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 September 30, 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 filerx   Accelerated filero   Non-accelerated filero   Smaller reporting companyo

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

As of October 19, 2009, the registrant had 42,860,540 shares of Class A Common Stock ($.01 par value) outstanding. The registrant also had 1,797,784 shares of Class B Stock ($.01 par value) outstanding on October 19, 2009 all of which is held by an affiliate of the registrant.
 


 
1

 

BERRY PETROLEUM COMPANY
THIRD QUARTER 2009 FORM 10-Q
TABLE OF CONTENTS
 
PART I. FINANCIAL INFORMATION
 
Page
     
 
Item 1. Financial Statements
3
     
 
3
     
 
4
     
 
4
     
 
5
     
 
5
     
 
6
     
 
7
     
 
19
     
 
31
     
 
35
     
     
     
     
PART II.
OTHER INFORMATION
   
     
 
36
     
 
36
     
 
38
     
 
38
     
 
38
     
 
38
     
 
39
 

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

   
September 30, 2009
   
December 31, 2008
 
ASSETS
           
Current assets:
           
Cash and cash equivalents
  $ 975     $ 240  
Short-term investments
    67       66  
Accounts receivable, net of allowance for doubtful accounts of $38,508 and $38,511
    67,726       65,873  
Fair value of derivatives
    30,460       111,886  
Crude oil inventory
    1,393       -  
Prepaid expenses and other
    8,780       11,015  
Total current assets
    109,401       189,080  
Oil and gas properties (successful efforts basis), buildings and equipment, net
    2,096,897       2,254,425  
Fair value of derivatives
    1,002       79,696  
Other assets
    33,245       19,182  
    $ 2,240,545     $ 2,542,383  
LIABILITIES AND SHAREHOLDERS' EQUITY
               
Current liabilities:
               
Accounts payable
  $ 53,755     $ 119,221  
Revenue and royalties payable
    14,325       34,416  
Accrued liabilities
    45,630       34,566  
Line of credit
    12,500       25,300  
Income taxes payable
    498       187  
Fair value of derivatives
    21,441       1,445  
Deferred income taxes
    892       45,490  
Total current liabilities
    149,041       260,625  
Long-term liabilities:
               
Deferred income taxes
    250,045       270,323  
Senior secured revolving credit facility
    365,000       931,800  
8 ¼ % Senior subordinated notes due 2016
    200,000       200,000  
10 ¼ % Senior notes due 2014, net of unamortized discount of $14,075 and $0, respectively
    435,925       -  
Abandonment obligation
    43,229       41,967  
Other long-term liabilities
    20,828       5,921  
Fair value of derivatives
    41,316       4,203  
Total long-term liabilities
    1,356,343       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; 42,855,902 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
    87,398       79,653  
Accumulated other comprehensive (loss) income
    (17,210 )     113,697  
Retained earnings
    664,528       633,749  
Total shareholders' equity
    735,161       827,544  
    $ 2,240,545     $ 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 September 30, 2009 and 2008
(In Thousands, Except Per Share Data)

   
Three months ended September 30,
 
   
2009
   
2008
 
REVENUES AND OTHER INCOME ITEMS
           
Sales of oil and gas
  $ 127,455     $ 193,890  
Sales of electricity
    9,137       18,317  
Gas marketing
    5,217       13,284  
Gain on derivatives
    531       701  
Gain on sale of assets
    828       95  
Interest and other income, net
    287       747  
      143,455       227,034  
EXPENSES
               
Operating costs - oil and gas production
    39,195       52,486  
Operating costs - electricity generation
    6,892       13,706  
Production taxes
    3,874       8,912  
Depreciation, depletion & amortization - oil and gas production
    33,502       37,354  
Depreciation, depletion & amortization - electricity generation
    951       646  
Gas marketing
    4,633       12,034  
General and administrative
    10,686       14,251  
Interest expense
    14,562       8,031  
Extinguishment of debt
    329       -  
Dry hole, abandonment, impairment and exploration
    69       1,488  
      114,693       148,908  
Income before income taxes
    28,762       78,126  
Provision for income taxes
    10,423       28,511  
Income from continuing operations
    18,339       49,615  
Income from discontinued operations, net of taxes
    668       3,733  
                 
Net income
  $ 19,007     $ 53,348  
                 
Basic net income from continuing operations per share
  $ 0.41     $ 1.10  
Basic net income from discontinued operations per share
  $ 0.01     $ 0.08  
Basic net income per share
  $ 0.42     $ 1.18  
                 
Diluted net income from continuing operations per share
  $ 0.40     $ 1.08  
Diluted netincome from discontinued operations  per share
  $ 0.01     $ 0.08  
Diluted net income per share
  $ 0.41     $ 1.16  
                 
Dividends per share
  $ 0.075     $ 0.075  


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

Net income
  $ 19,007     $ 53,348  
Unrealized gains (losses) on derivatives, net of income taxes (benefits) of ($345) and $144,881, respectively
    (563 )     225,693  
Reclassification of realized (losses) gains on derivatives included in net income, net of income taxes (benefits) of ($279) and $18,745, respectively
    (454 )     30,584  
Comprehensive income
  $ 17,990     $ 309,625  

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

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

   
Nine months ended September 30,
 
   
2009
   
2008
 
REVENUES AND OTHER INCOME ITEMS
           
Sales of oil and gas
  $ 374,117     $ 514,578  
Sales of electricity
    26,032       51,223  
Gas marketing
    17,646       28,046  
Gain (loss) on derivatives
    6,565       (27 )
Gain on sale of assets
    828       510  
Interest and other income, net
    1,375       2,509  
      426,563       596,839  
EXPENSES
               
