 

 

 

 

 

 

 

 

 

Total derivatives designated as hedging instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity – Oil

 

Current assets

 

$

4.5

 

Current liability

 

$

44.9

 

Commodity – Oil

 

 

 

 

 

Long term liabilities

 

57.6

 

Commodity – Natural Gas

 

Current assets

 

5.2

 

 

 

 

 

Commodity – Natural Gas

 

Current liability

 

3.0

 

 

 

 

 

Commodity – Natural Gas

 

Long term assets

 

2.4

 

 

 

 

 

Commodity – Natural Gas

 

Long term liabilities

 

3.6

 

 

 

 

 

Interest rate contracts

 

 

 

 

 

Current assets

 

3.5

 

Interest rate contracts

 

 

 

 

 

Current liability

 

3.0

 

Interest rate contracts

 

 

 

 

 

Long term liabilities

 

3.8

 

Total derivatives not designated as hedging instruments

 

18.7

 

 

 

112.8

 

Total Derivatives

 

 

 

$

18.7

 

 

 

$

112.8

 

 

 

 

As of December 31, 2009

 

 

 

Derivative Assets

 

Derivative Liabilities

 

(in millions)

 

Balance Sheet
Classification

 

Fair Value

 

Balance Sheet
Classification

 

Fair Value

 

Commodity – Oil

 

Current assets

 

$

14.2

 

Current liability

 

$

30.8

 

Commodity – Oil

 

 

 

 

 

Long term liabilities

 

74.1

 

Commodity – Natural Gas

 

Current assets

 

1.3

 

 

 

 

 

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

 

 

10



Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

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

 

Three Months Ended March 31, 2010

 

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

 

$

 

Sales of oil and gas

 

$

(3.2

)

 

 

$

 

Commodity - Natural Gas

 

 

Sales of oil and gas

 

0.4

 

 

 

 

Interest rate

 

 

Interest expense

 

(2.7

)

 

 

 

Total

 

$

 

 

 

$

(5.5

)

 

 

$

 

 

Three Months Ended March 31, 2009

 

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

 

$

36.5

 

Sales of oil and gas

 

$

41.6

 

Realized and unrealized gain on derivatives, net

 

$

14.3

 

Commodity - Natural Gas

 

8.9

 

Sales of oil and gas

 

6.6

 

 

 

 

 

Commodity - Oil

 

 

 

 

 

 

 

Realized and unrealized gain on derivatives, net

 

22.7

 

Interest rate

 

(3.4

)

Interest expense

 

(1.0

)

 

 

 

 

Total

 

$

42.0

 

 

 

$

47.2

 

 

 

$

37.0

 

 

Amount of gain or (loss) recognized in income on derivatives not designated as hedging instruments under authoritative guidance for the three months ended March 31, 2010 and 2009:

 

Three Months Ended March 31, 2010

 

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

 

Realized and unrealized gain on derivatives, net

 

$

(7.5

)

Commodity - Natural Gas

 

Realized and unrealized gain on derivatives, net

 

12.4

 

Interest Rates

 

Realized and unrealized gain on derivatives, net

 

(3.3

)

Total derivatives not designated as hedging instruments

 

$

1.6

 

 

11



Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

Three Months Ended March 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

 

Realized and unrealized gain on derivatives, net

 

$

0.2

 

Commodity - Natural Gas

 

Loss from discontinued operations, net of taxes

 

(0.5

)

Total derivatives not designated as hedging instruments

 

$

(0.3

)

 

During the three months ended March 31, 2010, the Company recorded a $1.6 million gain under the caption Realized and unrealized gain on derivatives, net resulting from a gain for the change in fair value of $3.3 million, net of a loss for cash settlements of $1.7 million.

 

During the three months ended March 31, 2009, the Company recorded a $37.2 million gain under the caption Realized and unrealized gain on derivatives, net.  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 Condensed Statements of Income under the caption Realized and unrealized gain on derivatives, net.  The Company also recognized an unrealized gain of $22.9 million on the Condensed Statements of Income under the caption Realized and unrealized gain on derivatives, net for the three months ended March 31, 2009, as a result of ineffectiveness related to sales prices that were not highly correlated with the Company’s hedges.  The Company recorded an unrealized net loss of $0.5 million on the Condensed Statements of Income under the caption Loss from discontinued operations, net of taxes during the first quarter of 2009 related to natural gas derivatives entered into on behalf of the purchaser of the Company’s DJ assets for which the Company did not elect hedge accounting.

