form10q.htm


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

FORM 10-Q

T Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2009
£ 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

Logo 1
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 T NO £

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 £ NO £

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 T Accelerated filer £ Non-accelerated filer £ Smaller reporting company £

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

As of July 20, 2009, the registrant had 42,826,373 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 July 20, 2009 all of which is held by an affiliate of the registrant.
 


 
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BERRY PETROLEUM COMPANY
SECOND QUARTER 2009 FORM 10-Q
TABLE OF CONTENTS
 
PART I.
FINANCIAL
INFORMATION
 
Page
     
 
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6
     
 
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19
     
 
31
     
 
35
     
     
     
PART II.
OTHER
INFORMATION
   
     
 
36
     
 
36
     
 
38
     
 
38
     
 
39
     
 
39
     
 
40


BERRY PETROLEUM COMPANY
Unaudited Condensed Balance Sheets
(In Thousands, Except Share Information)

   
June 30,
2009
   
December 31,
2008
 
ASSETS
           
Current assets:
           
Cash and cash equivalents
  $ 236     $ 240  
Short-term investments
    67       66  
Accounts receivable, net of allowance for doubtful accounts of $38,511 and $38,511
    65,854       65,873  
Deferred income taxes
    428       -  
Fair value of derivatives
    35,453       111,886  
Crude oil inventory
    2,794       -  
Prepaid expenses and other
    8,046       11,015  
Total current assets
    112,878       189,080  
Oil and gas properties (successful efforts basis), buildings and equipment, net
    2,096,966       2,254,425  
Fair value of derivatives
    3,614       79,696  
Other assets
    32,888       19,182  
    $ 2,246,346     $ 2,542,383  
LIABILITIES AND SHAREHOLDERS' EQUITY
               
Current liabilities:
               
Accounts payable
  $ 42,606     $ 119,221  
Revenue and royalties payable
    12,291       34,416  
Accrued liabilities
    26,084       34,566  
Line of credit
    -       25,300  
Income taxes payable
    -       187  
Fair value of derivatives
    34,235       1,445  
Deferred income taxes
    222       45,490  
Total current liabilities
    115,438       260,625  
Long-term liabilities:
               
Deferred income taxes
    243,537       270,323  
Senior secured revolving credit facility
    580,900       931,800  
8 ¼ % Senior subordinated notes due 2016
    200,000       200,000  
10 ¼ % Senior notes due 2014, net of unamortized discount of $20,707 and $0, respectively
    304,293       -  
Abandonment obligation
    40,986       41,967  
Other long-term liabilities
    4,789       5,921  
Fair value of derivatives
    40,462       4,203  
Total long-term liabilities
    1,414,967       1,454,214  
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; 42,826,373 shares issued and outstanding (42,782,365 in 2008)
    427       427  
Class B Stock, 3,000,000 shares authorized;  1,797,784 shares issued and outstanding in 2009 and 2008 (liquidation preference of $899)
    18       18  
Capital in excess of par value
    84,786       79,653  
Accumulated other comprehensive (loss) income
    (18,227 )     113,697  
Retained earnings
    648,937       633,749  
Total shareholders' equity
    715,941       827,544  
    $ 2,246,346     $ 2,542,383  

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


BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Operations
Three Months Ended June 30, 2009 and 2008
(In Thousands, Except Per Share Data)

   
Three months ended June 30,
 
   
2009
   
2008
 
REVENUES AND OTHER INCOME ITEMS
           
Sales of oil and gas
  $ 118,793     $ 169,022  
Sales of electricity
    6,624       16,979  
Gas marketing
    4,848       11,531  
Loss on derivatives
    (31,130 )     (20 )
Gain on sale of assets
    -       414  
Interest and other income, net
    806       934  
      99,941       198,860  
EXPENSES
               
Operating costs - oil and gas production
    34,738       52,332  
Operating costs - electricity generation
    6,397       15,515  
Production taxes
    4,885       6,568  
Depreciation, depletion & amortization - oil and gas production
    34,371       25,902  
Depreciation, depletion & amortization - electricity generation
    1,028       652  
Gas marketing
    4,232       11,071  
General and administrative
    13,164       10,929  
Interest expense
    10,589       3,552  
Loss on extinguishment of debt
    10,492       -  
Dry hole, abandonment, impairment and exploration
    17       3,180  
      119,913       129,701  
(Loss) income before income taxes
    (19,972 )     69,159  
(Benefit) provision for income taxes
    (7,204 )     25,447  
(Loss) income from continuing operations
    (12,768 )     43,712  
(Loss) income from discontinued operations, net of taxes
    (212 )     5,429  
                 
Net (loss) income
  $ (12,980 )   $ 49,141  
                 
Basic net (loss) income from continuing operations per share
  $ (0.28 )   $ 0.97  
Basic net (loss) income from discontinued operations per share
  $ -     $ 0.12  
Basic net (loss) income per share
  $ (0.28 )   $ 1.09  
                 
Diluted net (loss) income from continuing operations per share
  $ (0.28 )   $ 0.95  
Diluted net (loss) income from discontinued operations  per share
  $ -     $ 0.12  
Diluted net (loss) income per share
  $ (0.28 )   $ 1.07  
                 
Dividends per share
  $ .075     $ .075  



Unaudited Condensed Statements of Comprehensive Income (Loss)
Three Months Ended June 30, 2009 and 2008
(In Thousands)

Net (loss) income
  $ (12,980 )   $ 49,141  
Unrealized gains (losses) on derivatives, net of income taxes (benefits) of $56,358 and ($162,792), respectively
    91,952       (260,225 )
Reclassification of realized (losses) gains on derivatives included in net (loss) income, net of income taxes (benefits) of ($5,873) and $21,898, respectively
    (9,583 )     37,268  
Comprehensive income (loss)
  $ 69,389     $ (173,816 )

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


BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Operations
Six Months Ended June 30, 2009 and 2008
(In Thousands, Except Per Share Data)

   
Six months ended June 30,
 
   
2009
   
2008
 
REVENUES AND OTHER INCOME ITEMS
           
Sales of oil and gas
  $ 246,662     $ 320,688  
Sales of electricity
    16,895       32,906  
Gas marketing
    12,429       14,762  
Gain (loss) on derivatives
    6,034       (728 )
Gain on sale of assets
    -       414  
Interest and other income, net
    1,088       1,763  
      283,108       369,805  
EXPENSES
               
Operating costs - oil and gas production
    72,122       91,672  
Operating costs - electricity generation
    15,179       31,914  
Production taxes
    10,537       11,751  
Depreciation, depletion & amortization - oil and gas production
    70,769       50,108  
Depreciation, depletion & amortization - electricity generation
    1,987       1,345  
Gas marketing
    11,516       14,053  
General and administrative
    26,457       22,061  
Interest expense
    20,639       6,879  
Loss on extinguishment of debt
    10,494       -  
Dry hole, abandonment, impairment and exploration
    140       5,908  
      239,840       235,691  
Income before income taxes
    43,268       134,114  
Provision for income taxes
    14,258       50,866  
Income from continuing operations
    29,010       83,248  
(Loss) income from discontinued operations, net of taxes
    (6,991 )     8,924  
                 
Net income
  $ 22,019     $ 92,172  
                 
Basic net income from continuing operations per share
  $ 0.63     $ 1.85  
Basic net (loss) income from discontinued operations per share
  $ (0.15 )   $ 0.20  
Basic net income per share
  $ 0.48     $ 2.05  
                 