Operating costs - oil and gas production
    111,317       144,158  
Operating costs - electricity generation
    22,071       45,620  
Production taxes
    14,411       20,663  
Depreciation, depletion & amortization - oil and gas production
    104,271       87,462  
Depreciation, depletion & amortization - electricity generation
    2,938       1,991  
Gas marketing
    16,149       26,087  
General and administrative
    37,143       36,312  
Interest expense
    35,201       14,910  
Extinguishment of debt
    10,823       -  
Dry hole, abandonment, impairment and exploration
    209       7,396  
      354,533       384,599  
Income before income taxes
    72,030       212,240  
Provision for income taxes
    24,681       79,377  
Income from continuing operations
    47,349       132,863  
(Loss) income from discontinued operations, net of taxes
    (6,323 )     12,657  
                 
Net income
  $ 41,026     $ 145,520  
                 
Basic net income from continuing operations per share
  $ 1.04     $ 2.95  
Basic net (loss) income from discontinued operations per share
  $ (0.14 )   $ 0.28  
Basic net income per share
  $ 0.90     $ 3.23  
                 
Diluted net income from continuing operations per share
  $ 1.03     $ 2.90  
Diluted net (loss) income from discontinued operations  per share
  $ (0.14 )   $ 0.28  
Diluted net income per share
  $ 0.89     $ 3.18  
                 
Dividends per share
  $ 0.225     $ 0.225  

 
Unaudited Condensed Statements of Comprehensive Income
Nine Months Ended September 30, 2009 and 2008
(In Thousands)

Net income
  $ 41,026     $ 145,520  
Unrealized gains (losses) on derivatives, net of income taxes (benefits) of $104,173 and $58,260, respectively
    169,966       (95,055 )
Reclassification of realized (losses)gains on derivatives included in net income, net of income taxes (benefits) of ($23,940) and $52,341, respectively
    (39,059 )     85,399  
Comprehensive income
  $ 171,933     $ 135,864  

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

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

   
Nine months ended September 30,
 
   
2009
   
2008
 
Cash flows from operating activities:
           
Net income
  $ 41,026     $ 145,520  
Depreciation, depletion and amortization
    109,397       98,579  
Extinguishment of debt
    10,823       -  
Dry hole and impairment
    9,643       6,858  
Commodity derivatives
    4,796       (8 )
Stock-based compensation expense
    7,054       6,653  
Deferred income taxes
    13,546       76,502  
Loss (gain) on sale of oil and gas properties
    79       (510 )
Other, net
    (362 )     (1,500 )
Cash paid for abandonment
    (293 )     (3,957 )
Change in book overdraft
    (20,199 )     3,935  
Increase in current assets other than cash and cash equivalents
    (9,828 )     (35,361 )
(Decrease) increase in current liabilities other than book overdraft, line of credit and fair value of derivatives
    (17,303 )     34,537  
Net cash provided by operating activities
    148,379       331,248  
Cash flows from investing activities:
               
Exploration and development of oil and gas properties
    (93,592 )     (302,266 )
Property acquisitions
    (11,904 )     (667,030 )
Additions to vehicles, drilling rigs and other fixed assets
    (1,044 )     (4,146 )
Proceeds from sale of assets
    139,796       2,038  
Capitalized interest
    (21,145 )     (15,461 )
Net cash provided by (used in) investing activities
    12,111       (986,865 )
Cash flows from financing activities:
               
Proceeds from line of credit
    323,100       308,000  
Payments on line of credit
    (335,900 )     (303,000 )
Proceeds from issuance of long-term debt
    1,099,238       1,481,300  
Payments on long-term debt
    (1,231,076 )     (817,000 )
Debt issuance cost
    (23,857 )     (8,353 )
Proceeds from financing obligation
    18,295       -  
Dividends paid
    (10,247 )     (10,084 )
Proceeds from stock option exercises
    601       2,834  
Excess tax benefit and other
    91       1,663  
Net cash (used in) provided by financing activities
    (159,755 )     655,360  
                 
Net increase (decrease) in cash and cash equivalents
    735       (257 )
Cash and cash equivalents at beginning of year
    240       316  
Cash and cash equivalents at end of period
  $ 975     $ 59  

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 September 30, 2009 and December 31, 2008 and results of operations and other comprehensive income for the three and nine months ended September 30, 2009 and 2008, and its cash flows for the nine months ended September 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 audited financial statements for the three years ended December 31, 2008 and at December 31, 2007 and 2008 included in our Form 8-K filed on August 11, 2009, which give effect to the classification of the DJ Basin assets as discontinued operations,  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 September 30, 2009 and December 31, 2008 is $11.6 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 Financial Accounting Standards Board (FASB) issued authoritative guidance to establish accounting and reporting standards for the noncontrolling interests in a subsidiary (formerly called minority interests) and for the deconsolidation of a subsidiary.  The adoption of this authoritative guidance did not have a material impact on our financial statements.

In March 2008, the FASB issued authoritative guidance, 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 and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The adoption of this authoritative guidance did not have a material impact on our financial statements.  We have expanded our disclosures accordingly.  See Note 4 to the unaudited financial statements.

In June 2008, the FASB issued authoritative guidance, which clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the earnings allocation in computing basic earnings per share under the two-class method described in authoritative guidance.  All prior period earnings per share data presented shall be adjusted retrospectively to conform with the provisions of this guidance. This guidance is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. The adoption of this authoritative guidance did not have a material impact on our financial statements.  See Note 12 to the unaudited financial statements.
 
