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, 2008
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 LOGO
 
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 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 20, 2008, the registrant had 42,738,091 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 20, 2008 all of which is held by an affiliate of the registrant.



 
1

 

 BERRY PETROLEUM COMPANY
THIRD QUARTER 2008 FORM 10-Q
TABLE OF CONTENTS
 
PART I. FINANCIAL INFORMATION
   
 
Page
 
         
 
Item 1. Financial Statements
    3  
           
 
Unaudited Condensed Balance Sheets at September 30, 2008 and December 31, 2007
    3  
           
 
Unaudited Condensed Statements of Income for the Three Month Periods Ended September 30, 2008 and 2007
    4  
           
 
Unaudited Condensed Statements of Income for the Nine Month Periods Ended September 30, 2008 and 2007
    5  
           
 
Unaudited Condensed Statements of Cash Flows for the Nine Month Periods Ended September 30, 2008 and 2007
    6  
           
 
Notes to Unaudited Condensed Financial Statements
    7  
           
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
    15  
           
 
Item 3. Quantitative and Qualitative Disclosures About Market Risk
    27  
           
 
Item 4. Controls and Procedures
    30  
           
           
           
           
PART II.
OTHER INFORMATION
         
           
 
Item 1. Legal Proceedings
    30  
           
 
Item 1A. Risk Factors
    30  
           
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
    30  
           
 
Item 3. Defaults Upon Senior Securities
    30  
           
 
Item 4. Submission of Matters to a Vote of Security Holders
    30  
           
 
Item 5. Other Information
    30  
           
 
Item 6. Exhibits
    31  



 
2

 

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

   
September 30, 2008
   
December 31, 2007
 
ASSETS
           
Current assets:
           
Cash and cash equivalents
  $ 59     $ 316  
Short-term investments
    65       58  
Accounts receivable
    145,701       117,038  
Deferred income taxes
    38,987       28,547  
Fair value of derivatives
    2,198       2,109  
Assets held for sale
    -       1,394  
Prepaid expenses and other
    19,432       11,557  
Total current assets
    206,442       161,019  
Oil and gas properties (successful efforts basis), buildings and equipment, net
    2,196,322       1,275,091  
Other assets
    17,307       15,996  
    $ 2,420,071     $ 1,452,106  
LIABILITIES AND SHAREHOLDERS' EQUITY
               
Current liabilities:
               
Accounts payable
  $ 150,750     $ 90,354  
Revenue and royalties payable
    35,779       47,181  
Accrued liabilities
    37,284       21,653  
Line of credit
    19,300       14,300  
Income taxes payable
    380       2,591  
Fair value of derivatives
    110,427       95,290  
Total current liabilities
    353,920       271,369  
Long-term liabilities:
               
Deferred income taxes
    206,848       128,824  
Long-term debt
    1,109,300       445,000  
Abandonment obligation
    40,414       36,426  
Unearned revenue
    -       398  
Other long-term liabilities
    6,226       1,657  
Fair value of derivatives
    106,459       108,458  
      1,469,247       720,763  
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; 42,737,029 shares issued and outstanding (42,583,002 in 2007)
    427       425  
Class B Stock, 3,000,000 shares authorized;  1,797,784 shares issued and outstanding (liquidation preference of $899) (1,797,784 in 2007)
    18       18  
Capital in excess of par value
    77,739       66,590  
Accumulated other comprehensive loss
    (130,361 )     (120,704 )
Retained earnings
    649,081       513,645  
Total shareholders' equity
    596,904       459,974  
    $ 2,420,071     $ 1,452,106  
The accompanying notes are an integral part of these financial statements.

 
3

 

BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Income
Three Month Periods Ended September 30, 2008 and 2007
(In Thousands, Except Per Share Data)

   
Three months ended September 30,
   
2008
   
2007
REVENUES AND OTHER INCOME ITEMS
         
Sales of oil and gas
  $ 207,863     $ 118,733    
Sales of electricity
    18,317       12,241    
Gas marketing
    13,284       -    
Gain on sale of assets
    95       1,418    
Interest and other income, net
    1,202       1,108    
      240,761       133,500    
EXPENSES
                 
Operating costs - oil and gas production
    56,038       33,995    
Operating costs - electricity generation
    13,706       9,760    
Production taxes
    9,673       4,344    
Depreciation, depletion & amortization - oil and gas production
    40,440       23,356    
Depreciation, depletion & amortization - electricity generation
    646       938    
Gas marketing
    12,034       -    
General and administrative
    14,524       9,333    
Interest
    8,755       4,326    
Commodity derivatives
    (594 )     -    
Dry hole, abandonment, impairment and exploration
    1,571       5,175    
      156,793       91,227    
Income before income taxes
    83,968       42,273    
Provision for income taxes
    30,620       15,418    
                   
Net income
  $ 53,348     $ 26,855    
                   
Basic net income per share
  $ 1.20     $ .61    
                   
Diluted net income per share
  $ 1.17     $ .60    
                   
Dividends per share
  $ .075     $ .075    
                   
Weighted average number of shares of capital stock outstanding used to calculate basic net income per share
                 
Effect of dilutive securities:
    44,527       44,112    
Equity based compensation
    886       772    
Director deferred compensation
    128       118    
Weighted average number of shares of capital stock used to calculate diluted net income per share
    45,541       45,002    
                   
Unaudited Condensed Statements of Comprehensive Income
   
Three Month Periods Ended September 30, 2008 and 2007
(In Thousands)
Net income
  $ 53,348     $ 26,855    
Unrealized gains (losses) on derivatives, net of income taxes (benefits) of $144,881 and ($7,027), respectively
    225,693       (10,541  
)
Reclassification of realized gains on derivatives included in net income, net of income taxes of $18,745 and $1,411, respectively
    30,584       2,116    
Comprehensive income
  $ 309,625     $ 18,430    
The accompanying notes are an integral part of these financial statements. 


 
4

 

BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Income
Nine Month Periods Ended September 30, 2008 and 2007
(In Thousands, Except Per Share Data)

   
Nine months ended September 30,
   
2008
 
2007
REVENUES AND OTHER INCOME ITEMS
       
Sales of oil and gas
  $ 557,689   $ 333,933  
Sales of electricity
    51,223     40,704  
Gas marketing
    28,046     -  
Gain on sale of assets
    510     51,816  
Interest and other income, net
    4,095     3,754  
      641,563     430,207  
EXPENSES
             
Operating costs - oil and gas production
    152,852     103,330  
Operating costs - electricity generation
    45,620     35,014  
Production taxes
    23,121     12,297  
Depreciation, depletion & amortization - oil and gas production
    96,588     65,478  
Depreciation, depletion & amortization - electricity generation
    1,991     2,661  
Gas marketing
    26,087     -  
General and administrative
    37,067     29,291  
Interest
    16,444     13,593  
Commodity derivatives
    172     -  
Dry hole, abandonment, impairment and exploration
    9,162     9,342  
      409,104     271,006  
Income before income taxes
    232,459     159,201  
Provision for income taxes
    86,939     61,534  
               