Diluted net income from continuing operations per share
  $ 0.63     $ 1.82  
Diluted net (loss) income from discontinued operations  per share
  $ (0.15 )   $ 0.19  
Diluted net income per share
  $ 0.48     $ 2.01  
                 
Dividends per share
  $ 0.15     $ 0.15  
 

Unaudited Condensed Statements of Comprehensive Income (Loss)
Six Months Ended June 30, 2009 and 2008
(In Thousands)

Net income
  $ 22,019     $ 92,172  
Unrealized gains (losses) on derivatives, net of income taxes (benefits) of $104,518 and ($203,141), respectively
    170,529       (320,748 )
Reclassification of realized gains on derivatives included in net income, net of income taxes (benefits) of ($23,661) and $33,596, respectively
    (38,605 )     54,815  
Comprehensive income (loss)
  $ 153,943     $ (173,761 )

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


BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Cash Flows
Six Months Ended June 30, 2009 and 2008
(In Thousands)

   
Six months ended June 30,
 
   
2009
   
2008
 
Cash flows from operating activities:
           
Net income
  $ 22,019     $ 92,172  
Depreciation, depletion and amortization
    74,944       57,493  
Loss on extinguishment of debt
    10,494       -  
Dry hole and impairment
    9,643       5,332  
Commodity derivatives
    8,287       494  
Stock-based compensation expense
    4,980       4,412  
Deferred income taxes
    8,090       39,030  
Loss (gain) on sale of oil and gas properties
    330       (414 )
Other, net
    (2,385 )     689  
Change in book overdraft
    (24,988 )     13,075  
Cash paid for abandonment
    (176 )     (2,127 )
Increase in current assets other than cash and cash equivalents
    (7,982 )     (29,294 )
(Decrease) increase in current liabilities other than book overdraft, line of credit and fair value of derivatives
    (44,076 )     12,952  
Net cash provided by operating activities
    59,180       193,814  
Cash flows from investing activities:
               
Exploration and development of oil and gas properties
    (72,651 )     (168,382 )
Property acquisitions
    (11,668 )     (380 )
Additions to vehicles, drilling rigs and other fixed assets
    (475 )     (3,201 )
Deposits on acquisitions
    -       (59,000 )
Proceeds from sale of assets
    138,597       1,809  
Capitalized interest
    (12,626 )     (8,463 )
Net cash provided by (used in) investing activities
    41,177       (237,617 )
Cash flows from financing activities:
               
Proceeds from line of credit
    248,500       187,100  
Payments on line of credit
    (273,800 )     (201,400 )
Proceeds from issuance of long-term debt
    890,300       286,300  
Payments on long-term debt
    (937,176 )     (220,300 )
Debt issuance cost
    (21,508 )     -  
Dividends paid
    (6,831 )     (6,705 )
Proceeds from stock option exercises
    87       2,640  
Excess tax benefit and other
    67       1,435  
Net cash (used in) provided by financing activities
    (100,361 )     49,070  
                 
Net (decrease) increase  in cash and cash equivalents
    (4 )     5,267  
Cash and cash equivalents at beginning of year
    240       316  
Cash and cash equivalents at end of period
  $ 236     $ 5,583  

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


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

1.
General

All adjustments which are, in the opinion of management, necessary for a fair statement of Berry Petroleum Company’s (the Company) financial position at June 30, 2009 and December 31, 2008 and results of operations and other comprehensive income (loss) and cash flows for the three and six months ended June 30, 2009 and 2008 have been included. All such adjustments, except as described below, are of a normal recurring nature. The results of operations and cash flows are not necessarily indicative of the results for a full year.

The accompanying unaudited condensed financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2008 financial statements, except that the DJ basin operations are now accounted for as discontinued operations as a result of the 2009 sale.  The December 31, 2008 Form 10-K should be read in conjunction herewith. The year-end condensed Balance Sheet was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Our cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at June 30, 2009 and December 31, 2008 is $6.8 million and $31.8 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

2.
Recent Accounting Developments

In December 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS 160 was issued to establish accounting and reporting standards for the noncontrolling interests in a subsidiary (formerly called minority interests) and for the deconsolidation of a subsidiary.  We adopted this Statement January 1, 2009 and it did not have a material effect on our financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities. Expanded disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. We adopted this Statement January 1, 2009 and we expanded our disclosures accordingly.

In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities ("FSP EITF 03-6-1"), which clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the earnings allocation in computing basic earnings per share under the two-class method described in SFAS No. 128, Earnings per Share.  All prior period earnings per share data presented shall be adjusted retrospectively to conform with the provisions of this pronouncement. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. We implemented EITF 03-06-1 during the first quarter of 2009.  See Note 12 to the condensed financial statements.

In September 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument.   This FSP also amends FASB Interpretation No.45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to require an additional disclosure about the current status of the payment/performance risk of a guarantee.  Further, this FSP clarifies the FASB’s intent about the effective date of FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities. This FSP became effective for our fiscal year beginning January 1, 2009 and we expanded our disclosures accordingly.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

In March 2009, the FASB unanimously voted for the FASB "Accounting Standards Codification" (the "Codification") to be effective beginning on July 1, 2009. Other than resolving certain minor inconsistencies in current United States Generally Accepted Accounting Principles ("GAAP"), the Codification is not supposed to change GAAP, but is intended to make it easier to find and research GAAP applicable to particular transactions or specific accounting issues. The Codification is a new structure which takes accounting pronouncements and organizes them by approximately ninety accounting topics. Once approved, the Codification will be the single source of authoritative U.S. GAAP. All guidance included in the Codification will be considered authoritative at that time, even guidance that comes from what is currently deemed to be a non-authoritative section of a standard. Once the Codification becomes effective in the third quarter of 2009, all non-grandfathered, non-SEC accounting literature not included in the Codification will become non-authoritative and we will update our disclosures accordingly.

In April 2009, the FASB issued FSP No. FAS 107-1, Interim Disclosures about Fair Value of Financial Instruments. FSP 107-1 requires disclosures about fair value of financial instruments for interim reporting periods as well as in annual financial statements.  FSP 107-1 was effective for us for the quarter ended June 30, 2009 and we expanded our disclosures accordingly.  See Note 3 to the condensed financial statements.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events, which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We implemented SFAS No. 165 during the second quarter of 2009 and we expanded our disclosures accordingly.  See Note 15 to the condensed financial statements.

3.
Fair Value Measurements

In September 2006, SFAS No. 157, Fair Value Measurements was issued by the FASB. This Statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. We adopted this Statement for financial instruments on January 1, 2008.

In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No. 157.  This Statement delayed the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities.  We adopted SFAS 157 for nonfinancial assets and nonfinancial liabilities on January 1, 2009 and it did not have a material effect on our financial statements.

In February of 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, which is effective for fiscal years beginning after November 15, 2007. SFAS 159 provides an option to elect fair value as an alternative measurement for selected financial assets and financial liabilities not previously carried at fair value. We adopted this Statement at January 1, 2008, but did not elect fair value as an alternative for any financial assets or liabilities.

