form10q.htm


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, 2009
oTransition 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 20, 2009, the registrant had 42,790,536 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 20, 2009 all of which is held by an affiliate of the registrant.
 


 
1

 

 BERRY PETROLEUM COMPANY
FIRST QUARTER 2009 FORM 10-Q
TABLE OF CONTENTS
 
PART I. FINANCIAL INFORMATION
 
Page
     
 
3
     
 
3
     
 
4
     
 
4
     
 
5
     
 
6
     
 
19
     
 
30
     
 
34
     
     
     
PART II. OTHER INFORMATION
 
 
     
 
35
     
 
35
     
 
35
     
 
35
     
 
35
     
 
35
     
 
36


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

   
March 31, 
2009
   
December 31, 2008
 
ASSETS
           
Current assets:
           
Cash and cash equivalents
  $ 49     $ 240  
Short-term investments
    65       66  
Accounts receivable
    72,846       65,873  
Fair value of derivatives
    95,931       111,886  
Assets held for sale
    142,820       -  
Prepaid expenses and other
    8,035       11,015  
Total current assets
    319,746       189,080  
Oil and gas properties (successful efforts basis), buildings and equipment, net
    2,096,593       2,254,425  
Fair value of derivatives
    48,641       79,696  
Other assets
    27,649       19,182  
    $ 2,492,629     $ 2,542,383  
LIABILITIES AND SHAREHOLDERS' EQUITY
               
Current liabilities:
               
Accounts payable
  $ 51,257     $ 119,221  
Revenue and royalties payable
    14,848       34,416  
Accrued liabilities
    42,088       34,566  
Line of credit
    -       25,300  
Income taxes payable
    460       187  
Fair value of derivatives
    2,983       1,445  
Deferred income taxes
    35,191       45,490  
Liabilities held for sale
    4,228       -  
Total current liabilities
    151,055       260,625  
Long-term liabilities:
               
Deferred income taxes
    272,351       270,323  
Long-term debt
    1,199,400       1,131,800  
Abandonment obligation
    40,105       41,967  
Other long-term liabilities
    4,835       5,921  
Fair value of derivatives
    12,324       4,203  
      1,529,015       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; 42,783,498 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
    82,641       79,653  
Accumulated other comprehensive income
    64,142       113,697  
Retained earnings
    665,331       633,749  
Total shareholders' equity
    812,559       827,544  
    $ 2,492,629     $ 2,542,383  

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


BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Income
Three Months Ended March 31, 2009 and 2008
(In Thousands, Except Per Share Data)

   
Three months ended March 31,
 
   
2009
   
2008
 
REVENUES AND OTHER INCOME ITEMS
           
Sales of oil and gas
  $ 127,869     $ 151,666  
Sales of electricity
    10,270       15,927  
Gas marketing
    7,581       3,231  
Gain on derivative terminations
    14,270       -  
Gain (loss) on ineffective commodity derivatives
    22,894       (708 )
Interest and other income, net
    283       830  
      183,167       170,946  
EXPENSES
               
Operating costs - oil and gas production
    37,384       39,340  
Operating costs - electricity generation
    8,783       16,399  
Production taxes
    5,652       5,183  
Depreciation, depletion & amortization - oil and gas production
    36,398       24,207  
Depreciation, depletion & amortization - electricity generation
    959       693  
Gas marketing
    7,284       2,982  
General and administrative
    13,294       11,132  
Interest expense
    10,050       3,327  
Dry hole, abandonment, impairment and exploration
    122       2,728  
      119,926       105,991  
Income before income taxes
    63,241       64,955  
Provision for income taxes
    21,462       25,419  
Income from continuing operations
    41,779       39,536  
(Loss) income from discontinued operations, net of taxes
    (6,781 )     3,495  
                 
Net income
  $ 34,998     $ 43,031  
                 
Basic net income from continuing operations per share
  $ .92     $ .88  
Basic net (loss) income from discontinued operations per share
  $ (.15 )   $ .08  
Basic net income per share
  $ .77     $ .96  
                 
Diluted net income from continuing operations per share
  $ .92     $ .86  
Diluted net (loss) income from discontinued operations  per share
  $ (.15 )   $ .08  
Diluted net income per share
  $ .77     $ .94  
                 
Dividends per share
  $ .075     $ .075  
                 
                 
                 
                 
Unaudited Condensed Statements of Comprehensive Income
 
Three Months Ended March 31, 2009 and 2008
 
(In Thousands)
 
Net income
  $ 34,998     $ 43,031  
Unrealized gains (losses) on derivatives, net of income taxes (benefits) of $48,160 and ($40,349), respectively
    78,577       (60,523 )
Reclassification of realized gains on derivatives included in net income, net of income taxes (benefits) of ($17,788) and $11,698, respectively
    (29,022     17,547  
Comprehensive income
  $ 84,553     $ 55  

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


BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Cash Flows
Three Months Ended March 31, 2009 and 2008
(In Thousands)
 
   
Three months ended March 31,
 
   
2009
   
2008
 
Cash flows from operating activities:
           