In December 2008, the Securities and Exchange Commission adopted revisions to its oil and gas disclosure requirements that are intended to align them with current practices and changes in technology. Among other things, the amendments will: replace the single-day year-end pricing assumption with a twelve-month average pricing assumption; permit the disclosure of probable and possible reserves; allow the use of certain technologies to establish reserves; require the disclosure of the qualifications of the technical person primarily responsible for preparing the reserves estimates or conducting a reserves audit; require the filing of the independent reserve engineers' summary report; and permit the disclosure of a reserves sensitivity analysis table to illustrate the impact of different price and/or cost assumptions on reserves. These amendments are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on December 31, 2009, with early adoption prohibited. The Company is currently evaluating the impact that the adoption of this pronouncement will have on the Company's financial position, results of operations, and disclosures.
 
In April 2009, the FASB issued authoritative guidance which requires disclosures about the fair value of financial instruments for interim reporting periods as well as in annual financial statements.  The adoption of this authoritative guidance did not have a material impact on our financial statements.  We have expanded our disclosures accordingly.  See Note 3 to the unaudited financial statements.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements

 
In May 2009, the FASB issued authoritative guidance, 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 this guidance during the second quarter of 2009 and we expanded our disclosures accordingly.  See Note 15 to the unaudited financial statements.

In June 2009, the FASB approved the FASB Accounting Standards Codification (ASC), which after its effective date of July 1, 2009 is the single source of authoritative, nongovernmental U.S. Generally Accepted Accounting Principles (GAAP).  The Codification reorganizes all previous U.S. GAAP pronouncements into roughly 90 accounting topics and displays all topics using a consistent structure.  All existing standards that were used to create the Codification are now superseded, replacing the previous references to specific Statements of Financial Accounting Standards (SFAS) with numbers used in the Codification’s structural organization.   The adoption of this authoritative guidance did not have a material impact on our financial statements. We have updated our disclosures accordingly.

3.
Fair Value Measurements
 
In September 2006, the Financial Accounting Standards Board (FASB) issued authoritative guidance that clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. We adopted the authoritative guidance as of January 1, 2008 for all financial and nonfinancial assets and liabilities recognized or disclosed at fair value on a recurring basis.  We have also adopted the authoritative guidance as it relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis as of January 1, 2009 pursuant to the authoritative guidance issued by the FASB in February 2008.  The adoption of the authoritative guidance did not have a material impact on our financial statements.
 
The authoritative guidance establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.
 
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy.  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.
 
The following tables sets forth by level within the fair value hierarchy the Company’s assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2009 and December 31, 2008.

September 30, 2009 (in millions)
 
Total carrying value on the condensed Balance Sheet
   
Level 2
   
Level 3
 
Commodity derivative asset (liability)
  $ (21.5 )   $ (54.1 )   $ 32.6  
Interest rate swap asset (liability)
    (9.8 )     (9.8 )     -  
Total fair value asset (liability)
  $ (31.3 )   $ (63.9 )   $ 32.6  

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  
 
 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


Changes in Level 3 fair value measurements

The following table sets forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:

   
Three months ended September 30,
   
Nine months ended September 30,
 
(in millions)
 
2009
   
2008
   
2009
   
2008
 
Fair value of Level 3 derivative assets, beginning of period
  $ 43.1     $ 569.6     $ 172.5     $ 194.3  
Total realized and unrealized losses included  in Gain (loss) on derivatives
    (1.0 )     (0.6 )     (1.7 )     0.2  
Purchases, sales and settlements, net
    (9.5 )     (360.1 )     (141.6 )     14.4  
Transfers in and/or out of Level 3
    -       -       3.4       -  
Fair value of Level 3 derivative assets, September 30, 2009
  $ 32.6     $ 208.9     $ 32.6     $ 208.9  
                                 
Total unrealized gains (losses) included in income related to financial assets and liabilities on the condensed balance sheet at September 30, 2009
  $ (0.7 )   $ -     $ (1.3 )   $ -  

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

Fair Market Value of Financial Instruments
 
The Company used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Company's credit facilities approximated fair value, because the interest rates on the credit facilities are variable. The fair values of our 8 ¼ % senior subordinated notes due 2016 and our 10 ¼ % senior notes due 2014 were estimated based on quoted market prices. The fair values of the Company's derivative instruments and other investments are discussed above.

(in millions)
 
Carrying Amount
   
Estimated Fair Value
 
Line of credit
  $ 13     $ 13  
Senior secured revolving credit facility
    365       365  
8 ¼ % Senior subordinated notes due 2016
    200       191  
10 ¼ % Senior notes due 2014
    436       479  
    $ 1,014     $ 1,048  

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.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


The related cash flow impact of all of our hedges is reflected in cash flows from operating activities. At September 30, 2009, our net fair value derivative liability was $31.3 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 September 30, 2009, we expect to receive hedge payments under the existing derivatives of $14.7 million during the next twelve months. At September 30, 2009, “Accumulated Other Comprehensive Income (Loss)” (“AOCL”) consisted of $17.2 million, net of tax, of unrealized losses from our crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at September 30, 2009. Deferred net losses recorded in AOCL at September 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 on 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 on 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 September 30, 2009
 