Determination of fair value
We have established and documented a process for determining fair values. Fair value is based upon quoted market prices, where available. We have various controls in place to ensure that valuations are appropriate.  These controls include: identification of the inputs to the fair value methodology, determination of the validity of the source of the inputs, corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. Furthermore, while we believe these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

Valuation hierarchy
SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
•   Level 1 - inputs to the valuation methodology that are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•   Level 2 - inputs to the valuation methodology that include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•   Level 3 - inputs to the valuation methodology that are unobservable and significant to the fair value measurement.
A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Our oil swaps, natural gas swaps and interest rate swaps are valued using internal models which are based on active market data and are classified within Level 2 of the valuation hierarchy. The observable inputs include underlying commodity and interest rate levels and quoted prices of these instruments on actively traded markets.  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. Level 3 derivatives include oil collars, natural gas collars and natural gas basis swaps.

Assets and (liabilities) measured at fair value on a recurring basis

June 30, 2009 (in millions)
 
Total carrying value on the condensed Balance Sheet
   
Level 2
   
Level 3
 
                   
Commodity derivative asset (liability)
    (28.7 )     (71.8 )     43.1  
Interest rate swap asset (liability)
    (6.9 )     (6.9 )     -  
Total fair value asset (liability)
    (35.6 )     (78.7 )     43.1  

December 31, 2008 (in millions)
 
Total carrying value on the condensed Balance Sheet
   
Level 2
   
Level 3
 
                   
Commodity derivative asset (liability)
    198.4       25.9       172.5  
Interest rate swap asset (liability)
    (12.5 )     (12.5 )     -  
Total fair value asset (liability)
    185.9       13.4       172.5  

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 us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).

(in millions)
 
Three months ended June 30, 2009
   
Six months ended June 30, 2009
 
Fair value of Level 3 derivative assets, beginning of period
  $ 137.5     $ 172.5  
Total realized and unrealized (gains) losses included in Gain (loss) on derivatives
    31.1       (6.0 )
Purchases, sales and settlements, net
    (125.5 )     (126.8 )
Transfers in and/or out of Level 3
    -       3.4  
Fair value of Level 3 derivative liabilities, June 30, 2009
  $ 43.1     $ 43.1  
                 
Total unrealized gains (losses) included in income related to financial assets and liabilities still on the condensed balance sheet at June 30, 2009
  $ (31.1 )     (8.3 )

The $3.4 million of transfers into Level 3 for the six months ended June 30, 2009, represent crude oil collars that were converted to crude oil swaps during the first quarter of 2009.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

4.
Hedging
 
To minimize the effect of a downturn in oil and gas prices and protect our profitability and the economics of our development plans, we enter into crude oil and natural gas hedge contracts from time to time. The terms of contracts depend on various factors, including management's view of future crude oil and natural gas prices, acquisition economics on purchased assets and our future financial commitments. This price hedging program is designed to moderate the effects of a severe crude oil and natural gas price downturn while allowing us to participate in some commodity price increases. We benefit from lower natural gas pricing as we are a consumer of natural gas in our California operations.  In the Rocky Mountains and East Texas we benefit from higher natural gas pricing. We have hedged, and may hedge in the future, both natural gas purchases and sales as determined appropriate by management.  Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate in accordance with policy established by our board of directors.  Currently, our hedges are in the form of swaps and collars.  However, we may use a variety of hedge instruments in the future to hedge WTI or the index gas price.  We also utilize interest rate derivatives to protect against changes in interest rates on our floating rate debt.

The related cash flow impact of all of our hedges is reflected in cash flows from operating activities. At June 30, 2009, our net fair value derivative liability was $35.6 million as compared to a net fair value asset of $185.9 million at December 31, 2008 which reflects changes in commodity prices and interest rates. Based on NYMEX strip pricing as of June 30, 2009, we expect to make cash hedge payments under the existing derivatives of $4.7 million during the next twelve months. At June 30, 2009, “Accumulated Other Comprehensive Loss” (“AOCL”) consisted of $18.2 million, net of tax, of unrealized losses from our crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at June 30, 2009. Deferred net losses recorded in AOCL at June 30, 2009 and subsequent mark-to-market changes in the underlying hedging contracts are expected to be reclassified to earnings in the same period that the forecasted transaction impacts earnings.

We present our derivative assets and liabilities in our Condensed Balance Sheets on a net basis.  We net derivative assets and liabilities whenever we have a legally enforceable master netting agreement with a counterparty to a derivative contract.  We use these agreements to manage and reduce our potential counterparty credit risk.

The following table disaggregates our net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to master netting arrangements.  Finally, we identify the line items in our 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.  We use the end of period accounting designation to determine the classification for each derivative position.

 
As of June 30, 2009
 
 
Derivative Assets
 
Derivative Liabilities
 
(in millions)
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
Commodity – Oil
Current assets
    35.8  
Current liability
    25.3  
Commodity – Natural Gas
Current assets
    2.5         -  
Commodity – Oil
Long term assets
    3.9  
Long term liabilities
    39.3  
Commodity – Natural Gas
Long term liabilities
    0.4         -  
Commodity – Natural Gas
Current liability
    1.1            
Interest rate contracts
         
Current assets
    2.8  
Interest rate contracts
         
Long term assets
    0.3  
Interest rate contracts
         
Current liabilities
    2.4  
Interest rate contracts
         
Long term liabilities
    1.4  
Total derivatives designated as hedging instruments under Statement 133
      43.7         71.5  
                     
Commodity – Oil
   -  
Current liabilities
    7.3  
Commodity – Natural Gas
    -  
Current liabilities
    0.3  
Commodity – Natural Gas
    -  
Long term liabilities
    0.2  
Total derivatives not designated as hedging instruments under Statement 133
    -         7.8  
Total Derivatives
    43.7         79.3  


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

The tables below summarize the Statement of Operations impacts on our derivative instruments:

Derivatives in Statement 133 cash flow hedging relationships
 
Amount of gain (loss) Recognized in OCI on Derivative
(Effective portion)
   
Location of Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
 
Amount of Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
   
Location of Gain (loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Amount of Gain (loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
   
Six Months Ended
June 30, 2009
       
Six Months Ended
June 30, 2009
       
Six Months Ended
June 30, 2009
 
Commodity  - Oil
  $ 163.9    
Sales of oil and gas
  $ 35.4    
Sales of oil and gas
  $ -  
Commodity  - Natural Gas
    11.3    
Sales of oil and gas
    4.8    
Gain (loss) on  derivatives
    14.6  
Interest rate
    (4.6 )  
Interest expense
    (1.6 )  
Gain (loss) on  derivatives
    (0.3 )
Total
  $ 170.6         $ 38.6         $ 14.3  

Amount of Gain or (Loss) Recognized in Income on Derivatives not designated as Hedging Instruments under Statement 133:

Derivatives not designated as Hedging Instruments under Statement 133
Location of Gain (Loss) Recognized in Income on Derivative
 
Amount of Gain (Loss) Recognized in Income on Derivatives not designated as Hedging Instruments under Statement 133
 
     
Six months ended June 30, 2009
 
Commodity – Oil
Gain (loss) on  derivatives
  $ (7.3 )
Commodity - Natural Gas
Gain (loss) on  derivatives
    (1.0 )
Total Derivatives
    $ (8.3 )

We entered into the following natural gas hedges during the three months ended June 30, 2009:

Instrument
Duration
 
Average MMBtu/D
 
Swap Price
NYMEX HH Swap
July – December 2009
 
5,000
 
$4.210
NYMEX HH Swap
Full year 2010
 
5,000
 
$6.020
NYMEX HH Swap
Full year 2011
 
5,000
 
$6.885
NYMEX HH Swap
Full year 2012
 
5,000
 
$7.160
Houston Ship Channel basis swap
July – December 2009
 
2,500
 
$0.305
Houston Ship Channel basis swap
Full year 2010
 
2,500
 
$0.345
Houston Ship Channel basis swap
Full year 2011
 
2,500
 
$0.325
Houston Ship Channel basis swap
Full year 2012
 
2,500
 
$0.320
NGPL-Tex OK basis swap
July – December 2009
 
2,500
 
$0.475
NGPL-Tex OK basis swap
Full year 2010
 
2,500
 
$0.415
NGPL-Tex OK basis swap
Full year 2011
 
2,500
 
$0.460
NGPL-Tex OK basis swap
Full year 2012
 
2,500
 
$0.440

The NYMEX HH swaps have been designated as cash flow hedges in accordance with SFAS No. 133.   The basis hedges at Houston Ship Channel and NGPL-Tex OK did not qualify for hedge accounting at June 30, 2009.

