Berry Petroleum Company (NYSE:BRY) Form 10-K for the period ended December 31, 2005


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

FORM 10-K
 
x Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2005
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)
 
5201 Truxtun Avenue, Suite 300
Bakersfield, California 93309
(Address of principal executive offices, including zip code)

Registrant's telephone number, including area code:   (661) 616-3900

Securities registered pursuant to Section 12(b) of the Act:
 
 
Title of each class
 
 Name of each exchange on which registered
 
 
Class A Common Stock, $.01 par value
 
New York Stock Exchange
 
 
(including associated stock purchase rights)
 
 
 

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
YES x NO o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
YES o NO x
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filerx  Accelerated filero  Non-accelerated filero
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 June 30, 2005, the aggregate market value of the voting and non-voting common stock held by non-affiliates was $962,312,197. As of February 10, 2006, the registrant had 21,077,915 shares of Class A Common Stock outstanding. The registrant also had 898,892 shares of Class B Stock outstanding on February 10, 2006 all of which is held by an affiliate of the registrant.

DOCUMENTS INCORPORATED BY REFERENCE

Part III is incorporated by reference from the registrant's definitive Proxy Statement for its Annual Meeting of Shareholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant's fiscal year.
 



Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents 

     
BERRY PETROLEUM COMPANY
TABLE OF CONTENTS
PART I
 
 
 
Page
Business
3
 
General
3
 
Crude Oil and Natural Gas Marketing
4
 
Steaming Operations
6
 
Electricity
7
 
Competition
8
 
Employees
8
 
Oil and Gas Properties
8
 
Capital Expenditures
12
 
Production
13
 
Acreage and Wells
13
 
Drilling Activity
14
 
Environmental and Other Regulations
14
 
Forward Looking Statements
15
Risk Factors
16
Unresolved Staff Comments
21
Properties
21
Legal Proceedings
21
Submission of Matters to a Vote of Security Holders
21
 
Executive Officers
21
 
 
 
 PART II
 
 
 
Market for the Registrant's Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities
22
Selected Financial Data
24
Management's Discussion and Analysis of Financial Condition and Results of Operations
26
Quantitative and Qualitative Disclosures About Market Risk
39
Financial Statements and Supplementary Data
41
   43
   44
   45
   46
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
67
Controls and Procedures
67
Other Information
68
 
 
 
PART III
 
 
 
Directors and Executive Officers of the Registrant
69
Executive Compensation
69
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
69
Certain Relationships and Related Transactions
69
Principal Accounting Fees and Services
69
 
 
 
PART IV
 
 
 
Exhibits, Financial Statement Schedules
69

 

2

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



PART I

Item 1. Business

General. Berry Petroleum Company, (Berry or Company), is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. While the Company was incorporated in Delaware in 1985 and has been a publicly traded company since 1987, it can trace its roots in California oil production back to 1909. Currently, Berry's principal reserves and producing properties are located in California, Utah and Colorado. The Company has its corporate headquarters in Bakersfield, California and a regional office in Denver, Colorado. The Company is increasing office space in both locations to accommodate growth. Information contained in this report on Form 10-K reflects the business of the Company during the year ended December 31, 2005 unless noted otherwise.

The Company’s website is located at http://www.bry.com. The website can be used to access recent news releases and Securities and Exchange Commission (SEC) filings, crude oil price postings, the Company’s Annual Report, Proxy Statement, Board committee charters, code of business conduct and ethics, the code of ethics for senior financial officers, and other items of interest. SEC filings, including supplemental schedules and exhibits, can also be accessed free of charge through the SEC website at http://www.sec.gov.

Corporate Strategy. Berry Petroleum Company’s mission is to increase shareholder value, primarily through increasing the net asset value, and maximizing the cash flow and earnings of the Company's assets. The strategies to accomplish these goals include:
·  
Growing production and reserves from existing assets while managing expenses - The Company intends to increase production and reserves annually and increase both net income and cash flow in total and per share. The Company will continue to focus on the further development of its properties through developmental drilling, down-spacing, well completions, remedial work and by application of enhanced oil recovery (EOR) methods, and optimization technologies, as applicable. With respect to the California heavy oil reserves, the Company owns three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the economic production of heavy oil.
·  
Acquiring more light oil and natural gas assets with significant growth potential in the Rocky Mountain and Mid-Continent region - The Company will compete to acquire oil and gas properties with proved reserves, probable reserves and/or sizeable acreage positions that the Company believes contain substantial reserves which can be developed at reasonable costs. As part of its resource diversification strategy, Berry desires to add natural gas production and reserves to complement its significant crude oil resource base. The Company has identified the Rocky Mountain and Mid-Continent region as its primary areas of interest for diversification.
·  
Appraising the Company’s exploitation and exploration projects in an expedient manner - The Company has been successful in adding significant acreage positions in the last two years with the intent of drilling exploration wells to test the potential of the acreage for the economic production of hydrocarbons. Its goal is to appraise this potential as quickly as is prudently possible.
·  
Investing the Company’s capital in an efficient, disciplined manner - Investing the Company’s capital prudently is of paramount importance in achieving long-term success. The oil and gas business is very capital intensive so managing the business with a focus on utilizing the available capital on projects where it is likely to have success in increasing production and/or reserves at attractive returns to shareholders. A portion of the Company’s capital will be directed to higher risk projects that have the potential for higher reward.
·  
Utilizing joint ventures with respected partners to enter new basins - The Company believes that it is beneficial to utilize the skills and knowledge of other industry participants upon entering new basins or areas of operations as it can reduce the risk and improve the success in the area.

Berry has the industry talent, experience, organization and motivation to accomplish the above strategies to fulfill its mission of increasing shareholder value. Berry also has the financial capacity and skill sets to accomplish these strategies. In addition to internally generated funds, it has a $500 million unsecured credit facility with a current borrowing base of $350 million which may be utilized in adding prospective acreage, reserves and/or production through acquisitions.

Proved Reserves and Revenues. As of December 31, 2005, the Company's estimated proved reserves were 126 million barrels of oil equivalent, (BOE), of which 74% are heavy crude oil, 8% light crude oil and 18% natural gas. Nearly 40% of reserves are owned in fee. Geographically, 74% of the Company’s reserves are located in California and 26% in the Rocky Mountain and Mid-Continent region. Proved undeveloped reserves make up 28% of the Company's proved total. The projected capital to develop these proved undeveloped reserves is $201million, at an estimated cost of approximately $5.54 per BOE. Approximately 77% of the capital to develop these reserves is expected to be expended in the next five years. Production in 2005 was 8.4 million BOE, up 12% from production of 7.5 million BOE in 2004. The Company’s reserves-to-production ratio was unchanged at 14.6 years at year-end 2005, compared to year-end 2004.



3

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents


The following table depicts all of the Company’s producing assets as of December 31, 2005. Berry operates all of the assets, except Wyoming:

State
Name
Type
Daily Production (BOE/D)
% of Daily Production
Proved Reserves (BOE) in thousands
% of Proved Reserves
Oil & Gas Revenues before hedging (in millions)
% of Oil & Gas Revenues
 
CA
Midway-Sunset
Heavy oil
12,214
53%
68,071
54%
$ 199
50%
 
UT
Brundage Canyon
Light oil/Natural gas
5,079
22
15,116
12
98
25
 
CA
Placerita
Heavy oil
2,654
12
16,592
13
48
12
 
CO
Tri-State
Natural gas
1,600
7
17,442
14
26
7
 
CA
Montalvo
Heavy oil
728
3
6,869
5
12
3
 
CA
Poso Creek
Heavy oil
544
2
2,046
2
10
3
 
WY/CA
Various
Various
196
1
149
-
2
-
 
Totals
   
23,015
100%
126,285
100%
$ 395
100%
 

The Company continued to engage DeGolyer and MacNaughton (D&M) to appraise the extent and value of its proved oil and gas reserves and the future net revenues to be derived from properties of the Company for the year ended December 31, 2005. D&M is an independent oil and gas consulting firm located in Dallas, Texas. In preparing their reports, D&M reviewed and examined geologic, economic, engineering and other data considered applicable to properly determine the reserves of the Company. They also examined the reasonableness of certain economic assumptions regarding forecasted operating and development costs and recovery rates in light of the economic environment on December 31, 2005. See Supplemental Information About Oil & Gas Producing Activities (Unaudited) for the Company's oil and gas reserve disclosures.

Acquisitions. See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Operations. In California, Berry operates all of its principal oil and gas producing properties. The Midway-Sunset, Placerita and Poso Creek fields contain predominantly heavy crude oil which requires heat, supplied in the form of steam, injected into the oil producing formations to reduce the oil viscosity which allows the oil to flow to the wellbore for production. Berry utilizes cyclic steam and/or steam flood recovery methods in all of these fields in addition to primary recovery methods at its Montalvo field. Berry is able to produce its heavy oil at its Montalvo field without steam since the majority of the producing reservoir is at a depth in excess of 11,000 feet and the reservoir temperature is high enough to produce the oil without the assistance of additional heat from steam. Field operations related to oil production include the initial recovery of the crude oil and its transport through treating facilities into storage tanks. After the treating process is completed, which includes removal of water and solids by mechanical, thermal and chemical processes, the crude oil is metered through automatic custody transfer units or gauged before sale and subsequently transferred into crude oil pipelines owned by other companies or transported via truck.

In the Rocky Mountain and Mid-Continent region, crude oil produced from the Brundage Canyon field is transported by truck, while its gas production, net of field usage, is transported by gathering or distribution systems to the Questar Pipeline. Natural gas produced from the eastern Colorado Niobrara gas assets is transported by Company and third party gathering lines to one of two main pipelines. The Company has a pipeline gathering system and gas compression facilities for delivery into these two interstate gas lines in this region.

Crude Oil and Natural Gas Marketing

Economy. The global and California crude oil markets continue to remain strong. Product prices continued to exhibit an overall-strengthening trend through 2005. The range of West Texas Intermediate (WTI) crude prices for 2005, based upon NYMEX settlements, was a low of $42.12 and a high of $69.81. The Company expects that crude prices will continue to be volatile in 2006.

 
 
2005
 
2004
 
2003
 
Average NYMEX settlement price for WTI
 
$
56.70
 
$
41.47
 
$
30.99
 
Average posted price for Berry’s:
 
 
               
Utah light crude oil
   
53.03
 
 
38.60
 
 
27.63
 
California 13 degree API heavy crude oil
 
 
44.36
 
 
32.84
 
 
25.33
 
Average crude price differential between WTI and Berry’s:
                   
Utah light crude oil
 
 
3.67
   
2.87
   
3.36
 
California 13 degree API heavy crude oil
   
12.34
 
 
8.63
 
 
5.66
 


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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



The above posting prices and differentials are not necessarily amounts paid or received by the Company due to the contracts discussed below. While the crude oil price differential between WTI and California’s heavy crude was fairly consistent with historical averages in 2003 at just under $6.00 per barrel, the differential widened dramatically during 2004 and 2005. On December 31, 2005 the differential was $11.61 and ranged from a low of $10.27 to a high of $14.83 per barrel during the year. Crude oil price differentials between WTI and Utah’s light crude oil were fairly consistent during 2003, 2004 and 2005 and were between $3 and $5 per barrel. On December 31, 2005 the differential was $4.67 and ranged from a low of $3.73 to a high of $4.77 per barrel during the year.

Oil Contracts. Berry markets its crude oil production to competing buyers including independent and major oil refining companies. Because of the Company’s ability to deliver significant volumes of crude oil over a multi-year period, the Company secured a three-year sales agreement, beginning in late 2002, with a major oil company whereby the Company sold over 90% of its California production under a negotiated pricing mechanism. This contract ended on January 31, 2006. Pricing in this agreement was based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential near $6.00 per barrel. This contract allowed the Company to improve its California revenues over the posted price by approximately $41 million and $13 million in 2005 and 2004, respectively.

On November 21, 2005, the Company entered into a new crude oil sales contract for its California production for deliveries beginning February 1, 2006 and ending January 31, 2010. 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 $8.15, or 2) heavy oil field postings plus a premium of approximately $1.35. The initial term of the contract is for four years with a one-year renewal at the Company’s option. The agreement effectively eliminates the Company’s exposure to the risk of a widening WTI to California heavy crude price differential over the next four years and allows the Company to effectively hedge its production based on WTI pricing similar to the previous contract. If this contract had been in place during 2005, it would have allowed the Company to improve its California revenues over the posted prices by approximately $25 million in 2005, but $16 million below what was actually received by the Company under the contract in place in 2005.

Brundage Canyon crude oil production, which is approximately 40 degree API gravity, is sold under contract at WTI less a fixed differential approximating $2.00 per barrel. This contract expires on September 30, 2006. Any new contract will be negotiated based on market prices. The Company believes the differential has widened by several dollars per barrel. The majority of this crude oil, while light, is a “paraffinic” crude, and can be processed efficiently by only a limited number of stranded inland refineries. The production of this type crude is increasing regionally and beginning to strain the capacity of these refineries. Other new crude sources from the region are pressuring pricing. If these refineries limit the volumes of this parraffinic crude oil they are willing to process, it could impact the marketability of this type of crude which, for Berry, represents approximately 3,500 Bbl/D of production or approximately 15% of total current production. The Company is investigating its market opportunities for this crude oil. If market prices continue to deteriorate, the Company may allocate its capital expenditures to projects which produce natural gas and crude oils with lower paraffinic content until the refinery constraint is resolved.
 
Natural Gas Marketing. Berry markets produced natural gas from Colorado, Utah, Wyoming and California. Generally, natural gas is sold at monthly index related prices plus an adjustment for transportation. Certain volumes are sold at a daily spot related price.

 
 
2005
 
2004
 
2003
 
Annual average closing price per MMBtu for:
 
               
 
NYMEX Henry Hub (HH) prompt month natural gas contract
 
$
9.01
 
$
6.18
 
$
5.84
 
Rocky Mountain Questar first-of-month indices (Brundage Canyon sales)
   
6.73
   
5.05
   
4.00
 
Rocky Mountain CIG first-of-month indices (Tri-State sales)
   
6.95
   
5.17
   
4.04
 
Average natural gas price per MMBtu differential between NYMEX HH and:
                   
Questar
   
2.28
   
1.13
   
1.84
 
CIG
   
2.06
   
1.01
   
1.80
 




5

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents

The Company has physical access to interstate gas pipelines to move gas to or from market. To assure delivery of gas, the Company has entered into several long-term gas transportation contracts as follows:

Firm Transportation Summary
Name
 
From
 
To
 
Quantity (Avg. MMBtu/D)
 
Term
 
2005 base costs per MMBtu
 
Remaining contractual obligation (in thousands)
 
Kern River Pipeline
   
Opal, WY
   
Kern County, CA
   
12,000
   
5/2003 to 4/2013
 
$
.6425
 
$
20,640
 
Questar Pipeline
   
Brundage Canyon
   
Salt Lake City, UT
   
2,500
   
9/2003 to 4/2007
   
.1739
   
211
 
Questar Pipeline
   
Brundage Canyon
   
Salt Lake City, UT
   
2,800
   
9/2003 to 9/2007
   
.1739
   
317
 
KMIGT
   
Yuma County, CO
   
Grant, KS
   
2,500
   
1/2005 to 10/2013
   
.2270
   
1,624
 
Cheyenne Plains Gas Pipeline
   
Tri-State, CO
   
Panhandle Eastern Pipeline
   
11,000
   
(Est.) Q4 2006 to Q4 2016
   
.3400
   
13,662
 
Total
               
30,800
             
$
36,454
 

Royalties. See Item 7A Quantitative and Qualitative Disclosures about Market Risk.

Hedging. See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to the financial statements.

Concentration of Credit Risk. See Note 4 to the financial statements.