Net income
  $ 34,998     $ 43,031  
Depreciation, depletion and amortization
    39,545       27,769  
Dry hole and impairment
    9,643       2,728  
Commodity derivatives
    (22,842 )     271  
Stock-based compensation expense
    2,988       2,107  
Deferred income taxes
    21,059       22,082  
Gain on sale of oil and gas properties
    -       (415 )
Other, net
    (3,952 )     491  
Change in book overdraft
    (23,510 )     4,609  
Cash paid for abandonment
    (112 )     (971 )
Increase in current assets other than cash and cash equivalents
    (12,933 )     (78 )
Decrease in current liabilities other than book overdraft, line of credit and fair value of derivatives
    (36,755 )     (14,389 )
Net cash provided by operating activities
    8,129       87,235  
Cash flows from investing activities:
               
Exploration and development of oil and gas properties
    (49,898 )     (75,869 )
Property acquisitions
    (1,173 )     (261 )
Additions to vehicles, drilling rigs and other fixed assets
    (283 )     (909 )
Proceeds from sale of assets
    -       1,809  
Deposits on asset sales
    14,000       -  
Capitalized interest
    (5,312 )     (4,485 )
Net cash used in investing activities
    (42,666 )     (79,715 )
Cash flows from financing activities:
               
Proceeds from issuances on line of credit
    147,800       100,600  
Payments on line of credit
    (173,100 )     (104,700 )
Proceeds from issuance of long-term debt
    159,600       69,200  
Payments on long-term debt
    (92,000 )     (69,200 )
Debt issuance cost
    (4,538 )     -  
Dividends paid
    (3,416 )     (3,327 )
Proceeds from stock option exercises
    -       1,388  
Excess tax benefit and other
    -       882  
Net cash provided by (used in) financing activities
    34,346       (5,157 )
                 
Net (decrease) increase  in cash and cash equivalents
    (191 )     2,363  
Cash and cash equivalents at beginning of year
    240       316  
Cash and cash equivalents at end of period
  $ 49     $ 2,679  
                 
The accompanying notes are an integral part of these financial statements. 


Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

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 March 31, 2009 and December 31, 2008 and results of operations and other comprehensive income and cash flows for the three months ended March 31, 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. 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.

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

Our cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at March 31, 2009 and December 31, 2008 is $8.2 million and $31.8 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

2.
Recent Accounting Developments

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.

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 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 December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which expands the information that a reporting entity provides in its financial reports about a business combination and its effects. This Statement establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interests in the acquiree, recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply the statement before that date. We may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141(R).

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

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 10 to the condensed financial statements.
 
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 will be effective for us for the quarter ending June 30, 2009. The adoption of FSP 107-1 will not have an impact on our financial position and results of operations.

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 through review of counterparty statements and other supporting documentation, 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.

Our oil swaps, natural gas swaps and interest rate swaps are valued using the counterparties’ mark-to-market statements which are validated by our internally developed models 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.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

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

March 31, 2009 (in millions)
 
Total carrying value on the condensed Balance Sheet
   
Level 2
   
Level 3
 
                   
Commodity derivative assets
    143.5       6.0       137.5  
Interest rate swaps
    (14.7 )     (14.7 )     -  
Total fair value
    128.8       (8.7 )     137.5  
 
    Included in the total $128.8 million asset above is a $0.5 million liability associated with our DJ liabilities which are classified as "Liabilities held for sale" as of March 31, 2009.
December 31, 2008 (in millions)
 
Total carrying value on the condensed Balance Sheet
   
Level 2
   
Level 3
 
                   
Commodity derivatives assets
    198.4       25.9       172.5  
Interest rate swap liabilities
    (12.5 )     (12.5 )     -  
Total fair value of derivative assets
    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 March 31, 2009
 
       
Fair value of Level 3 derivative assets, beginning of period
  $ 172.5  
Total realized and unrealized gains and (losses) included in sales of oil and gas
    (22.9 )
Purchases, sales and settlements, net
    (15.5 )
Transfers in and/or out of Level 3
    3.4  
Fair value of Level 3 derivative assets, March 31, 2009
  $ 137.5  
         
Total unrealized gains and (losses) included in income related to financial assets and liabilities still on the condensed balance sheet at March 31, 2009
  $  22.8  

The fair value of our DJ basin asset sale determined by our Borad of Directors was confirmed by the sales price paid to us.  The following nonrecurring fair value measurements were recorded during the three months ended March 31, 2009 in conjunction with the sale of our DJ basin assets:

   
Three Months Ended
March 31, 2009
   
Significant Unobservable Inputs
Level 3
   
Total Gains (Losses)
 
                   
Long lived assets and liabilities held for sale (in millions)
  $ 138,592     $ 138,592     $ (9,637 )