We entered into the following oil collar derivatives during the three months ended June 30, 2009:

Crude Oil Sales (NYMEX WTI) Collars
 
Average Barrels Per Day
 
Floor/Ceiling Prices
Full year 2012
 
1,000
 
$63.00 / $83.50
Full year 2012
 
1,000
 
$70.00 / $93.00


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

These oil hedge derivatives have been designated as cash flow hedges in accordance with SFAS No. 133.

We entered into the following oil swap derivatives during the three months ended June 30, 2009:

Crude Oil Sales (NYMEX WTI) Collars
 
Average Barrels Per Day
 
Swap Price
October 2009
 
1,613
 
$65.85
November 2009
 
1,667
 
$65.85

These oil hedge derivatives have been designated as cash flow hedges in accordance with SFAS No. 133.

During the first quarter of 2009, we also converted oil collars for 6,000 Bbl/D ranging from floors of $55.00 to $60.00 and ceilings of $75.00 to $83.10 for full year 2010 swaps for the same volumes with swap prices ranging from $61.00 to $64.80.

We generally utilize NYMEX WTI based derivatives to hedge cash flows from our California oil sales.  Our oil sales contracts with multiple refiners are primarily based on the field posting prices.  There is a high correlation between WTI and the field posting prices which allows us to utilize hedge accounting.  As there is a ready market for our crude oil in California, we do not believe the loss of any particular refiner impacts the probability that our hedged forecasted transactions will occur.  We generally hedge our natural gas at the basis location that corresponds to the sale.  
 
While we designate the majority of our hedges as cash flow hedges, we have not elected hedge accounting on certain of our crude oil and natural gas hedges.  During the three and six months ended June 30, 2009, we recorded ($8.3) million and $6.0 million under the caption “Gain (loss) on derivatives”  related to hedges for which we either did not elect hedge accounting or they no longer qualified for hedge accounting.  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 accumulated other comprehensive income (loss) to the statement of operations under the caption “Gain (loss) on derivative.”  Additionally, a portion of the change in fair value for hedges that we have designated as cash flow hedges impacts our income as our sales price is not perfectly correlated with our hedges.  We recognized an unrealized net loss of approximately $22.8 million and $0 million on the statement of operations under the caption “Gain (loss) on derivatives” for the second quarter and six months ended June 30, 2009, respectively, as a result of this ineffectiveness.  During the first quarter of 2009, we entered into natural gas derivatives on behalf of the purchaser of our DJ assets.   We did not elect hedge accounting for these hedges and recorded an unrealized net loss of $0.5 million on the statement of operations under the caption “(Loss) income from discontinued operations, net of taxes.”

Our hedge contracts have been primarily executed with counterparties that are party to our senior secured revolving credit facility. Neither we nor our counterparties are required to post collateral in connection with our derivative positions and netting agreements are in place with each of our counterparties allowing us to offset our derivative asset and liability positions.  The credit rating of each of these counterparties was AA-/Aa2, or better as of June 30, 2009.  Our derivatives are held with a small number of counterparties and as of June 30, 2009, our largest three counterparties accounted for 70% of the value of our total derivative positions.

As of June 30, 2009, we had the following commodity hedges:

 
2009
2010
2011
2012
Oil Bbl/D:
17,535
14,930
9,020
3,000
Natural Gas MMBtu/D:
10,000
14,000
5,000
5,000

5.
Crude Oil Inventory

 
In May 2009, we entered into a sales agreement with a refiner for 1,500 barrels per day of production from our Poso Creek property for the months of May and June 2009.  Under this agreement, we delivered approximately 100,000 barrels of oil to the refiner and received inventory of a slightly higher quality crude oil at the refinery.  The refiner will purchase the inventory from us in September and October 2009 at the then current market price.  This transaction was accounted for as a non-monetary exchange and the amount recorded in crude oil inventory as of June 30, 2009 reflects the cost of production, transportation costs and quality differentials for the inventory volume.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

6.
Asset Retirement Obligations

Inherent in the fair value calculation of the asset retirement obligation (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.

The following table summarizes the change in abandonment obligation for the six months ended June 30, 2009 (in thousands):

Beginning balance at January 1, 2009
  $ 41,967  
Liabilities incurred
    -  
Liabilities settled
    (2,927 )
Revisions in estimated liabilities
    -  
Accretion expense
    1,946  
Ending balance at June 30, 2009
  $ 40,986  

7.
Acquisitions

During the six months ended June 30, 2009, we completed acquisitions totaling $11.7 million. In June 2009, we acquired property near McKittrick, California; the deep rights to one of the leases in our Darco property in E. Texas; and additional interests in our Piceance Garden Gulch assets.

8.
Dispositions and Discontinued Operations

On March 3, 2009, we entered into an agreement to sell our 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.  We recorded a pre-tax impairment loss of $9.6 million related to the sale, which is aggregated within the $7.0 million “(Loss) income from discontinued operations, net of taxes” on our statement of operations for the six months ended June 30, 2009.

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

   
For the Three Months Ended
   
For the Six Months Ended
 
   
June 30,
   
June 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Oil and gas revenue
  $ -     $ 16,310     $ 5,396     $ 29,139  
Loss on sale of asset
    (330 )     (414 )     (330 )     -  
Other revenue
    -       591       623       1,091  
Total Revenue
    (330 )     16,487       5,689       30,230  
                                 
Operating expenses
    -       2,853       2,576       5,142  
Production taxes
    -       913       195       1,697  
DD&A
    -       3,171       2,188       6,040  
General and administrative
    -       231       388       482  
Interest expense
    -       399       815       810  
Commodity derivatives
    -       -       484       -  
Dry hole, abandonment, impairment and exploration
    -       284       9,637       1,682  
Total Expenses
    -       7,851       16,283       15,853  
                                 
(Loss) income from discontinued operations, before income taxes
    (330 )     8,636       (10,594 )     14,377  
Income tax benefit (expense)
    118       (3,207 )     3,603       (5,453 )
(Loss) income from discontinued operations
  $ (212 )   $ 5,429     $ (6,991 )   $ 8,924  


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

9.
Dry Hole, Abandonment and Impairment

During the six months ended June 30, 2009 and 2008, we recorded dry hole, abandonment, impairment and exploration expense of $0.1 million and $5.9 million, respectively.   In the first quarter of 2008, technical difficulties on three wells in the Piceance basin were encountered before reaching total depth and these holes were abandoned in favor of drilling to the same bottom hole location by drilling a new well.