Steaming Operations

Cogeneration Steam Supply. As of December 31, 2005, approximately 74% of the Company's proved reserves, or 93 million barrels, consisted of heavy crude oil produced from depths of less than 2,000 feet. The Company, in pursuing its goal of being a cost-efficient heavy oil producer in California, has remained focused on minimizing its steam cost. One of the main methods of keeping steam costs low is through the ownership and efficient operation of cogeneration facilities. Two of these cogeneration facilities, a 38 megawatt (MW) and an 18 MW facility are located in the Company’s Midway-Sunset field. The Company also owns a 42 MW cogeneration facility which is located in the Placerita field. Steam generation from these cogeneration facilities is more efficient than conventional steam generation as both steam and electricity are concurrently produced from a common fuel stream. By maintaining a correlation between electricity and natural gas prices, the Company is able to better control its cost of producing steam.

Conventional Steam Generation. In addition to these cogeneration plants, the Company owns 16 conventional boilers. The quantity of boilers operated at any point in time is dependent on 1) the steam volume required for the Company to achieve its targeted production and 2) the price of natural gas compared to the price of crude oil sold.

Total barrels of steam per day (BSPD) capacity as of December 31, 2005 is as follows:
         
Total steam generation capacity of Cogeneration plants
   
38,000
 
Additional steam purchased under contract with third party
   
2,000
 
Total steam generation capacity of conventional boilers
   
43,000
 
Total steam capacity
   
83,000
 

The average volume of steam injected for the years ended December 31, 2005 and 2004 was 70,032 and 69,200 BSPD, respectively.

Ownership of these varied steam generation facilities and sources allows for maximum operational control over the steam supply, location, and to some extent control over the aggregated cost of steam generation. The Company’s steam supply and flexibility are crucial for the maximization of California thermally enhanced heavy oil production, cost control and ultimate reserve recovery.

The Company believes that it may become necessary to add additional steam capacity for its future development projects at Midway-Sunset and Poso Creek to allow for full development of its properties. The Company regularly reviews its most economical source for obtaining additional steam to achieve its growth objectives.

Most of the Company’s conventional steam generators operated in 2005 to achieve the Company’s goal of increasing heavy oil production to record levels. Approximately 70% of the volume of natural gas purchased to generate steam and electricity is based upon SoCal Border indices. While there are no transportation charges for gas purchased at the SoCal Border location, all locations except the central portion of the Midway-Sunset field pay distribution/transportation charges to either SoCal Gas or Pacific Gas &

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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



Electric (PG&E) to have the gas delivered to the field. The remaining 30% of supply volume is purchased in Wyoming and moved to the Midway-Sunset field using the Company’s firm transport on the Kern River Pipeline. This gas is purchased based upon the Rocky Mountain Northwest Pipeline (NWPL) index.

 
 
2005
 
2004
 
2003
Average SoCal Border Monthly Index Price per MMBtu
 
$
7.37
 
$
5.60
 
$
5.00
Average Rocky Mountain NWPL Monthly Index Price per MMBtu (*contract began May 2003)
   
6.96
   
5.24
   
4.34*

The Company historically was a net purchaser of natural gas and thus its net income was negatively impacted when natural gas prices rose higher than its oil equivalent. In 2005, due to its eastern Colorado Niobrara gas acquisition, the Company on a gas balance basis achieved parity. Thus, going forward, the Company is a net seller of gas and operationally should benefit when gas prices are higher. The balance between natural gas (MMBtu/D) consumed and produced during the month of December 2005 was approximately as follows:

Natural gas consumed in:
     
Cogeneration operations
 
27,000
 
Conventional boilers
 
11,000
 
Total natural gas consumed
 
38,000
 
Less: Company’s estimate of approximate natural gas consumed to produce electricity (1)
 
(20,000)
 
Total approximate natural gas volumes consumed to produce steam
 
18,000
 
       
Natural gas produced:
     
Tri-State (Niobrara)
 
11,900
 
Brundage Canyon (associated gas)
 
11,400
 
Other
 
1,700
 
Total natural gas volumes produced in operations
 
25,000
 
(1) The Company estimates this volume based on electricity revenues divided by the purchase price, including transportation, per MMBtu for the respective period.

Electricity.

Generation. The total annual average electrical generation of the Company’s three cogeneration facilities is approximately 93 megawatts (MW), of which the Company consumes approximately 8 MW for use in its operations. Each facility is centrally located on an oil producing property such that the steam generated by the facility is capable of being delivered to the wells that require steam for the enhanced oil recovery process. The Company’s investment in its cogeneration facilities has been for the express purpose of lowering the steam costs in its heavy oil operations and securing operating control of the respective steam generation. Expenses of operating the cogeneration plants are analyzed regularly to determine whether they are advantageous versus conventional steam boilers. Cogeneration costs are allocated between electricity generation and oil and gas operations based on the conversion efficiency (of fuel to electricity and steam) of each cogeneration facility and certain direct costs to produce steam. Cogeneration costs allocated to electricity will vary based on, among other factors, the thermal efficiency of the Company's cogeneration plants, the price of natural gas used for fuel in generating electricity and steam, and the terms of the Company's power contracts. The Company views any profit or loss from the generation of electricity as a decrease or increase, respectively, to its total cost of producing its heavy oil in California. DD&A related to the Company's cogeneration facilities is allocated between electricity operations and oil and gas operations using a similar allocation method.

Sales Contracts. Historically, the Company has sold electricity produced by its cogeneration facilities to two California public utilities, Southern California Edison Company (Edison) and PG&E, under long-term contracts. These contracts are referred to as Standard Offer (SO) contracts under which the Company is paid an energy payment that reflects the utility’s Short Run Avoided Cost (SRAC) plus a capacity payment that reflects a recovery of capital expenditures that would otherwise have been made by the utility. An SO2 contract is more beneficial as it receives a higher capacity payment than an SO1 contract. The SRAC energy price is currently determined by a formula that reflects the utility’s marginal fuel cost and a conversion efficiency that represents a hypothetical resource to generate electricity in the absence of the cogenerator. During most periods natural gas is the marginal fuel for California utilities so this formula provides a hedge against the Company’s cost of gas to produce electricity and steam in its cogeneration facilities. A proceeding is now underway at the California Public Utilities Commission (CPUC) to review and revise the methodology used to determine SRAC energy prices. This proceeding is currently scheduled to be completed by the third quarter of 2006. There is no assurance that any new methodology will continue to provide a hedge against the Company’s fuel cost or that a revised pricing mechanism will be as beneficial as the current contract pricing.



7

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents


The original SO contract for Placerita Unit 1 continues in effect through March 2009, which makes up approximately 17% of total approximate barrels of steam per day. The modified SRAC pricing terms of this contract reflect a fixed energy price of 5.37 cents/kilowatt hour (KWh) through June 2006, at which time the energy price reverts to the SRAC pricing methodology. The Company will be paid a reduced capacity payment that is fixed through the term of the contract.

In December 2004, the Company executed a five-year SO contract with Edison for the Placerita Unit 2 facility, and five-year SO contracts with PG&E for the Cogen 18 and Cogen 38 facilities, each effective January 1, 2005. Pursuant to these contracts, the Company is paid the purchasing utility’s SRAC energy price and a capacity payment that is subject to adjustment from time to time by the CPUC. Edison and PG&E challenged, in the California Court of Appeals, the legality of the CPUC decision that ordered the utilities to enter into these five-year SO contracts, and similar one-year SO contracts that were ordered for 2004. The Court ruled that the CPUC had the right to order the utilities to execute these contracts. The Court also ruled that the CPUC was obligated to review the prices paid under the contracts and to retroactively adjust the prices to the extent it was later determined that such prices did not comply with the requirements of the Public Utilities Regulatory Policy Act of 1978, as amended (PURPA).

The Company believes that Qualifying Facilities (QF), such as the Company's facilities, provide an important source of distributive power generation into California's electricity grid, and as such, that the Company's facilities will be economic to operate for at least the current five-year contract term. Based on the current pricing mechanism for its electricity under the contracts (which includes electricity purchased for internal use), the Company expects that its electricity revenues will be in the $50 million to $60 million range for 2006.

Facility and Contract Summary
Location and Facility
Type of Contract
Purchaser
Contract Expiration
Approximate Megawatts Available for Sale
Approximate Megawatts Consumed in Operations
Approximate Barrels of Steam Per Day
Placerita
 
 
 
 
 
 
Placerita Unit 1
SO2
Edison
Jun-06 (1)
20
-
6,600
Placerita Unit 2
SO1
Edison
Dec-09
16
4
6,700
 
 
 
 
 
 
 
Midway-Sunset
 
 
 
 
 
 
Cogen 18
SO1
PG&E
Dec-09
12
4
6,600
Cogen 38
SO1
PG&E
Dec-09
37
-
18,000
(1) After expiration at June 2006, the contract will convert to SO1 through its expiration at March 2009.

Competition. The oil and gas industry is highly competitive. As an independent producer, the Company does not own any refining or retail outlets and, therefore, it has little control over the price it receives for its crude oil. As such, higher costs, fees and taxes assessed at the producer level cannot necessarily be passed on to the Company's customers. In acquisition activities, significant competition exists as integrated and independent companies and individual producers are active bidders for desirable oil and gas properties and prospective acreage. Although many of these competitors have greater financial and other resources than the Company, Management believes that Berry is in a position to compete effectively due to its efficient operating cost structure, transaction flexibility, strong financial position, experience and determination.

Employees. On December 31, 2005, the Company had 209 full-time employees, up from 156 full-time employees on December 31, 2004.

Berry’s Net Oil and Gas Producing Properties at December 31, 2005. 
Name
% Average Working Interest
Total Net Acres
Proved Reserves (BOE) in thousands
Proved Developed Reserves (BOE) in thousands
% of Total Proved Reserves
Proved Undeveloped Reserves (BOE) in thousands
% of Total Proved Reserves
Average Depth of Producing Reservoir (feet)
Midway-Sunset, CA
99
4,836
68,071
60,627
48%
7,443
6%
1,200
Brundage Canyon, UT
100
45,420
15,116
8,554
7
6,561
5
6,000
Placerita, CA
100
965
16,592
7,462
6
9,130
7
1,800
Tri-State, CO/KS/NE
50
315,473
17,442
8,411
7
9,031
7
2,600
Montalvo, CA
100
8,563
6,869
2,811
2
4,059
3
11,500
Poso Creek, CA
100
680
2,046
2,046
2
-
-
1,200
Various
15
815
149
150
-
-
-
various
Totals
 
376,752
126,285
90,061
72%
36,224
28%
 



8

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



San Joaquin Valley Basin

Midway-Sunset, California - Berry owns and operates working interests in 38 properties, including 23 owned in fee, in the Midway-Sunset field. Production from this field relies on thermal enhanced oil recovery (EOR) methods, primarily cyclic steaming.

2005 - Development activities at Midway-Sunset continued to be focused on horizontal drilling to improve ultimate recovery of original oil-in-place, reduce the development and operating costs of properties and to accelerate production.
2006 - Capital of $40 million ($15 million for development and $25 million for exploration/appraisal) is directed to 1) development - maximizing the recovery from horizontal wells, improving steam efficiency and expanding two steam flood projects and 2) exploration/appraisal - expanding of the Diatomite project which includes up to 50 wells and related facilities.

Poso Creek, California - Berry acquired these properties beginning in 2003 and is evaluating the potential for thermal EOR.

2005 - The Company initiated a steam flood on the property.
2006 - Capital of $5 million is directed at drilling infill wells and, upon success, expanding the steam flood area.

Los Angeles Basin

Placerita, California - Berry owns and operates working interests in 13 properties, including 9 leases and 4 fee properties, in the Placerita field. Production relies on thermal recovery methods, primarily steam flooding.

2005 - Began major recompletion effort in mature steam flood and drilled 10 wells on northern acreage.
2006 - Capital of $8 million is directed at converting northern leases to steam flood, expanding another steam flood project and focusing on utilizing optimization technology to improve recovery.
 
Ventura Basin

Montalvo, California - Berry owns 6 leases in the Ventura Basin comprising the entire Montalvo field. The State of California is the lessor for 2 of these leases. The wells produce heavy oil and due to the depth of the reservoir, steam injection is not necessary.

2005 - Berry performed several well recompletions.
2006 - Capital of $8 million is directed at testing the western Sespe reservoir through additional drilling and adding production in the Colonia zone.

Uinta Basin

Brundage Canyon, Utah - The Brundage Canyon leasehold in Duchesne County, northeastern Utah consists of federal, tribal and private leases.

2005 - The Company continued its focus on development of the Brundage Canyon property, drilling 53 wells including 33 infill wells to validate 40-acre spacing.
2006 - Capital of $58 million is directed at continuing the development of the Green River formation, including testing 20-acre infills. 

Lake Canyon Prospect, Utah - The Company holds, with an industry partner, a 169,000 gross acre block which is located immediately west of the Company’s Brundage Canyon producing properties. The Company will drill and operate the shallow wells which target light oil and natural gas in the Green River formation and retain up to a 75% working interest. The Company's partner will drill and operate the deep wells which target natural gas in the Mesaverde and Wasatch formations. Berry will hold up to a 25% working interest in these deep wells. The Ute Tribe has the option to participate in each well and obtain a 25% working interest which would reduce the Company’s and its partner’s participation. The Ute Tribe did participate in the first two shallow Green River wells.

2005 - The Company drilled 2 shallow Green River oil and gas wells and participated in a 57 square mile 3-D seismic survey. In October 2005, the Company’s partner began drilling a deep Mesaverde gas test well that reached targeted depth of 14,500 feet in December. This deep well is being evaluated. In January 2006, the Company announced that its 2 shallow wells have commercial quantities of oil and gas.
2006 - Capital of $4 million is directed at an additional 4 shallow wells and participation in deep Mesaverde tests. Upon further success with the shallow wells, the Company will accelerate development and capital on this project.



9

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



Coyote Flats Prospect, Utah - In December 2004, the Company entered into a development agreement with an industry partner to develop their Coyote Flats prospect. The property is located approximately 45 miles southwest of the Company’s Brundage Canyon property. The Company is obligated to drill four test wells into the Ferron sand to a depth of approximately 7,500 feet and also drill a five well Emery coalbed methane (CBM) pilot, found at approximately 4,500 feet. Upon the completion of this total nine well drilling program, the Company will earn a 50% working interest in the approximately 69,250 gross (33,500 net) acres. The Company expects to complete this nine well drilling program in 2006.

2005 - The Company has drilled 3 Ferron sand test wells in 2005, one of which was a dry hole. The Company began its CBM development with 1 well drilled.
2006 - Capital of $5 million is directed at fulfilling Berry’s obligation wells, which consists of four CBM wells and one Ferron well. A gas pipeline is also planned to tie in gas production for sale in mid-summer.

Big Wash Unit, Utah - The Company, and an industry partner, owns working interest in 3 acreage blocks, the largest being the Big Wash Unit, which is located one mile southeast of Brundage Canyon.

2005 - Participated in one deep Mesaverde test in 2005, and the well (net working interest to Berry of 16%) is an economic producer.
2006 - Capital of $2 million is directed at participating in one exploratory gas well in the deep Mesaverde and one exploratory oil well in the shallow Green River formation.

Denver-Julesburg Basin

Tri-State Area (includes eastern Colorado producing assets) - This area is comprised of the following three acquisitions during 2005 totaling approximately 315,000 net acres, including approximately 100,000 net acres of producing acreage:
·  
Niobrara gas producing assets in Yuma County in northeastern Colorado in which the Company has approximately 52% working interest.
·  
Eastern Colorado, western Kansas and southwestern Nebraska in which the Company has approximately 50% working interest. The Company’s joint venture (JV) will apply seismic technologies to explore and, if successful, develop the Niobrara formation for gas and Sharon Springs shale gas, which lies at less than 2,000 feet, and apply seismic technologies to evaluate oil potential in the Pennsylvanian formations at depths of 4,000 feet to 4,800 feet.
·  
Colorado’s Phillips and Sedgwick Counties in which the Company has approximately 50% working interest. This Niobrara leasehold position is adjacent to and immediately north of Berry’s producing natural gas assets in Yuma County.