 

4.                      Shareholder’s Equity

 

In January 2010, the Company issued 8,000,000 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 Wolfberry Acquisition and to repay a portion of the outstanding borrowings under the senior secured revolving credit facility.  See Note 5 to the Condensed Financial Statements.

 

5.                      Acquisitions and Divestitures

 

Acquisitions

 

On March 5, 2010, the Company acquired interests in producing properties principally on 6,900 acres in the Wolfberry trend in the Permian basin of West Texas (W. Texas) for $132 million, including an initial purchase price of $126 million, and customary post-closing adjustments of approximately $6 million (Wolfberry Acquisition).  The acquisition had an effective date of January 1, 2010 and activity from January 1, 2010 through March 4, 2010 was a purchase price adjustment.  The acquisition was financed with the proceeds from the issuance of the Company’s common stock in January of 2010.  The Company operates approximately 70% of, and has an average 68.5% working interest (54.1% net revenue interest) in, the properties acquired in the Wolfberry trend.

 

The Wolfberry Acquisition qualifies as a business combination and, as such, the Company estimated the fair value of this property as of the March 5, 2010 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.

 

The fair value of the properties acquired exceeded the consideration paid to the seller by $1.4 million which the Company recorded in the Condensed Statements of Income under the caption Transaction costs on acquisitions, net of gain.  The gain resulted from the changes in oil and natural gas prices used to value the reserves.

 

12



Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

The acquisition related costs totaling $2.1 million have been recorded in the Condensed Statements of Income under the caption Transaction costs on acquisitions, net of gain.  Revenues of $1.7 million and earnings of $0.5 million generated by the acquired properties from March 5, 2010 to March 31, 2010 have been included in the accompanying Condensed Statements of Income.

 

The following table summarizes the consideration paid to the seller and the amounts of the assets acquired and liabilities assumed as of March 5, 2010.  The purchase price allocation is preliminary and subject to customary adjustments.

 

 

 

(In thousands)

 

Consideration paid to seller:

 

 

 

Cash, net of accrued purchase price adjustment

 

$

132,241

 

 

 

 

 

Recognized amounts of identifiable assets acquired and liabilities assumed:

 

 

 

Proved developed and undeveloped properties

 

134,649

 

Fair value of derivatives

 

316

 

Asset retirement obligation

 

(1,367

)

 

 

 

 

Total identifiable net assets

 

$

133,598

 

 

In February 2010, the Company entered into an agreement and paid a deposit of $0.5 million with a private seller to acquire interests in producing properties in the Wolfberry trend in W. Texas for approximately $14 million cash.  This transaction closed in April 2010. The initial accounting for the business combination is not complete pending detailed analyses of the facts and circumstances that existed as of the acquisition date.

 

Divestitures

 

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 $6.8 million Loss from discontinued operations, net of taxes, on its Condensed Statement of Income for the three months ended March 31, 2009.

 

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

 

 

 

Three Months Ended March 31,

 

 

 

2010

 

2009

 

 

 

 

 

 

 

Total revenues

 

 

$

6,018

 

Total expenses

 

 

16,283

 

Loss from discontinued operations, before income taxes

 

 

(10,265

)

Income tax benefit

 

 

3,484

 

Loss from discontinued operations, net of taxes

 

 

$

(6,781

)

 

6.                    Dry hole, abandonment, impairment and exploration

 

In the first quarter of 2010 the Company incurred dry hole, abandonment, impairment and exploration expense of $1.4 million, which was primarily a result of 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.  In the first quarter of 2009 the Company had dry hole, abandonment, impairment and exploration charges of $0.1 million.