 
Derivative Assets
 
Derivative Liabilities
 
(in millions)
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
Commodity – Oil
Current assets
  $ 31.7  
Current liability
  $ 14.5  
Commodity – Natural Gas
Current assets
    1.4            
Commodity – Oil
Long term assets
    1.0  
Long term liabilities
    37.3  
Commodity – Natural Gas
         
Long term liabilities
    0.3  
Commodity – Natural Gas
Current liability
    0.7            
Interest rate contracts
         
Current assets
    2.7  
Interest rate contracts
         
Current liabilities
    3.6  
Interest rate contracts
         
Long term liabilities
    3.4  
Total derivatives designated as hedging instruments under authoritative guidance
      34.8         61.8  
                     
Commodity – Oil
      -  
Current liabilities
    3.1  
Commodity – Natural Gas
      -  
Current liabilities
    0.9  
Commodity – Natural Gas
      -  
Long term liabilities
    0.3  
Total derivatives not designated as hedging instruments under authoritative guidance
      -         4.3  
Total Derivatives
    $ 34.8       $ 66.1  
 
 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


The tables below summarize the Statement of Operations impacts of our derivative instruments for the three and nine months ending September 30,2009 (in millions):

Derivatives cash flow hedging relationships
 
Amount of gain (loss) Recognized in AOCI 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 of Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Amount of Gain (loss) Recognized in Income of Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
   
Three Months Ended
September 30, 2009
     
Three Months Ended
September 30, 2009
     
Three Months Ended
September 30, 2009
 
Commodity  - Oil
  $ (2.5 )
Sales of oil and gas
  $ 1.0  
Sales of oil and gas
  $ -  
Commodity  - Natural Gas
    1.8  
Sales of oil and gas
    0.6  
Gain (loss) on  derivatives
    (0.6 )
Interest rate
    0.7  
Interest expense
    (1.1 )
Gain (loss) on  derivatives
    0.1  
Total
  $ -       $ 0.5       $ (0.5 )

 

 
Derivatives cash flow hedging relationships
 
Amount of gain (loss) Recognized in AOCI 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 of Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
Amount of Gain (loss) Recognized in Income of Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
 
   
Nine Months Ended
September 30, 2009
     
Nine Months Ended
September 30, 2009
     
Nine Months Ended
September 30, 2009
 
Commodity  - Oil
  $ 161.4  
Sales of oil and gas
  $ 36.4  
Sales of oil and gas
  $ -  
Commodity  - Natural Gas
    13.1  
Sales of oil and gas
    5.4  
Gain (loss) on  derivatives
    14.0  
Interest rate
    (3.9 )
Interest expense
    (2.7 )
Gain (loss) on  derivatives
    (0.2 )
Total
  $ 170.6       $ 39.1       $ 13.8  

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

Derivatives not designated as Hedging Instruments under authoritative guidance
Location of Gain (Loss) Recognized in Income on Derivative
 
Amount of Gain (Loss) Recognized in Income on Derivatives not designated as Hedging Instruments under authoritative guidance
   
Amount of Gain (Loss) Recognized in Income on Derivatives not designated as Hedging Instruments under authoritative guidance
 
     
Three months ended
September 30, 2009
   
Nine months ended
September 30, 2009
 
Commodity – Oil
Gain (loss) on derivatives
  $ 1.6       (5.7 )
Commodity - Natural Gas
Gain (loss) on derivatives
    (0.5 )     (1.5 )
Commodity - Natural Gas
(Loss) income from discontinued operations, net of taxes
    -       (0.5 )
Total Derivatives
    $ 1.1       (7.7 )

We did not enter into any crude oil or natural gas hedges during the three months ended September 30, 2009.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


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

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 contract impacts the probability that our hedged forecasted transactions will occur.  We generally hedge our natural gas at the basis location that corresponds to the forecasted 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 nine months ended September 30, 2009, we recorded $0.5 million and $6.6 million under the caption “Gain (loss) on derivatives”  related to hedges for which we either did not elect hedge accounting or which no longer qualified for hedge accounting.  In conjunction with the sale of the DJ basin assets, during the first quarter of 2009, 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 may impact our income as our sales price is not perfectly correlated with our hedges.  We recognized an unrealized net loss of $0.5 million and $0.4 million on the statement of operations under the caption “Gain (loss) on derivatives” for the three and nine months ended September 30, 2009, respectively, as a result of 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 executed only 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 commodity derivative asset and liability positions.  The credit rating of each of these counterparties was AA-/Aa2, or better as of September 30, 2009.  Our derivatives are held with a small number of counterparties and as of September 30, 2009, our largest four counterparties accounted for 90% of the value of our total derivative positions.

As of September 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:
14,000
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.  This transaction was accounted for as a non-monetary exchange and the amount was recorded in crude oil inventory.  The refiner purchased 50,000 barrels from us during the third quarter of 2009 and the remaining balance in “Crude Oil Inventory” at September 30, 2009 reflects the cost of production, transportation costs and quality differentials for the remaining 50,000 barrels of inventory volume.

6.
Asset Retirement Obligations

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

Beginning balance at January 1, 2009
  $ 41,967  
Liabilities incurred
    1,407  
Liabilities settled
    (3,044 )
Revisions in estimated liabilities
    -  
Accretion expense
    2,899  
Ending balance at September 30, 2009
  $ 43,229  
 
 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


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

7.
Acquisitions

During the nine months ended September 30, 2009, we completed acquisitions totaling $11.9 million. In June 2009, we acquired property near McKittrick, California, the deep rights to one of the leases in our Darco property in East Texas, and additional interests in our Piceance Garden Gulch assets. 