2005 - In 2005, the Company drilled approximately 103 gross wells as part of its ongoing development program and the initiation of the 40-acre infill program from the existing 80-acre development. The JV’s initial exploratory wells at Prairie Star Sherman County, Kansas are commercial. Additionally, the JV drilled 7 gross wells (4 net) in 2005 at Prairie Star.
2006 - Capital of $25 million ($17 million development and $8 million exploration) is directed at drilling over 160 wells to add production from both proved undeveloped and probable reserves and over 30 exploratory wells, based on various seismic data and interpretation. The Company will also participate in at least five 3-D seismic surveys covering in excess of 250 square miles.

Williston Basin

Bakken Play, North Dakota - In 2005, the Company completed several transactions and Berry now has total working interests of 50% in 186,000 gross acres (46,000 net) located in the Williston Basin in North Dakota. These acquisitions, totaling approximately $9 million, provide the Company an entry into the emerging Bakken oil play in the Williston Basin. The acreage covers several contiguous blocks located primarily on the eastern flank of the Nesson Anticline. Development activity in the Middle Bakken play is generally expanding to the area surrounding the Nesson Anticline.

2005 - The Company participated in one exploratory well which is undergoing evaluation.
2006 - Capital of $4 million is directed at participating in at least four exploratory horizontal wells. Berry does not anticipate being the operator of any of these wells.




10

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



Piceance Basin

Grand Valley, Colorado - On January 27, 2006 the Company announced that it had entered into an agreement with a private seller to acquire a 50% working interest in natural gas assets (6,314 gross acres) in the Piceance Basin of western Colorado for approximately $150 million. Berry internally estimates 26 billion cubic feet (Bcf) of proved reserves. Berry has identified over 600 drilling locations based on 10-acre development. Berry will be targeting gas in the Williams Fork section of the Mesaverde formation. The Company increased its 2006 capital budget by an additional $48 million to $208 million to develop this resource. There are two drilling rigs dedicated to this project and based on the productivity of this acreage and surrounding producing operations, Berry is seeking to add additional drilling rigs to accelerate development. Estimated production, net to Berry’s interests as of March 1, 2006 is 1 million cubic feet per day. The transaction closed on February 28, 2006.

2006 - Capital of $48 million is directed at beginning the extensive development of the acreage. The Company intends to drill over 30 wells in 2006 and, depending on rig availability and commodity prices, may increase its capital committed to the project.




11

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



The following is a summary of the Company's capital expenditures incurred during 2005 and 2004 and budgeted capital expenditures for 2006:
 
CAPITAL EXPENDITURES SUMMARY
(in thousands)

 
2006
 
2005
 
2004
 
 
(Budgeted) (1)
 
 
 
 
 
CALIFORNIA
 
 
 
 
 
 
Midway-Sunset field
 
 
 
 
 
 
New wells
$
23,380
 
$
17,369
 
$
11,376
 
Remedials/workovers
 
1,145
 
 
1,079
 
 
1,415
 
Facilities - oil & gas
 
14,493
 
 
7,879
 
 
4,045
 
Facilities - cogeneration
 
543
 
 
3,053
 
 
1,055
 
General
 
540
 
 
1,271
 
 
2,144
 
 
 
40,101
 
 
30,651
 
 
20,035
 
Other California fields
 
 
 
 
 
 
 
 
 
New wells
 
10,647
 
 
6,965
 
 
426
 
Remedials/workovers
 
2,650
 
 
5,303
 
 
1,589
 
Facilities - oil & gas
 
7,202
 
 
3,677
 
 
3,416
 
Facilities - cogeneration
 
400
 
 
1,446
 
 
555
 
General
 
110
   
46
   
-
 
 
 
21,009
 
 
17,437
 
 
5,986
 
Total California
 
61,110
 
 
48,088
 
 
26,021
 
 
 
 
 
 
 
 
 
 
 
ROCKY MOUNTAIN AND MID-CONTINENT
 
 
 
 
 
 
 
 
 
Uinta Basin
 
 
 
 
 
 
 
 
 
New wells
 
64,100
 
 
50,354
 
 
39,467
 
Remedials/workovers
 
1,496
 
 
3,415
 
 
4,597
 
Facilities
 
2,500
 
 
1,860
 
 
1,979
 
General
 
552
   
4
   
-
 
 
 
68,648
 
 
55,633
 
 
46,043
 
Piceance Basin
 
 
 
 
 
 
 
 
 
New wells
 
47,615
   
-
   
-
 
 
 
47,615
 
 
-
 
 
-
 
DJ Basin
 
 
 
 
 
 
 
 
 
New wells/workovers
 
14,819
 
 
11,257
 
 
-
 
Remedials/workovers
 
275
   
693
   
-
 
Facilities
 
5,215
 
 
2,569
 
 
-
 
General
 
4,838
   
387
   
-
 
Land and seismic
 
-
 
 
-
 
 
-
 
 
 
25,147
 
 
14,906
 
 
-
 
Williston Basin - New wells
 
4,400
 
 
-
 
 
161
 
Total Rocky Mountain and
 
 
 
 
 
 
 
 
 
Mid-Continent
 
145,810
 
 
70,539
 
 
46,204
 
Other Fixed Assets
 
770
 
 
647
 
 
-
 
 
 
 
 
 
 
 
 
 
 
TOTAL
$
207,690
 
$
119,274
 
$
72,225
 



12

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



(1)  Budgeted capital expenditures may be adjusted for numerous reasons including, but not limited to, oil, and natural gas price levels and equipment availability, permitting and regulatory issues. See Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations. 

Production. The following table sets forth certain information regarding production for the years ended December 31, as indicated:
 
 
 
2005
 
2004
 
2003
 
Net annual production: (1)
 
 
 
 
 
 
 
Oil (Mbbl)
 
 
7,081
 
 
7,044
 
 
5,827
 
Gas (MMcf)
 
 
7,919
 
 
2,839
 
 
1,277
 
Total equivalent barrels (MBOE) (2)
 
 
8,401
 
 
7,517
 
 
6,040
 
 
 
 
 
 
 
 
 
 
 
 
Average sales price:
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl) before hedging
 
$
47.04
 
$
33.43
 
$
24.41
 
Oil (per Bbl) after hedging
 
 
40.83
 
 
29.89
 
 
22.37
 
Gas (per Mcf) before hedging
 
 
7.88
 
 
6.13
 
 
4.40
 
Gas (per Mcf) after hedging
 
 
7.73
 
 
6.12
 
 
4.43
 
Per BOE before hedging
 
 
47.01
 
 
33.64
 
 
24.48
 
Per BOE after hedging
 
 
41.62
 
 
30.32
 
 
22.52
 
Average operating cost - oil and gas production (per BOE)
 
 
11.79
 
 
10.09
 
 
9.57
 
 
Mbbl - Thousands of barrels
MMcf - Million cubic feet
BOE - Barrels of oil equivalent
MBOE - Thousand barrels of oil equivalent
(1) Net production represents that owned by Berry and produced to its interests.
(2) Equivalent oil and gas information is at a ratio of 6 thousand cubic feet (Mcf) of natural gas to 1 barrel (Bbl) of oil. A barrel of oil is equivalent to 42 U.S. gallons

Acreage and Wells. As of December 31, 2005, the Company's properties accounted for the following developed and undeveloped acres:
 
 
 
Developed Acres
 
Undeveloped Acres
 
Total
 
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
California
 
 
8,007
   
8,007
   
7,038
   
7,038
   
15,045
   
15,045
 
Colorado
   
79,910
   
67,302
   
162,966
   
77,029
   
242,876
   
144,331
 
Illinois
 
 
-
   
-
   
35,481
   
33,249
   
35,481
   
33,249
 
Kansas
 
 
-
   
-
   
424,885
   
275,494
   
424,885
   
275,494
 
Nebraska
   
-
   
-
   
124,025
   
57,756
   
124,025
   
57,756
 
North Dakota
   
-
   
-
   
185,976
   
46,252
   
185,976
   
46,252
 
Utah (1) (2)
 
 
9,520
   
9,360
   
99,033
   
66,686
   
108,553
   
76,046
 
Wyoming
 
 
3,800
   
750
   
3,146
   
1,130
   
6,946
   
1,880
 
Other
 
 
80
   
19
   
-
   
-
   
80
   
19
 
 
 
 
101,317
   
85,438
   
1,042,550
   
564,634
   
1,143,867
   
650,072
 
(1) Includes 44,583 gross undeveloped acres (22,292 net) where the Company has an interest in 75% of the deep rights and 25% of the shallow rights.
(2) Does not include 125,000 gross (70,000 net) acres, 125,000 gross (23,000 net) acres and 69,000 gross (34,000 net) acres at Lake Canyon (shallow), Lake Canyon (deep) and Coyote Flats, respectively, which the Company can earn upon fulfilling specific drilling obligations.

Gross acres represent acres in which Berry has a working interest; net acres represent Berry's aggregate working interests in the gross acres.



13

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



As of December 31, 2005, the Company has 2,035 gross oil wells (1,951 net) and 976 gross gas wells (419 net). Gross wells represent the total number of wells in which Berry has a working interest. Net wells represent the number of gross wells multiplied by the percentages of the working interests owned by Berry. One or more completions in the same bore hole are counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well.

Drilling Activity. The following table sets forth certain information regarding Berry's drilling activities for the periods indicated:
 
 
 
2005
 
2004
 
2003
 
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Exploratory wells drilled (2):
 
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
 
13
   
6
 
 
5
 
 
5
 
 
-
 
 
-
 
Dry (1)
 
 
1
   
1
 
 
-
 
 
-
 
 
-
 
 
-
 
Development wells drilled:
 
 
       
 
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
 
213
   
176
 
 
123
 
 
111
 
 
121
 
 
119
 
Dry (1)
 
 
7
   
5
 
 
-
 
 
-
 
 
1
 
 
1
 
Total wells drilled:
 
 
       
 
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
 
226
   
182
 
 
128
 
 
116
 
 
121
 
 
119
 
Dry (1)
 
 
8
   
6
 
 
-
 
 
-
 
 
1
 
 
1
 
(1) A dry well is a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
(2) Does not include one gross well drilled by the Company’s industry partner that is being evaluated at December 31, 2005.

 
 
2005
 
 
Gross
 
Net
Total productive wells drilled:
 
 
       
Oil
 
 
113
   
111
Gas
 
 
113
   
71

Dry hole, abandonment and impairment. See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations.

California Drilling Rig. The Company entered into a three-year drilling contract for the services of an automated drilling rig. This rig provides a means for Berry to meet at least half of its California new well drilling needs for the next three years, with the other half being met by conventional drilling rigs. The three-year drilling contract begins upon commissioning of the rig which is expected in the second quarter of 2006.

Rocky Mountain and Mid-Continent Region Drilling Rigs. During 2005, the Company purchased two drilling rigs. The first rig is leased to a drilling company under a three year contract, while the second rig is currently being refurbished in preparation for leasing under a similar drilling contract. Owning these rigs allows the Company to successfully meet a portion of its drilling needs in the Uinta Basin over the next several years, while both rigs carry purchase options available to the drilling company.

Other. At year-end, the Company had no subsidiaries, no special purpose entities and no off-balance sheet debt. The Company did not enter into any significant related party transactions in 2005. See Note 17 to the financial statements for discussion regarding Canyon Drilling, LLC.

Environmental and Other Regulations. Berry Petroleum Company is committed to responsible management of the environment, health and safety, as these areas relate to the Company’s operations. The Company strives to achieve the long-term goal of sustainable development within the framework of sound environmental, health and safety practices and standards. Berry makes environmental, health and safety protection an integral part of all business activities, from the acquisition and management of its resources through the decommissioning and reclamation of its wells and facilities.

All facets of the Company's operations are affected by a myriad of federal, state, regional and local laws, rules and regulations. Berry is further affected by changes in such laws and by constantly changing administrative regulations. Furthermore, government agencies may impose substantial liabilities if the Company fails to comply with such regulations or for any contamination resulting from the Company's operations. Therefore, Berry has programs in place to identify and manage known risks, to train employees in the proper performance of their duties and to incorporate viable new technologies into its operations. The costs incurred to ensure


14

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



compliance with environmental, health and safety laws and other regulations are normal operating expenses and are not material to the Company’s operating cost. There can be no assurances, however, that changes in, or additions to, laws and regulations regarding the protection of the environment will not have an impact in the future. Berry maintains insurance coverage that it believes is customary in the industry although it is not fully insured against all environmental or other risks.

Regulation of Oil and Gas. The oil and gas industry, including the Company’s operations, is extensively regulated by numerous federal, state and local authorities, and with respect to tribal lands, and one Native American tribe.

These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Regulations may also govern the location of wells, the method of drilling and casing wells, the rates of production or "allowables," the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and notice to surface owners and other third parties. Certain laws and regulations may limit the amount of oil and natural gas the Company can produce from its wells or limit the number of wells or the locations at which it can drill. The Company is also subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases and other exploration agreements, fees, taxes, and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations.

Federal Energy Regulation. The enactment of PURPA, as amended, and the adoption of regulations thereunder by the Federal Energy Regulation Commission (FERC) provided incentives for the development of cogeneration facilities such as those owned by the Company. A domestic electricity generating project must be a QF under FERC regulations in order to take advantage of certain rate and regulatory incentives provided by PURPA.

PURPA provides two primary benefits to QFs. First, QFs generally are relieved of compliance with extensive federal and state regulations that control the financial structure of an electricity generating plant and the prices and terms on which electricity may be sold by the plant. Second, FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility’s avoided cost, and that the utility sell back-up power to the QF on a non-discriminatory basis. The term "avoided cost" is defined as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate for itself or purchase from another source. The Energy Policy Act of 2005 amends PURPA to allow a utility to petition FERC to be relieved of its obligation to enter into any new contracts with QFs if the FERC determines that a competitive electricity market is available to QFs in its service territory. This amendment does not affect any of the Company’s current SO contracts. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates lower than the utilities’ avoided costs. In California, the utility’s avoided cost is generally referred to as Short Run Avoided Cost or SRAC.

In order to be a QF, a cogeneration facility must produce not only electricity, but also useful thermal energy for use in an industrial or commercial process for heating or cooling applications in certain proportions to the facility’s total energy output, and must meet certain energy efficiency standards. Each of the Company’s cogeneration facilities is a QF, pursuant to PURPA.

State Energy Regulation. The CPUC has broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in this state and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility’s cost structure (generally reflected in its retail rates), power sales agreements with independent electricity producers, such as the Company, are potentially under the regulatory purview of the CPUC and in particular the process by which the utility has entered into the power sales agreements. While the Company is not subject to regulation by the CPUC, the CPUC's implementation of PURPA is important to the Company.

Forward Looking Statements

"Safe harbor under the Private Securities Litigation Reform Act of 1995:” Any statements in this Form 10-K that are not historical facts are forward-looking statements that involve risks and uncertainties. Words such as “will,” “might,” “intend,” “continue,” “target(s),” “expect,” “achieve,” “strategy,” “future,” “may,” “could,” “goal(s),” or other comparable words or phrases or the negative of those words, and other words of similar meaning indicate forward-looking statements and important factors which could affect actual results. Forward-looking statements are made based on management’s current expectations and beliefs concerning future developments and their potential effects upon Berry Petroleum Company. These items are discussed at length in Part I, Item 1A on page 16 of this Form 10-K filed with the Securities and Exchange Commission, under the heading “Other Factors Affecting the Company's Business and Financial Results" in the section titled "Management’s Discussion and Analysis of Financial Condition and Results of Operations.”