 

13



Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

7.                      Asset Retirement Obligation (ARO)

 

The following table summarizes the change in the ARO for the three months ended March 31 (in thousands):

 

 

 

2010

 

2009

 

Beginning balance at January 1

 

$

43,487

 

$

41,967

 

Liabilities incurred

 

1,024

 

 

Liabilities settled

 

(22

)

(113

)

Acquisition of assets

 

1,367

 

 

Accretion expense

 

1,063

 

1,002

 

Ending balance at March 31

 

$

46,919

 

$

42,856

 

 

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.

 

8.                      Debt Obligations

 

Short-term lines of credit

 

Borrowings under 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.  In conjunction with the amendment to the Company’s senior secured credit facility, on July 15, 2008, the Secured 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.

 

There were no outstanding borrowings on the Secured Line of Credit at March 31, 2010 or December 31, 2009.  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 Secured Line of Credit at March 31, 2010 and December 31, 2009 was 0%.

 

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:

 

 

 

 

 

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.

 

The Agreement contains a current ratio covenant which, as defined, must be at least 1.0.  The total outstanding debt at March 31, 2010 under the Agreement, as amended, and the Line of Credit was $270 million and zero, respectively, and $4 million in letters of credit have been issued under the facility, leaving $664 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 Company’s borrowing base was reconfirmed in April 2010.  The Agreement is collateralized by oil and natural gas properties representing at least 80% of the present value of the Company’s proved reserves.  The Agreement matures on July 15, 2012.

 

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Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

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 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 previously issued $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 Sub Notes and 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 March 31, 2010.

 

 

 

As of March 31, 2010

 

Current Ratio (Not less than 1.0)

 

5.7

 

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

 

3.0

 

Interest Coverage Ratio (Not less than 2.5)

 

3.7

 

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

 

0.9

 

 

The weighted average interest rate on the Company’s total outstanding borrowings was 7.5% and 7.0% at March 31, 2010 and December 31, 2009, respectively.

 

9.                      Income Taxes

 

The effective income tax rate was 36.9% for the first quarter of 2010 compared to 33.9% for the first quarter of 2009. The increase in rate for the first quarter is primarily due to one-time reductions in deferred state taxes in the prior quarter.  Reductions in the rate during the prior quarter were the result of acquisitions in more tax favorable jurisdictions, reducing future state tax obligations in addition to favorable state tax incentives.  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 March 31, 2010, the Company had a gross liability for uncertain tax benefits of $6.5 million of which $5.3 million, 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 March 31, 2010 and December 31, 2009, respectively.

 

15


 


Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

10.               Earnings per Share

 

Basic net income per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of common shares outstanding during each period.  Diluted net income per common share is calculated by dividing adjusted net income 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 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 stock 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 stock incentive plans also have the right to receive non-forfeitable dividends, participating on an equal basis with common stock.  Stock options issued under the Company’s stock incentive plans do not participate in dividends. Therefore, restricted stock issued to employees prior to January 1, 2010 and stock units issued to directors are participating securities and earnings must now be allocated to both common stock and these participating securities under the two-class method.

 

The following table shows the computation of basic and diluted net income (loss) per share from continuing and discontinued operations for the three months ended March 31, 2010 and 2009 (in thousands):

 

 

 

Three Months Ended March 31,

 

 

 

2010

 

2009

 

Net income from continuing operations

 

$

17,669

 

$

41,779

 

Less: Income allocable to participating securities

 

359

 

3,416

 

Income available for shareholders

 

$

17,310

 

$

38,363

 

 

 

 

 

 

 

Net loss from discontinued operations

 

$

 

$

(6,781

)

Less: Income allocable to participating securities

 

 

 

Loss from discontinued operations available for shareholders

 

$

 

$

(6,781

)

 

 

 

 

 

 

Basic earnings per share from continuing operations

 

$

0.34

 

$

0.92

 

Basic loss per share from discontinued operations

 

 

(0.15

)

Basic earnings per share

 

$

0.34

 

$

0.77

 

 

 

 

 

 

 

Diluted earnings per share from continuing operations

 

$

0.34

 

$

0.92

 

Diluted loss per share from discontinued operations

 

 

(0.15

)

Diluted earnings per share

 

$

0.34

 

$

0.77

 

 

 

 

 

 

 

Weighted average shares outstanding - basic

 

51,076

 

44,581

 

Add: dilutive effects of stock options

 

365

 

12

 

Weighted average shares outstanding - dilutive

 

51,441

 

44,593

 

 

Options to purchase $1.2 million and $2.3 million shares were not included in the diluted earnings (loss) per share calculation for the three months ended March 31, 2010 and 2009, respectively, because their effect would have been anti-dilutive.