Net income
  $ 145,520   $ 97,667  
               
Basic net income per share
  $ 3.27   $ 2.22  
               
Diluted net income per share
  $ 3.20   $ 2.18  
               
Dividends per share
  $ .225   $ .225  
               
Weighted average number of shares of capital stock outstanding used to calculate basic net income per share
    44,466     44,020  
Effect of dilutive securities:
             
Equity based compensation
    914     701  
Director deferred compensation
    126     115  
Weighted average number of shares of capital stock used to calculate diluted net income per share
    45,506     44,836  
               
Unaudited Condensed Statements of Comprehensive Income
 
Nine Month Periods Ended September 30, 2008 and 2007
(In Thousands)
Net income
  $ 145,520   $ 97,667  
Unrealized losses on derivatives, net of income tax benefits of $58,260 and $19,484, respectively
    (95,055 )   (29,226
)
Reclassification of realized gains on derivatives included in net income, net of income taxes of $52,341 and $529, respectively
    85,399     793  
Comprehensive income
  $ 135,864   $ 69,234  
The accompanying notes are an integral part of these financial statements. 

 
5

 

BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Cash Flows
Nine Month Periods Ended September 30, 2008 and 2007
(In Thousands)
   
Nine months ended September 30,
 
   
2008
   
2007
 
Cash flows from operating activities:
           
Net income
  $ 145,520     $ 97,667  
Depreciation, depletion and amortization
    98,579       68,139  
Dry hole and impairment
    6,858       8,725  
Commodity derivatives
    (180 )     804  
Stock-based compensation expense
    6,653       5,437  
Deferred income taxes
    76,502       53,162  
Unrealized loss on ineffective hedges
    172       -  
Gain on sale of oil and gas properties
    (510 )     (51,816 )
Other, net
    (1,500 )     750  
Change in book overdraft
    3,935       (2,995 )
Cash paid for abandonment
    (3,957 )     (660 )
Increase in current assets other than cash and cash equivalents
    (35,361 )     (10,785 )
Increase in current liabilities other than book overdraft, line of credit and fair value of derivatives
    34,537       13,116  
Net cash provided by operating activities
    331,248       181,544  
Cash flows from investing activities:
               
Exploration and development of oil and gas properties
    (302,266 )     (206,240 )
Property acquisitions
    (667,030 )     (56,167 )
Additions to vehicles, drilling rigs and other fixed assets
    (4,146 )     (2,944 )
Proceeds from sale of assets
    2,038       68,432  
Capitalized interest
    (15,461 )     (13,160 )
Net cash used in investing activities
    (986,865 )     (210,079 )
Cash flows from financing activities:
               
Proceeds from issuances on line of credit
    308,000       285,150  
Payments on line of credit
    (303,000 )     (296,650 )
Proceeds from issuance of long-term debt
    1,481,300       179,300  
Payments on long-term debt
    (817,000 )     (134,300 )
Debt issuance cost
    (8,353 )     -  
Dividends paid
    (10,084 )     (10,036 )
Proceeds from stock option exercises
    2,834       3,051  
Excess tax benefit and other
    1,663       1,795  
Net cash provided by financing activities
    655,360       28,310  
                 
Net decrease in cash and cash equivalents
    (257 )     (225 )
Cash and cash equivalents at beginning of year
    316       416  
Cash and cash equivalents at end of period
  $ 59     $ 191  
                 
The accompanying notes are an integral part of these financial statements. 

 
6

 
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, 2008 and December 31, 2007 and results of operations and comprehensive (loss) income and cash flows for the three month and nine month periods ended September 30, 2008 and 2007 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, 2007 financial statements. The December 31, 2007 Form 10-K/A 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, 2008 and December 31, 2007 is $11.7 million and $7.8 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

Certain reclassifications have been made to prior period financial statements to conform them to the current year presentation. Specifically, the change in book overdraft line in the Statements of Cash Flows is classified as an operating activity to reflect the use of these funds in operations, rather than their prior year classification as a financing activity.

In March 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.

The price sensitive royalty that burdens our Formax property in the South Midway Sunset field has changed.  We previously paid a royalty equal to 75% of the amount of the heavy oil posted above a price of $16.11.  This price escalates at 2% annually.  Effective January 1, 2008, the royalty rate is reduced from 75% to 53% as long as we maintain a minimum steam injection level, which we expect to meet, that reduces over time.  Current net production from this property is approximately 2,300 Bbl/D.


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. We do not expect the adoption of this FSP to have a material effect on our financial statements and related disclosures. This FSP is effective for financial statements issued for reporting periods (annual or interim) ending after November 15, 2008, with early application encouraged.

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 interest in a subsidiary (formerly called minority interests) and for the deconsolidation of a subsidiary. We do not expect the adoption of SFAS 160 to have a material effect on our financial statements and related disclosures. The effective date of this Statement is for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.
 
7

 
Berry Petroleum Company
Notes to the Unaudited Condensed 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 interest 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 principle 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).

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. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement will require us to provide the additional disclosures described above.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America (the GAAP hierarchy).  This Statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles, which has not yet occurred.  We do not expect the adoption of SFAS 162 to have a material effect on our financial statements or related disclosures.

3.
Fair Value Measurement

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 as of January 1, 2008.

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.

 
8

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


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.

Assets and liabilities measured at fair value on a recurring basis

September 30, 2008 (in millions)
 
Total carrying value on the condensed Balance Sheet
   
Level 2
   
Level 3
 
                   
Commodity derivatives
    209.8       .9       208.9  
Interest rate swaps
    4.9       4.9       -  
Total liabilities at fair value
    214.7       5.8       208.9  

Changes in Level 3 fair value measurements
The table below includes a rollforward of the 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 September 30, 2008
   
Nine months ended September 30, 2008
 
             
Fair value, beginning of period
  $ 569.6     $ 194.3  
Total realized and unrealized gains and (losses) included in sales of oil and gas
    (370.5 )     31.1  
Purchases, sales and settlements, net
    9.8       (16.5 )
Transfers in and/or out of Level 3
    -       -  
Fair value, September 30, 2008
  $ 208.9     $ 208.9  
                 
Total unrealized gains and (losses) included in income related to financial assets and liabilities still on the condensed balance sheet at September 30, 2008
  $ -     $ -  

In February of 2007, the FASB issued SFAS 159, 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.

4.
Hedging

 
The related cash flow impact of all of our hedges is reflected in cash flows from operating activities. At September 30, 2008, our net fair value of derivatives liability was $214.7 million as compared to $201.6 million at December 31, 2007 which reflects increases in commodity prices in the period. Based on NYMEX strip pricing as of September 30, 2008, we expect to make hedge payments under the existing derivatives of $115.4 million during the next twelve months. At September 30, 2008, Accumulated Other Comprehensive Loss consisted of $130.4 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, 2008. Deferred net losses recorded in Accumulated Other Comprehensive Loss at September 30, 2008 and subsequent mark-to-market changes in the underlying hedging contracts are expected to be reclassified to earnings over the life of these contracts.