10.
Pro Forma Results

On July 15, 2008, the Company acquired certain interests in natural gas producing properties on 4,500 net acres in Limestone and Harrison Counties in East Texas for $668 million cash (East Texas Acquisition) including an initial purchase price of $622 million, and normal post closing adjustments of $46 million.

The unaudited pro forma results presented below for the three and six months ended June 30, 2008 have been prepared to give effect to the East Texas Acquisition on the Company’s results of continuing operations under the purchase method of accounting as if it had been consummated at January 1, 2008.  The unaudited pro forma results (in millions) do not purport to represent the results of continuing operations that actually would have occurred on such date or to project the Company’s results of operations for any future date or period:

   
Three Months Ended
June 30, 2008
   
Six Months Ended
June 30, 2008
 
Pro forma revenue
  $ 224,200     $ 410,160  
Pro forma income from operations
  $ 73,703     $ 133,776  
Pro forma net income
  $ 46,097     $ 83,039  
Pro forma basic earnings per share
  $ 1.02     $ 1.81  
Pro forma diluted earnings per share
  $ 1.00     $ 1.81  
 
 
11.
Income Taxes

The effective income tax rate was 36.1% for the second quarter of 2009 compared to 33.9% for the first quarter of 2009 and 36.8% for the second quarter of 2008.  Our estimated annual effective tax rate varies from the 35% federal statutory rate due to the effects of state income taxes, the reduction in our liability related to uncertain tax positions and estimated permanent differences.

As of June 30, 2009, we had a gross liability for uncertain tax benefits of $8.8 million of which $7.1 million, if recognized, would affect the effective tax rate. The liability related to uncertain tax positions has been reduced during the second quarter ended June 30, 2009 due to the resolution of our IRS examination for 2005.

Due to the uncertainty about the future periods in which other examinations will be completed and limited information related to current audits, we are not able to make reasonably reliable estimates of the periods in which cash settlements will occur with taxing authorities for the noncurrent liabilities.
 
12.
Earnings per Share

In SFAS No. 128, “Earnings per Share (as amended)”, the two-class method is an earnings allocation formula that determines earnings per share for each class of stock according to dividends declared (or accumulated) and participation rights in undistributed earnings.  In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities ("FSP EITF 03-6-1"), which clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the earnings allocation in computing basic earnings per share under the two-class method described in SFAS No. 128.  All prior period earnings per share data presented were adjusted retrospectively to conform with the provisions of this pronouncement. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. Accordingly, we have adopted this pronouncement as of January 1, 2009.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following table shows the computation of basic and diluted net (loss) income per share from continuing and discontinued operations for the three and six months ended June 30, 2009 and 2008.
 
   
Three months ended
   
Six months ended
 
   
June 30,
   
June 30,
   
June 30,
   
June 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Net (loss) income from continuing operations
  $ (12,768 )   $ 43,712     $ 29,010     $ 83,248  
Less: Income allocable to participating securities
    -       601       712       1,142  
(Loss) income available for shareholders
    (12,768 )     43,111       28,298       82,106  
                                 
Net (loss) income from discontinued operations
    (212 )     5,429       (6,991 )     8,924  
Less:  Income allocable to participating securities
    -       76       -       131  
Loss (income)  from discontinued operations available for shareholders
    (212 )     5,353       (6,991 )     8,793  
                                 
Basic (loss) earnings per share from continuing operations
    (.28 )     .97       .63       1.85  
Basic (loss) earnings per share from discontinued operations
    -       .12       (.15 )     .20  
Basic (loss) earnings per share
    (.28 )     1.09       .48       2.05  
                                 
Diluted (loss) earnings per share from continuing operations
    (.28 )     .95       .63       1.82  
Diluted (loss) earnings per share from discontinued operations
    -       .12       (.15 )     .19  
Basic (loss) earnings per share
  $ (.28 )   $ 1.07     $ .48     $ 2.01  
                                 
Weighted average shares outstanding - basic
    44,606       44,478       44,594       44,435  
Add:  dilutive effects of stock options
    206       783       126       723  
Weighted average shares outstanding - dilutive
    44,812       45,261       44,720       45,158  
 
Options to purchase 1.7 million and 1.9 million shares were not included in the diluted (loss) earnings per share calculation for the three and six months ended June 30, 2009, because their effect would have been anti-dilutive.  All outstanding options for the three and six months ended June 30, 2008 were included in the calculation of dilutive (loss) earnings per share.

The adoption of EITF 03-06-1 decreased basic (loss) earnings per share from continuing operations by $.01 and $.02 for the three and six months ended June 30, 2008 and dilutive (loss) earnings per share from continuing operations by $.01 for the three and six months ended June 30, 2008.  Basic (loss) earnings per share from discontinued operations remained unchanged for the three and six months ended June 30, 2008 and diluted (loss) earnings per share from discontinued operations remained unchanged for the three months ended June 30, 2008 and decreased $.01 for the six months ended June 30, 2008.

13.
Debt Obligations

Short-term lines of credit
In 2005, we completed an unsecured uncommitted money market line of credit (Line of Credit). Borrowings under the Line of Credit may be up to $30 million for a maximum of 30 days.  The Line of Credit may be terminated at any time upon written notice by either us or the lender.  In conjunction with the amendment to our senior secured credit facility, on July 15, 2008, the Line of Credit was secured by our assets.  At June 30, 2009 and December 31, 2008, the outstanding balance under this Line of Credit was $0 and $25.3 million, respectively.  Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1.5%.

Senior Secured Revolving Credit Facility
Our Senior Secured Revolving Credit Facility (the Agreement) has a current borrowing base and lender commitments of $969 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 ratio
 
Senior secured debt to EBITDAX ratio
2009
2010
Thereafter
 
to Sep 2010
Mar 2011
Sep 2011
Thereafter
4.75
4.50
4.00
 
3.75
3.50
3.25
3.0


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

The write off of $38.5 million to bad debt expense associated with the bankruptcy of Big West Oil of California (‘Big West”) is excluded from the calculation of EBITDAX.  The Agreement contains a current ratio covenant which, as defined, must be at least 1.0.  During the second quarter of 2009 our borrowing base decreased from $1.25 billion to $969 million as a result of our scheduled semi-annual borrowing base redetermination and the issuance of our senior unsecured notes.  We wrote off $3.3 million of deferred loan fees during the second quarter of 2009 as a result of the decrease to our borrowing base in accordance with Emerging Issues Task Force (EITF) 98-14, Debtor’s Accounting for Changes in Line-of-Credit or Revolving-Debt Arrangements.

The total outstanding debt at June 30, 2009 under the Agreement, as amended, and the Line of Credit was $581 million and $0, respectively, and $3 million in letters of credit have been issued under the facility, leaving $384 million in borrowing capacity available.  The maximum amount available is subject to semi-annual redeterminations of the borrowing base, based on the value of our proved oil and gas reserves, in April and October of each year in accordance with the lenders’ customary procedures and practices.  Both we and the banks have the bilateral right to one additional redetermination each year.

2nd Lien Term Loan
On April 27, 2009 we completed a $140 million second lien credit facility, with lenders from among our current lending group, with a maturity of January 16, 2013.  We paid off the 2nd lien term loan on May 29, 2009 from the proceeds of our senior unsecured notes issuance and expensed $7.2 million in associated fees in the second quarter of 2009.