 

16



Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

11.               Commitments and Contingencies

 

The Company’s contractual obligations not included in its Condensed Balance Sheet as of March 31, 2010 (except Long-term debt and ARO) are as follows (in millions):

 

 

 

Total

 

2010

 

2011

 

2012

 

2013

 

2014

 

Thereafter

 

Long-term debt and interest

 

$

1,234

 

$

52

 

$

69

 

$

335

 

$

63

 

$

485

 

$

230

 

ARO

 

47

 

3

 

3

 

3

 

2

 

3

 

33

 

Operating lease obligations

 

16

 

2

 

2

 

3

 

3

 

3

 

3

 

Drilling and rig obligations

 

49

 

11

 

28

 

2

 

2

 

6

 

 

Firm natural gas transportation contracts

 

132

 

15

 

20

 

17

 

16

 

15

 

49

 

Total

 

$

1,478

 

$

83

 

$

122

 

$

360

 

$

86

 

$

512

 

$

315

 

 

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 March 31, 2010 and 2009. In 2006, the Company purchased an airplane for business travel which was subsequently sold and contracted under a ten year operating lease beginning December 2006.

 

Drilling obligations

 

The Company amended and restated its Utah Lake Canyon agreement in December 2009 and has a 14 gross well drilling commitment over the amended term (December 2009 to December 2014).  The Company’s minimum obligation under this exploration and development agreement is $14.7 million as of March 31, 2010.  Also included in the table above are the Company’s contractual obligations on its Piceance assets in Colorado.  The Company must spud 120 wells by February 2011 to avoid penalties of $0.2 million per well.  The Company expects to meet all obligations but its ability to meet this commitment depends on the capital resources available to the Company to fund its activities to develop these assets.

 

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 March 31, 2010 and 2009, the Company incurred $1.0 million and $0, respectively, under the agreements.

 

In June 2009, the Company amended its natural gas firm transportation agreement 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 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 the sales point. The pre-tax net of its gas marketing revenue and its gas marketing expense in the Condensed Statements of Income is $0.5 million and $0.3 million for the three months ended March 31, 2010 and 2009, respectively.

 

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.

 

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Table of Contents

 

Berry Petroleum Company

Notes to Unaudited Financial Statements

 

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 2,427 Bbl/D in the first quarter of 2010.

 

In December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC 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 California production.  Included in the allowance for doubtful accounts is $38.5 million due from BWOC. Of the $38.5 million due from BWOC, $11.8 million represents 20 days of the Company’s December 2008 crude oil sales, an administrative claim under the bankruptcy proceedings, and $26.7 million represents November 2008 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.  The Company has guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, in the event that the claim is not fully collectible from BWOC. While the Company believes that it may recover some or all of the amounts due from BWOC, the data 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 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, or on the 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 it 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 and accrued such amount in the second quarter of 2009.

 

During the California energy crisis in 2000 and 2001, the Company had electricity sales contracts with various utilities and a portion of the electricity prices paid to the Company under such contracts from December 2000 to March 27, 2001 has been under a degree of legal challenge since that time.  It is possible that the Company may have a liability pending the final outcome of the California Public Utilities Commission (CPUC) proceedings on the matter.  There are ongoing proceedings before the CPUC in which Edison and PG&E are seeking credit against future payments they are to make for electricity purchases based on retroactive adjustments to pricing under contracts with the Company.  Whether or not retroactive adjustments will be ordered, how such adjustments would be calculated and what period they would cover are too uncertain to estimate at this time.

 

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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 unaudited Condensed Financial Statements.  You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Conditions 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 and the unaudited 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 First Quarter Items.