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

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 and 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 March 31, 2009, our net fair value of derivative assets was $128.8 million as compared to $185.9 million at December 31, 2008 which reflects decreases in commodity prices in the period. Based on NYMEX strip pricing as of March 31, 2009, we expect to receive hedge proceeds under the existing derivatives of $104.4 million during the next twelve months. At March 31, 2009, Accumulated Other Comprehensive Income consisted of $64.1 million, net of tax, of unrealized gains from our crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at March 31, 2009. Deferred net gains recorded in “Accumulated Other Comprehensive Income” at March 31, 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 substantially 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 March 31, 2009
 
 
Derivative Assets
 
Derivative Liabilities
 
 
(in millions)
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
Commodity – Oil
Current assets
    94.6  
Current liability
    2.3  
Commodity – Natural Gas
Current assets
    4.1  
Current liability
    0.3  
Commodity – Oil
Long term assets
    52.4  
Long term liabilities
    6.5  
Commodity – Natural Gas
Long term assets
    0.7         -  
Commodity – Natural Gas
Long term liabilities
    1.1         -  
Interest rate contracts
      -  
Current assets
    2.9  
Interest rate contracts
      -  
Long term assets
    4.4  
Interest rate contracts
      -  
Current liabilities
    0.4  
Interest rate contracts
      -  
Long term liabilities
    7.0  
Total derivatives designated as hedging instruments under Statement 133
      152.9         23.8  
                     
Commodity – Oil
Current assets
    0.2  
Current liabilities
    -  
Commodity – Natural Gas
Liabilities held for sale
    0.8  
Liabilities held for sale
    1.3  
Total derivatives not designated as hedging instruments under Statement 133
      1.0         1.3  
Total Derivatives
      153.9         25.1  


Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

The tables below summarize the Statement of Income 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 Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Amount of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
   
Three Months Ended
March 31, 2009
     
Three Months Ended
March 31, 2009
     
Three Months Ended
March 31, 2009
Commodity  - Oil
  $ 36.5  
Sales of oil and gas
  $ 41.6  
Sales of oil and gas
  $ -  
Commodity  - Natural Gas
    8.9  
Sales of oil and gas
    6.6  
Sales of oil and gas
    -  
Commodity – Oil
    -  
Gain (loss) on commodity –Oil
    -  
Gain (loss) on commodity-Oil
    22.7  
Interest rate
    (3.4 )
Interest expense
    (1.0 )
Interest expense
    -  
Total
  $ 42.0       $ 47.2       $ 22.7  

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 Derivate for Derivatives not designated as Hedging Instruments under Statement 133
 
     
Three months ended March 31, 2009
 
Commodity – Oil
Gain (loss) on ineffective commodity derivatives
  $ 0.2  
Commodity - Natural Gas
(Loss) income  from discontinued operations, net of tax
    (0.5 )
Total Derivatives
    $ (0.3 )

We entered into the following natural gas hedges during the three months ended March 31, 2009:

·
Houston Ship Channel basis swaps on 2,000 MMBtu/D for $0.38 for full year 2010
·
NGPL basis swaps on 2,000 MMBtu/D for $0.49 for the full year 2010
·
Collars on 4,000 MMBtu/D with floors of $6.50 and ceilings ranging from $8.75 to $8.90 for full year 2010

These gas hedges have been designated as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

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 the unrealized net loss of $0.5 million on the income statement under the caption “Income from discontinued operations, net of taxes.”

In conjunction with the sale of the DJ 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 to the statement of income under the caption “Gain on derivative terminations.”

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

We entered into the following oil collar derivatives during the three months ended March 31, 2009:

Crude Oil Sales (NYMEX WTI) Collars
 
Average Barrels Per Day
   
Floor/Ceiling Prices
 
Full year 2011
    1,000     $ 55.20 / $70.00  
Full year 2011
    1,000     $ 55.00 / $70.50  
Full year 2011
    1,000     $ 55.00 / $68.65  
Full year 2011
    1,000     $ 55.00 / $68.00  
Full year 2011
    1,000     $ 55.00 / $71.20  
Full year 2011
    1,000     $ 60.00 / $76.00  
Full year 2011
    1,000     $ 60.00 / $81.25  

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 March 31, 2009:

Crude Oil Sales (NYMEX WTI) Collars
 
Average Barrels Per Day
   
Swap Price
 
May 2009
    1,000     $ 55.60  
June 2009
    400     $ 57.00  
3rd Quarter 2009
    500     $ 52.40  
Full year 2010
    650     $ 56.90  
Full year 2011
    250     $ 61.80  
Full year 2011
    500     $ 57.36  
Full year 2011
    500     $ 57.40  
Full year 2011
    500     $ 57.50  

The oil hedge derivatives have been designated as cash flow hedges in accordance with SFAS No. 133, except as noted below.   We did not elect hedge accounting for the May and June 2009 hedges and recorded an unrealized net gain of $0.2 million at March 31, 2009 on the income statement under the caption “Gain (loss) on ineffective commodity derivatives”.

During the first quarter of 2009, we also converted 6,000 Bbl/D oil collars 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.