We entered into the following natural gas hedges during the three months ended March 31, 2008:
·  
Swaps on 15,400 MMBtu/D at $8.50 for the full year of 2009 and basis swaps on the same volumes for average prices of $1.17, $1.12, $.97, and $1.05 for each of the four quarters of 2009, respectively.

 
9

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


These swaps were not highly effective at inception, so we subsequently entered into basis swaps and established effectiveness at that time.  In 2007, we entered into natural gas swap contracts that were not highly effective.   We recognized an unrealized net gain of approximately $.6 million and an unrealized net loss of $.2 million on the income statement under the caption Commodity derivatives in the three and nine months ended September 30, 2008, respectively.

We entered into the following oil hedges during the three months ended September 30, 2008:

Crude Oil Sales (NYMEX WTI) Collars
 
Average Barrels Per Day
   
Floor/Ceiling Prices
   
Deferred Premium Per Barrel
 
Full year 2009
   
1,000
   
$
100.00 / $163.60    
$
1.00  
Full year 2009
   
1,000
   
$
100.00 / $150.30    
$
-  
Full year 2009
   
1,000
   
$
100.00 / $160.00    
$
2.00  
Full year 2009
   
1,000
    $ 100.00 / $150.00    
$
0.63  
Full year 2009
   
1,000
   
$
100.00 / $157.48    
$
-  
Full year 2010
   
1,000
    $ 100.00 / $161.10    
$
1.00  
Full year 2010
   
1,000
   
$
100.00 / $150.30    
$
-  
Full year 2010
   
1,000
   
$
100.00 / $160.00    
$
2.00  
Full year 2010
   
1,000
   
$
100.00 / $150.00    
$
1.55  
Full year 2010
   
1,000
   
$
100.00 / $158.50    
$
-  

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

Our hedge contracts have been primarily executed with the counterparties that are party to our senior secured revolving credit facility.  The credit rating of each of these counterparties is  AA/Aa2  or better as of September 30, 2008.

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.

Under SFAS 143, the following table summarizes the change in abandonment obligation for the nine months ended September 30, 2008 (in thousands):

Beginning balance at January 1
 
$
36,426
 
Liabilities incurred
   
3,490
 
Liabilities settled
   
(3,957
)
Revisions in estimated liabilities
   
2,006
 
Accretion expense
   
2,449
 
Ending balance at September 30
 
$
40,414
 

6.
Acquisitions and Dispositions

During the third quarter of 2008, Berry completed the acquisition of certain interests in natural gas producing properties on 4,500 net acres in Limestone and Harrison Counties of East Texas for $666 million cash including an initial purchase price of $622 million, and normal post closing adjustments of $44 million.  See the pro forma discussion in Footnote 8 of these financial statements.  As part of the acquisition we assumed commitments for drilling rig contracts and compressor rental agreements which approximate $30 million.  Oil and gas properties increased $921 million or 72% from December 31, 2007 to September 30, 2008 primarily due to this acquisition.
Proceeds from the first quarter 2008 sale of our Prairie Star assets were $1.8 million and are reflected in the Statements of Cash Flows.  The gain from that sale is $.4 million and is reflected in the Statements of Income for the nine month period ended September 30, 2008.


 
10

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


7.
Dry Hole, Abandonment and Impairment

In the first nine months of 2008, we recorded a total of $9.2 million in dry hole, abandonment, impairment and exploration expense.  Charges of $2.7 million, $2.6 million and $1.6 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, $2.3 million of exploration expense was recorded for exploration activities which were primarily 3-D seismic activity in the DJ basin.

 
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 $666 million cash (East Texas Acquisition) including an initial purchase price of $622 million, and normal post closing adjustments of $44 million.

The unaudited pro forma results presented below for the three and nine months ended September 30, 2008 and 2007 have been prepared to give effect to the East Texas Acquisition on the Company’s results of operations under the purchase method of accounting as if it had been consummated on January 1, 2007.  The unaudited pro forma results do not purport to represent the results of 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
   
Three Months Ended
September 30, 2007
   
Nine Months Ended
September 30, 2008
   
Nine Months Ended
September 30, 2007
 
Pro forma revenue
  $ 253,112     $ 142,785     $ 694,269     $ 454,747  
Pro forma income from operations
  $ 91,082     $ 31,035     $ 239,235     $ 124,520  
Pro forma net income
  $ 57,427     $ 20,913     $ 150,423     $ 78,878  
Pro forma basic earnings per share
  $ 1.29     $ 0.47     $ 3.38     $ 1.79  
Pro forma diluted earnings per share
  $ 1.27     $ 0.46     $ 3.31     $ 1.76  

 
The following is a preliminary calculation and allocation of purchase price to the East Texas Acquistion assets and liabilities based on their relative fair values:
 
 
Purchase price (in thousands):
 
As of
September 30, 2008
   
Original purchase price
  $ 622,356    
           
Closing adjustments for property costs, and operating expenses in excess of revenues between the effective date and closing date
    43,811    
           
Total purchase price allocation
  $ 666,167    
           
Preliminary allocation of purchase price (in thousands):
         
Oil and natural gas properties
  $ 651,803  
(i)
Pipeline
    17,288    
           
Total assets acquired
    669,091    
           
Current liabilities
    (1,569 )
(ii)
Asset retirement obligation
    (1,355 )  
           
Net assets acquired
  $ 666,167    
 
(i)  Determined by reserve analysis.
 
 
(ii)  Accrual for royalties payable and transaction costs, which are primarily legal and accounting fees.
 



 
11

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


9.
Income Taxes

The effective tax rate was 36.5% for the third quarter of 2008 compared to 36.8% for the second quarter of 2008 and 36.5% for the third quarter of 2007. 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, 2008, we had a gross liability for uncertain tax benefits of $11.9 million of which $9.6 million, if recognized, would affect the effective tax rate. There were no significant changes to the calculation since year end 2007.  For the nine months ending September 30, 2008, we recognized a net tax benefit of approximately $0.9 million due to the closure of the 2004 federal tax year offset by additional FIN 48 accruals including interest.

Due to the uncertainty about the periods in which 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.

10.
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 with oil and gas properties.  At September 30, 2008 the outstanding balance under this Line of Credit was $19.3 million. Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The weighted average interest rate on outstanding borrowings on the Line of Credit at September 30, 2008 was 5.35%.

In July, 2008, we completed a $100 million senior unsecured credit facility that was to mature on December 31, 2008.  There was no outstanding balance under this credit facility at September 30, 2008 and we terminated it without penalty in October, 2008 (see footnote 12 Subsequent Events in these financial statements).

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 amends and restates the Company’s previous credit agreement dated as of April 28, 2006, as amended.  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.  The borrowing base under the previous agreement was $650 million.  Interest on amounts borrowed under this debt is 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.   Additionally, an annual commitment fee of .25% to .375% is charged on the unused portion of the credit facility.  The deferred costs of approximately $8.2 million associated with the issuance of this credit facility and $.6 million associated with the issuance of the previous credit facility are being amortized over the 5 year life of the Agreement.  $.1 million was charged to the income statement as a loss on debt extinguishment during the third quarter of 2008 related to parties who reduced their commitment or chose not to participate in the Agreement.