 

·                  Achieved production averaging 29,391 BOE/D supported by a 500 BOE/D increase in oil

·                  Generated discretionary cash flow of $70 million (a)

·                  Increased diatomite net production to an average of 3,570 BOE/D, up 34% from the first quarter of 2009

·                  Closed on the acquisition of 6,900 net acres and 11 MMBOE of proved reserves, primarily in the Wolfberry trend in W. Texas for approximately $132 million

·                  Completed our first horizontal Haynesville well with an initial potential of approximately 10.3 MMcf/D gross production and 30-day average production of 9.0 MMcf/D

·                  Issued 8 million shares of Class A Common Stock for net proceeds of $224 million to fund the Wolfberry Acquisition and reduce debt

 

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

 

·                  Acquired a 90 acre lease from Chevron U.S.A. Inc. increasing diatomite acreage by 20%

·                  Closed on the acquisition of an additional 3,200 acres and 2 MMBOE of proved reserves in the Wolfberry trend for $14 million

·                  Expecting 2010 development capital expenditures between $250 million and $290 million to be fully funded from operating cash flow

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

 


(a)  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.

 

Overview of the First Quarter of 2010.

 

We had net income from continuing operations of $17.7 million, or $0.34 per diluted share, and net cash from operations was $63.5 million in the first quarter of 2010. Net income from continuing operations includes a $0.9 million gain on purchase of oil and natural gas properties related to the Wolfberry Acquisition offset by $1.3 million of acquisition-related expenses.  Also included in net income is a $0.9 million loss on derivatives as a result of amortization of frozen fair values and non-cash changes in fair values and $0.8 million of dry hole costs resulting from mechanical failure on one well in the Piceance basin. We drilled 59 gross wells and capital expenditures, excluding property acquisitions, totaled $48 million.  We achieved average production of 29,391 BOE/D in the first quarter of 2010, up 1% and down 3% from an average of 29,149 BOE/D and 30,231 BOE/D in the fourth quarter of 2009 and the first quarter of 2009, respectively.

 

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Table of Contents

 

Acquisitions.

 

During the first quarter of 2010, we acquired certain properties primarily in the Wolfberry trend in W. Texas from a private seller for total consideration of $132 million, including an initial purchase price of $126 million, and normal post-closing adjustments of $6 million.  The properties included total proved reserves of 11.2 MMBOE, of which 85% were crude oil and 23% were proved developed.  We have identified over 130 drilling locations on forty acre spacing in the Wolfberry trend targeting the Spraberry, Dean, Wolfcamp and Strawn formations.  We plan to test twenty acre down spacing in late 2010, which would provide an additional 150 drilling locations.  We operate approximately 70% of, and have an average 68.5% working interest (54.1% net revenue interest) in, the properties acquired in the Wolfberry trend.

 

Revenues.

 

Approximately 88% 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 6% 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. The remaining 6% of our revenues are primarily derived from gas marketing sales which represent our excess capacity on the Rockies Express pipeline which we used to market natural gas for our working interest partners.

 

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

 

 

 

March 31,
2010

(1Q10)

 

March 31,
2009

(1Q09)

 

1Q10 to
1Q09
Change

 

December
31, 2009

(4Q09)

 

1Q10 to
4Q09
Change

 

Sales of oil (1)

 

$

122

 

$

99

 

23%

 

$

109

 

12%

 

Sales of gas

 

26

 

29

 

(10)%

 

24

 

8%

 

Total sales of oil and gas

 

$

148

 

$

128

 

16%

 

$

133

 

11%

 

Sales of electricity

 

10

 

10

 

 

10

 

 

Gas marketing

 

8

 

8

 

 

5

 

60%

 

Realized and unrealized gain on derivatives, net

 

2

 

37

 

(95)%

 

 

 

Total revenues and other income

 

$

168

 

$

183

 

(8)%

 

$

148

 

14%

 

Net income from continuing operations

 

$

18

 

$

42

 

(57)%

 

$

13

 

38%

 

Diluted earnings per share from continuing operations

 

$

0.34

 

$

0.92

 

(63)%

 

$

0.28

 

21%

 

 


(1) Included in the fourth quarter of 2009 are adjustments to correct the prior accounting for royalties in the amount of $3 million, which resulted in decreasing our sales of oil and gas and increasing our royalties payable.  Management concluded the impact was immaterial to the fourth quarter of 2009 and prior periods.