In December 2008, Big West Oil of California filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.  Our contract with Big West provided for an oil price differential that was linked to NYMEX WTI prices and allowed us to effectively hedge our oil production at the NYMEX WTI index.  Subsequent to the Big West bankruptcy, our crude oil has been sold at field posting prices which resulted in some ineffectiveness related to our WTI linked hedges.  We recognized an unrealized net gain of approximately $22.8 million on the income statement under the caption “Gain (loss) on ineffective commodity derivatives” for the quarter ended March 31, 2009 as a result of this ineffectiveness.

We entered into the following interest rate hedges during the three months ended March 31, 2009 which have been designated as cash flow hedges:

Beginning/Maturity
 
Rate
   
Notional Amount (in millions)
 
4/15/09 – 7/15/12
    1.89 %   $ 25  
12/15/09 – 7/15/12
    2.15 %   $ 25  
12/15/09 – 7/15/12
    2.05 %   $ 25  
12/15/09 – 7/15/12
    2.00 %   $ 25  
12/15/09 – 7/15/12
    2.00 %   $ 25  
12/15/09 – 7/15/12
    1.94 %   $ 25  

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

Our hedge contracts have been primarily executed with the 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 is AA-/Aa2, or better.  Our derivatives are held with a small number of counterparties and as of March 31, 2009, our largest two counterparties accounted for 80% of the value of our total derivative positions.

As of March 31, 2009, we had the following outstanding commodity contracts:

Commodity Hedges
 
   
2009
   
2010
   
2011
   
2012
 
Oil Bbl/D:
    17,435       14,930       9,020       1,000  
Natural Gas MMBtu/D:
    5,000       9,000       -       -  

5.
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 three months ended March 31, 2009 (in thousands):

Beginning balance at January 1, 2009
 
$
41,967
 
Liabilities incurred
   
-
 
Liabilities settled
   
(113
)
Revisions in estimated liabilities
   
-
 
Accretion expense
   
1,002
 
Ending balance at March 31, 2009
 
$
42,856
 

Included in the total of $42.9 million above is $2.8 million in AROs that are associated with our DJ liabilities which are classified as "Liabilities held for sale" as of March 31, 2009.

6.
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 $14 million sale of our DJ basin related hedges was completed in March 2009.  The hedge forecasted transaction is no longer expected to occur and the gain on the sale of these hedges is recorded under the caption “Gain on derivative terminations” in the condensed statement of income and is included in operating cash flows for the three months ended March 31, 2009. We received a deposit of $14 million on the sale of the DJ basin assets which is included in “Accrued Liabilities” on the condensed balance sheet as of March 31, 2009.  The closing date of the sale was April 1, 2009. In accordance with SFAS No. 144, these properties have been separately presented in the accompanying condensed balance sheet at fair value less the cost to sell, as of March 31, 2009. The sales cost associated with the DJ basin assets were $1.2 million.  We recorded a pre-tax  impairment loss of $9.6 million, which is aggregated within the $6.8 million “(loss) income from discontinued operations, net of tax” on our statement of income for the three months ended March 31, 2009.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

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

   
For the Three Months Ended March 31,
 
   
2009
   
2008
 
             
Oil and gas revenue
  $ 5,396     $ 12,829  
Other revenue
    622       914  
Total Revenue
    6,018       13,743  
                 
Operating expenses
    2,576       2,289  
Production taxes
    195       784  
DD&A
    2,188       2,869  
General and administrative
    388       251  
Interest expense
    815       411  
Commodity derivatives
    484       -  
Dry hole, abandonment, impairment and exploration
    9,637       1,398  
Total Expenses
    16,283       8,002  
                 
Income (loss) from discontinued operations, before income taxes
    (10,265 )     5,741  
Income tax benefit (expense)
    3,484       (2,246 )
Income (loss) from discontinued operations
  $ (6,781 )   $ 3,495  

The following is a summary of the assets and liabilities held for sale related to the DJ Basin sale at March 31, 2009 (in thousands):

   
March 31, 2009
 
       
Inventory
 
$
1,275
 
Oil and gas properties, net of accumulated depreciation and impairment
   
140,730
 
Other Assets
   
815
 
Total assets
 
$
142,820
 
         
         
Asset retirement obligation
 
$
2,751
 
Other liabilities
   
1,477
 
Total liabilities
 
$
4,228
 

7.
Dry Hole, Abandonment and Impairment

During the three months ended March 31, 2009 and 2008, we recorded dry hole, abandonment, impairment and exploration expense of $0.1 million and $2.7 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.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

8.        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 months ended March 31, 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
March 31, 2008
 
Pro forma revenue
  $ 185,960  
Pro forma income from operations
  $ 60,073  
Pro forma net income
  $ 36,942  
Pro forma basic earnings per share
  $ 0.82  
Pro forma diluted earnings per share
  $ 0.81  
 
9.
Income Taxes

The effective income tax rate was 33.9% for the first quarter of 2009 compared to 45.1% for the fourth quarter of 2008 and 39% for the first quarter of 2008. The decrease in rate for first quarter is primarily due to a decrease in anticipated state taxes.  Our 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, 2009, we had a gross liability for uncertain tax benefits of $11.2 million of which $10.0 million, if recognized, would affect the effective tax rate. There were no significant changes to the calculation since year end 2008.