The total outstanding debt at September 30, 2008 under the Agreement and the Line of Credit was $910 million and $19 million, respectively, and $8 million in letters of credit have been issued under the facility, leaving $63 million in borrowing capacity available under the Agreement and $100 million available under our $100 million senior unsecured credit facility.  The maximum amount available is subject to annual redetermination of the borrowing base in accordance with the lender’s customary procedures and practices.  Both we and the banks have bilateral right to one additional redetermination each year.  We further amended this credit facility in October 2008 (see Footnote 12 Subsequent Events in these financial statements).

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.  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.


 
12

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


 
Financial Covenants
The senior secured revolving credit facility contains restrictive covenants which, among other things, require us to maintain a debt to EBITDA ratio of not greater than 3.5 to 1.0 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 September 30, 2008.

Interest Rates and Interest Rate Hedges
Additionally, in 2006 we entered into five year interest rate swaps for a fixed rate of approximately 5.5% on $100 million of our outstanding borrowings under our credit facility for five years beginning on September 29, 2006. These interest rate swaps have been designated as cash flow hedges.

The weighted average interest rate on total outstanding borrowings at September 30, 2008 was 5.3%.

11.
Contingencies and Commitments

We have no 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.

We have a crude oil sales contract with an independent refiner for substantially all of our California production for deliveries beginning February 1, 2006 and ending January 31, 2010. After the initial term of the contract, we have a one-year renewal at our option. The per barrel price, calculated on a monthly basis and blended across the various producing locations, is the higher of 1) the WTI NYMEX crude oil price less a fixed differential approximating $8.10, or 2) heavy oil field postings plus a premium of approximately $1.35. The agreement effectively eliminates our exposure to the risk of a widening WTI to California heavy crude price differential over the four year contract term and allows us to effectively hedge our production based on WTI pricing.

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 purchase volume capacity to 5,000 Bbl/D as provided in our contract.  The differential under the contract, which includes transportation and gravity adjustments, is linked to WTI and would range from $15 to $20 per barrel at WTI prices between $60 and $80 per barrel.  Gross oil production averaged approximately 4,150 BOE/D in the quarter ended September 30, 2008.

We have two long-term firm transportation contracts for our Colorado natural gas production 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 $2.0 million for the nine month period ended September 30, 2008.

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

 
Berry Petroleum Company
Notes to the Unaudited Condensed Financial Statements


12.  
Subsequent Events

On October 17, 2008, we amended our $1.5 billion credit facility with the Company’s syndicate of seventeen banks which increased our borrowing base from $1.0 billion to $1.25 billion with current commitments of $1.08 billion and a new maturity date of July 15, 2012.  The amendment includes an accordion feature which allows the Company to increase borrowing commitments to $1.25 billion without further bank approval, and modifies the annual commitment fee and interest rate margins.  Interest on amounts borrowed under the facility is charged at LIBOR or the prime rate plus a margin.  The LIBOR and prime rate margins range between 1.375% and 2.125% based on the ratio of credit outstanding to the borrowing base.  Additionally, an annual commitment fee of .30% to .50% is charged on the unused portion of the credit facility.  We also terminated our $100 million senior unsecured credit facility without penalty that was to mature at December 31, 2008.

 
14

 
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 month periods ended September 30, 2008 and 2007 and our financial condition, liquidity and capital resources as of September 30, 2008. 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
·  
Acquiring additional assets with significant growth potential
·  
Accumulating significant acreage positions near our producing operations
·  
Utilizing joint ventures with respected partners to enter new basins

Notable Third Quarter Items.
·  
Achieved target production averaging 35,150 BOE/D, up 31% from the third quarter of 2007 and up 21% from the second quarter of 2008
·  
Closed on our East Texas acquisition on July 15, 2008, adding approximately 335 Bcfe of proved reserves
·  
Increased Diatomite net production to an average of 2,100 BOE/D, up 24% from the second quarter of 2008
·  
Increased Piceance net average production to 22.7 MMcf/D in the third quarter of 2008, up 37% from the second quarter of 2008
·  
Production at Poso Creek averaged 3,300 Bbl/D, up 3% from the second quarter of 2008
·  
Increased both oil and natural gas production during the quarter with oil production up 9% and natural gas production up 89% from the third quarter of 2007
·  
Amended our credit facility increasing the borrowing base from $600 million to $1 billion
·  
David D. Wolf joined the Company as Executive Vice President and Chief Financial Officer

Notable Items and Expectations for the Fourth Quarter of 2008.
·  
Increased the borrowing base on our senior secured credit facility from $1.0 billion to $1.25 billion with an increase in our commitments to $1.08 billion on October 17, 2008
·  
Reducing drilling activity from 12 rigs to 4 rigs by year-end 2008 with 1 rig in California, 1 rig in the Piceance basin and 2 rigs in East Texas
·  
Targeting a production average of 37,000 to 38,000 BOE/D in the fourth quarter
·  
Planning to takeover operations in East Texas from the seller on November 1, 2008
·  
Anticipating a 2009 Capital budget of approximately $200 million focusing on development of the diatomite and other high return oil projects in California and high impact recompletions in East Texas
·  
Expect proved reserves at year-end to range between 235-245 MMBOE, up over 40% from 169 MMBOE at year-end 2007, with organic growth of 27 MMBOE

Overview of the Third Quarter of 2008. We had net income of $53.3 million, or $1.17 per diluted share and net cash from operations was $137.4 million in the third quarter of 2008. We drilled 118 gross wells and capital expenditures, excluding property acquisitions, totaled $134.8 million. We achieved average production of 35,150 BOE/D in the third quarter of 2008, up 21% from an average of 29,000 BOE/D in the second quarter of 2008.

 
15

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

Results of Operations. The following companywide results are in millions (except per share data) for the three months ended:
   
September 30,  2008
(3Q08)
   
September 30,  2007
(3Q07)
   
3Q07 to 3Q08 Change
   
June 30,  2008
(2Q08)
   
2Q08 to 3Q08 Change
 
Sales of oil
  $ 145     $ 100       45 %   $ 146       (1 %)
Sales of gas
    63       19       232 %     39       62 %
Total sales of oil and gas
  $ 208     $ 119       75 %   $ 185       12 %
Sales of electricity
    18       12       50 %     17       6 %
Gain on sale of assets
    -       2       - %     -       - %
Other revenues
    15       1       1,400 %     13       15 %
Total revenues and other income
  $ 241     $ 134       80 %   $ 215       12 %
Net income
  $ 53     $ 27       96 %   $ 49       8 %
Earnings per share (diluted)
  $ 1.17     $ .60       95 %   $ 1.08       8 %

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, 2008 were flat with the three months ended June 30, 2008 resulting from price decreases of 1% and sales volume increases of 1%. While crude oil production was 3% higher during the quarter, our sales were up 1% due to a build up in our inventory which we expect to draw during the fourth quarter of 2008.  Gas sales in the three months ended September 30, 2008 were 62% higher than the three months ended June 30, 2008 resulting from production increases of 69%, in part due to the East Texas acquisition, and a price decrease of 6%.