15

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



Item 1A. Risk Factors

Other Factors Affecting the Company's Business and Financial Results

Oil and gas prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business. Our revenues, profitability and future growth and reserve calculations depend substantially on reasonable prices for oil and gas. These prices also affect the amount of our cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our credit facility is subject to periodic asset redeterminations based in part on changing expectations of future crude oil and natural gas prices. Lower prices may also reduce the amount of oil and gas that we can produce economically.

Among the factors that can cause fluctuations are:
·  
domestic and foreign supply of oil and natural gas;
·  
price and availability of alternative fuels;
·  
weather conditions;
·  
level of consumer demand;
·  
price of foreign imports;
·  
world-wide economic conditions;
·  
political conditions in oil and gas producing regions; and
·  
domestic and foreign governmental regulations.

The Company has crude oil hedges on 10,000 Bbl/D for 4 years beginning in 2006. We have an oil collar in place based on WTI pricing with a $47.50 floor and a $70 ceiling.

Our heavy crude in California is less economic than lighter crude oil and natural gas. As of December 31, 2005, approximately 74% of our proved reserves or 93 million barrels, consisted of heavy oil, light crude oil represented 8% and natural gas represented 18% of our oil and gas reserves. Our objective is to diversify our predominantly heavy crude oil base with light crude oil and natural gas.

In November 2005, the Company entered into a new crude oil sales contract for its California production for deliveries beginning February 1, 2006 and ending January 31, 2010. 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 $8.15, or 2) heavy oil field postings plus a premium of approximately $1.35.

A widening of commodity differentials may adversely impact our revenues and per barrel economics. Both our produced crude oil and natural gas are subject to pricing in the local markets where the production occurs. It is customary that such products are priced based on local or regional supply and demand factors. California heavy crude sells at a discount to WTI, the U.S. benchmark crude oil, primarily due to the additional cost to refine gasoline or light product out of a barrel of heavy crude. Our Utah light crude also is currently priced at $2.00 below WTI. Natural gas field prices are normally priced off of Henry Hub NYMEX price, the benchmark for U.S. natural gas. While we attempt to contract for the best possible price in each of our producing locations, there is no assurance that past price differentials will continue into the future. Numerous factors may influence local pricing, such as refinery capacity, particularly for black wax crude, pipeline capacity and specifications, upsets in the mid-stream or downstream sectors of the industry, trade restrictions, governmental regulations, etc. We may be adversely impacted by a widening differential on the products sold.

Market conditions or operational impediments may hinder our access to crude oil and natural gas markets or delay our production. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity, processing facilities or refineries. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market. See firm transportation summary schedule at Item 1 Business.




16

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



Factors that can cause price volatility for crude oil and natural gas include:
·  
availability and capacity of refineries;
·  
availability of gathering systems with sufficient capacity to handle local production;
·  
seasonal fluctuations in local demand for production;
·  
local and national gas storage capacity;
·  
interstate pipeline capacity; and
·  
availability and cost of gas transportation facilities.

Brundage Canyon crude oil production, which is approximately 40 degree API gravity, is sold under contract at WTI less a fixed differential approximating $2.00 per barrel. This contract expires on September 30, 2006. Any new contract will be negotiated based on market prices. We believe the differential has widened by several dollars per barrel. The majority of this crude oil, while light, is a “paraffinic” crude, and can be processed efficiently by only a limited number of stranded inland refineries. The production of this type crude is increasing regionally and beginning to strain the capacity of these refineries. Other new crude sources from the region are pressuring pricing. If these refineries limit the volumes of this parraffinic crude oil they are willing to process, it could impact the marketability of this type of crude which, for Berry, represents approximately 3,500 Bbl/D of production or approximately 15% of total current production. We are investigating the market opportunities for this crude oil. If market prices continue to deteriorate, we may allocate capital expenditures to projects which produce natural gas and crude oils with lower paraffinic content until the refinery constraint is resolved.

We may be subject to the risk of adding additional steam generation equipment if the electrical market deteriorates significantly. We may be subject to the risk of adding additional steam generation equipment if the electrical market deteriorates significantly. We are dependent on several cogeneration facilities that provide over half of our steam requirement. These facilities are dependent on reasonable electrical contracts. If, for any reason, we were unable to enter into an electrical contract or were to lose an existing contract, we may not be able to supply 100% of the steam requirements necessary to maximize production from our heavy oil assets. An additional investment in various steam sources may be necessary to replace such steam, and there may be risks and delays in being able to install conventional steam equipment due to permitting requirements. The financial cost and timing of such investment may adversely affect our production, capital outlays and cash provided by operating activities. We have electricity contracts covering most of our electricity generation which contracts expire in 2009.

A shortage of natural gas in California could adversely affect our business. We may be subject to the risks associated with a shortage of natural gas and/or the transportation of natural gas into and within California. We are highly dependent on sufficient volumes of natural gas that we use for fuel in generating steam in our heavy oil operations in California. If the required volume of natural gas for use in our operations were to be unavailable or too highly priced to produce heavy oil economically, our production could be adversely impacted. The Company has firm transportation to move 12,000 MMBtu/D on the Kern River Pipeline from the Rocky Mountains to Kern County, CA. This volume is approximately one-third of the Company’s current requirement.

Our use of oil and gas price hedging contracts involves credit risk and may limit future revenues from price increases and result in significant fluctuations in net income. We use hedging transactions with respect to a portion of our oil and gas production to achieve more predictable cash flow and to reduce our exposure to a significant decline in the price of crude oil. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations. The Company utilizes several counterparties for its hedging contracts.

Our future success depends on our ability to find, develop and acquire oil and gas reserves. To maintain production levels, we must locate and develop or acquire new oil and gas reserves to replace those depleted by production. Without successful exploration, exploitation or acquisition activities, our reserves, production and revenues will decline. We may not be able to find and develop or acquire additional reserves at an acceptable cost. In addition, substantial capital is required to replace and grow reserves. If lower oil and gas prices or operating difficulties result in our cash flow from operations being less than expected or limit our ability to borrow under credit arrangements, we may be unable to expend the capital necessary to locate and develop or acquire new oil and gas reserves.

Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves , future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses most likely will vary from estimates. Estimating accumulations of oil and gas is complex. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, some of which are mandated by the SEC. The accuracy of a reserve estimate is a function of:
·  
quality and quantity of available data;
·  
interpretation of that data; and
·  
accuracy of various mandated economic assumptions.


17

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Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of development and exploration and prevailing oil and gas prices.

In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

If oil or gas prices decrease, we may be required to take writedowns. We may be required to writedown the carrying value of our oil and gas properties when oil or gas prices are low, including basis differentials, or there are substantial downward adjustments to our estimated proved reserves, increases in estimates of development costs or deterioration in exploration or production results.

We capitalize costs to acquire, find and develop our oil and gas properties under the successful efforts accounting method. If net capitalized costs of our oil and gas properties exceed fair value, we must charge the amount of the excess to earnings. We review the carrying value of our properties annually and at any time when events or circumstances indicate a review is necessary, based on prices in effect as of the end of the reporting period. The carrying value of oil and gas properties is computed on a field-by-field basis. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if oil or gas prices increase. See Item 7A Quantitative and Qualitative Disclosures About Market Risk for the Company’s hedge position on February 10, 2006.

Competitive industry conditions may negatively affect our ability to conduct operations. Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. Major and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop their properties. Many of our competitors have financial resources that are substantially greater, which may adversely affect our ability to compete within the industry.

Drilling is a high-risk activity. Our future success will partly depend on the success of our drilling program. In addition to the numerous operating risks described in more detail below, these drilling activities involve the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, we are often uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
·  
obtaining government and tribal required permits;
·  
unexpected drilling conditions;
·  
pressure or irregularities in formations;
·  
equipment failures or accidents;
·  
adverse weather conditions;
·  
compliance with governmental or landowner requirements; and
·  
shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services.

The oil and gas business involves many operating risks that can cause substantial losses; insurance may not protect us against all of these risks. These risks include:
·  
fires;
·  
explosions;
·  
blow-outs;
·  
uncontrollable flows of oil, gas, formation water or drilling fluids;
·  
natural disasters;
·  
pipe or cement failures;
·  
casing collapses;
·  
embedded oilfield drilling and service tools;
·  
abnormally pressured formations;
·  
major equipment failures, including cogeneration facilities; and
·  
environmental hazards such as oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases.

If any of these events occur, we could incur substantial losses as a result of:
·  
injury or loss of life;
·  
severe damage or destruction of property, natural resources and equipment;
·  
pollution and other environmental damage;
·  
investigatory and clean-up responsibilities;
·  
regulatory investigation and penalties;
·  
suspension of operations; and
·  
repairs to resume operations.



18

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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If we experience any of these problems, our ability to conduct operations could be adversely affected. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us. In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our Management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. While we intend to obtain and maintain appropriate insurance coverage for these risks, there can be no assurance that our operations will not expose us to liabilities exceeding such insurance coverage or to liabilities not covered by insurance.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. Our development, exploration, production and marketing operations are regulated extensively at the federal, state and local levels. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by Native American tribes. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations oppose certain drilling projects and/or access to prospective lands.

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to the regulation by oil and natural gas-producing states and one Native American tribe of conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a negative effect on our ability to explore on or develop its properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.

Property acquisitions are a component of our growth strategy, and our failure to complete future acquisitions successfully could reduce our earnings and slow our growth. Our business strategy has emphasized growth through strategic acquisitions, but we may not be able to continue to identify properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If we are unable to achieve strategic acquisitions, our growth may be impaired, thus impacting earnings, cash from operations and reserves.

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities. Our recent growth is due in part to acquisitions of producing properties, and we expect acquisitions will continue to contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, exploration potential, future oil and natural gas prices, operating costs, production taxes and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not allow us to become sufficiently familiar with the properties, and we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited.

We generally are not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities, on acquisitions. Often, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. If material breaches are discovered by us prior to closing, we could require adjustments to the purchase price or if the claims are significant, we or the seller may have a right to terminate the agreement. We could also fail to discover breaches or defects prior to closing and incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, for which we would have limited or no contractual remedies or insurance coverage.




19

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of Management attention, and costs of increased scope, geographic diversity and complexity of our operations. Increasing our reserve base through acquisitions is an important part of our business strategy. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant Management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations

Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

The loss of key personnel could adversely affect our business. We depend to a large extent on the efforts and continued employment of our executive Management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business, and we do not maintain key man insurance on the lives of any of these persons. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

We have limited control over the activities on properties that we do not operate. Although we operate most of the properties in which we have an interest, other companies operate some of the properties. We have limited ability to influence or control the operation or future development of these nonoperated properties or the amount of capital expenditures that we are required to fund their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.

We may not adhere to our proposed drilling schedule. Our final determination of whether to drill any scheduled or budgeted wells will depend on a number of factors, including:
·  
results of our exploration efforts and the acquisition, review and analysis of our seismic data, if any;
·  
availability of sufficient capital resources to us and any other participants for the drilling of the prospects;
·  
approval of the prospects by other participants after additional data has been compiled;
·  
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and crews; and
·  
availability of leases, license options, farm-outs, other rights to explore and permits on reasonable terms for the prospects.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame, or at all. In addition, our drilling schedule may vary from our expectations because of future uncertainties and rig availability and access to our drilling locations utilizing available roads. As of December 31, 2005, the Company owns two drilling rigs and has additional one-year contract commitments on another two drilling rigs. See Note 10 to the financial statements.

We may incur losses as a result of title deficiencies. We purchase working and revenue interests in the oil and natural gas leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, often, we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. As is customary in our industry, we rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be generally lost, and the target area can become undrillable.




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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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The future of the electricity market in California is uncertain. We utilize cogeneration plants in California to generate lower cost steam compared to conventional steam generation methods. Electricity produced by our cogeneration plants is sold to utilities and the steam costs are allocated to our oil and gas operations. While we have electricity sales contracts in place with the utilities that are currently scheduled to terminate in 2009, legal and regulatory decisions, especially related to the pricing of electricity under the contracts, can adversely affect the economics of our cogeneration facilities and thereby, the cost of steam for use in our oil and gas operations.

Estimates may differ from actual. The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities, the related present value of estimated future net cash flows therefrom, the costs to develop and abandon oil and gas properties, the valuation of derivative positions and stock-based compensation valuation.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information required by Item 2 Properties is included under Item 1 Business.

Item 3. Legal Proceedings

While the Company is, from time to time, a party to certain lawsuits in the ordinary course of business, the Company does not believe any of such existing lawsuits will have a material adverse effect on the Company's operations, financial condition, or liquidity.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the most recently ended fiscal quarter.

Executive Officers of the Registrant. Listed below are the names, ages (as of December 31, 2005) and positions of the executive officers of Berry and their business experience during at least the past five years. All officers of the Company are appointed in May of each year at an organizational meeting of the Board of Directors. There are no family relationships between any of the executive officers and members of the Board of Directors.

ROBERT F. HEINEMANN, 52, has been President and Chief Executive Officer since June 2004. Mr. Heinemann was Chairman of the Board and interim President and Chief Executive Officer from April 2004 to June 2004. From December 2003 to March 2004, Mr. Heinemann was the director designated to serve as the presiding director at executive sessions of the Board in the absences of the Chairman and to act as liaison between the independent directors and the CEO. Mr. Heinemann joined the Company’s Board in March of 2003. From 2000 until 2002, Mr. Heinemann served as the Senior Vice President and Chief Technology Officer of Halliburton Company and as the Chairman of the Halliburton Technology Advisory Committee. He was previously with Mobil Oil Corporation (Mobil) where he served in a variety of positions for Mobil and its various affiliate companies in the energy and technical fields from 1981 to 1999, with his last responsibilities as Vice President of Mobil Technology Company and General Manager of the Mobil Exploration and Producing Technical Center.

RALPH J. GOEHRING, 49, has been Executive Vice President and Chief Financial Officer since June 2004. Mr. Goehring was Senior Vice President from April 1997 to June 2004, and has been Chief Financial Officer since March 1992 and was Manager of Taxation from September 1987 until March 1992. Mr. Goehring is also an Assistant Secretary for the Company.

MICHAEL DUGINSKI, 39, has been Executive Vice President of Corporate Development and California since October 2005. Mr. Duginski was Senior Vice President of Corporate Development from June 2004 through October 2005 and was Vice President of Corporate Development from February 2002 through June 2004. Mr. Duginski, a mechanical engineer, was previously with Texaco, Inc. from 1988 to 2002 where his positions included Director of New Business Development, Production Manager and Gas and Power Operations Manager. Mr. Duginski is also an Assistant Secretary for the Company.




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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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LOGAN MAGRUDER, 49, has been Executive Vice President of the Rocky Mountains and Mid-Continent region since October 2005. Mr. Magruder was Senior Vice President of the Rocky Mountain and Mid-Continent region from June 2004 through October 2005 and was Vice President of the Rocky Mountain and Mid-Continent region from August 2003 through June 2004. Mr. Magruder, a petroleum engineer, was a consultant for the Company from February 2003 through August 2003. Mr. Magruder was previously Vice President of U.S. Operations for Calpine Natural Gas Company from 2001 to 2003. Prior to Calpine, Mr. Magruder was employed by Barrett Resources as Vice President of Engineering and Operations from 1996 to 2001.

DAN ANDERSON, 43, has been Vice President of Rocky Mountains and Mid-Continent Production since October 2005. Mr. Anderson was Rocky Mountain and Mid-Continent Manager of Engineering from August 2003 through October 2005. Mr. Anderson was previously a Senior Staff Petroleum Engineer with Williams Production RMT from August 2001 through August 2003. He previously was a Senior Staff Engineer with Barrett Resources from October 2000 through August 2001.