We anticipate the balance of our unrecognized tax benefits could be reduced during the next 12 months as the IRS finalizes certain examinations which are in progress, however, we cannot reasonably estimate the impact of the examination at this time.

10.
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
Notes to the Unaudited Condensed Financial Statements

Undistributed and distributed earnings allocated to shareholders are calculated as follows for the three month periods ended:

   
March 31, 2009
   
March 31, 2008
 
             
Income from continuing operations
  $ 41,779     $ 39,536  
Less:
               
Dividends paid  - shareholders
    3,344       3,289  
Dividends paid - unvested shares and deferred stock units
    72       38  
                 
Undistributed income from continuing operations
  $ 38,363     $ 36,209  
                 
(Loss) income from discontinued operations
  $ (6,781 )   $ 3,495  

   
March 31, 2009
   
March 31, 2008
 
             
Income from continuing operations available to shareholders
           
Distributed earnings to shareholders
  $ 3,344     $ 3,289  
Allocation of undistributed earnings to shareholders
    37,387       35,705  
Total income from continuing operations available to shareholders
  $ 40,731     $ 38,994  
                 
Income from discontinued operations available to shareholders
               
Distributed earnings to shareholders
  $ -     $ -  
Allocation of undistributed (loss) earnings available to shareholders
    (6,608 )     3,445  
Total (loss) income from discontinued operations available to shareholders
  $ (6,608 )   $ 3,445  

Undistributed earnings available to shareholders is calculated by dividing weighted average shares outstanding by the total of weighted shares outstanding plus weighted average of unvested shares outstanding plus the weighted average of deferred stock units outstanding multiplied by undistributed earnings.  Shares issued during the period and shares reacquired during the period are weighted for the portion of the period in which the shares were outstanding.   The weighted average number of unvested shares and deferred stock units for the three month periods ended March 31, 2009 and 2008 is 1,164,391 and 628,685, respectively.

Weighted average shares outstanding and dilutive shares outstanding are calculated as follows:

 
March 31, 2009
 
March 31, 2008
 
         
Weighted average shares outstanding:
    44,581       44,392  
Add: dilutive effects of stock options
    12       623  
Weighted average shares outstanding, including the effects of dilutive common shares
    44,593       45,015  

Options to purchase 2.3 million and .2 million shares were outstanding at March 31, 2009 and 2008, respectively, and were excluded from the calculation of diluted earnings per share because the options’ exercise price was greater than the average market price of the shares.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

Basic and dilutive earnings per share from continuing and discontinued operations are calculated as follows:

   
March 31, 2009
   
March 31, 2008
 
Basic
           
Income from continuing operations available to shareholders
  $ 40,731     $ 38,994  
shares outstanding
    44,581       44,392  
Basic earnings per share from continuing operations
  $ .92     $ .88  
                 
(Loss) income from discontinued operations available to shareholders
  $ (6,608 )   $ 3,445  
Shares outstanding
    44,581       44,392  
Basic (loss) earnings per share from discontinued operations
  $ (.15 )   $ .08  
                 
Basic earnings per share
  $ .77     $ .96  
                 
Dilutive
               
Income from continuing operations available to shareholders
  $ 40,731     $ 38,994  
Dilutive shares
    44,593       45,015  
Dilutive earnings per share from continuing operations
  $ .92     $ .86  
                 
(Loss) income from discontinued operations available to shareholders
  $ (6,608 )   $ 3,445  
Dilutive shares
    44,593       45,015  
Dilutive (loss) earnings per share from discontinued operations
  $ (.15 )   $ .08  
                 
Dilutive earnings per share
  $ .77     $ .94  

Upon adoption, both basic income and dilutive income per share for the first quarter of 2008 decreased by $.01 for continuing operations.  Basic income and dilutive income per share was unchanged for discontinued operations.

11.
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 March 31, 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%.

Senior Secured Revolving Credit Facility
On July 15, 2008, we entered into a five year amended and restated credit agreement (the Agreement) with Wells Fargo Bank, N.A. as administrative agent and other lenders.  The Agreement is a revolving credit facility for up to $1.5 billion with a borrowing base of $1.0 billion.  The outstanding Line of Credit reduces our borrowing capacity available under the Agreement.  Interest on amounts borrowed under the Agreement was charged at LIBOR plus a margin of 1.125% to 1.875% or the prime rate, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base.   An annual commitment fee of .25% to .375% was charged on the unused portion of this credit facility.