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.  
 
   
  
Operating data. The following table is for the three months ended:
   
September 30, 2008
   
%
   
September 30, 2007
   
%
   
June 30, 2008
   
%
 
                                     
Heavy Oil Production (Bbl/D)
    17,264       49       15,806       59       16,888       58  
Light Oil Production (Bbl/D)
    3,898       11       3,675       14       3,723       13  
Total Oil Production (Bbl/D)
    21,162       60       19,481       73       20,611       71  
Natural Gas Production (Mcf/D)
    83,928       40       44,346       27       50,339       29  
Total (BOE/D)
    35,150       100       26,873       100       29,000       100  
                                                 
Oil and gas, per BOE:
                                               
Average sales price before hedging
  $ 80.22             $ 49.35             $ 91.89          
Average sales price after hedging
    64.98               47.93               69.77          
                                                 
Oil, per Bbl:
                                               
Average WTI price
  $ 118.22             $ 75.15             $ 123.80          
Price sensitive royalties
    (5.30 )             (5.50 )             (5.92 )        
Quality differential and other
    (10.80 )             (9.56 )             (11.52 )        
Crude oil hedges
    (26.12 )             (4.37 )             (29.37 )        
Average oil sales price after hedging
  $ 76.00             $ 55.72             $ 76.99          
                                                 
Natural gas price:
                                               
Average Henry Hub price per MMBtu
  $ 10.24             $ 6.24             $ 10.93          
Conversion to Mcf
    .52               .31               .55          
Natural gas hedges
    .15               1.07               (.69 )        
Location, quality differentials and other
    (2.81 )             (3.06 )             (2.15 )        
Average gas sales price after hedging per Mcf
  $ 8.10             $ 4.56             $ 8.64          

 
16

 
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, 2008
   
%
   
September 30, 2007
   
%
 
                         
Heavy Oil Production (Bbl/D)
    16,845       54       16,019       60  
Light Oil Production (Bbl/D)
    3,710       12       3,655       14  
Total Oil Production (Bbl/D)
    20,555       66       19,674       74  
Natural Gas Production (Mcf/D)
    61,201       34       41,109       26  
Total (BOE/D)
    30,755       100       26,525       100  
                                 
Oil and gas, per BOE:
                               
Average sales price before hedging
  $ 82.57             $ 45.98          
Average sales price after hedging
    66.37               45.82          
                                 
Oil, per Bbl:
                               
Average WTI price
  $ 113.52             $ 66.22          
Price sensitive royalties
    (3.36 )             (4.48 )        
Quality differential and other
    (12.90 )             (9.26 )        
Crude oil hedges
    (23.83 )             (1.61 )        
Correction to royalties payable
    1.88               -          
Average oil sales price after hedging
  $ 75.31             $ 50.87          
                                 
Natural gas price:
                               
Average Henry Hub price per MMBtu
  $ 9.74             $ 7.02          
Conversion to Mcf
    .49               .36          
Natural gas hedges
    (.15 )             .67          
Location, quality differentials and other
    (2.01 )             (2.85 )        
Average gas sales price after hedging per Mcf
  $ 8.07             $ 5.20          
                                 


 
17

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


 
Gas Basis Differential.  The basis differential between Henry Hub (HH) and Colorado Interstate Gas (CIG) index increased during the third quarter after decreasing at the start up of the Rockies Express Pipeline (REX) in January.  The differential averaged $4.31 in the third quarter.  In the second quarter of 2008, the CIG basis differential per MMBtu, based upon first-of-month values, averaged $2.45 below HH and ranged from $1.77 to $3.24 below HH.   For the third quarter, the differential averaged $4.31 with the range from $2.19 at the start of the quarter to $6.61 below HH at the end of the quarter. The large September differential was due primarily to maintenance on REX which put a large portion of the pipeline out of service for almost the entire month.  Maintenance was completed and REX was back in service September 28, 2008.  We have contracted a total of 35,000 MMBtu/D on the REX pipeline under two separate transactions to provide firm transportion for our Piceance basin gas production.  After the REX startup in 2008, all of the Piceance basin gas was sold at mid-continent (ANR, NGPL or PEPL) indexes which averaged approximately $1.08 above the CIG index pricing before the cost of transportation.
 
 

Gas from the Uinta basin sold for approximately $.30 below CIG pricing before deducting the cost of pipeline transport.  A portion of the Uinta gas is priced on the Questar index while the remainder is based upon the CIG or NWPL index.

DJ Basin gas is priced using one of two indices. Approximately two-thirds of our volume from our DJ natural gas properties is tied to the Panhandle Eastern Pipeline (PEPL) index for pricing and the remaining volume to CIG pricing. For that portion of the production with firm transportation on either the Cheyenne Plains Pipeline or the KMIGT pipeline, pricing is based upon the PEPL index which averaged approximately $1.91 below the HH index during the third quarter, before the cost of transportation. The remainder of the DJ Basin gas is sold slightly above the CIG index price.

Gas Marketing. We have two long-term (ten year) firm transportation contracts for our Colorado 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 Statements of Income is $2.0 million in the nine month period ended September 30, 2008.

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.


 
18

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


Oil Contracts. California - We have a crude oil sales contract with an independent refiner for substantially all of our California production for deliveries beginning February 1, 2006 and ending January 31, 2010. After the initial term of the contract, we have a one-year renewal at our option. The per barrel price, calculated on a monthly basis and blended across the various producing locations, is the higher of 1) the WTI NYMEX crude oil price less a fixed differential approximating $8.10, or 2) heavy oil field postings plus a premium of approximately $1.35. The agreement effectively eliminates our exposure to the risk of a widening WTI to California heavy crude price differential over the four year contract term and allows us to effectively hedge our production based on WTI pricing.

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 4,150 BOE/D in the quarter ended September 30, 2008. The differential under the contract, which includes transportation and gravity adjustments, is linked to WTI and would range from $15 to $20 per barrel at WTI prices between $60 and $80. This contract provides us an outlet to sell all of our current oil production in the Uinta basin.

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.

In 2007, our electricity operations improved partially from the lower cost of our firm transportation natural gas compared to California prices which are used to determine our electricity payment. 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 differential between Rocky Mountain gas prices and Southern California Border prices increased during 2007 allowing us to purchase a portion of our gas at a discount to the Southern California Border price. As our electricity revenue is linked to Southern California Border prices, the fuel we purchased at lower Rocky Mountain prices was the primary contributor to the increase in our electricity margin in 2007. We purchased approximately 38,000 MMBtu/D as fuel for use in our cogeneration facilities in the year ended December 31, 2007.

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 third quarter of 2008, our margin on electricity increased to $4.6 million.  Approximately $2 million of this margin was due to lower Rockies gas prices when compared to Southern California border prices and $2.4 million of this change was due to seasonal capacity payments the Company receives during the summer months.