 

20


 


Table of Contents

 

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

 

 

 

March 31,
2010

 

%

 

March 31,
2009

 

%

 

December 31,
2009

 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Heavy Oil Production (Bbl/D)

 

17,752

 

61

 

16,436

 

50

 

17,280

 

60

 

Light Oil Production (Bbl/D)

 

2,754

 

9

 

3,066

 

9

 

2,719

 

9

 

Total Oil Production (Bbl/D)

 

20,506

 

70

 

19,502

 

59

 

19,999

 

69

 

Natural Gas Production (Mcf/D)

 

53,309

 

30

 

82,979

 

41

 

54,899

 

31

 

Total operations (BOE/D)

 

29,391

 

100

 

33,332

 

100

 

29,149

 

100

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DJ Basin Production (BOE/D)

 

 

 

 

3,101

 

 

 

 

 

 

Production - Continuing Operations (BOE/D)

 

29,391

 

 

 

30,231

 

 

 

29,149

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and gas BOE for continuing operations

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price before hedging

 

$

57.06

 

 

 

$

29.36

 

 

 

$

50.76

 

 

 

Average sales price after hedging

 

55.99

 

 

 

47.11

 

 

 

48.77

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, per Bbl, for continuing operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

Average WTI price

 

$

78.88

 

 

 

$

43.24

 

 

 

$

76.13

 

 

 

Price sensitive royalties

 

(3.04

)

 

 

(1.02

)

 

 

(2.64

)

 

 

Quality differential and other

 

(8.12

)

 

 

(9.53

)

 

 

(9.63

)

 

 

Crude oil hedges reported with Sales of oil and gas

 

(1.72

)

(a)

 

23.79

 

(b)

 

(3.96

)

(b)

 

Correction to royalties payable (c)

 

 

 

 

 

 

 

(1.78

)

 

 

Average oil sales price after hedging

 

$

66.00

 

 

 

$

56.48

 

 

 

$

58.12

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas price for continuing operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Henry Hub price per MMBtu

 

$

5.30

 

 

 

$

4.90

 

 

 

$

4.17

 

 

 

Conversion to Mcf

 

0.27

 

 

 

0.25

 

 

 

0.21

 

 

 

Natural gas hedges reported with Sales of oil and gas

 

0.07

 

(a)

 

1.14

 

(b)

 

0.40

 

(b)

 

Location, quality differentials and other

 

(0.15

)

 

 

(1.27

)

 

 

(0.13

)

 

 

Average gas sales price after hedging per Mcf

 

$

5.49

 

 

 

$

5.02

 

 

 

$

4.65

 

 

 

 


(a)               Includes non-cash amortization of frozen December 31, 2009  fair values resulting from January 1, 2010 discontinuing of hedge accounting

(b)               Includes cash settlements on derivatives for which we had elected hedge accounting

(c)                Included in the fourth quarter of 2009 is a correction to one of our royalties in the amount of $3 million, which resulted in decreasing our sales of oil and gas and increasing our royalties payable.

 

Sales of Oil and Gas:

 

Oil and gas revenue increased 16% to $148 million in the first quarter of 2010 compared to $128 million in the first quarter of 2009.  The increase is primarily due to an increase in the average sales price after hedging to $55.99 per BOE in the first quarter of 2010 from $47.11 per BOE in the first quarter of 2009.  Oil and gas revenue increased 11% in the first quarter of 2010 compared to the fourth quarter of 2009.  The increase is primarily due to an increase in the average sales price after hedging to $55.99 per BOE in the first quarter of 2010 from $48.77 per BOE in the fourth quarter of 2009.  Approximately 70% of our oil and gas sales volumes in the first quarter of 2010 were crude oil, with 87% of the crude oil being heavy oil produced in California which was sold under various contracts with prices tied to the San Joaquin posted price.