On October 17, 2008, we amended the Agreement which increased our borrowing base from $1.0 billion to $1.25 billion with commitments of $1.08 billion and a new maturity date of July 15, 2012.  Commitments were increased during the fourth quarter of 2008 with the addition of $130 million in commitments bringing the total commitments under the facility to $1.21 billion from 19 banks.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

On February 19, 2009, we executed another amendment to the Agreement which modified our covenants as follows:

Total funded debt to EBITDAX ratio
 
2009
   
2010
   
Thereafter
 
  4.75       4.50       4.00  

Senior secured debt to EBITDAX ratio
 
to Sep 2010
   
Mar 2011
   
Sep 2011
   
Thereafter
 
  3.75       3.50       3.25       3.0  
 
Additionally, the write off of $38.5 million to bad debt expense associated with the bankruptcy of Big West is excluded from the calculation of EBITDAX.  There were no changes to the current ratio covenant which, as defined, must be at least 1.0.  The LIBOR and prime rate margins increased to between 2.25% and 3.0% based on the ratio of credit outstanding to the borrowing base.  Additionally, the annual commitment fee on the unused portion of the credit facility increased to 0.50%, regardless of the amount outstanding.   This transaction was accounted for 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 March 31, 2009 under the Agreement, as amended, and the Line of Credit was $999 million and $0, respectively, and $3 million in letters of credit have been issued under the facility, leaving $208 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.

We further amended the Agreement on April 27, 2009.  See Note 13 “Subsequent Events.”

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 Notes).  Interest on the Notes is paid semiannually in May and November of each year.  Under the Notes, as long as the interest coverage ratio (as defined) is greater than 2.5 times, we may incur additional debt.  The deferred costs of approximately $5 million associated with the issuance of this debt are being amortized over the ten year life of the Notes.

Financial Covenants
The senior secured revolving credit facility contains restrictive covenants which, among other things, require us to currently maintain a debt to EBITDAX ratio of not greater than 4.75 and a minimum current ratio, as defined, of 1.0. The $200 million Notes are subordinated to our credit facility indebtedness. Under the Notes, 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 March 31, 2009.

   
As of
March 31, 2009
 
Current Ratio (Not less than 1.0)
   
2.9
 
EBITDAX To Total Funded Debt Ratio (Not greater than 4.75)
   
2.8
 
Interest Coverage Ratio (Not less than 2.5)
   
7.4
 

The weighted average interest rate on total outstanding borrowings at March 31, 2009 was 4.2%.

12.
Contingencies and Commitments

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.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

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, $12.4 million represents December crude oil sales by the Company and $26.1 million represents November crude oil sales.  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.

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 Bbl/d.  The agreement is effective April 1, 2009 and continues until September 30, 2009.

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.

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 Income is $0.3 million and $0.2 million for the three month periods ended March 31, 2009 and 2008, 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.

13.
Subsequent Events

On April 1, 2009, we completed the sale of our DJ basin assets.  Total proceeds received for the sale were $139 million, including closing adjustments and the $14 million deposit received in March 2009.

On April 27, 2009, we completed the scheduled redetermination of the borrowing under our credit facility.  Our borrowing base was reduced from $1.25 billion to $1.05 billion, with $100 million of the reduction resulting from the sale of our DJ basin assets.  Also on April 27, 2009 we completed a $140 million second lien credit facility, with lenders from among our current lending group, which matures on January 16, 2013.  Interest on the facility is charged at LIBOR plus a margin of eight percent with a minimum LIBOR rate of three percent.  Covenants under this facility are similar but slightly less restrictive than our senior secured credit facility.  Our Line of Credit is suspended as long as the second lien credit facility is outstanding. Additionally, each dollar outstanding under the second lien credit facility reduces the borrowing base under our senior secured credit facility by 30 cents such that the $140 million second lien facility reduces our borrowing base from $1.05 billion to $1.0 billion. Proceeds from the second lien facility were used to pay down borrowings under our senior secured credit facility. On April 27, 2009, following the closing of the second lien credit facility, the outstanding amount under our senior secured credit facility was approximately $735 million providing us with approximately $275 million of liquidity.

 
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 months ended March 31, 2009 and 2008 and our financial condition, liquidity and capital resources as of March 31, 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:
 
·
Investing our capital in a disciplined manner and maintaining a strong financial position
 
·
Developing our existing resource base
 
·
Calibrating our cost structure to the current commodity price environment
 
·
Acquiring additional assets with significant growth potential
 
·
Accumulating significant acreage positions near our producing operations

Notable First Quarter Items.
 
·
Achieved production averaging 33,330 BOE/D, up 19% from the first quarter of 2008
 
·
Announced the sale of our DJ basin assets and related hedges for approximately $154 million
 
·
Entered into short-term sales contracts for our California crude oil to replace our terminated contract with Big West
 
·
Continued to return California wells to production after the December 2008 Big West bankruptcy, increasing average California production from 16,000 Bbl/D in the fourth quarter of 2008 to 16,440 Bbl/D in the first quarter of 2009
 
·
Increased Diatomite net production to an average of 2,670 BOE/D, up 94% from the first quarter of 2008
 
·
Amended the covenants under our credit facility providing increased financial flexibility going forward
 
·
Added to our oil hedge positions increasing 2011 hedged volumes to 9,000 BOE/D and 2012 volumes to 2,000 BOE/D
 
·
Increased our fixed rate debt position to $725 million utilizing interest rate swaps

Notable Items and Expectations for the Second Quarter and Full Year 2009.
 