8.
Dispositions and Discontinued Operations

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

On March 3, 2009, 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 $6.3 million “(Loss) income from discontinued operations, net of taxes” on our statement of operations for the nine months ended September 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
September 30,
   
For the Nine Months Ended
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Oil and gas revenue
  $ -     $ 13,972     $ 5,396     $ 43,111  
Loss on sale of asset
    (578 )     -       (908 )     -  
Other revenue
    -       350       623       1,441  
Total Revenue
    (578 )     14,322       5,111       44,552  
                                 
Operating expenses
    -       3,552       2,576       8,694  
Production taxes
    -       761       195       2,458  
DD&A
    -       3,086       2,188       9,126  
General and administrative
    -       273       388       755  
Interest expense
    -       724       815       1,534  
Commodity derivatives
    -       -       484       -  
Dry hole, abandonment, impairment and exploration
    -       84       9,637       1,766  
Total Expenses
    -       8,480       16,283       24,333  
                                 
(Loss) income from discontinued operations, before income taxes
    (578 )     5,842       (11,172 )     20,219  
Income tax benefit (expense)
    1,246       (2,109 )     4,849       (7,562 )
Income (Loss) from discontinued operations
  $ 668     $ 3,733     $ (6,323 )   $ 12,657  
 
 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


9.
Dry Hole, Abandonment and Impairment

During the nine months ended September 30, 2009 and 2008, we recorded dry hole, abandonment, impairment and exploration expense of $0.2 million and $7.4 million, respectively.   Charges of $2.7 million,  $2.6 million and $1.5 million were recorded during the first, second and third quarters of 2008, respectively for technical difficulties that were encountered on five wells in the Piceance basin before reaching total depth.  These holes were abandoned in favor of drilling to the same bottom hole location by drilling new wells.  In addition, $0.5 million of exploration expense was recorded during the nine months ended September 30, 2008 for exploration activities which were primarily 3-D seismic in nature.

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 nine months ended September 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
September 30, 2008
   
Nine Months Ended
September 30, 2008
 
Pro forma revenue
  $ 233,236     $ 643,396  
Pro forma income from operations
  $ 83,575     $ 217,351  
Pro forma net income
  $ 52,977     $ 136,016  
Pro forma basic earnings per share
  $ 1.17     $ 3.02  
Pro forma diluted earnings per share
  $ 1.16     $ 2.97  
 
11.
Income Taxes

The effective income tax rate was 36.2% for the third quarter of 2009 compared to 36.1% for the second quarter of 2009 and 36.5% for the third quarter of 2008.  The effective tax rate was 34.3% and 37.4% for the nine months ended September 30, 2009 and 2008, respectively.  The change for the nine month period ended September 30, 2009 when compared to the same period in 2008 was primarily due to reduced state tax rates and the reduction in our liability related to uncertain tax positions.  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 September 30, 2009, we had a gross liability for uncertain tax benefits of $7.4 million of which $6.2 million, if recognized, would affect the effective tax rate. The liability related to uncertain tax positions was reduced during the nine months ended September 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 June 2008, the FASB issued authoritative guidance, which clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the earnings allocation in computing basic earnings per share under the two-class method.  All prior period earnings per share data presented were adjusted retrospectively to conform with the provisions of the guidance which is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements
 
 
The following table shows the computation of basic and diluted net (loss) income per share from continuing and discontinued operations for the three and nine months ended September 30, 2009 and 2008 (in thousands):

   
Three months ended
September 30,
   
Nine months ended
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Net income from continuing operations
  $ 18,339     $ 49,615     $ 47,349     $ 132,863  
Less: Income allocable to participating securities
    445       691       1,153       1,841  
Income available for shareholders
    17,894       48,924       46,196       131,022  
                                 
Net income (loss) from discontinued operations
    668       3,733       (6,323 )     12,657  
Less:  Income allocable to participating securities
    17       53       -       178  
Income (loss)  from discontinued operations available for shareholders
    651       3,680       (6,323 )     12,479  
                                 
Basic earnings per share from continuing operations
    0.41       1.10       1.04       2.95  
Basic earnings (loss) per share from discontinued operations
    0.01       0.08       (0.14 )     0.28  
Basic earnings per share
    0.42       1.18       0.90       3.23  
                                 
Diluted earnings per share from continuing operations
    0.40       1.08       1.03       2.90  
Diluted earnings (loss) per share from discontinued operations
    0.01       0.08       (0.14 )     0.28  
Diluted earnings per share
  $ 0.41     $ 1.16     $ 0.89     $ 3.18  
                                 
Weighted average shares outstanding – basic
    44,633       44,527       44,607       44,466  
Add:  dilutive effects of stock options
    303       651       189       702  
Weighted average shares outstanding – dilutive
    44,936       45,178       44,796       45,168  
 
 
Options to purchase 1.2 million and 1.6 million shares were not included in the diluted (loss) earnings per share calculation for the three and nine months ended September 30, 2009, respectively, because their effect would have been anti-dilutive.  Options to purchase 0.2 million and 0.1 million shares were not included in the diluted (loss) earnings per share calculation for the three and nine months ended September 30, 2008, respectively, because their effect would have been anti-dilutive.

The adoption of the guidance issued by the FASB decreased basic earnings per share from continuing operations by $0.02 and $0.04 for the three and nine months ended September 30, 2008, respectively, and dilutive earnings per share from continuing operations by $0.01 and $0.02 for the three and nine months ended September 30, 2008, respectively.  Basic and dilutive (loss) earnings per share from discontinued operations remained unchanged for the three and nine months ended September 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 September 30, 2009 and December 31, 2008, the outstanding balance under this Line of Credit was $12.5 million and $25.3 million, respectively.  Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1.6%.