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 has been appealed to the Court of Appeal.  We do not believe that the proposed  pricing changes will materially affect us in 2008. 


 
19

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


The following table is for the three months ended:

   
September 30,  2008
 
September 30,  2007
   
June 30,  2008
 
Electricity
               
Revenues (in millions)
$
18.3
$
12.3
 
$
17.0
 
Operating costs (in millions)
$
13.7
$
9.8
 
$
15.5
 
Electric power produced - MWh/D
 
2,096
 
2,257
   
1,919
 
Electric power sold - MWh/D
 
1,908
 
2,077
   
1,724
 
Average sales price/MWh
$
104.91
$
71.28
 
$
108.21
 
Fuel gas cost/MMBtu (including transportation)
$
8.20
$
4.84
 
$
10.01
 

Oil and Gas Operating, Production Taxes, G&A and Interest Expenses. The following table presents information about our operating expenses for each of the three month periods ended:
 
   
Amount per BOE
   
Amount (in thousands)
 
   
September 30, 2008
   
September 30, 2007
   
June 30,
 2008
   
September 30, 2008
   
September 30, 2007
   
June 30,  2008
 
Operating costs – oil and gas production
  $ 17.33     $ 13.75     $ 20.91     $ 56,038     $ 33,995     $ 55,185  
Production taxes
    2.99       1.76       2.83       9,673       4,344       7,481  
DD&A – oil and gas production
    12.51       9.45       11.02       40,440       23,356       29,073  
G&A
    4.49       3.78       4.23       14,524       9,333       11,160  
Interest expense
    2.71       1.75       1.50       8,755       4,326       3,951  
Total
  $ 40.03     $ 30.49     $ 40.49     $ 129,430     $ 75,354     $ 106,850  

Our total operating costs, production taxes, DD&A, G&A and interest expenses for the three months ended September 30, 2008, stated on a unit-of-production basis, increased 32% over the three months ended September 30, 2007 and decreased 1% as compared to the three months ended June 30, 2008. The changes were primarily related to the following items:

 
·
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:

   
September 30,  2008
(3Q08)
   
September 30, 2007
(3Q07)
   
3Q07
to 3Q08 Change
   
June 30,  2008
(2Q08)
   
2Q08 to 3Q08 Change
 
Average volume of steam injected (Bbl/D)
    105,574       88,711       19 %     97,853       8 %
Fuel gas cost/MMBtu (including transportation)
  $ 8.20     $ 4.84       69 %   $ 10.01       (18 %)
Approximate net fuel gas volume consumed in steam generation (MMBtu/D)
    29,362       23,348       26 %     27,382       7 %

Operating costs increased by $1 million or 2% between the second and third quarters of 2008.  The East Texas Acquisition increased our total operating costs on a nominal basis with the impact of decreasing per barrel costs as these natural gas assets have lower per barrel operating costs.  This increase was offset by a $4 million decrease in fuel gas costs due to a decrease in natural gas prices offset by increased fuel gas consumption.  Our total cost to purchase fuel for our steam operations decreased by $1.81 per MMBtu or 18% in the three months ended September 30, 2008 compared to the three months ended June 30, 2008 as the SoCal border natural gas price decreased over this time period.  We plan to increase our fuel gas consumption by 3,000 MMBtu/D in the fourth quarter of 2008 as we add additional steam generation capacity at Poso Creek and the Diatomite.

 
20

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


·  
Production taxes: Our production taxes have increased compared to the third quarter of 2007 as commodity prices and thus the value of our oil and natural gas has increased.  The increase from the second quarter of 2008 is primarily due to an increase in the assessed value of our properties in California.   Severance taxes paid in Utah, Colorado and Texas are directly related to the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves. We expect production taxes to fluctuate with oil and gas prices.

·  
Depreciation, depletion and amortization: DD&A increased per BOE by 32% and 14% in the third quarter of 2008 as compared to the third quarter of 2007 and as compared to the second quarter of 2008, respectively, due to an increase in the contribution of our development properties with higher drilling and leasehold acquisition costs and the integration of our East Texas assets which have higher finding and development costs than our legacy assets.

·  
General and administrative: Approximately 70% of our G&A is related to compensation. The primary reason for the increase in G&A during the third quarter of 2008 as compared to the third quarter of 2007 was due to due to additional staffing and the costs associated with the 2008 relocation of our corporate office from Bakersfield, California to Denver, Colorado.

·  
Interest expense: Our total outstanding borrowings were approximately $1.1 billion at September 30, 2008 compared to $440 million and $511 million at September 30, 2007 and June 30, 2008, respectively. Our average borrowings increased since June 30, 2008 primarily due to the East Texas acquisition in the third quarter of 2008.  For the three months ended September 30, 2008, $7 million of interest cost has been capitalized and we expect to capitalize approximately $23 million of interest cost during the full year of 2008.

Estimated 2008 and Actual Nine Months Ended September 30, 2008 and 2007 Oil and Gas Operating, G&A and Interest Expenses. Based upon our reduced activity in the fourth quarter of 2008, we estimate our average 2008 production volume will range between 32,000 BOE/D and 33,000 BOE/D.
 
   
Anticipated range
Full Year 2008
per BOE
   
Nine months ended
September 30, 2008
   
Nine months ended
 September 30, 2007
 
Operating costs-oil and gas production
  $ 17.00 to 19.00     $ 18.14     $ 14.27  
Production taxes
 
2.50 to 3.00
      2.74       1.70  
DD&A – oil and gas production (1)
 
11.75 to 12.25
      11.46       9.04  
G&A
 
4.00 to 4.50
      4.40       4.05  
Interest expense
 
1.50 to 2.00
      1.95       1.88  
Total
  $ 36.75 to 40.75     $ 38.69     $ 30.94  
(1) Full year estimate includes both oil and gas and electricity

Our total operating costs, production taxes, DD&A, G&A and interest expenses for the nine months ended September 30, 2008, stated on a unit-of-production basis, increased 25% over the nine months ended September 30, 2007. The changes were primarily related to the following items:

 
·
Operating costs: The majority of the increase in our operating costs was due to higher steam costs resulting from higher fuel costs. The following table presents steam information:

   
Nine months ended
 September 30, 2008
   
Nine months ended
 September 30, 2007
   
Change
 
Average volume of steam injected (Bbl/D)
    98,050       86,157       14 %
Fuel gas cost/MMBtu (including transportation)
  $ 8.70     $ 5.78       51 %
Approximate net fuel gas volume consumed in
  steam generation (MMBtu/D)
    26,128       21,698       20 %

Our total cost to purchase fuel for our steam operations increased by $2.92 per MMBtu or 51% in the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 as the SoCal border natural gas price increased over this time period.  We consumed an additional 4,430 MMBtus per day in the first nine months of 2008 when compared to the first nine months of 2007 primarily related to increased conventional steam generation consumption.

 
21

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


·  
Production taxes: Production taxes per BOE in the nine months ended September 30, 2008 were 61% higher than the comparable period in 2007 as commodity prices and thus the value of our oil and natural gas has increased. Severance taxes paid in Utah, Colorado and Texas are directly related to the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves.