Senior Unsecured 10.25% notes due 2014
On May 27, 2009, we issued in a public offering $325 million of 10.25% senior subordinated notes due 2014 (the Notes).  Interest on the Notes is paid semiannually in June and December of each year.  The notes were issued at a discount to par value of 93.546%, and are carried on the balance sheet at their amortized cost. The deferred costs of approximately $9.5 million associated with the issuance of this debt are being amortized over the five year life of the Notes.  The proceeds were used to pay down the $140 million second lien facility in full and to reduce outstanding amounts under our credit facility.   Pursuant to the terms of our senior secured credit facility, the issuance of the Notes automatically reduced our borrowing base by 25 cents per dollar of Notes issued, or approximately $81 million.

Senior Subordinated 8.25% notes due 2016
In 2006, we 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 senior secured revolving credit facility contains restrictive covenants as described above.  The $200 million Sub notes are subordinated to our credit facility indebtedness, and as long as the interest coverage ratio (as defined) is greater than 2.5 times, we may incur additional debt.    We were in compliance with all of these covenants as of June 30, 2009.

 
As of
June 30, 2009
Current Ratio (Not less than 1.0)
5.7
EBITDAX To Total Funded Debt Ratio (Not greater than 4.75)
3.1
Interest Coverage Ratio (Not less than 2.5)
5.2

The weighted average interest rate on total outstanding borrowings at June 30, 2009 was 6.0%.

Fair Value of Debt Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties.  We use available quoted market prices to estimate the fair value of debt.  The cost and fair value of our debt instruments are as follows at June 30, 2009:

(in millions)
 
Cost
   
Fair Value
 
Senior secured revolving credit facility
  $ 581     $ 581  
8 ¼ % Senior subordinated notes due 2016
    200       171  
10 ¼ % Senior notes due 2014
    325       327  
    $ 1,106     $ 1,079  


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

14.
Contingencies and Commitments

Our contractual obligations as of June 30, 2009 are as follows (in millions):

 
Total
 
2009
 
2010
 
2011
 
2012
 
2013
 
Thereafter
 
Total debt and interest
$ 1,440.5   $ 33.1   $ 66.2   $ 66.2   $ 639.6   $ 49.8   $ 585.6  
Abandonment obligations
  41.0     1.6     1.6     1.6     1.6     1.6     33.0  
Operating lease obligations
  17.1     1.2     2.4     2.4     2.4     2.5     6.2  
Drilling and rig obligations
  40.7     6.5     8.0     8.0     18.2     -     -  
Firm natural gas transportation contracts
  144.7     9.2     19.1     19.1     17.8     15.7     63.8  
Total
$ 1,684.0   $ 51.6   $ 97.3   $ 97.3   $ 679.6   $ 69.6   $ 688.6  

We have no material accrued environmental liabilities for our sites, including sites in which governmental agencies have designated us 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. We are involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of our business. In the opinion of management, the resolution of these matters will not have a material effect on our financial position, or on the results of operations or liquidity.

During the California energy crisis in 2000 and 2001, we had electricity sales contracts with various utilities and a portion of the electricity prices paid to us 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 we may have a liability pending the final outcome of the 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 adjustment to pricing under contracts with us.  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.

On May 27, 2009, we issued in a public offering $325 million of 10.25% senior subordinated notes due 2014 (the Notes).  Interest on the Notes is paid semiannually in June and December of each year.

On June 17, 2009, we amended our natural gas firm transportation agreement with Enbridge Pipelines providing for transportation of our 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.

Certain of our royalty payment calculations are being disputed.  We believe that our royalty calculations are in accordance with applicable leases and other agreements.  However, the disputed amounts that we may be required to pay are up to approximately $4 million.

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 production.  Included in our 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 our December crude oil sales and an administrative claim under the bankruptcy proceedings and $26.7 million represents November and the balance of December crude oil sales which would have the same priority as other general unsecured claims.  BWOC will also be liable to us for damages under this contract.  We have guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, in the event that our claim is not fully collectible from BWOC. While we believe that we may recover some or all of the amounts due from BWOC, the data received from the bankruptcy proceedings to date has not provided us with adequate data from which to make a conclusion that any amounts will be collected.

In February 2007, we entered into a multi-staged crude oil sales contract with a refiner for our Uinta light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D in July 2007. After partial completion of its refinery expansion in Salt Lake City in March 2008, the refiner increased its total purchase capacity to 5,000 Bbl/D.  This contract is in effect through June 30, 2013.  Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI, which ranges  from $10 to $15 per barrel at WTI prices between $40 and $60 per barrel.  This contract is our only sales contract for our Uinta oil.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

We have two long-term firm transportation contracts that total 35,000 MMBtu/D on the Rockies Express (REX) pipeline for gas production in the Piceance basin.  We pay a demand charge for this capacity and our own production did not completely fill that capacity. To maximize the utilization of our firm transportation, we bought our partners’ share of the gas produced in the Piceance basin at the market rate for that area and used our excess transportation to move this gas to the sales point. The pre-tax net of our gas marketing revenue and our gas marketing expense in the Statements of Operations is $0.6 million and $0.9 million for the three and six month periods ended June 30, 2009, respectively.

In addition, Berry has signed a binding precedent agreement with El Paso Corporation for an average of 35,000 MMBtu/d of firm transportation on the proposed Ruby Pipeline from Opal, WY to Malin, OR.  While it is not certain that this new line will be constructed, the expectation is that the project will proceed and be in service by 2011.  As part of this agreement and in order to access the Ruby pipeline, we also secured firm transportation from the Piceance basin to Opal.

15.
Subsequent Events

Subsequent events have been evaluated through August 5, 2009, the date these financial statements were issued.

On July 17, 2009, we closed on the sale of our E. Texas gas gathering system for $18.4 million in cash.  We entered into concurrent long-term gas gathering agreements for the E. Texas production.  The transaction meets the criteria to be accounted for as a sale-leaseback and a capital lease.
 
In July 2009, we 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 our Uinta basin operations.  The proposed civil penalty was $69.6 million and reflects the theoretical maximum penalty amount under applicable regulations, absent mitigating factors.  We immediately remediated the instances of non-compliance in 2007, cooperated fully with BLM's investigation and we believe no production was lost, all royalties were paid and there was no harm to the invironment.  Due to the above mitigating factors, among others, we believe this matter will be resolved by the payment of a penalty that will not exceed $2.1 million and have accrued such amount in the second quarter of 2009.


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

General. The following discussion provides information on the results of operations for the three and six months ended June 30, 2009 and 2008 and our financial condition, liquidity and capital resources as of June 30, 2009. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion.

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. 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.

Overview. We seek to increase shareholder value through consistent growth in our production and reserves, both through the drill bit and acquisitions. We strive to operate our properties in an efficient manner to maximize the cash flow and earnings of our assets. The strategies to accomplish these goals include:
 
·
Developing our existing resource base
 
·
Investing our capital in a disciplined manner and maintaining a strong financial position
 
·
Accumulating acreage positions near our producing operations
 
·
Acquiring additional assets with significant growth potential

Notable Second Quarter Items.
 