 

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Table of Contents

 

Effective January 1, 2010, we elected to de-designate all of our commodity derivative 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 of discontinuing hedge accounting on January 1, 2010, changes in fair values at December 31, 2009 are frozen in accumulated other comprehensive loss (AOCL) as of the de-designation date and will be reclassified into oil and gas revenues in future periods as the original hedged transactions affect earnings.  As a result, in the first quarter of 2010, we reclassified $2.8 million of non-cash derivative losses relating to de-designated commodity hedges from AOCL into earnings under the caption Sales of oil and gas.  Beginning January 1, 2010 all of our derivative contracts are recorded at fair value each quarter with fair value gains and losses recognized immediately in earnings as Realized and unrealized gain on derivatives, net.  Cash flow is impacted to the extent that actual cash settlements under these contracts result in making or receiving a payment from the counterparty, and such cash settlement gains and losses are also recorded to earnings as Realized and unrealized gain on derivatives, net. See Realized and unrealized gain on derivatives, net below.

 

The average sales price received for oil sales during the first quarter of 2010 was $66.00 per BOE, an increase of 17% or $9.52 per BOE compared to the first quarter of 2009.  The range of NYMEX light sweet crude prices for the first quarter of 2010, based upon settlements, was from a low of $71.19 to a high of $83.76.  NYMEX light sweet crude prices for the first quarter of 2009, based upon settlements, was a low of $33.98 and a high of $54.34.  In California the differential on March 31, 2010 was $8.31 and ranged from a low of $6.82 to a high of $8.32 per barrel during the first quarter of 2010. The California differential ranged from a low of $5.20 to a high of $14.02 per barrel during the first quarter of 2009.  In Utah, we are a party to a crude oil sales contract through June 30, 2013 with a refiner for the purchase of our 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 our 40 degree black wax (light) crude oil can vary seasonally and this contract provides a stable outlet for the our crude oil.

 

The average sales price received for gas sales during the first quarter of 2010 was $5.49 per Mcf, an increase of 9% or $0.47 per Mcf compared to the first quarter of 2009. We sell our produced natural gas at various indices.  Henry Hub (HH) natural gas averaged $5.30 in the first quarter of 2010 and $4.90 in the first quarter of 2009.  As of mid-2009, the pricing of our Piceance basin natural gas production is tied to the eastern markets in Lebanon or Clarington Ohio, which averaged $0.21 above HH for the first quarter of 2010.  The Piceance basin natural gas was sold in the first quarter of 2009 based upon a mid-continent index such as PEPL, which averaged $1.51 below HH.  Correspondingly, most of the Uinta basin natural gas is sold based on a Questar index which averaged $0.28 below HH for the first quarter of 2010 and $1.72 below HH for the first quarter of 2009.  The E. Texas natural gas production was generally sold during the first quarter of 2010 at the Florida Zone 1 index which was $0.01 below HH for the first quarter of 2010.  The E. Texas natural gas production was sold during the first quarter of 2009 at the Texas Eastern - East Texas index, which averaged $0.78 below HH for the first quarter of 2009.

 

Sales of Electricity:

 

Electricity revenues remained relatively unchanged and operating costs increased in the first quarter of 2010 compared to the fourth quarter of 2009 as a result of flat electricity prices and 27% higher natural gas prices.  Electricity revenues decreased and operating costs increased in the first quarter of 2010 compared to the first quarter of 2009 due to 5% lower electricity prices and 8% higher natural gas prices. We purchased approximately 28 MMBtu/D and 27 MMBtu/D of natural gas as fuel for use in our cogeneration facilities for the three months ended March 31, 2010 and December 31, 2009, respectively.