Senior Secured Revolving Credit Facility
Our Senior Secured Revolving Credit Facility (the Agreement) has a current borrowing base and lender commitments of $938 million. The LIBOR and prime rate margins are between 2.25% and 3.0% based on the ratio of credit outstanding to the borrowing base and the annual commitment fee on the unused portion of the credit facility is 0.50%. 

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


Covenants under the Agreement are as follows:

Total funded debt to EBITDAX ratio not greater than:
 
Senior secured debt to EBITDAX ratio not greater than:
2009
2010
Thereafter
 
to Sep 2010
Mar 2011
Sep 2011
Thereafter
4.75
4.50
4.00
 
3.75
3.50
3.25
3.0

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, per the Agreement.

The Agreement contains a current ratio covenant which, as defined, must be at least 1.0.  During the third quarter of 2009 our borrowing base decreased from $969 billion to $938 million as a result of the add-on of our senior unsecured notes.  The total outstanding debt at September 30, 2009 under the Agreement, as amended, and the Line of Credit was $365 million and $13 million, respectively, and $4 million in letters of credit have been issued under the facility, leaving $556 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.

Second 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 second lien term loan on May 29, 2009 from the proceeds of our senior unsecured notes issuance and wrote off $7.2 million in deferred loan fees for the nine months ended September 30, 2009.

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

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

The $125 million Notes and the previously issued $325 million Notes will be treated as a single series of debt securities under the indenture and are carried on the balance sheet at their combined amortized cost in which the $325 million Notes discount and the $125 million Notes premium net to a discount.

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.  Under our senior subordinated and senior unsecured 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 September 30, 2009.

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


 
As of
September 30, 2009
 
Current Ratio (Not less than 1.0)
5.1
 
EBITDAX To Total Funded Debt Ratio (Not greater than 4.75)
3.3
 
Interest Coverage Ratio (Not less than 2.5)
4.0
 
EBITDAX To Senior Secured Debt Ratio (Not greater than 3.75)
1.2
 

The weighted average interest rate on total outstanding borrowings at September 30, 2009 was 7.0%.

14.
Contingencies and Commitments

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

   
Total
   
2009
   
2010
   
2011
   
2012
   
2013
   
Thereafter
 
Total debt and interest
  $ 1,385.1     $ 30.5     $ 71.8     $ 71.8     $ 430.3     $ 62.6     $ 718.1  
Abandonment obligations
    43.2       1.3       2.9       2.9       2.8       2.8       30.5  
Operating lease obligations
    16.6       0.6       2.4       2.4       2.5       2.5       6.2  
Drilling and rig obligations
    38.6       4.4       8.0       8.0       18.2       -       -  
Firm natural gas transportation contracts
    140.1       4.6       19.1       19.1       17.8       15.7       63.8  
Total
  $ 1,623.6     $ 41.4     $ 104.2     $ 104.2     $ 471.6     $ 83.6     $ 818.6  

On July 17, 2009, we closed on the financing of our East Texas gas gathering system for $18.4 million in cash.  We entered into concurrent long-term gas gathering agreements for the East Texas production which contained an embedded lease.  There is no minimum payment required under these agreements.  For the first nine months of 2009, we have incurred $1.0 million under the agreements.

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.

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 $1.5 million for the three and nine month periods ended September 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.

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 3,100 BOE/D in the quarter ended September 30, 2009.
 
On August 13, 2009, we issued in a public offering a $125 million add-on to our 10.25% senior notes due 2014.
 
On May 27, 2009, we issued in a public offering $325 million of 10.25% senior notes due 2014.  Interest on the $325 million Notes is paid semiannually in June and December of each year.

 
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 California 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, 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.

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.

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 $6 million.
 
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.   In 2007 we immediately remediated the instances of non-compliance, cooperated fully with the BLM’s investigation and we believe no production was lost, all royalties were paid and there was no harm to the environment. 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 accrued such amount in the second quarter of 2009.

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 adjustments 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.

15.
Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued, which for the quarterly period ended September 30, 2009, is October 30, 2009.  No subsequent events requiring disclosure were identifited by the Company.

 
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 nine months ended September 30, 2009 and 2008 and our financial condition, liquidity and capital resources as of September 30, 2009. The unaudited 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:
 
·
Maximize production from our base oil assets
 
·
Grow oil production from our inventory of organic development projects
 
·
Increase natural gas production that will meet the growing demand for steam generation
 
·
Acquire additional resources with an emphasis on crude oil

Notable Third Quarter Items.
 
·
Achieved production averaging 28,417 BOE/D, of which 68% is crude oil production, with $22 million of capital investment
 
·
Increased Diatomite net production to an average of 3,119 BOE/D, up 49% from the third quarter of 2008
 
·
Secured twelve month contracts for approximately 90% of our California crude oil
 
·
Issued a $125 million add-on to our 10.25% senior unsecured notes due in 2014 with a yield of 9%
 
·
Paid down $78 million of additional debt and increased liquidity to approximately $550 million
 
·
Completed the sale of our East Texas midstream assets for $18 million
 
·
Tested our new completion method in the Piceance basin, delivering a 25% improvement compared to our historical field average
 
·
Received category exemption allowing 25 wells to be drilled in the Uinta basin in Ashley Forest

Notable Items and Expectations for the Fourth Quarter and Full Year 2009.
 