GEORGE T. CRAWFORD, 45, has been Vice President of California Production since October 2005. Mr. Crawford was Vice President of Production from December 2000 through October 2005 and was Manager of Production from January 1999 to December 2000. Mr. Crawford, a petroleum engineer, was previously the Production Engineering Supervisor for Atlantic Richfield Corp. (ARCO) from 1989 to 1998 in numerous engineering and operational assignments including Production Engineering Supervisor, Planning and Evaluation Consultant and Operations Superintendent.

BRUCE S. KELSO, 50, has been Vice President of Rocky Mountains and Mid-Continent Exploration since October 2005. Mr. Kelso was Rocky Mountain and Mid-Continent Exploration Manager from August 2003 through October 2005. Mr. Kelso, a petroleum geologist, was previously a Senior Staff Geologist assigned to Rocky Mountain assets with Williams Production RMT, from January 2002 through August 2003. He previously was the Vice President of Exploration and Development at Redstone Resources, Inc. from 2000 to 2001.

BRIAN L. REHKOPF, 58, has been Vice President of Technology since October 2005. Mr. Rehkopf was Vice President of Engineering from March 2000 through October 2005 and was Manager of Engineering from September 1997 to March 2000. Mr. Rehkopf, a registered petroleum engineer, joined the Company’s engineering department in June 1997 and was previously a Vice President and Asset Manager with ARCO since 1992 and an Operations Engineering Supervisor from 1988 to 1992. Mr. Rehkopf is also an Assistant Secretary for the Company.

SHAWN M. CANADAY, 30, has been Treasurer since December 2004 and was Senior Financial Analyst from November 2003 until December 2004. Mr. Canaday has worked in the oil and gas industry since 1998 in various finance functions at ChevronTexaco and in public accounting. Mr. Canaday is also an Assistant Secretary for the Company.

DONALD A. DALE, 59, has been Controller since December 1985.

KENNETH A. OLSON, 50, has been Corporate Secretary since December 1985 and was Treasurer from August 1988 until December 2004.

PART II

Item 5. Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $1.00 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.

In November 1999, the Company adopted a Shareholder Rights Agreement and declared a dividend distribution of one such Right for each outstanding share of Capital Stock on December 8, 1999. Each share of Capital Stock issued after December 8, 1999 includes one Right. The Rights expire on December 8, 2009. See Note 7 to the financial statements.




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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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Berry's Class A Common Stock is listed on the New York Stock Exchange (NYSE) under the symbol BRY. The Class B Stock is not publicly traded. The market data and dividends for 2005 and 2004 are shown below:
 
 
 
2005
 
2004
 
 
 
Price Range
 
Dividends
 
Price Range
 
Dividends
 
 
 
High
 
Low
 
Per Share
 
High
 
Low
 
Per Share
 
First Quarter
 
$
66.09
 
$
43.85
 
$
.12
 
$
27.30
 
$
18.25
 
$
0.11
 
Second Quarter
 
 
54.95
   
40.78
   
.12
 
 
31.07
 
 
25.09
 
 
0.11
 
Third Quarter
 
 
67.00
   
52.30
   
.23
 
 
38.44
 
 
27.73
 
 
0.18
 
Fourth Quarter
 
 
68.66
   
52.30
   
.13
 
 
50.58
 
 
35.16
 
 
0.12
 
Total Dividend Paid
             
$
.60
             
$
.52
 
 
 
 
February 10, 2006
 
December 31, 2005
 
December 31, 2004
 
Berry’s Common Stock closing price per share as reported on NYSE Composite Transaction Reporting System
 
$
68.90
 
$
57.20
 
$
47.70
 

The number of holders of record of the Company's Common Stock was 605 as of February 10, 2006. There was one Class B Shareholder of record as of February 10, 2006.

Dividends. The Company paid a special dividend of $.10 per share on September 29, 2005 and increased its regular quarterly dividend by 8%, from $.12 to $.13 per share beginning with the September 29, 2005 dividend. The Company's regular annual dividend is currently $.52 per share, payable quarterly in March, June, September and December. The Company paid a special dividend of $.06 per share on September 29, 2004 and increased its regular quarterly dividend by 9%, from $.11 to $.12 per share beginning with the September 2004 dividend.

Since Berry Petroleum Company's formation in 1985 through December 31, 2005, the Company has paid dividends on its Common Stock for 65 consecutive quarters and previous to that for eight consecutive semi-annual periods. The Company intends to continue the payment of dividends, although future dividend payments will depend upon the Company's level of earnings, operating cash flow, capital commitments, financial covenants and other relevant factors. Dividend payments are limited by covenants in the Company's credit facility to the greater of $20 million or 75% of net income.

As of December 31, 2005, dividends declared on 3,984,080 shares of certain Common Stock are restricted, whereby 37.5% of the dividends declared on these shares are paid by the Company to the surviving member of a group of individuals, the B group, for as long as this remaining member shall live.

Equity Compensation Plan Information

 
 
Number of securities to be
 
 
 
 
 
 
issued upon exercise of
 
Weighted average exercise
 
Number of securities
 
 
outstanding options, warrants
 
price of outstanding options,
 
remaining available for future
Plan category
 
and rights
 
warrants and rights
 
issuance
Equity compensation plans approved by security holders
 
1,625,763
 
$33.52
 
1,080,187
 
 
         
Equity compensation plans not approved by security holders
 
-
 
-
 
-

 
In June 2005, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate of $50 million of the Company's outstanding Class A Common Stock. Through December 31, 2005, the Company repurchased 108,900 shares for approximately $6.3 million, which increased diluted earnings by $.01 per share.
 
 



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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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In December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities Exchange Act of 1934 to facilitate the repurchase of its shares of common stock. Rule 10b5-1 allows a company to purchase its shares at times when it would not normally be in the market due to possession of nonpublic information, such as the time immediately preceding its quarterly earnings releases. In addition to share repurchases by the Rule 10b5-1 plan, Berry expects to continue repurchases in the open market from time to time during its normal trading windows. This 10b5-1 plan is authorized under, and is administered consistent with, the Company's $50 million share repurchase program. All repurchases of common stock are made in compliance with regulations set forth by the SEC and are subject to market conditions, applicable legal requirements and other factors.

This program does not obligate the Company to acquire any particular amount of common stock and the plan may be suspended at any time at the Company's discretion.

Issuer Purchases of Equity Securities

Period
 
(a) Total number of shares purchased
 
(b) Average price paid per share
 
(c) Total number of shares purchased as part of publicly announced plans or programs
 
(d) Maximum number (or approximate dollar value) of shares that may yet be purchased under the plans or programs
Third Quarter 2005
 
43,900
 
$58.48
 
43,900
 
$47,433,000
November 2005
 
16,300
 
57.25
 
16,300
 
46,500,000
December 2005
 
48,700
 
57.80
 
48,700
 
43,684,500
Total
 
108,900
 
$57.99
 
108,900
 
$43,684,500

Item 6. Selected Financial Data

The following table sets forth certain financial information with respect to the Company and is qualified in its entirety by reference to the historical financial statements and notes thereto of the Company included in Item 8 Financial Statements and Supplementary Data. The statement of income and balance sheet data included in this table for each of the five years in the period ended December 31, 2005 were derived from the audited financial statements and the accompanying notes to those financial statements (in thousands, except per share, per BOE and % data).




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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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2005
 
2004 (3)
 
2003 (3)
 
2002 (1) (3)
 
2001 (1) (3)
 
Audited Financial Information
 
 
 
 
 
 
 
 
 
 
 
Statement of Income Data:
 
 
 
 
 
 
 
 
 
 
 
Sales of oil and gas
 
$
349,691
 
$
226,876
 
$
135,848
 
$
102,026
 
$
100,146
 
Sales of electricity
 
 
55,230
 
 
47,644
 
 
44,200
 
 
27,691
 
 
35,133
 
Operating costs - oil and gas production
 
 
99,066
 
 
73,838
 
 
57,830
 
 
41,108
   
34,605
 
Operating costs - electricity generation
 
 
55,086
 
 
46,191
 
 
42,351
 
 
26,747
 
 
36,890
 
Production taxes
   
11,506
   
6,431
   
3,097
   
2,907
   
2,479
 
General and administrative expenses (G&A)
 
 
21,396
 
 
22,504
 
 
14,495
 
 
10,417
 
 
9.748
 
Depreciation, depletion & amortization (DD&A)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil and gas production
 
 
38,150
 
 
29,752
 
 
17,258
 
 
13,388
 
 
13,225
 
Electricity generation
 
 
3,260
 
 
3,490
 
 
3,256
 
 
3,064
 
 
3,295
 
Net income
 
 
112,356
 
 
69,187
 
 
32,363
 
 
29,210
 
 
20,985
 
Basic net income per share
 
 
5.10
 
 
3.16
 
 
1.49
 
 
1.34
 
 
0.96
 
Diluted net income per share
 
 
5.00
 
 
3.08
 
 
1.47
 
 
1.33
 
 
0.95
 
Weighted average number of shares outstanding (basic)
 
 
22,041
 
 
21,894
 
 
21,772
 
 
21,741
 
 
21,973
 
Weighted average number of shares outstanding (diluted)
 
 
22,490
 
 
22,470
 
 
22,031
 
 
21,902
 
 
22,162
 
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Working capital
 
$
(54,757
)
$
(3,840
)
$
(3,540
)
$
(2,892
)
$
6,314
 
Total assets
 
 
635,051
 
 
412,104
 
 
340,377
 
 
259,325
 
 
238,779
 
Long-term debt
 
 
75,000
 
 
28,000
 
 
50,000
 
 
15,000
 
 
25,000
 
Shareholders' equity
 
 
334,210
 
 
263,086
 
 
197,338
 
 
172,774
 
 
153,590
 
Cash dividends per share
 
 
0.60
 
 
0.52
 
 
0.47
 
 
0.40
 
 
0.40
 
Operating Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow from operations
 
 
187,780
 
 
124,613
 
 
64,825
 
 
57,895
 
 
35,433
 
Exploration and development of oil and gas properties
 
 
118,718
 
 
71,556
 
 
41,061
 
 
30,163
 
 
14,776
 
Property/facility acquisitions
 
 
112,249
 
 
2,845
 
 
48,579
 
 
5,880
 
 
2,273
 
Additions to vehicles, drilling rigs and other fixed assets
 
 
11,762
   
669
   
494
   
469
   
119
 
 Unaudited Operating Data
 
                           
 
Oil and gas producing operations (per BOE):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average sales price before hedging
 
$
47.01
 
$
33.64
 
$
24.48
 
$
20.11
 
$
19.63
 
Average sales price after hedging
 
 
41.62
 
 
30.32
 
 
22.52
 
 
19.39
 
 
19.79
 
Average operating costs - oil and gas production
 
 
11.79
 
 
10.09
 
 
9.57
 
 
7.83
 
 
6.86
 
Production taxes
   
1.37
   
.86
   
.51
   
.55
   
.49
 
G&A
 
 
2.55
 
 
2.99
 
 
2.40
 
 
1.98
 
 
1.93
 
DD&A - oil and gas production
 
 
4.54
 
 
3.96
 
 
2.86
 
 
2.55
 
 
3.28
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Production (MBOE)
 
 
8,401
 
 
7,517
 
 
6,040
 
 
5,251
 
 
5,044
 
Production (MMWh)
 
 
741
 
 
776
 
 
767
 
 
748
 
 
483
 
Proved Reserves Information:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total BOE
 
 
126,285
 
 
109,836
 
 
109,920
 
 
101,719
 
 
102,855
 
Standardized measure (2)
 
$
1,251,380
 
$
686,748
 
$
528,220
 
$
449,857
 
$
278,453
 
Year-end average BOE price for PV10 purposes
 
 
48.21
 
 
29.87
 
 
25.89
 
 
24.91
 
 
14.13
 
Other:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Return on average shareholders' equity
 
 
37.63
%
 
31.06
%
 
17.50
%
 
17.90
%
 
14.00
%
Return on average total assets
 
 
20.15
%
 
18.60
%
 
10.80
%
 
11.70
%
 
8.80
%
(1) Information has been revised to reflect the Company's change in allocation of cogeneration costs to oil and gas operations. See Item 7 Management’s Discussion and Analysis.


25

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



(2) See Supplemental Information About Oil & Gas Producing Activities.
(3) Information has been revised to reflect the Company's change in allocation of technical labor and production taxes. See Note 2 to the financial statements.

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations
 
Corporate Strategy. Berry’s mission is to increase shareholder value, primarily through increasing the net asset value and maximizing the cash flow and earnings of its assets. The strategies to accomplish these goals include:
·  
Growing production and reserves from existing assets while managing expenses
·  
Acquiring more light oil and natural gas assets with significant growth potential in the Rocky Mountain and Mid-Continent region
·  
Appraising our exploitation and exploration projects in an expedient manner
·  
Investing our capital in an efficient, disciplined manner to increase production and reserves
·  
Utilizing joint ventures with respected partners to enter new basins

Notable Items in 2005.
·  
Achieved record production which averaged 23,015 BOE/D, up 12% from 2004
·  
Achieved record cash from operating activities of $188 million, up 50% from 2004
·  
Achieved record net income of $112 million, up 62% from 2004
·  
2005 developmental capital expenditures were $131 million, up 82% from 2004
·  
Acquired and integrated the eastern Colorado Niobrara natural gas producing assets - acquisition cost of $105 million
·  
Added 24.9 million BOE of reserves before production ending 2005 at 126.3 million BOE
·  
Achieved reserve replacement rate of 296%
·  
Negotiated new four-year crude oil sales contract for California heavy oil production
·  
Observed positive results on Diatomite play and expanded pilot
·  
Placed price collars on 10,000 barrels per day of future production from 2006 through 2009
·  
Added approximately 186,000 gross (46,000 net) acres in the North Dakota Bakken play
·  
Added approximately 624,000 gross (315,000 net) acres to Tri-State area inventory
·  
Increased quarterly dividend to $.13 per share and paid special dividend of $.10 per share for total payout of $.60 per share
·  
Began drilling to assess several prospects including Lake Canyon, Coyote Flats and Tri-State area
·  
Increased financial capacity by establishing a $500 million unsecured credit facility
·  
Initiated a $50 million share buyback program

Acquisitions. On January 27, 2005, we acquired certain interests in the Niobrara fields in northeastern Colorado for approximately $105 million. At December 31, 2005 the properties consist of approximately 127,000 gross (100,000 net) acres. Production at acquisition was approximately 9 MMcf of natural gas per day, with estimated proved reserves of 87 Bcf. For the month of December 2005, production averaged approximately 13,800 MMcf per day and reserves were 105 Bcf. The acquisition included approximately 200 miles of a pipeline gathering system and gas compression facilities for delivery into interstate gas lines.

In January 2005, we acquired a working interest in eastern Colorado, western Kansas and southwestern Nebraska, from an industry partner. Berry and its partner, will jointly explore and develop shallow Niobrara natural gas, Sharon Springs shale gas and deeper Pennsylvanian formation oil assets on the acreage. We paid approximately $5 million for our working interest in the acreage and believe the potential of the Tri-State area can be exploited by using new drilling techniques, with 3-D seismic technology, to assess structural complexity, estimate potentially recoverable oil and gas and determine drilling locations.

In 2005, we completed several transactions whereby we now have working interests in 186,000 gross acres (46,000 net) located in the Williston Basin in North Dakota. These lease acquisitions, totaling approximately $11 million, provide us an entry into the emerging Bakken oil play in the Williston Basin. The acreage covers several contiguous blocks located primarily on the eastern flank of the Nesson Anticline. Development activity in the Middle Bakken play is generally expanding to the area surrounding the Nesson Anticline.