 

The following table is for the three months ended:

 

 

 

March 31,
2010

 

March 31,
2009

 

December 31,
2009

 

Electricity

 

 

 

 

 

 

 

Revenues (in millions)

 

$

9.9

 

$

10.3

 

$

10.0

 

Operating costs (in millions)

 

$

9.7

 

$

8.8

 

$

9.3

 

Electric power produced - MWh/D

 

2,154

 

2,068

 

2,141

 

Electric power sold - MWh/D

 

1,979

 

1,939

 

1,942

 

Average sales price/MWh

 

$

56.17

 

$

58.85

 

$

56.17

 

Fuel gas cost/MMBtu (including transportation)

 

$

5.39

 

$

4.01

 

$

4.57

 

 

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Table of Contents

 

Natural Gas Marketing

 

We have long-term firm transportation contracts for our Piceance natural gas production, with total capacity of 35,000 MMBtu/D.  We pay a demand charge for this capacity and our own production does not currently fill that capacity. In order to maximize our firm transportation, we bought our partners’ share of the gas produced in the Piceance at the market rate for that area. We used our excess transportation to move this gas to where it was eventually sold. The pre-tax net of our gas marketing revenue and our gas marketing expense in the Condensed Statements of Income is $0.5 million and $0.3 million in the three months ended March 31, 2010 and 2009, respectively.  Firm transportation costs related to all of our Rockies Express volumes is reflected in Operating costs - oil and gas production and total $3.2 million and $2.9 million for the three months ended March 31, 2010 and 2009, respectively.

 

Realized and unrealized gain on derivatives, net

 

Realized and unrealized gain on derivatives, net is primarily related to derivatives which did not qualify for cash flow hedge accounting either at their inception or where hedge accounting was discontinued during their term. When the criteria for cash flow hedge accounting is not met or when cash flow hedge accounting is not elected, realized gains and losses (i.e., cash settlements) are recorded in Realized and unrealized gain on derivatives, net in the condensed statements of income. Similarly, changes in the fair value of the derivative instruments are recorded as unrealized gains or losses in the Condensed Statements of Income.  In contrast, cash settlements for derivative instruments that qualify for hedge accounting are recorded as additions to or reductions of oil and gas revenues, while changes in fair value of cash flow hedges are recognized, to the extent the hedge is effective, in AOCL until the hedged item is recognized in earnings.  Realized and unrealized gain on derivatives, net also includes any hedge ineffectiveness on cash flow hedges that qualify for hedge accounting.

 

During 2009, we entered into certain commodity derivative contracts that we did not designate as cash flow hedges.  In addition, effective January 1, 2010, we elected to de-designate all of our commodity and interest rate derivative contracts that had been previously designated as cash flow hedges as of December 31, 2009 and have elected to discontinue hedge accounting prospectively.  Accordingly, beginning January 1, 2010 all of our derivative contracts are recorded at fair value each quarter with fair value gains and losses recognized immediately in earnings.  Cash flow is impacted to the extent that actual cash settlements under these contracts result in making or receiving a payment from the counterparty, and such cash settlement gains and losses are also recorded to earnings under the caption Realized and unrealized gain on derivatives, net.

 

During the three months ended March 31, 2010, we recorded a $1.6 million gain under the caption Realized and unrealized gain on derivatives, net resulting from a gain for the change in fair value of $3.3 million, net of a loss on cash settlements of $1.7 million.

 

During the three months ended March 31, 2009, we recorded a $37.2 million gain under the caption Realized and unrealized gain on derivatives, net.  In conjunction with the sale of the DJ basin assets, during the first quarter of 2009, we concluded that the forecasted transaction in certain of our hedging relationships was not probable of occurring.  As such, we reclassified a gain of $14.3 million from AOCL to the Condensed Statements of Income under the caption Realized and unrealized gain on derivatives, net.  We also recognized an unrealized net gain of $22.9 million on the Condensed Statements of Income under the caption Realized and unrealized gain on derivatives, net for the three months ended March 31, 2009, respectively, as a result of ineffectiveness related to sales prices that were not perfectly correlated with our hedges.  We recorded an unrealized net loss of $0.5 million on the Condensed Statements of Income under the caption Loss from discontinued operations, net of taxes during the first quarter of 2009 related to natural gas derivatives entered into on behalf of the purchaser of our DJ assets for which we did not elect hedge accounting.

 

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Table of Contents

 

Oil and Gas Operating and Other Expenses. The following table presents information about our continuing operating expenses for each of the three month periods ended:

 

 

 

Amount per BOE

 

Amount (in thousands)