·
Closed on the sale of our DJ assets using proceeds for the repayment of debt
 
·
Completed the redetermination of our credit facility with a borrowing base of $1.05 billion with no changes to the terms or interest rate margins
 
·
Completed a $140 million second lien facility, with existing lenders, increasing our liquidity to approximately $275 million
 
·
Expect production to average approximately 30,000 BOED with no future contributions from the DJ assets which averaged approximately 3,100 BOE/D in the first quarter of 2009.

Overview of the first Quarter of 2009. We had net income from continuing operations of $41.8 million, or $0.92 per diluted share, and net cash from operations was $8.1 million in the first quarter of 2009. We drilled 26 gross wells and capital expenditures, excluding property acquisitions, totaled $50.2 million.  We achieved average production of 33,330 BOE/D in the first quarter of 2009, down 6% from an average of 35,583 BOE/D in the fourth quarter of 2008.

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

Results of Operations. The following results from continuing operations are in millions (except per share data) for the three months ended:
   
March 31,  2009
(1Q09)
   
March 31,  2008
(1Q08)
   
1Q09 to 1Q08 Change
   
December 31, 2008
(4Q08)
   
1Q09 to 4Q08 Change
 
Sales of oil
  $ 99     $ 131       (24 %)   $ 97       2 %
Sales of gas
    29       21       38 %     38       (24 %)
Total sales of oil and gas
  $ 128     $ 152       (16 %)   $ 135       (6 %)
Sales of electricity
    10       16       (38 %)     12       (17 %)
Gas Marketing
    8       3       167 %     8       -  
Gain on sale of assets
    -       -       -       (2 )     -  
Gain on hedge terminations
    14       -       -       -       -  
Gain (loss) on commodity derivatives
    23       (1 )     -       (2 )     -  
Interest and other income, net
    -       1       -       1       -  
Total revenues and other income
  $ 183     $ 171       7 %   $ 152       20 %
Net income (loss) from continuing operations
  $ 42     $ 40             $ (12 )        
Diluted earnings (loss) per share from continuing operations
  $ 0.92     $ 0.88             $ (.26 )        

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 March 31, 2009 were relatively flat with the three months ended December 31, 2008 resulting from price increases of 5% offset by sales volume decreases of 3%.  Total oil sales volumes decreased primarily from lower sales volumes in the Uinta basin where no capital activity occurred during the first quarter of 2009 offset by increased production in California where wells were brought back online after disruptions from the Big West bankruptcy. The decrease in revenue when compared to the first quarter of 2008 is primarily the result of a 23% decrease in realized prices.  Natural gas revenues decreased from the quarter ended December 31, 2008 as a result of a 13% decrease in volumes from our Piceance and Uinta properties where no capital activity occurred during the quarter and a 9% decrease in realized prices.  Natural gas revenues were higher in the first quarter of 2009 compared to the first quarter of 2008 from volume increases of 69%, primarily due to the contribution of our East Texas assets and the results of our 2008 capital program offset by a 32% decrease in realized prices.

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

 
 
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:
 
   
March 31, 2009
   
%
   
March 31, 2008
   
%
   
December 31, 2008
   
%
 
                                     
Heavy Oil Production (Bbl/D)
    16,436       50       16,375       58       15,999       45  
Light Oil Production (Bbl/D)
    3,066       9       3,510       13       3,659       10  
Total Oil Production (Bbl/D)
    19,502       59       19,885       71       19,658       55  
Natural Gas Production (Mcf/D)
    82,979       41       49,086       29       95,548       45  
Total operations (BOE/D)
    33,332       100       28,066       100       35,583       100  
                                                 
DJ Basin Production (BOE/D)
    3,101               3,157               3,415          
Production - Continuing Operations (BOE/D)
    30,231               24,909               32,168          
                                                 
Oil and gas BOE for continuing operations
                                               
Average sales price before hedging
  $ 29.36             $ 75.11             $ 40.61          
Average sales price after hedging
    47.11               62.44               45.57          
                                                 
Oil, per Bbl, for continuing operations:
                                               
Average WTI price
  $ 43.24             $ 97.82             $ 59.08          
Price sensitive royalties
    (1.02 )             (4.47 )             (1.69 )        
Quality differential and other
    (9.53 )             (10.78 )             (8.55 )        
Crude oil hedges
    23.79               (15.60 )             4.69          
Correction to royalties payable
    -               5.85               -          
Average oil sales price after hedging
  $ 56.48             $ 72.82             $ 53.53          
                                                 
Natural gas price for continuing operations:
                                               
Average Henry Hub price per MMBtu
  $ 4.90             $ 8.74             $ 6.95          
Conversion to Mcf
    .25               .44               .35          
Natural gas hedges
    1.14               (.19 )             .89          
Location, quality differentials and other
    (1.27 )             (1.56 )             (2.67 )        
Average gas sales price after hedging per Mcf
  $ 5.02             $ 7.43             $ 5.52          

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

Gas Basis Differential.  Natural gas prices in the Rockies continue to decline due to various factors, including takeaway pipeline capacity, supply / inventory volumes, and regional demand issues. 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. The CIG basis differential per MMBtu, based upon first-of-month values, averaged $2.81 below HH and ranged from $0.93 to $6.61 below HH in 2008.  For the first quarter of 2009, the CIG basis averaged $1.62 below HH.  The Piceance gas was sold in the first quarter of 2009 based upon a mid-continent index such as PEPL.  For the first three months of 2009, the mid-continent PEPL index averaged $1.51 below HH.  Correspondingly, most of the Uinta Basis gas is sold based upon a Questar index which averaged $1.72 below HH.  For E. Texas, the Texas Eastern - East Texas index averaged $0.78 below HH for the first quarter of 2009.  