In October 2005, we purchased a 50% working interest in approximately 69,000 gross undeveloped acres (24,000 net) in Colorado’s Phillips and Sedgwick Counties. This additional Niobrara leasehold position is adjacent to and immediately north of Berry’s producing natural gas assets in Yuma County. We expect to begin shooting a 3-D seismic survey and drilling the first delineation wells in 2006.




26

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



On January 27, 2006, we announced an agreement with a private seller to acquire a 50% working interest in natural gas assets in the Piceance Basin of western Colorado for approximately $150 million in cash. Berry internally estimates there are 26 billion cubic feet (Bcf) of proved reserves and has identified over 600 drilling locations based on 10-acre development. We will be the operator in the 6,314 gross acres targeting gas in the Williams Fork section of the Mesaverde formation. We increased the 2006 capital budget by an additional $48 million to $208 million to develop this resource. There are two drilling rigs dedicated to this project, and we will ramp up our drilling activity to four rigs by the end of the year along with complementary services and goods to accelerate the development of this acquisition. Based on the productivity of this acreage and surrounding producing operations, we are seeking to add additional drilling rigs to accelerate development. The transaction closed on February 28, 2006.

Capital Expenditures. Excluding any future acquisitions, in 2006 we plan to spend approximately $208 million. These expenditures will be directed toward developing reserves, increasing oil and gas production and exploration opportunities. For 2006, Berry plans to invest approximately $146 million, or 70%, in our Rocky Mountain and Mid-Continent region assets, and $61 million, or 30%, in our California assets. Approximately half the capital budget is focused on converting probable and possible reserves into proved reserves and on our appraisal and exploratory projects.

This robust capital program allows Berry to continue its record activity levels by planning to drill 476 net wells and perform 55 well workover activities in 2006 versus approximately 188 wells and 140 well workovers in 2005. As a result, we are targeting production growth of 12% to average approximately 25,800 BOE per day, which includes the Piceance Basin acquisition, but before any other acquisitions, and we plan to continue to actively appraise significant acreage positions held for hydrocarbon potential. In 2006, we expect production to be approximately 70% heavy oil, 15% light oil and 15% natural gas and anticipate funding our capital program from internally generated cash flow. Successes may also encourage the initiation of additional discretionary projects. We have currently secured the necessary equipment and are meeting permit requirements to achieve the 2006 program.

Appraisal, Evaluation and Exploitation Activity. Since 2003, we have been active in assembling significant acreage positions which we believe are highly prospective for finding and developing commercial quantities of hydrocarbons. This chart depicts our prospective acreage by basin, all of which is in the Rocky Mountain and Mid-Continent region:
 
Rocky Mountain and Mid-Continent
We plan to appraise five project areas in this region in 2006 for an estimated $23 million budgeted. These five projects are Lake Canyon, Coyote Flats, Big Wash Unit, Tri-State Area and the Bakken Play. We have interests in over one million gross acres, including both productive and prospective, in the Rocky Mountain and Mid-Continent region and the acreage in the five appraisal projects accounts for about 80% of that total.




27

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



Uinta Basin Projects
Lake Canyon - Shallow: On January 13, 2006, we announced commercial success from our first two wells on this acreage. The Nielsen Marsing and Taylor Herrick wells have tested production rates of 98 and 163 BOE/D, respectively, from the same Green River formation that is productive immediately east (approximately 3 miles) in our Brundage Canyon field. Initial performance from these discovery wells suggests that expected reserves per well are on par with the Brundage Canyon field (approximately 80,000 BOE gross) that is currently being developed on 40-acre spacing. Current production from the Taylor Herrick well is not at full capacity as additional facilities are in the process of being installed. Production from the Nielsen Marsing well is selectively limited to two of five completion intervals within the well and will be further optimized by March 2006 when natural gas facilities are completed. We are proceeding with another four wells on the eastern edge of this 169,000 acre block. If the results of these wells are deemed satisfactory, Berry will expand the drilling program and attempt to drill up to another 30 wells over approximately 20,000 acres. The focus will be to begin the methodical appraisal of a sizeable portion of this acreage block. Berry’s working interest in these wells will be either 75% or 56.25% depending on the participation of the land owner. The shallow zones are those above the Wasatch which is at approximately 6,500 feet.

Lake Canyon - Deep: Berry’s industry partner recently reached total depth of 14,325 feet on its Mesaverde test and set casing to a depth of 11,539 feet. Testing will focus on several Upper Price River and shallower Wasatch intervals where analysis indicates gas potential; the deeper Mesaverde and Blackhawk intervals did not warrant further evaluation. Berry will participate with its industry partner to complete the testing and evaluation of the first deep well on the acreage once pipeline construction into the area is completed, which is currently targeted by May 1, 2006. The second well is scheduled to begin drilling in the fourth quarter of 2006.

Coyote Flats: We will continue to test the viability of the Ferron gas development and Emery CBM pilot with additional drilling.

Big Wash Unit: We will test the shallow oil and deeper gas potential located about two miles southeast of Brundage Canyon.

Denver-Julesburg Basin Projects
Tri-State Area: We will be very active in testing the Niobrara gas potential located in the Tri-State area of Colorado, Kansas and Nebraska. We will participate in 16 exploratory gas wells, drill 11 development wells and acquire additional 3D seismic. Immediately to the north of our producing assets in Yuma County, Colorado, we may drill up to 17 wells based on the acquisition of new seismic data covering the northern acreage.

Williston Basin Projects
Bakken Play: In North Dakota, we intend to participate with up to a 15% working interest in at least four horizontal oil wells to appraise the prospective oil formation.

California-Diatomite
In 2005, oil production from the initial 14 well pilot (6 producers) averaged approximately 135 Bbl/D. Based on promising results from the pilot project, we began an expansion of the pilot with a 25 well program (15 producers) in the third quarter of 2005, and completed it in the fourth quarter. We continue to assess the long-term economic and operating viability of the project as the early wells are an indication of future large-scale development. Results are in accordance with expectations. We are judiciously monitoring the steam to oil ratio (SOR) because we believe achieving an SOR of 6 or less is the threshold for commerciality. SOR measures how much steam is required for injection into the reservoir to produce one barrel of oil. Estimated original oil in place ranges between 200 million to 250 million barrels with targets of a minimum 25% recovery of original oil in place. In 2005, we booked 2.5 million BOE of reserves based on asset performance. We believe that the project continues to remain on track towards commerciality.

In 2006, we are expanding the commercial test of our diatomite resource by investing approximately $25 million in a program that will add another 50 wells (31 producers, 16 steam injectors, and 3 service wells). Since completing our expansion of the initial pilot in December 2005, we now have a total of 39 wells (21 producers, 15 steam injectors, and 3 service wells) that we will be using to monitor reservoir performance. In addition to the drilling program, we will add significant facilities including steam generation equipment and will be optimizing the pattern configuration and layout for the eventual full-field development if commerciality is determined.

Development Activity

Rocky Mountain and Mid-Continent
Approximately $93 million will be invested in this region, with $58 million targeting the continued development drilling of the Green River formation at Brundage Canyon to assist full development and will include a 20-acre spacing pilot. In northeastern Colorado, $17 million will be invested to acquire additional seismic data and drill 150 wells to further develop the Niobrara natural gas production from our producing assets.




28

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



California
Berry will invest $37 million in its heavy oil properties, utilizing horizontal well and new steam-optimization technologies to maximize recovery from our legacy assets. Development activity at our Poso Creek, Ethel D and Midway-Sunset assets will utilize improved application of steam flood technology to provide production growth.

See Item 1 Business for more information on Development Activity.

Obstacles and Risks to Accomplishment of Strategies and Goals. See Item 1A Other Factors Affecting the Company's Business and Financial Results for a detailed discussion of factors that affect our business, financial condition and results of operations.

Results of Operations. Approximately 86% of Berry's revenues are generated through the sale of oil and natural gas production under either negotiated contracts or spot gas purchase contracts at market prices. Over 83% of these volumes are from oil production, and the majority of those volumes are from heavy oil production in California. The remaining 14% of Berry's revenues are derived from electricity sales from cogeneration facilities which supply over half of Berry’s steam requirement for use in its California thermal heavy oil operations. We have invested in these facilities for the purpose of lowering our steam costs which are significant in the production of heavy crude oil.

Revenues. Sales of oil and gas were up 54% in 2005 compared to 2004 and up 157% from 2003. This significant improvement was due to increases in both oil and gas prices and production levels.

Improvements in production volume are due to acquisitions and sizable capital investments. Improvement in prices during 2005 are due to a tighter supply and demand balance and the nervousness of the market about possible supply disruptions. The increase in oil prices contributed roughly two-thirds of the revenue increase and the increase in production volumes contributed the other third. Approximately 84% of Berry’s oil and gas sales volumes in 2005 were crude oil, with 78% of the crude oil being heavy oil produced in California which was sold under a contract based on the higher of WTI minus a fixed differential or the average posted price plus a premium. This contract ended on January 31, 2006. The contract allowed us to improve our California revenues over the posted price by approximately $38 million and $13 million in 2005 and 2004, respectively.
 
On November 21, 2005, we entered into a new crude oil sales contract for our California production for deliveries beginning February 1, 2006. 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 $8.15, or 2) heavy oil field postings plus a premium of approximately $1.35. The initial term of the contract is for four years with a one-year renewal at our option. The agreement effectively eliminates our exposure to the risk of a widening WTI to California heavy crude price differential and allows us to effectively hedge our production based on WTI pricing similar to the previous contract. Initial deliveries under the contract are approximately 15,000 net barrels per day or approximately two-thirds of Berry's total production.

Brundage Canyon crude oil production, which is approximately 40 degree API gravity, is sold under contract at WTI less a fixed differential approximating $2.00 per barrel. This contract expires on September 30, 2006. Any new contract will be negotiated based on market prices. We believe the differential has widened by several dollars per barrel. The majority of this crude oil, while light, is a “paraffinic” crude, and can be processed efficiently by only a limited number of stranded inland refineries. The production of this type crude is increasing regionally and beginning to strain the capacity of these refineries. Other new crude sources from the region are pressuring pricing. If these refineries limit the volumes of this parraffinic crude oil they are willing to process, it could impact the marketability of this type of crude which, for Berry, represents approximately 3,500 Bbl/D of production or approximately 15% of total current production. We are investigating the market opportunities for this crude oil. If market prices continue to deteriorate, we may allocate capital expenditures to projects which produce natural gas and crude oils with lower paraffinic content until the refinery constraint is resolved.




29

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



The following companywide results are in millions (except per share data) for the years ended December 31:

 
 
2005
 
2004
 
2003
 
Sales of oil
 
$
289
 
$
210
 
$
130
 
Sales of gas
   
61
   
17
   
6
 
Total sales of oil and gas
 
$
350
 
$
227
 
$
136
 
Sales of electricity
   
55
 
 
48
   
44
 
Interest and other income, net
   
2
 
 
-
   
1
 
Total revenues and other income
 
$
407
 
$
275
 
$
181
 
Net income
 
$
112
 
$
69
 
$
32
 
Earnings per share (diluted)
 
$
5.00
 
$
3.08
 
$
1.47
 


Reserve Replacement Rate. The reserve replacement rate is calculated by dividing total new proved reserves added for the year by total production for the year. This measure is important because it is an indication of growth in proved reserves of the Company and, thus may impact the value of the Company. We believe our calculation of this measure is substantially similar to how other companies compute reserve replacement rate.

Hedging. See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to the financial statements.




30

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents


Operating data. The following table is for the years ended December 31:
 
 
 
2005
2004
2003
%
Oil and Gas
 
 
 
 
 
 
 
Heavy Oil Production (Bbl/D)
   
16,063
70
 
15,901
77
 
15,477
94
Light Oil Production (Bbl/D)
   
3,336
14
 
3,345
16
 
489
3
Total Oil Production (Bbl/D)
 
 
19,399
84
 
19,246
93
 
15,966
97
Natural Gas Production (Mcf/D)
 
 
21,696
16
 
7,752
7
 
3,499
3
Total (BOE/D)
 
 
23,015
100
 
20,537
100
 
16,549
100
Percentage increase from prior year
   
12%
   
24%
   
15%
 
 
 
 
 
 
 
 
 
 
 
 
Per BOE:
 
 
 
 
 
 
 
 
 
 
Average sales price before hedging
 
$
47.01
 
$
33.64
 
$
24.48
 
Average sales price after hedging
 
 
41.62
 
 
30.32
 
 
22.52
 
 
 
 
 
 
 
 
 
 
 
 
Oil, per Bbl:
                   
Average WTI price
 
$
56.70
 
$
39.21
 
$
31.16
 
Price sensitive royalties
   
(4.42
)
 
(2.78
)
 
(1.79
)
Gravity differential
   
(5.22
)
 
(4.93
)
 
(2.97
)
Crude oil hedges
   
(6.21
)
 
(2.93
)
 
(2.03
)
Average oil sales price after hedging
 
$
40.85
 
$
28.57
 
$
24.37
 
                     
Gas, per MMBtu:
                   
Average Henry Hub price
 
$
8.05
 
$
6.13
 
$
5.11
 
Natural gas hedges
   
(.11
)
 
(.01
)
 
.02
 
Location and quality differentials
   
(1.45
)
 
(.63
)
 
(.81
)
Average gas sales price after hedging
 
$
6.49
 
$
5.49
 
$
4.32
 

Electricity. Berry consumes natural gas as fuel to operate its three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the economic production of heavy oil. We sell our electricity to utilities under Standard Offer contracts, under which our revenues are linked to the cost of natural gas. Natural gas index prices are the primary determinant of Berry’s electricity sales price. The correlation between electricity sales and natural gas prices allows us to more effectively manage our cost of producing steam. Revenue and operating costs in the year ended 2005 were up from the year ended 2004 due to 18% higher electricity prices and 34% higher natural gas prices, respectively. We purchased approximately 38 MMBtu/D as fuel for use in our cogeneration facilities in the year ended December 31, 2005.

 
 
 
2005
   
2004
   
2003
 
Electricity
                   
Revenues (in millions)
 
$
55.2
 
$
47.6
 
$
44.2
 
Operating costs (in millions)
 
$
55.1
 
$
46.2
 
$
42.4
 
Decrease to total oil and gas operating expenses-per barrel
 
$
.02
 
$
.19
 
$
.32
 
Electric power produced - MWh/D
 
 
2,030
 
 
2,121
 
 
2,100
 
Electric power sold - MWh/D
 
 
1,834
 
 
1,915
 
 
1,925
 
Average sales price/MWh before hedging
 
$
82.73
 
$
70.24
 
$
62.91
 
Average sales price/MWh after hedging
 
$
82.73
 
$
70.24
 
$
61.95
 
Fuel gas cost/MMBtu (after hedging and excluding transportation)
 
$
7.30
 
$
5.46
 
$
4.88
 

Royalties. A price-sensitive royalty burdens a portion of our Midway-Sunset California property which produces approximately 3,800 barrels per day. This royalty is 75% of the amount of the heavy oil posted price above a base price which was $15.18 in 2005. This base price escalates at 2% annually, thus the threshold price is $15.48 per barrel in 2006. Amounts paid were $29 million, $19.3 million and $10.2 million in the years ended December 31, 2005, 2004 and 2003, respectively. Accounts payable associated with this royalty at year end 2005 was $29 million. Because our interest in the revenue varies according to crude prices, the continuing development on this property will depend on its future profitability.


31

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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A second price sensitive royalty burdens approximately 700 barrels per day at our Placerita field in California. This royalty is calculated when the sales price exceeds $26 per barrel up to a maximum. The royalty was $2.8 million, $1.4 million and $.3 million in the years ended December 31, 2005, 2004 and 2003, respectively. The maximum amount of the royalty over its life is $5 million, thus, we expect this royalty payable will end in the first quarter of 2006.