·  
Depreciation, depletion and amortization: DD&A per BOE was 27% higher in the nine months ended September 30, 2008 compared to the same period in the prior year due to an increase in the contribution of our development properties with higher drilling and leasehold acquisition costs and the integration of our East Texas acquisition.

·  
General and administrative: G&A per BOE increased by 9% in the nine months ended September 30, 2008 compared to the same period in the prior year due to additional staffing and higher overall compensation costs associated with our growth activities and the relocation of our corporate headquarters.

·  
Interest expense: Our total outstanding borrowings was approximately $1.1 billion at September 30, 2008 compared to approximately $440 million at September 30, 2007. Our average borrowings increased since September 30, 2007 primarily due to the East Texas acquisition in the third quarter of 2008.  For the nine months ended September 30, 2008, $16 million of interest cost has been capitalized.

Royalties.  The price sensitive royalty that impacts our Formax property in the South Midway Sunset field has changed.  We previously paid a royalty equal to 75% of the amount of the heavy oil posted above a price of $16.11.  This price escalates at 2% annually.  Effective January 1, 2008, the royalty rate is reduced from 75% to 53% as long as we maintain a minimum steam injection level, which we expect to meet, that reduces over time.  Current net production from this property is approximately 2,300 Bbl/D.

Dry Hole, Abandonment, impairment and exploration.  In the first nine months of 2008, we recorded a total of $9.2 million in dry hole, abandonment, impairment and exploration expense.  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, $2.3 million of exploration expense was recorded for exploration activities which were primarily 3-D seismic activity in the DJ basin.

Income Taxes. We experienced an effective tax rate of 36.5% in both the three months ended September 30, 2008 and the three months ended September 30, 2007.  Our rate differs from the combined federal and state statutory tax rate (net of the federal benefit), primarily due to certain business incentives. See Note 9 to the unaudited condensed financial statements.

Development, Exploitation and Exploration Activity. We drilled 118 gross (101 net) wells during the third quarter of 2008.

Drilling Activity. The following table sets forth certain information regarding drilling activities (including operated and non-operated wells):
 
   
Three months ended
September 30, 2008
   
Nine months ended
 September 30, 2008
 
Asset Team
 
Gross Wells
   
Net Wells
   
Gross Wells
   
Net Wells
 
S. Midway
    11       11       68       68  
N. Midway
    23       23       92       92  
S. Cal
    -       -       25       25  
Piceance
    26       16       65       37  
Uinta
    16       16       45       45  
DJ
    33       26       79       65  
Texas
    9       9       9       9  
Totals
    118       101       383       341  


 
22

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


Properties

Asset Team Descriptions

S. Midway – During the three months ended September 30, 2008, production averaged approximately 8,950 Bbl/D compared to approximately 9,350 Bbl/D and 9,100 Bbl/D during the three month periods ended September 30, 2007 and June 30, 2008, respectively. In 2008 we drilled 18 deeper horizontal wells in the reservoir. This series of horizontal wells, coupled with targeted steam placement, has helped offset the natural decline of the mature resource.  In addition we drilled two horizontal wells on the Formax property following the renegotiation of the price sensitive royalty.  In 2008, we also began developing the Monarch reservoir on our Ethel D property.  We drilled 32 wells in the Monarch in the first nine months of the year and production averaged 1,200 Bbl/D using cyclic steam injection.  We believe that Ethel D production can be further enhanced through a steamflood and we will be expanding the pilot we began in 2007 later this year.

N. Midway – During the three months ended September 30, 2008, production from the area averaged approximately 3,000 Bbl/D compared to approximately 2,200 Bbl/D and 2,600 Bbl/D during the three month periods ended September 30, 2007 and June 30, 2008, respectively. In October 2007, we embarked on a full-scale, continuous development program of the Diatomite and we expect to drill continuously over the next four years. Over 98 new producers have been drilled since October 2007. We are bringing these wells on production as the necessary infrastructure is installed to steam and produce these wells.  The additional wells, steam and supporting infrastructure has enabled us to increase production of the Diatomite which averaged 1,700 BOE/D during the second quarter of 2008 to over 2,100 BOE/D during the third quarter of 2008.

S. Cal – During the three months ended September 30, 2008, production averaged approximately 5,350 Bbl/D compared to approximately 4,300 Bbl/D and 5,300 Bbl/D during the three month periods ended September 30, 2007 and June 30, 2008, respectively. This year’s plans at Poso Creek call for further expansion including the addition of a fourth steam generator, which we brought on line in February, drilling 28 producers and expanding the steam flood. As of September 2008, all 28 planned producers have been drilled and Poso Creek production is currently averaging 3,300 BOE/D. During the fourth quarter of 2008, additional steam injectors will be drilled and a fifth steam generator will be installed to further increase our production from this asset.

Piceance – During the three months ended September 30, 2008, production from the Piceance basin averaged 22.7 MMcf/D, an increase of 37% from the prior quarter. Of the Company operated wells, we drilled 26 gross wells (16 net) during the third quarter of 2008. We have drilled over 130 wells since we acquired our original Piceance basin acreage in early 2006. We are currently operating two drilling rigs and continue to realize further efficiencies with repeated drilling times reduced to 9 to 13 days for a mesa well.  Throughout the third quarter of 2008, we realized increasing production from the summer completion season with current production now over 30 MMcf/D.  Initial production rates from these wells have been in line with our expectations.

Uinta Average daily production during the three months ended September 30, 2008 from all Uinta basin assets was approximately 6,400 BOE/D, an increase of 6% from the prior quarter. During the three months ended September 30, 2008, we returned to a one rig drilling program at Brundage Canyon following the temporary operation of two drilling rigs during the prior quarter.  The development at Brundage Canyon continues to be focused on drilling high potential areas in the core of the field where we drilled 11 wells in the third quarter of 2008.  Evaluating the waterflood feasibility at Brundage Canyon has progressed and we anticipate receiving regulatory approval before year-end with first injection in early 2009. During the third quarter of 2008, we further delineated the Ashley Forest by drilling 4 wells under our existing environmental approvals and currently we are drilling the 8th and final well of our 2008 Ashley Forest program.  We continue to optimize and pace our Uinta drilling program while the Ashley Forest Development EIS progresses towards its anticipated approval in early 2009. 

DJ During the three months ended September 30, 2008, we drilled 33 gross Niobrara development wells in Yuma County, Colorado, with a 100% success rate. Average daily production in the DJ basin for the three months ended September 30, 2008 was 20 MMcf/D.  Earlier this year we completed the interpretation of an additional 75 square miles of 3-D seismic that we acquired over the winter.  The seismic surveys replenished our low risk repeatable drilling inventory and we are currently permitting many of those drilling locations for our 2009 capital program.