Gas Marketing. We have two long-term (ten year) firm transportation contracts for our Piceance natural gas production. The first contract is for 10,000 MMBtu/D on the Rockies Express (REX) pipeline for gas production in the Piceance basin.  The second contract is for 25,000 MMBtu/D on the REX pipeline for gas production in the Piceance basin. We pay a demand charge for this capacity and our own production did not fill that capacity. In order to maximize our firm transportation capacity, we bought our partners’ share of the gas produced in the Piceance at the market rate for that area. We then 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 Income is $0.3 million in the three month period ended March 31, 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.  

We continue to market our California crude oil production, other than production from the Midway Sunset field discussed above, to various parties.  The term of these contracts range from nine months to one month.  

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 3,280 BOE/D in the quarter ended March 31, 2009. The differential under the contract, which includes transportation and gravity adjustments, is linked to WTI and would range from $10 to $15 per barrel at WTI prices between $40 and $60. This contract provides us an outlet to sell all of our current oil production in the Uinta basin.

 
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 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 continued to benefit from lower Rockies natural gas prices during 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 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 March 31, 2009 from the quarter ended March 31, 2008 due to 35% lower electricity prices and 50% lower natural gas prices.   Revenues and operating costs were down for the quarter ended March 31, 2009 from the quarter ended December 31, 2008 due to 16% lower electricity prices and 16% lower natural gas prices, respectively. We purchased approximately 27 MMBtu/D as fuel for use in our cogeneration facilities in both the quarter ended March 31, 2009 and the quarter ended March 31, 2008.

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 first quarter of 2009, our margin on electricity increased to $1.5 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 Standard Offer (SO) contracts and revises the capacity prices paid under current SO1 contracts. The effective date of the new pricing under the SRAC Decision has not been determined as of yet and a portion of the SRAC Decision is being reconsidered by the CPUC.  We do not believe that the proposed pricing changes will materially affect us in 2009. 

The following table is for the three months ended:

   
March 31, 2009
   
March 31, 2008
   
December 31, 2008
 
Electricity
                 
Revenues (in millions)
  $ 10.3     $ 15.9     $ 12.3  
Operating costs (in millions)
  $ 8.8     $ 16.4     $ 9.3  
Electric power produced - MWh/D
    2,068       2,152       2,086  
Electric power sold - MWh/D
    1,939       1,959       1,904  
Average sales price/MWh
  $ 58.85     $ 90.48     $ 69.94  
Fuel gas cost/MMBtu (including transportation)
  $ 4.01     $ 7.94     $ 4.80  

 
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)
 
   
March 31, 2009
   
March 31, 2008
   
December 31, 2008
   
March 31, 2009
   
March 31, 2008
   
December 31, 2008
 
Operating costs – oil and gas production
  $ 13.74     $ 17.36     $ 15.07     $ 37,384     $ 39,340     $ 44,598  
Production taxes
    2.08       2.29       2.10       5,652       5,183       6,213  
DD&A – oil and gas production
    13.38       10.68       12.89       36,398       24,207       38,133  
G&A
    4.89       4.91       6.07       13,294       11,132       17,972  
Interest expense
    3.69       1.47       3.05       10,050       3,327       9,032  
Total
  $ 37.78     $ 36.71     $ 39.18     $ 102,778     $ 83,189     $ 115,948  

 
·
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:

   
March 31, 2009
(1Q09)
   
March 31, 2008
(1Q08)
   
1Q09
to 1Q08 Change
   
December 31, 2008
(4Q08)
   
1Q09 to 4Q08 Change
 
Average volume of steam injected (Bbl/D)
    103,342       91,326       13 %     105,443       (2 %)
Fuel gas cost/MMBtu (including transportation)
  $ 4.01     $ 7.94       (49 %)   $ 4.80       (16 %)
Approximate net fuel gas volume consumed in steam generation (MMBtu/D)
    26,427       21,634       22 %     27,978       (6 %)

Operating costs decreased by $7.2 million or 16% between the fourth quarter of 2008 and the first quarter of 2009.  The majority of the decrease came from decreased fuel gas costs of $4 million from decreased natural gas prices and a $1 million decrease in compression, gathering and dehydration from lower natural gas production volumes.  The remainder of the decrease is due to decreased activity levels and our cost reduction efforts.  The decrease in operating costs from the first quarter of 2008 to the first quarter of 2009 was also primarily due to natural gas prices which decreased 49%, offset, on an absolute basis by the addition of our East Texas assets.

 
·