In 2005, the Bureau of Land Management revoked their royalty exemption for certain heavy oil properties. This resulted in a reduction to Berry of .9 million barrels of reserves and approximately 100 BOE/D in the fourth quarter of 2005. In December 2004, certain royalty owners exercised their right to convert their royalty interest into a working interest on our Formax property in the Midway-Sunset field. This resulted in a reduction of 1.8 million barrels of reserves and represented approximately 450 BOE/day as of December 31, 2004.

Oil and Gas Operating, Production Taxes, G&A and Interest Expenses. We believe that the most informative way to analyze changes in recurring operating expenses from one period to another is on a per unit-of-production, or BOE, basis. The following table presents information about our operating expenses for each of the years in the two-year period ended December 31, 2005:
 
 
 
Amount per BOE
 
Amount (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2005
 
2004
 
Change
 
2005
 
2004
 
Change
 
Operating costs - oil and gas production
 
$
11.79
 
$
10.09
 
 
17
%
$
99,066
 
$
73,838
 
 
34
%
Production taxes
   
1.37
   
.86
   
59
%
 
11,506
   
6,431
   
79
%
DD&A - oil and gas production
 
 
4.54
 
 
3.96
 
 
15
%
 
38,150
 
 
29,752
 
 
28
%
G&A
 
 
2.55
 
 
2. 99
 
 
(15)
%
 
21,396
 
 
22,504
 
 
(5)
%
Interest expense
 
 
0.72
 
 
0.27
 
 
167
%
 
6,048
 
 
2,067
 
 
193
%
Total
 
$
20.97
 
$
18.17
 
 
15
%
$
176,166
 
$
134,592
 
 
31
%
 
Our total operating costs, production taxes, G&A and interest expenses for 2005, stated on a unit-of-production basis, increased 15% over 2004. The changes were primarily related to the following items:

·  
Operating costs: Higher crude oil and natural gas prices have created an incentive for the U.S. domestic oil and gas industry to significantly increase exploration and development activities, which is straining the capacity for goods and services that support our industry. Thus, higher costs are prominent throughout the industry and resulted in higher operating costs per BOE for the year ended 2005 as compared to 2004. Costs in California were also higher due to increased well servicing activities and increases in steam costs. The cost of Berry’s steaming operations on our heavy oil properties represents a significant portion of our operating costs and will vary depending on the cost of natural gas used as fuel and the volume of steam injected. The following table presents steam information:
 
       
 
2005
2004
Change
 
Average volume of steam injected (Bbl/D)
70,032
69,200
1%
 
Fuel gas cost/MMBtu
$7.30
$5.46
34%
 

As commodity prices remain robust, we anticipate that cost pressures within our industry may continue. Natural gas prices impact our cost structure in California by approximately $1.75 per California BOE for each $1.00 move in natural gas price. The California production target for 2006 is 16,700 BOE/D.

·  
Production taxes: Higher prices, such as those exhibited in 2005, create increased production taxes.

·  
Depreciation, depletion and amortization: DD&A increased per BOE in the year ended 2005 from the year ended 2004 due to higher acquisition costs of our Rocky Mountain and Mid-Continent region assets as compared to our legacy heavy oil assets in California and higher finding and development costs. As these costs increase, our DD&A rates per BOE will also increase.





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Berry Petroleum Company - Dec. 31, 2005 Form 10-K
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·  
General and administrative: Approximately two-thirds of Berry’s G&A is compensation or compensation related costs. We intend to remain competitive in workforce compensation to achieve our growth plans. Stock-based compensation expense was $.35 per BOE and $.56 per BOE for the years ended December 31, 2005 and 2004, respectively. Compensation expenses increased due to increased staffing resulting from our growth, and increases in compensation levels and bonuses. Additionally, we incurred increased legal and accounting fees, primarily due to compliance with Sarbanes-Oxley, and growth through acquisitions and other financial reporting related matters. Legal and accounting expenses were $.28 per BOE in 2005 as compared to $.23 per BOE in 2004.

·  
Interest expense: We increased our outstanding borrowings to $75 million at December 31, 2005 as compared to $28 million at December 31, 2004. Average borrowings increased as a result of acquisitions of $112 million during 2005. Additionally, interest rates have increased by approximately 1.75% since December 31, 2004.

The following table presents information about our operating expenses for each of the years in the two-year period ended December 31, 2004:
 
 
 
Amount per BOE
 
Amount (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
   
 
 
2004
 
2003
 
Change
 
2004
 
2003
 
Change
 
Operating costs - oil and gas production
 
$
10.09
 
$
9.57
 
 
5
%
$
73,838
 
$
57,830
 
 
28
%
Production taxes
   
.86
   
.51
   
69
%
 
6,431
   
3,097
   
108
%
DD&A - oil and gas production
 
 
3.96
 
 
2.86
 
 
38
%
 
29,752
 
 
17,258
 
 
72
%
G&A
 
 
2.99
 
 
2.40
 
 
25
%
 
22,504
 
 
14,495
 
 
55
%
Interest expense
 
 
0.27
 
 
0.23
 
 
17
%
 
2,067
 
 
1,414
 
 
46
%
Total
 
$
18.17
 
$
15.57
 
 
17
%
$
134,592
 
$
94,094
 
 
43
%

Our total operating, production taxes, G&A and interest expenses for 2004, stated on a unit-of-production basis, increased 17% over 2003. The changes were primarily related to the following items:

    · Operating costs: 2004, on a per barrel basis, increased over 2003 due primarily to higher steam costs. The cost of Berry's steaming operations for its heavy oil properties   represents a significant portion of our operating costs and will vary depending on both the cost of natural gas used as fuel and the volume of steam injected during the year. The following table presents steam information:

 
2004
2003
Change
 
Average volume of steam injected (Bbl/D)
69,200
63,300
9%
 
Fuel gas cost/MMBtu
$5.46
$4.88
12%
 
 
    · Depreciation, depletion and amortization: 2004 was higher due to higher finding and development costs, the shorter reserve life of our Brundage Canyon properties in Utah and the cumulative effect of increased development activities in recent years. We expect DD&A to trend higher over the next few years due to the shorter reserve life of the Rocky Mountain assets compared to our California properties and continued development of our California and Rocky Mountain properties.
 
    · General and administrative: 2004 was up from 2003 due to stock-based compensation costs increasing by $2.8 million in 2004, or $.56 per BOE, which are primarily non-cash charges resulting from marked-to-market adjustments under the variable method of accounting prior to the change of certain exercise provisions of our stock option plan on July 29, 2004 and non-cash compensation expense under the fair value method of accounting. Compensation expenses increased due to increased staffing resulting from our growth, an increase in compensation levels and bonuses and costs related to a change in chief executive officers. Additionally, we incurred increased legal and accounting fees during 2004, primarily due to compliance with Sarbanes-Oxley and other financial reporting related matters.

    · Interest expense: 2004 was up from 2003. Although our borrowings at year-end 2004 were $28 million, down from $50 million in 2003, we borrowed $40 million in August 2003 to fund the acquisition of our Brundage Canyon property. We reduced our debt from 2003 levels during the latter half of 2004.


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Estimated 2006 Oil and Gas Operating, G&A and Interest Expenses

 
 
Amount per BOE
 
 
 
 Anticipated
 
 
 
   
 
 
range in 2006
 
2005
 
2004
 
 
 
                 
Operating costs-oil and gas production (1)
 
$
13.00 to 16.00
 
$
11.79
 
$
10.09
 
Production taxes
   
1.35 to 1.65
   
1.37
   
.86
 
DD&A
 
 
5.75 to 6.50
 
 
4.54
 
 
3.96
 
G&A
 
 
2.75 to 3.00
 
 
2.55
 
 
2.99
 
Interest expense
 
 
1.35 to 1.60
 
 
0.72
 
 
.27
 
Total
 
$
24.20 to 28.75
 
$
20.97
 
$
18.17
 
(1)  
Assuming natural gas prices of approximately NYMEX HH $8.50 MMBtu, we plan to inject steam at levels in 2006 comparable to, or slightly higher than 2005 levels.

Dry hole, abandonment and impairment. The $5.7 million reflected on Berry’s income statement under dry hole, abandonment and impairment is made up of the following three items:
·  
At December 31, 2004, we were in the process of drilling one exploratory well on our Midway-Sunset property and one exploratory well on our Coyote Flats prospect. These two wells were determined non-commercial in February 2005 and $2.2 million was incurred and expensed in 2005.
·  
Two exploratory wells at northern Brundage Canyon were expensed for $.6 million.
·  
Finally, we impaired the remaining carrying value of our Illinois and eastern Kansas prospective CBM acreage acquired in 2002 by $2.9 million.

Costs of $.7 million which were incurred on the Midway-Sunset property and the exploratory well on the Coyote Flats prospect as of December 31, 2004 were charged to expense. During 2003, we recorded a pre-tax write down of $4.2 million related to two CBM pilot projects.

Exploration costs. We incurred exploration costs of $3.6 million in 2005 compared to zero costs in 2004 and 2003. These costs consist primarily of geological and geophysical costs. Berry participated in 3-D seismic surveys at Lake Canyon, Utah and in the Tri-State area. We are projecting exploration costs in 2006 of between $4 million and $6 million.

Income Taxes. The Revenue Reconciliation Act of 1990 included a tax credit for certain costs associated with extracting high-cost, capital-intensive marginal oil or gas and which utilizes at least one of nine designated "enhanced" or tertiary recovery methods (EOR). Cyclic steam and steam flood recovery methods for heavy oil, which Berry utilizes extensively, are qualifying EOR methods. In 1996, California conformed to the federal law, thus, on a combined basis, we are able to achieve credits approximating 12% of our qualifying costs. The credit is earned only for qualified EOR projects by investing in one of three types of expenditures: 1) drilling development wells, 2) adding facilities that are integrally related to qualified EOR production, or 3) utilizing a tertiary injectant, such as steam, to produce oil. The credit may be utilized to reduce our tax liability down to, but not below, our alternative minimum tax liability. This credit has been significant through 2005 in reducing our income tax liabilities and effective tax rate. However, with higher crude oil prices and the increasing investment in its light crude oil and natural gas properties, Berry’s effective income tax rate trended higher in 2005 compared to prior years. The average U.S. wellhead price for crude oil exceeded $43 in 2005, thus triggering a full phase-out of the EOR credit for 2006. If the U.S. wellhead price of crude oil declines below the triggering point in future years, we will be able to claim the EOR credit on qualifying expenditures and our effective tax rate should decline. As of December 31, 2005 the Company has approximately $23 million of federal and $17 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2024 and 2015 for federal and California, respectively.

We experienced an effective tax rate of 31%, 23% and 12% reported in 2005, 2004 and 2003, respectively. The increase in effective tax rate during 2005 is primarily due to a much higher (over 80%) pre-tax income in relation to consistent EOR credits in 2005 over 2004. Our expansion outside of California and investment in non-thermal projects are also key factors in the increase. We have been able to achieve an effective tax rate below the statutory tax rate of approximately 40% through 2005 primarily as a result of significant EOR tax credits earned by our continued investment in the development of thermal EOR projects, both through capital expenditures and continued steam injection. We expect our effective tax rate will be higher as the EOR credit will be non-existent for 2006 and possibly later years, and we expect to have an effective tax rate in the 37% to 39% range in 2006, based on WTI prices averaging between $50 and $70. See Note 9 to the financial statements for further information.



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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 have been the primary reason for short-term changes in our cash flow from operating activities. The net long-term growth in our cash flow from operating activities is the result of growth in production as affected by period to period fluctuations in commodity prices.

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. We may revise our capital budget during the year as a result of acquisitions and/or drilling outcomes. Excess cash generated from operations is expected to be applied toward acquisitions, debt reduction or other corporate purposes.

Excluding any future acquisitions, in 2006 we plan to spend approximately $208 million on capital projects and anticipate funding these expenditures from internally generated cash flow. These expenditures will be directed toward developing reserves, increasing oil and gas production and exploration opportunities. For 2006, Berry plans to invest approximately $146 million, or 70%, in our Rocky Mountain and Mid-Continent region assets, and $61 million, or 30%, in our California assets. Approximately half the capital budget is focused on converting probable and possible reserves into proved reserves and on our appraisal and exploratory projects. Total capital expenditures in 2005, excluding acquisitions, were $119 million and included the drilling of approximately 188 new wells and completing 140 workovers on our properties. All capital expenditures, excluding acquisitions, were funded out of internally generated cash flow. See Item 1 Business for further details.

Dividends. The regular quarterly dividend was increased by 8%, from $.12 to $.13 per share, beginning with the September 2005 dividend. The total dividend payable on September 29, 2005 was $.23 per share which included a special $.10 per share dividend. This is the third consecutive year that we have raised the quarterly dividend and distributed a special dividend. This action resulted in a total payout in 2005 of $.60 per share, up 16% from the $.52 per share paid out in 2004 and up 28% from the $.47 per share paid out in 2003.

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. Crude oil and natural gas prices increased in 2005 (see graphs on page 30) and we increased production by 12%.

Our working capital balance fluctuates as a result of the amount of borrowings and the timing of repayments under our credit arrangements. We used 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. In 2005, the working capital deficit was substantially greater than 2004. The deficit is primarily made up of changes in the following four balance sheet accounts from 2005 as compared to 2004; a $14.7 million decrease in cash, an $11 million increase in the Formax royalty payable, an $11.5 million increase in the short-term line of credit which is used to improve cash management and a $9 million increase in fair value of derivatives (net liability) which is associated with our increased use of hedging in 2005.

The table below compares financial condition, liquidity and capital resources changes for the years ended December 31 (in millions, except for production and average prices):

 
2005
2004
Change
Production (BOE/D)
23,015
20,537
+12%
Average oil and gas sales prices, per BOE after hedging
$ 41.62
$ 30.32
+37%
Net cash provided by operating activities
$ 188
$ 125
+50%
Working capital
$ (54.8)
$ (3.8)
(134)%
Sales of oil and gas
$ 350
$ 227
+54%
Long-term debt
$ 75
$ 28
+168%
Capital expenditures, including acquisitions and deposits on acquisitions
$ 231
$ 85.3
+171%
Dividends paid
$ 13.2
$ 11.4
+16%

In June 2005, a share repurchase program was authorized for up to an aggregate of $50 million of Berry's outstanding Class A Common Stock. Through December 31, 2005, we had repurchased 108,900 shares for approximately $6.3 million. See Note 7 to the financial statements.

Hedging. See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to the financial statements.



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Credit Facility. See Note 6 to the financial statements for more information. We have a $500 million unsecured credit facility, which has a current borrowing base of $350 million and is an integral part of our financing structure that provides improved access to capital and the flexibility to support growth plans.

Contractual Obligations. Refer to Note 10 to the financial statements.
 
Application of Critical Accounting Policies. The preparation of financial statements in conformity with generally accepted accounting principles requires Management to make estimates and assumptions for the reporting period and as of the financial statement date. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities and the reported amounts of revenues and expenses. Actual results could differ from those amounts.

A critical accounting policy is one that is important to the portrayal of the Company's financial condition and results, and requires Management to make difficult subjective and/or complex judgments. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. The Company believes the following accounting policies are critical policies.

Successful Efforts Method of Accounting. The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned.

Oil and Gas Reserves. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company's oil and gas reserves are based on estimates prepared by independent engineering consultants. Reserve engineering is a subjective process that requires judgment in the evaluation of all available geological, geophysical, engineering and economic data. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices may significantly impact estimated reserve quantities. Depreciation, depletion and amortization (DD&A) expense and impairment of proved properties are impacted by the Company's estimation of proved reserves. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased DD&A expense, increased impairment of proved properties and a lower standardized measure of discounted future net cash flows.