·
Completed our credit facility borrowing base redetermination and reconfirmed our $938 million borrowing base
 
·
Initiate a steam flood pilot on the McKittrick, California property
 
·
Expect to drill our first East Texas Haynesville well during the fourth quarter of 2009
 
·
Expect production to average approximately 30,000 BOED for the full year 2009

Overview of the Third Quarter of 2009. We had net income from continuing operations of $18 million, or $0.40 per diluted share, and cash provided from operations was $89 million in the third quarter of 2009.  Net income includes $1 million from the sale of crude oil inventory.  We drilled 32 gross wells, and capital expenditures excluding property acquisitions totaled $22 million.  We achieved average production of 28,417 BOE/D in the third quarter of 2009.

Acquisitions.  In June 2009, we acquired the 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 East 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 July 17, 2009, we completed the sale of our East Texas gas gathering system for $18.4 million in cash.  See Note 8 to the unaudited financial statements.

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 and third quarters of 2009 totaled $0.5 million income, net of tax.  The total loss on sale was recorded within “(Loss) income from discontinued operations, net of tax,” on the condensed statements of operations for the nine months ended September 30, 2009.

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

   
Three months ended,
   
Nine months ended,
 
   
Sept 30, 2009
   
Sept 30, 2008
   
June 30, 2009
   
Sept 30, 2009
   
Sept 30, 2008
 
Sales of oil
  $ 109     $ 146     $ 103     $ 311     $ 423  
Sales of gas
    18       48       16       63       92  
Total sales of oil and gas
  $ 127     $ 194     $ 119     $ 374     $ 515  
Sales of electricity
    9       18       6       26       51  
Gas Marketing
    5       13       5       18       28  
Gain (loss) on derivative
    1       1       (31 )     7       -  
Interest and other income, net
    1       1       1       2       3  
Total revenues and other income
  $ 143     $ 227     $ 100     $ 427     $ 597  
Net income (loss) from continuing operations
  $ 18     $ 50     $ (13 )   $ 47     $ 133  
Diluted earnings (loss) per share from continuing operations
  $ 0.40     $ 1.08     $ (0.28 )   $ 1.03     $ 2.90  

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 September 30, 2009 were higher compared to the three months ended June 30, 2009 resulting from realized price increases of 1%, sales volume increases of 6% and we recognized revenue of $2.7 million resulting from the sale of 50,000 barrels of crude oil inventory.  The decrease in crude oil revenue when compared to the third quarter of 2008 is primarily the result of a 24% decrease in realized prices.  Natural gas revenues increased from the quarter ended June 30, 2009 as a result of a 12% increase in realized prices and a 2% decrease in volumes from our Piceance and Uinta properties where no capital activity occurred during the quarter.  Natural gas revenues were lower in the third quarter of 2009 compared to the third quarter of 2008 primarily due to a 58% decrease in realized prices.
 
 
 
 
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:
 
   
September 30, 2009
   
%
   
September 30, 2008
   
%
   
June 30, 2009
   
%
 
                                     
Heavy Oil Production (Bbl/D)
    16,780       59       17,264       49       16,822       57  
Light Oil Production (Bbl/D)
    2,530       9       3,898       11       3,085       11  
Total Oil Production (Bbl/D)
    19,310       68       21,162       60       19,907       68  
Natural Gas Production (Mcf/D)
    54,637       32       83,928       40       56,174       32  
Total operations (BOE/D)
    28,417       100       35,150       100       29,270       100  
                                                 
DJ Basin Production (BOE/D)
    -               3,337               -          
Production - Continuing Operations (BOE/D)
    28,417               31,813               29,270          
                                                 
Oil and gas, per BOE for continuing operations
                                               
Average sales price before hedging
  $ 45.41             $ 83.90             $ 39.34          
Average sales price after hedging
    46.39               67.04               45.74          
                                                 
Oil, per Bbl, for continuing operations:
                                               
Average WTI price
  $ 68.24             $ 118.22             $ 59.79          
Price sensitive royalties
    (2.36 )             (5.30 )             (2.08 )        
Quality differential and other
    (8.78 )             (10.80 )             (7.86 )        
Crude oil hedges reported with Sales of oil and gas
    2.28               (26.12 )             8.91          
Crude oil hedges reported with Gain on derivatives (a)
    (1.41 )             -               -          
Average oil sales price after hedging
  $ 57.97             $ 76.00             $ 58.76          
                                                 
Natural gas price for continuing operations:
                                               
Average Henry Hub (HH) price per MMBtu
  $ 3.39             $ 10.24             $ 3.51          
Conversion to Mcf
    0.17               0.51               0.18          
Natural gas hedges reported with Sales of oil and gas
    0.27               0.20               0.21          
Natural gas hedges reported with Gain (loss) on derivatives (a)
    (0.07 )             -               -          
Location, quality differentials and other
    (0.28 )             (2.69 )             (0.72 )        
Average gas sales price after hedging per Mcf
  $ 3.48             $ 8.26             $ 3.18          

(a) Includes cash settlements on hedges for which the Company has not elected hedge accounting that are recorded in ‘Gain (Loss) on hedges.”