·
Achieved production averaging 29,270 BOE/D, of which 68% is crude oil production
 
·
Increased Diatomite net production to an average of 2,930 BOE/D, up 72% from the second quarter of 2008
 
·
Reduced operating expenses by 42% on a BOE basis from the second quarter of 2008
 
·
Completed our credit facility borrowing base redetermination with a current borrowing base of $969 million
 
·
Issued $325 million of 10.25% senior unsecured notes due in 2014
 
·
Acquired property near McKittrick, California with development potential similar to our Poso Creek asset and plan to initiate a steam flood pilot in late 2009
 
·
Acquired deep rights on our E. Texas Darco property providing an additional 13 Haynesville horizontal locations
 
·
Completed the sale of our DJ basin assets using proceeds for the repayment of debt
 
·
Agreed to sell our E. Texas midstream assets for $18.4 million and increased our capital budget by up to $32 million

Notable Items and Expectations for the Third Quarter and Full Year 2009.
 
·
On July 17, 2009, closed the sale of our E. Texas midstream assets with net proceeds after closing adjustments of $18.4 million
 
·
Increased liquidity to approximately $400 million subsequent to closing our E. Texas midstream asset sale
 
·
Expect production to average approximately 30,000 BOED for the full year 2009

Overview of the second Quarter of 2009. We had a net loss from continuing operations of $12.8 million, or $0.28 per diluted share, and net cash from operations was $51.1 million in the second quarter of 2009. The net loss includes a pre-tax non-cash loss on derivatives of $31.1 million and a pre-tax charge of $10.5 million for debt extinguishment costs and a liability for a regulatory compliance matter of $2.1 million.  We drilled 35 gross wells and capital expenditures, excluding property acquisitions, totaled $22.9 million.  We achieved average production of 29,270 BOE/D in the second quarter of 2009.

Acquisitions.  In June 2009, we acquired Section 21Z property in McKittrick, California.  We believe this acquisition provides us with another opportunity to increase our crude oil production and reserves with potential similar to our Poso Creek asset.  We also acquired deep rights to one of the leases in our Darco property in E. Texas, providing us with an additional 13 Haynesville horizontal locations, and increased our interest at Garden Gulch in the Piceance.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Asset Dispositions.  On March 3, 2009, we entered into an agreement to sell our DJ basin assets and related hedges for $154 million before customary closing adjustments. The closing date of the sale of our DJ basin assets was April 1, 2009.  We recorded an impairment charge associated with the sale of $9.6 million during the first quarter of 2009.  Post closing adjustments recorded in the second quarter of 2009 were $0.2 million.  The total loss on sale was recorded within “(Loss) income from discontinued operations, net of tax,” on the condensed statements of operations for the six months ended June 30, 2009.

Results of Operations. The following results from continuing operations are in millions (except per share data) for the three and six month periods ended:

   
Three months ended,
   
Six months ended,
 
   
June 30,
2009
   
June 30,
2008
   
March 31,
2009
   
June 30,
2009
   
June 30,
2008
 
Sales of oil
  $ 103     $ 146     $ 99     $ 201     $ 277  
Sales of gas
    16       23       29       46       44  
Total sales of oil and gas
  $ 119     $ 169     $ 128     $ 247     $ 321  
Sales of electricity
    6       17       10       17       33  
Gas Marketing
    5       12       8       12       15  
Gain (loss) on derivative
    (31 )     -       37       6       (1 )
Interest and other income, net
    1       1       -       1       2  
Total revenues and other income
  $ 100     $ 199     $ 183     $ 283     $ 370  
Net income (loss) from continuing operations
  $ (13 )   $ 44     $ 42     $ 29     $ 83  
Diluted earnings (loss) per share from continuing operations
  $ (0.28 )   $ 0.95     $ 0.92     $ .63     $ 1.82  

Our revenues may vary significantly from period to period as a result of changes in commodity prices and/or production volumes.  Crude oil sales in the three months ended June 30, 2009 were higher than the three months ended March 31, 2009 resulting from price increases of 4% and relatively flat sales volume.  The decrease in revenue when compared to the second quarter of 2008 is primarily the result of a 24% decrease in realized prices.  Natural gas revenues decreased from the quarter ended March 31, 2009 as a result of a 37% decrease in realized prices and a 6 % decrease in volumes from our Piceance and Uinta properties where no capital activity occurred during the quarter.  Natural gas revenues were lower in the second quarter of 2009 compared to the second quarter of 2008 primarily due to a 65% decrease in realized prices, offset by the 25 MMcfe/D contribution from our East Texas assets which we purchased in July of 2008.

Graph 1
 

Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operating data. The following table is for the three months ended:
 
   
June 30, 2009
   
%
   
June 30, 2008
   
%
   
March 31, 2009
   
%
 
                                     
Heavy Oil Production (Bbl/D)
    16,822       57       16,888       58       16,436       50  
Light Oil Production (Bbl/D)
    3,085       11       3,723       13       3,066       9  
Total Oil Production (Bbl/D)
    19,907       68       20,611       71       19,502       59  
Natural Gas Production (Mcf/D)
    56,174       32       50,339       29       82,979       41  
Total operations (BOE/D)
    29,270       100       29,000       100       33,332       100  
                                                 
DJ Basin Production (BOE/D)
    -               3,269               3,101          
Production - Continuing Operations (BOE/D)
    29,270               25,731               30,231          
                                                 
Oil and gas, per BOE for continuing operations
                                               
Average sales price before hedging
  $ 39.34             $ 96.55             $ 29.36          
Average sales price after hedging
    45.74               71.64               47.11          
                                                 
Oil, per Bbl, for continuing operations:
                                               
Average WTI price
  $ 59.79             $ 123.80             $ 43.24          
Price sensitive royalties
    (2.08 )             (5.92 )             (1.02 )        
Quality differential and other
    (7.86 )             (11.52 )             (9.53 )        
Crude oil hedges
    8.91               (29.37 )             23.79          
Average oil sales price after hedging
  $ 58.76             $ 76.99             $ 56.48          
                                                 
Natural gas price for continuing operations:
                                               
Average Henry Hub price per MMBtu
  $ 3.51             $ 10.49             $ 4.90          
Conversion to Mcf
    0.18               0.53               0.25          
Natural gas hedges
    0.21               -               1.14          
Location, quality differentials and other
    (0.72 )             (1.87 )             (1.27 )        
Average gas sales price after hedging per Mcf
  $ 3.18             $ 9.15             $ 5.02          


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operating data. The following table is for the six months ended:
 
   
June 30, 2009
   
%
   
June 30, 2008
   
%
 
                         
Heavy Oil Production (Bbl/D)
    16,646       53       16,631       58  
Light Oil Production (Bbl/D)
    3,076       10       3,617       13  
Total Oil Production (Bbl/D)
    19,722       63       20,248       71  
Natural Gas Production (Mcf/D)
    69,502       37       49,712       29  
Total operations (BOE/D)
    31,305       100       28,534       100  
                                 
DJ Basin Production (BOE/D)
    1,542               3,213          
Production - Continuing Operations (BOE/D)
    29,763               25,321          
                                 
Oil and gas, per BOE for continuing operations
                               
Average sales price before hedging
  $ 34.24             $ 88.34          
Average sales price after hedging
    46.44               69.42          
                                 
Oil, per Bbl, for continuing operations:
                               
Average WTI price
  $ 51.58             $ 111.12          
Price sensitive royalties
    (1.55 )             (5.21 )        
Quality differential and other
    (8.77 )             (11.15 )        
Crude oil hedges
    16.36               (22.66 )        
Correction to royalties payable
    -               2.85          
Average oil sales price after hedging
  $ 57.62             $ 74.95          
                                 
Natural gas price for continuing operations:
                               
Average Henry Hub price per MMBtu
  $ 4.21             $ 9.26          
Conversion to Mcf
    0.21               0.46          
Natural gas hedges
    0.70               -          
Location, quality differentials and other
    (0.96 )             (1.41 )        
Average gas sales price after hedging per Mcf
  $ 4.16             $ 8.31          


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

graph2
 
Gas Basis Differential.  We have contracted a total of 35,000 MMBtu/D on the Rockies Express Pipeline under two separate transactions to provide firm transport for our Piceance gas production.  As was the case during the first quarter, the Piceance gas was sold based upon a mid-continent index such as PEPL.  For the second quarter of 2009, the mid-continent PEPL index averaged $0.91 below HH.  Our Uinta basin gas is sold based upon a Questar index which averaged $1.12 below HH.  In East Texas, the majority of the gas was sold based on the Florida Gas Transmission Zone 1 index which averaged $0.06 below HH.