 
23

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


East Texas – On July 15, 2008, we acquired certain interests in natural gas producing properties on 4,500 net acres in Limestone and Harrison Counties in East Texas. We have assembled our asset team and plan to take over operations from the seller on November 1, 2008.  Production should increase from its current level of approximately 30 MMcf/d as our team transitions field, drilling and completion operations.  We drilled 9 wells on the property during the quarter and have brought 2 of these wells on production.  We plan to drill approximately 8 wells during the fourth quarter and complete the remaining wells drilled during the third quarter of 2008.   We have drilled four vertical Haynesville appraisal wells which demonstrate productivity to support a horizontal development of this resource.  We expect to drill our first Haynesville horizontal well during the first half of 2009.

Financial Condition, Liquidity and Capital Resources.  Substantial capital is required to replace and grow reserves. We achieve reserve replacement and growth primarily through successful development and exploration drilling and the acquisition of properties. Fluctuations in commodity prices, production rates and operating expenses have been the primary reason for changes in our cash flow from operating activities.

We had a senior unsecured revolving bank credit facility agreement (the Agreement) with a banking syndicate through June 30, 2011. The Agreement was a revolving credit facility for up to $750 million with a borrowing base as of June 30, 2008 of $600 million.  As of June 30, 2008, we had total borrowings under the Agreement and Line of Credit of $311 million and $200 million under our senior subordinated ten year notes.

On July 15, 2008, we entered into a five-year amended and restated secured credit agreement (the Credit Agreement) with Wells Fargo Bank, N.A as administrative agent and other lenders.  The total outstanding debt at September 30, 2008 under the Agreement and the short-term Line of Credit was $910 million and $19 million, respectively, and $8 million in letters of credit have been issued under the facility leaving $63 million in borrowing capacity available under the Agreement and $100 million available under our $100 million senior unsecured credit facility.

 On October 17, 2008, we amended our $1.5 billion Credit Agreement with the Company’s syndicate of seventeen banks which increased our borrowing base from $1.0 billion to $1.25 billion with current commitments of $1.08 billion and a new maturity date of July 15, 2012.  The amendment includes an accordion feature which allows the Company to increase borrowing commitments to $1.25 billion without further bank approval, and modifies the annual commitment fee and interest rate margins.   As of October 27, 2008 we had $144 million in borrowing capacity available.  The maximum amount available is subject to a semi-annual redetermination of the borrowing base in accordance with the lender's customary procedures and practices. Both we and the banks have bilateral rights to one additional redetermination each year.

Capital Expenditures. We establish a capital budget for each calendar year based on our development opportunities and the expected cash flow from operations for that year. Acquisitions are typically debt financed. We may revise our capital budget during the year as a result of acquisitions and/or drilling outcomes or significant changes in cash flows.

In 2008, we had an original capital program of approximately $295 million, excluding acquisitions. The capital development program was increased by $75 million during the second quarter of 2008 in conjunction with the East Texas Acquisition to a total of $370 million.  Increases in steel prices and other services will likely result in total capital spending for the full year 2008 of approximately $400 million.  While we have reduced our activity during the fourth quarter of 2008, we do not expect to see the results of this reduction until early in the first quarter of 2009 as we complete projects and release rigs after contractual commitments are complete.  Excess cash generated from operations is expected to be applied toward acquisitions, debt reduction or other corporate purposes.
Capital expenditures, excluding property acquisitions, totaled $135 million and $306 million during the three and nine months ended September 30, 2008, respectively.

Working Capital and Cash Flows. Cash flow from operations is dependent upon the price of crude oil and natural gas and our ability to increase production and manage costs. Our working capital balance fluctuates as a result of the amount of borrowings and the timing of repayments under our credit arrangements. We use our long-term borrowings under our credit facility primarily to fund property acquisitions. Generally, we use excess cash to pay down borrowings under our credit arrangement. As a result, we often have a working capital deficit or a relatively small amount of positive working capital.


 
24

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


The table below compares financial condition, liquidity and capital resources changes for the three month periods ended (in millions, except for production and average prices):
   
September 30,  2008
(3Q08)
   
September 30, 2007
(3Q07)
   
3Q07 to 3Q08
Change
   
June 30,  2008
(2Q08)
   
2Q08 to 3Q08
 Change
 
Average production (BOE/D)
    35,150       26,873       31 %     29,000       21 %
Average oil and gas sales prices, per BOE after hedging
  $ 64.98     $ 47.93       36 %   $ 69.77       (7 )%
Net cash provided by operating activities (1)
  $ 137     $ 93       47 %   $ 107       28 %
Working capital
  $ (148 )   $ (91 )     (63 )%   $ (225 )     34 %
Sales of oil and gas
  $ 208     $ 119       75 %   $ 185       12 %
Total debt
  $ 1,129     $ 440       157 %   $ 511       1,21 %
Capital expenditures, including acquisitions and deposits on acquisitions
  $ 742     $ 63       1,078 %   $ 154       382 %
Dividends paid
  $ 3.4     $ 3.4       - %   $ 3.4       - %
(1)  
The change in the book overdraft line in the Statements of Cash Flows is classified as an operating activity to reflect the use of these funds in operations, rather than their prior year classification as a financing activity.

Contractual Obligations. Our contractual obligations as of September 30, 2008 are as follows (in millions):

   
Total
   
2008
   
2009
   
2010
   
2011
   
2012
   
Thereafter
 
Total debt and interest
  $ 1,524.7     $ 37.7     $ 70.6     $ 70.6     $ 70.6     $ 70.6     $ 1,204.6  
Abandonment obligations
    40.4       .4       1.7       1.7       1.6       1.6       33.4  
Operating lease obligations
    17.5       .6       2.3       2.3       2.3       2.3       7.7  
Drilling and rig obligations
    74.4       12.4       27.6       15.0       19.4       -       -  
Firm natural gas
                                                       
    transportation contracts
    161.9       3.9       19.5       19.5       19.5       19.1       80.4  
Total
  $ 1,818.9     $ 55.0     $ 121.7     $ 109.1     $ 113.4     $ 93.6     $ 1,326.1  

Drilling obligations - - Under our June 2006 joint venture agreement in the Piceance basin we are required to have 120 wells drilled by February 2011 to avoid penalties of $.2 million per well or a maximum of $24 million. As of September 30, 2008 we have drilled 29 of these wells and we expect to meet our obligation to have the remaining wells drilled by February 2011.

Other Obligations - We adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no material adjustment to retained earnings. As of September 30, 2008, we had a gross liability for uncertain tax benefits of $11.9 million of which $9.6 million, if recognized, would affect the effective tax rate.

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, as provided in our contract.  The refiner has increased its total purchase capacity to 5,000 Bbl/D as provided in our contract. The differential under the contract, which includes transportation and gravity adjustments, is linked to WTI and would range from $15 to $20 per barrel at WTI prices between $60 and $80.  Gross oil production averaged approximately 4,150 BOE/D in the quarter ended September 30, 2008.


 
25

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



 
Item 3.  Quantitative and Qualitative Disclosures About Market Risk

As discussed in Note 4 to the unaudited condensed financial statements, 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. In California, we benefit from lower natural gas pricing as we are a consumer of natural gas in our operations and elsewhere, 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.