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


Operating data. The following table is for the nine months ended:
 
   
September 30, 2009
   
%
   
September 30, 2008
   
%
 
                         
Heavy Oil Production (Bbl/D)
    16,691       55       16,845       54  
Light Oil Production (Bbl/D)
    2,892       10       3,710       12  
Total Oil Production (Bbl/D)
    19,583       65       20,555       66  
Natural Gas Production (Mcf/D)
    64,493       35       61,201       34  
Total operations (BOE/D)
    30,332       100       30,755       100  
                                 
DJ Basin Production (BOE/D)
    1,020               3,255          
Production - Continuing Operations (BOE/D)
    29,312               27,500          
                                 
Oil and gas, per BOE for continuing operations
                               
Average sales price before hedging
  $ 37.99             $ 86.63          
Average sales price after hedging
    46.43               68.50          
                                 
Oil, per Bbl, for continuing operations:
                               
Average WTI price
  $ 57.22             $ 113.52          
Price sensitive royalties
    (1.83 )             (3.36 )        
Quality differential and other
    (8.65 )             (12.90 )        
Crude oil hedges reported with Sales of oil and gas
    11.49               (23.83 )        
Crude oil hedges reported with Gain on derivatives (a)
    (0.49 )             -          
Correction to royalties payable
    -               1.88          
Average oil sales price after hedging
  $ 57.74             $ 75.31          
                                 
Natural gas price for continuing operations:
                               
Average HH price per MMBtu
  $ 3.94             $ 9.74          
Conversion to Mcf
    0.20               0.49          
Natural gas hedges reported with Sales of oil and gas
    0.56               (0.22 )        
Natural gas hedges reported with Gain (loss) on derivatives (a)
    (0.02 )             -          
Location, quality differentials and other
    (0.74 )             (1.93 )        
Average gas sales price after hedging per Mcf
  $ 3.94             $ 8.08          

(a) Includes cash settlements on hedges for which the Company has not elected hedge accounting that are recorded in ‘Gain (Loss) on hedges.”

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


Gas Basis Differential.  We have two contracts with the Rockies Express pipeline providing for 35,000 MMBtu/d of firm transport.  Unlike the first and second quarters of 2009 in which the Piceance gas was sold based upon a mid-continent index such as PEPL, third quarter gas was sold based an eastern price such as the Gas Daily Lebanon, Ohio index.  For the third quarter of 2009, this index was approximately equal to HH based on daily averages.  Our Uinta basin gas is sold based upon a Questar index which averaged $0.77 below HH during the third quarter of 2009 using first of month averages.  In East Texas, the majority of the gas was sold based on the Florida Gas Transmission Zone 1 index which averaged $0.03 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 have contracted to purchase our partners’ share of the gas produced in the Piceance at the market rate for that area through December 2009. We used our excess transportation to move this gas to eastern markets 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 $1.5 million in the three and nine month periods ended September 30, 2009. Firm transportation costs related to all of our Rockies Express volumes is reflected in Operating costs - oil and gas production and total $3.5 million and $8.5 million for the three months and nine months ended September 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 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 September 24, 2009, we executed a crude oil purchase contract with a refiner for the sale of all of our crude oil production from the Midway Sunset field.  The volume approximates 12,500 barrels per day.  The agreement was effective on October 1, 2009 and continues until September 30, 2010.    We also signed a 13 month contract for the sale of the Poso Creek crude oil to a refiner which had an effective date of September 1, 2009.  Previously 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 3,100 BOE/D in the quarter ended September 30, 2009. The differential under the contract, which includes transportation and gravity adjustments, is linked to the price for NYMEX WTI.

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


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.  This transaction was accounted for as a non-monetary exchange and the amount recorded in crude oil inventory.  The refiner purchased 50,000 barrels from us during the third quarter of 2009 and the remaining balance in “Crude Oil Inventory” at September 30, 2009 reflects the cost of production, transportation costs and quality differentials for the remaining 50,000 barrels of inventory volume.

Hedging. See Note 4 to the unaudited 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. On July 9, 2009, the CPUC issued a resolution that implemented a revised SRAC price methodology effective August 1, 2009 and resolved 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. 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.

Electricity revenues and operating costs were down for the quarter ended September 30, 2009 from the quarter ended September 30, 2008 primarily due to 67% lower natural gas prices. Revenues and operating costs were higher in the quarter ended September 30, 2009 than in the quarter ended June 30, 2009 due to a 10% increase in electricity sold offset by 3% lower electricity prices and 3% lower natural gas prices, respectively. We purchased approximately 28,000 MMBtu/D and 26,000 MMBtu/D as fuel for use in our cogeneration facilities in the quarters ended September 30, 2009 and September 30, 2008, respectively.

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.

The following table is for the three months ended:

   
September 30, 2009
   
September 30, 2008
   
June 30, 2009
 
Electricity
                 
Revenues (in millions)
  $ 9.1     $ 18.3     $ 6.6  
Operating costs (in millions)
  $ 6.9     $ 13.7     $ 6.4  
Electric power produced - MWh/D
    2,048       2,096       2,007  
Electric power sold - MWh/D
    1,966       1,908       1,783  
Average sales price/MWh
  $ 45.24     $ 104.91     $ 46.99  
Fuel gas cost/MMBtu (including transportation)
  $ 3.26     $ 8.20     $ 3.54  
 
 
Berry Petroleum Company
Management's Discussion and Analysis of Financial Condition and Results of Operations


The following table is for the nine months ended:

   
September 30, 2009
   
September 30, 2008
 
Electricity
           
Revenues (in millions)
  $ 26.0     $ 51.2  
Operating costs (in millions)
  $ 22.1     $ 45.6  
Electric power produced - MWh/D
    2,048       1,539  
Electric power sold - MWh/D
    1,896       1,869  
Average sales price/MWh
  $ 65.88     $ 100.88  
Fuel gas cost/MMBtu (including transportation)
  $ 3.44     $ 8.70  

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)