Gas Marketing. We have two 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 Statement of Operations is $0.6 million and $0.9 million in the three and six month periods ended June 30, 2009. Firm transportation costs related to all of our Rockies Express volumes is reflected in Operating costs - oil and gas production and total $5.0 million for the six months ended June 30, 2009.

In addition, Berry has signed a binding precedent agreement with El Paso Corporation for an average of 35,000 MMBtu/D of firm transportation on the proposed Ruby Pipeline from Opal, WY to Malin, OR.  While it is not certain that this new line will be constructed, the expectation is that the project will proceed and be in service in 2011.  As part of this agreement and in order to access the Ruby pipeline, we also secured firm transportation from Piceance to Opal.

Oil Contracts. California - On March 20, 2009, we entered into a crude oil purchase contract with a refiner for the sale of all of the Company’s crude oil production from the Midway Sunset field.  The volume approximates 12,000 barrels per day.  The agreement is effective on April 1, 2009 and continues until September 30, 2009.  Also on March 20, 2009, we entered into a crude oil purchase contract with a refiner for the sale of all the Placerita crude.  The agreement covers the period April 2009 through December 2009.

Utah - In February 2007, we entered into a multi-staged crude oil sales contract with a refiner for our Uinta basin light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D in July 2007. The refiner has increased its total capacity to 5,000 Bbl/D as provided in our contract. As operator we deliver all produced volumes under our sales contracts, although our working interest partners or royalty owners may take their respective volumes in kind and market their own volumes.  Gross oil production averaged approximately 3,623 BOE/D in the quarter ended June 30, 2009. The differential under the contract, which includes transportation and gravity adjustments, is linked to the price for NYMEX WTI.

Crude Oil Inventory.  In May, 2009, we entered into a sales agreement with a refiner for 1,500 barrels per day of production from our Poso Creek property for the months of May and June 2009.  Under this agreement, we delivered approximately 100,000 barrels of oil to the refiner and received inventory of a slightly higher quality crude oil at the refinery.  The refiner will purchase the inventory from us in September and October 2009 at the then current market price.  This transaction was accounted for as a non-monetary exchange and the amount recorded in crude oil inventory as of June 30, 2009 reflects the cost of production, transportation costs and quality differentials for the inventory volume.


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Hedging. See Note 4 to the unaudited condensed financial statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Electricity. We consume natural gas as fuel to operate our three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the cost-effective production of heavy oil in California. We sell our electricity to utilities under standard offer contracts based on "avoided cost" or SRAC pricing approved by the California Public Utilities Commission (CPUC) and under which our revenues are currently linked to the cost of natural gas. Natural gas index prices and an avoided utility heat rate are the primary determinant of our electricity sales price based on the current pricing formula under these contracts. The correlation between electricity sales and natural gas prices allows us to manage our cost of producing steam more effectively.

Our electricity margins benefited from lower Rockies natural gas prices during the first six months of 2009.  We purchase and transport 12,000 MMBtu/D on the Kern River Pipeline under our firm transportation contract and use this gas to produce cogeneration steam in the Midway-Sunset field. The Rocky Mountain natural gas price differentials have been greater than California differentials allowing us to purchase a portion of our gas at a discount to the California price. As our electricity revenue is linked to California natural gas prices, the fuel we purchased at lower Rocky Mountain prices is the primary contributor to our electricity margin.

Revenues and operating costs were down for the quarter ended June 30, 2009 from the quarter ended June 30, 2008 due to 57% lower electricity prices and 67% lower natural gas prices.   Revenues and operating costs were down for the quarter ended June 30, 2009 from the quarter ended March 31, 2009 due to 20% lower electricity prices and 28% lower natural gas prices, respectively. We purchased approximately 26,000 MMBtu/D and 25,000 MMBtu/D as fuel for use in our cogeneration facilities in the quarter ended June 30, 2009 and the quarter ended June 30, 2008, respectively.

We generally expect to have small gains or losses on electricity on a quarterly basis which depends on seasonality as we receive improved pricing during the summer months. However, wider natural gas price differentials in the Rockies when compared to California will increase our margin on electricity as described above.  In the second quarter of 2009, our margin on electricity was $0.2 million.

On September 20, 2007, the CPUC issued a decision (SRAC Decision) that changes the way SRAC energy prices will be determined for existing and new SO contracts, revises the capacity prices paid under current S01 contracts and establishes the capacity prices that will be paid under new SO contracts.  On July 9, 2009, the CPUC issued a resolution that implements a revised SRAC price methodology effective August 1, 2009 and resolves many of the disputed issues regarding the calculation of SRAC.  The revised pricing changes the gas indices upon which SRAC is based and reduces the avoided utility heat rates used to calculate SRAC.  These changes are not expected to have a material impact on electricity revenues.

The following table is for the three months ended:

   
June 30, 2009
   
June 30, 2008
   
March 31, 2009
 
Electricity
                 
Revenues (in millions)
  $ 6.6     $ 17.0     $ 10.3  
Operating costs (in millions)
  $ 6.4     $ 15.5     $ 8.8  
Electric power produced - MWh/D
    2,007       1,919       2,068  
Electric power sold - MWh/D
    1,783       1,724       1,939  
Average sales price/MWh
  $ 46.99     $ 108.21     $ 58.85  
Fuel gas cost/MMBtu (including transportation)
  $ 3.54     $ 10.01     $ 4.01  


Berry Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Oil and Gas Operating, Production Taxes, G&A and Interest 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)
 
   
June 30,
2009
   
June 30,
2008
   
March 31,
2009
   
June 30,
2009
   
June 30,
2008
   
March 31,
2009
 
Operating costs – oil and gas production
  $ 13.03     $ 22.35     $ 13.74     $ 34,738     $ 52,332     $ 37,384  
Production taxes
    1.83       2.80       2.08       4,885       6,568       5,652  
DD&A – oil and gas production
    12.89       11.06       13.38       34,371       25,902       36,398  
G&A
    4.94       4.67       4.89       13,163       10,929       13,294  
Interest expense
    3.97       1.52       3.69       10,589       3,552       10,050  
Total
  $ 36.66     $ 42.40     $ 37.78     $ 97,746     $ 99,283     $ 102,778  

 
·
Operating costs: Steam costs are the primary variable component of our operating costs and fluctuate based on the amount of steam we inject and the price of fuel used to generate steam. The following table presents steam information:

   
June 30, 2009
(2Q09)
   
June 30, 2008
(2Q08)
   
2Q09
to 2Q08 Change
   
March 31, 2009
(1Q09)
   
2Q09 to 1Q09 Change
 
Average volume of steam injected (Bbl/D)
    107,739       97,853       10 %     103,342