Carrying Value of Long-lived Assets. Downward revisions in the Company’s estimated reserve quantities, increases in future cost estimates or depressed crude oil or natural gas prices could cause the Company to reduce the carrying amounts of its properties. The Company performs an impairment analysis of its proved properties annually by comparing the future undiscounted net revenue per the annual reserve valuation prepared by the Company’s independent reserve engineers to the net book carrying value of the assets. An analysis of the proved properties will also be performed whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable from future net revenue. Assets are grouped at the field level and if it is determined that the net book carrying value cannot be recovered by the estimated future undiscounted cash flow, they are written down to fair value. Cash flows used in the impairment analysis are determined based on Management’s estimates of crude oil and natural gas reserves, future crude oil and natural gas prices in effect at the end of the period and costs to extract these reserves. For its unproved properties, the Company performs an impairment analysis annually or whenever events or changes in circumstances indicate an asset’s net book carrying value may not be recoverable.

Derivatives and Hedging. The Company follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income. Under the provisions of SFAS 133, the Company may designate a derivative instrument as hedging the exposure to change in fair value of an asset or liability that is attributable to a particular risk (a fair value hedge) or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a cash flow hedge). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the


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derivative contract or by effectiveness assessments using statistical measurements. The Company's policy is to assess hedge effectiveness at the end of each calendar quarter.

Income Taxes. The Company computes income taxes in accordance with SFAS No. 109, Accounting for Income Taxes. SFAS No. 109 requires an asset and liability approach which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the Company's financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, the Company's federal and state income tax returns are generally not filed before the financial statements are prepared, therefore the Company estimates the tax basis of its assets and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carryforwards. A valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods. Adjustments related to differences between the estimates used and actual amounts reported are recorded in the period in which income tax returns are filed. These adjustments and changes in estimates of asset recovery could have an impact on results of operations. The Company may generate enhanced oil recovery tax credits from the production of its heavy crude oil in California which results in a deferred tax asset and believes that these credits will be fully utilized in future years and consequently has not recorded any valuation allowance related to these credits. Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate.

Asset Retirement Obligations. The Company has significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and gas production operations. The computation of the Company's asset retirement obligations (ARO) was prepared in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record the fair value of liabilities for retirement obligations of long-lived assets. The adoption of SFAS No. 143 in 2002 resulted in an immaterial difference in the liability that had been previously recorded by the Company. Estimating the future ARO requires Management to make estimates and judgments regarding timing, current estimates of plugging and abandonment costs, as well as what constitutes adequate remediation. The Company obtained estimates from third parties and used the present value of estimated cash flows related to its ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Changes in any of these assumptions can result in significant revisions to the estimated ARO. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment will be made to the related asset. Due to the subjectivity of assumptions and the relatively long life of the Company's assets, the costs to ultimately retire the Company's wells may vary significantly from previous estimates.

Environmental Remediation Liability. The Company reviews, on a quarterly basis, its estimates of costs of the cleanup of various sites including sites in which governmental agencies have designated the Company as a potentially responsible party. In accordance with SFAS No. 5, Accounting for Contingencies, when it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of remediation can be determined, the applicable amount is accrued. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is an estimation process that includes the subjective judgment of Management. In many cases, Management's judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations, which can be interpreted differently by regulators or courts of law, the experience of the Company and other companies in dealing with similar matters and the decision of Management on how it intends to respond to a particular matter. A change in estimate could impact the Company's oil and gas operating costs and the liability, if applicable, recorded on the Company's balance sheet.

Accounting for Business Combinations. The Company has grown substantially through acquisitions and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations using the purchase method, which is the only method permitted under SFAS 141. The accounting for business combinations is complicated and involves the use of significant judgment. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.
 
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices, where available, appraisals, comparisons to transactions for similar assets and liabilities and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.




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Each of the business combinations completed were of interests in oil and gas assets. We believe the consideration we paid to acquire these assets represents the fair value of the assets and liabilities acquired at the time of acquisition. Consequently, we have not recognized any goodwill from any of our business combinations, nor do we expect to recognize any goodwill from similar business combinations that we may complete in the future.
 
Stock-Based Compensation. Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plan as prescribed by SFAS 123, Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, the Company recognizes stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Stock option compensation expense is recognized from the date of grant to the vesting date. The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the following assumptions. Expected volatilities are based on the historical volatility of the Company's stock. The Company uses historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; the range results from certain groups of employees exhibiting different exercise behavior. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.

Electricity Cost Allocation. The Company’s investment in its cogeneration facilities has been for the express purpose of lowering steam costs in its California heavy oil operations and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam and use natural gas as fuel. The Company allocates steam costs to its oil and gas operating costs based on the conversion efficiency (of fuel to electricity and steam) of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. Electricity used in oil and gas operations is allocated at cost. A portion of the DD&A expenses associated with capital is allocated to DD&A - oil and gas production.

Recent Accounting Pronouncements. In December 2004, SFAS No. 123(R), Share-Based Payment, was issued which establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. This standard requires an issuer to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This eliminates the exception to account for such awards using the intrinsic method previously allowable under Accounting Principles Board (APB) Opinion No. 25. In April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for annual reporting periods beginning on or after June 15, 2005. As a result, the Company expects to adopt this statement on January 1, 2006. The Company previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Accordingly the Company believes SFAS No. 123(R) will not have a material impact on its financial statements; however, it continues to assess the potential impact that the adoption of SFAS No. 123(R) will have on the classification of tax deductions for stock-based compensation in the statements of cash flows.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities and is effective for the fiscal year end December 31, 2005. The adoption of FIN 47 by the Company did not have an immediate affect on the financial statements.

On April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1 Accounting for Suspended Well Costs that amends SFAS 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, to permit the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. In accordance with the guidance in the FSP, the Company applied the requirements prospectively in its second quarter of 2005. The adoption of FSP 19-1 by the Company did not have an immediate effect on the financial statements. However, it could impact the timing of the recognition of expenses for exploratory well costs in future periods.

In May 2005, SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on


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the nature and extent of any voluntary accounting changes and correction of errors after the effective date.

In February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 was issued. This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS No. 155 will become effective for the Company’s fiscal year after September 15, 2006. The impact of SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

As discussed in Note 15 to the financial statements, to minimize the effect of a downturn in oil and gas prices and protect the profitability of the Company and the economics of the Company’s development plans, from time to time the Company enters into crude oil and natural gas hedge contracts. The terms of contracts depend on various factors, including Management’s view of future crude oil and natural gas prices and the Company’s 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 Berry to participate in the upside. In California, Berry benefits from lower natural gas pricing and elsewhere, Berry benefits from higher natural gas pricing. The Company has, and may hedge both natural gas purchases and sales as determined appropriate by Management. Management regularly monitors the crude oil and natural gas markets and the Company’s financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate in accordance with Board established policy.

Currently, the Company’s hedges are in the form of swaps and collars. However, the Company may use a variety of hedge instruments in the future to hedge WTI or the index gas price. The Company has crude oil sales contracts in place, which are priced based on a correlation to WTI. Natural gas (for cogeneration and conventional steaming operations) is purchased at the SoCal border price and the Company sells its produced gas in Colorado and Utah at the Colorado Interstate Gas (CIG) and Questar index prices, respectively.

The following table summarizes the hedge position of the Company as of December 31, 2005:
 
 
 
Average
 
 
 
 
 
Average
 
 
 
 
Barrels
 
Average
 
 
 
MMBtu
 
Average
Term
 
Per Day
 
Price
 
Term
 
Per Day
 
Price
Crude Oil Sales (NYMEX WTI)
 
 
 
 
 
Natural Gas Sales (CIG)
 
 
 
 
Swaps
 
 
 
 
 
Swaps
 
 
 
 
1st Quarter 2006
 
3,000
 
$ 50.90
 
1st Quarter 2006
 
3,000
 
$ 7.49
2nd Quarter 2006
 
3,000
 
$ 50.20
 
 
 
 
 
 
3rd Quarter 2006
 
3,000
 
$ 49.56
 
 
 
 
 
 
     
 
 
 
Natural Gas Purchases (SoCal Border) 
 
 
 
 
Collars
   
 
Floor/Ceiling Prices
 
Swaps
 
     
1st through 3rd Quarter 2006 
 
7,000 
 
$47.50 / $70
 
1st Quarter 2006
 
5,000
 
$ 4.85
4th Quarter 2006
 
10,000
 
$47.50 / $70
 
2nd Quarter 2006
 
5,000
 
$ 4.85
Full year 2007
 
10,000
 
$47.50 / $70
 
         
Full year 2008
 
10,000
 
$47.50 / $70
 
         
Full year 2009
 
10,000
 
$47.50 / $70
 
         
 


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On March 1, 2006, the Company entered into the following derivative instruments:

 
 
Average
 
 
 
 
Average
   
 
 
MMBtu
 
Average
 
 
MMBtu
 
Average
Term
 
Per Day
 
Price
Term
 
Per Day
 
Price
Natural Gas Sales (NYMEX HH)
 
 
 
 
Natural Gas Sales (NYMEX HH)
 
 
 
 
Swaps
 
 
 
 
Collars
     
Floor/Ceiling Prices
2nd Quarter 2006
 
4,000
 
$ 6.96
4th Quarter 2006
 
8,000 
 
$8 / $9.72
3rd Quarter 2006
 
6,000
 
$ 7.35
1st Quarter 2007
 
12,000
 
$8 / $16.70
     
 
 
2nd Quarter 2007
 
13,000
 
$8 / $8.82
         
3rd Quarter 2007
 
14,000
 
$8 / $9.10
         
4th Quarter 2007
 
15,000
 
$8 / $11.39
         
1st Quarter 2008
 
16,000
 
$8 / $15.65
         
2nd Quarter 2008
 
17,000
 
$7.50 / $8.40
         
3rd Quarter 2008
 
19,000
 
$7.50 / $8.50
         
4th Quarter 2008
 
21,000
 
$8 / $9.50

Payments to the Company's counterparties are triggered when the monthly average prices are above the swap price in the case of the Company's crude oil and natural gas sales hedges and below the swap price for the Company's natural gas purchase hedge positions. Conversely, payments from our counterparties are received when the monthly average prices are below the swap price for the Company's crude oil and natural gas sales hedges and above the swap price for the Company's natural gas purchase hedge positions.

The collar strike prices will allow the Company to protect a significant portion of its future cash flow if 1) oil prices decline below $47.50 per barrel while still participating in any oil price increase up to $70 per barrel on these volumes and 2) if gas prices decline below approximately $8 per MMBtu. These hedges improve the Company’s financial flexibility by locking in significant revenues and cash flow upon a substantial decline in crude oil or natural gas prices. It also allows the Company to develop its long-lived assets and pursue exploitation opportunities with greater confidence in the projected economic outcomes and allows the Company to borrow a higher amount under the credit facility.

While the Company has designated its hedges as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, it is possible that a portion of the hedge related to the movement in the WTI to California heavy crude oil price differential may be determined to be ineffective. Likewise, the Company may have some ineffectiveness in its natural gas hedges put into place on March 1, 2006, due to the movement of HH pricing as compared to actual sales points. If this occurs, the ineffective portion will directly impact net income rather than being reported as Other Comprehensive Income. While Management believes that the differential will narrow and move closer toward its historical level over time, there are no assurances as to the movement in the differential. If the differential were to change significantly, it is possible that the Company’s hedges, when marked-to-market, could have a material impact on earnings in any given quarter and, thus, add increased volatility to the Company’s net income. The marked-to-market values reflect the liquidation values of such hedges and not necessarily the values of the hedges if they are held to maturity. Irrespective of the unrealized gains reflected in Other Comprehensive Income, the ultimate impact to net income over the life of the hedges will reflect the actual settlement values. All of these hedges have historically been deemed to be cash flow hedges with the marked-to-market valuations provided by external sources, based on prices that are actually quoted.

At December 31, 2005, Accumulated Other Comprehensive Loss, net of income taxes, consisted of $24.4 million of unrealized losses from the Company's crude oil and natural gas hedges. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2005 are expected to be reclassified to earnings through 2006 for the Company’s swaps and at current prices the Company’s collars are not expected to impact earnings.

     
2005
   
2004
   
2003
 
Net reduction of sales of oil and gas revenue due to hedging activities (in millions)
 
$
45.3
 
$
24.9
 
$
11.8
 
Net reduction of cost of gas due to hedging activities (in millions)
 
$
5.0
 
$
1.3
 
$
.1
 
Net reduction in revenue per BOE due to hedging activities
 
$
5.39
 
$
3.32
 
$
1.96
 

The use of hedging transactions may involve basis risk. The Company's oil hedges are based on reported settlement prices on the NYMEX. The basis risk between NYMEX and the Company's California heavy crude oil is mitigated by the Company's crude oil


40

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



sales contracts. On November 21, 2005, the Company entered into a new crude oil sales contract for its California production for deliveries beginning February 1, 2006. 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 $8.15, or 2) heavy oil field postings plus a premium of approximately $1.35. The initial term of the contract is for four years with a one-year renewal at the Company’s option. The Company has redesignated its existing crude oil collars as cash flow hedges related to California crude oil production, and there was no related effect to Other Comprehensive Income with regard to this redesignation.

Pricing in the existing crude oil sales agreement at Brundage Canyon is based upon average weekly WTI minus a fixed differential of approximately $2 per barrel through September 30, 2006. Any new contract will be negotiated based on market prices. Upon the expiration of these crude oil contracts, and absent any new contracts, the Company will be exposed to fluctuations in the basis differentials between WTI and the posted price for its crude oil at its various producing locations until new contracts which lock in such differential can be obtained.

The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. With respect to the Company’s hedging activities, the Company utilizes multiple counterparties on its hedges and monitors each counterparty’s credit rating. The Company also attempts to minimize credit exposure to counterparties through diversification.

Based on NYMEX futures prices as of December 31, 2005, (WTI $62.71; HH $10.83) and due to the backwardated nature of the futures prices as of that date, the Company would expect to make pre-tax future cash payments or to receive payments over the remaining term of its crude oil and natural gas hedges in place as follows: 

 
 
 
 
 Impact of percent change in futures prices
 
 
 
12/31/05
 
 on earnings
 
 
 
NYMEX Futures
 
 -20%
 
-10%
 
+ 10%
 
+ 20%
 
Average WTI Price
 
$
62.71
 
$
50.17
 
$
56.44
 
$
68.98
 
$
75.25
 
Crude Oil gain/(loss) (in millions)
 
 
(10.4
)
 
(.1
 
(5.2
 
(17.5
)
 
(92.8
)
Average HH Price
 
 
10.83
 
 
8.67
 
 
9.75
 
 
11.92
 
 
13.00
 
Natural Gas gain/(loss) (in millions)
   
3.8
   
2.4
   
3.1
   
4.4
   
5.1
 
 
                               
Net pre-tax future cash (payments) and receipts by year (in millions):
                               
2006
 
$
(6.6
)
$
2.3
 
$
(2.1
)
$
(11.5
)
$
(32.3
)
2007
   
-
   
-
   
-
   
(1.6
)
 
(24.8
)
2008
   
-
   
-
   
-
   
-
   
(18.7
)
2009
 
 
-
 
 
-
   
-
   
-
   
(11.9
Total
 
$
(6.6
)
2.3
 
$
(2.1
)
$
(13.1
)
$
(87.7
 
Interest Rates. The Company’s exposure to changes in interest rates results primarily from long-term debt. Total long-term debt outstanding at December 31, 2005 and 2004 was $75 million and $28 million, respectively. Interest on amounts borrowed is charged at LIBOR plus 1.0% to 1.75%. Based on year-end 2005 borrowings, a 1% change in interest rates would not have a material impact on the Company’s financial statements.

Item 8.  Financial Statements and Supplementary Data
 
Page
Report of PricewaterhouseCoopers LLP, an Independent Registered Public Accounting Firm
42
Balance Sheets at December 31, 2005 and 2004
43
Statements of Income for the Years Ended December 31, 2005, 2004 and 2003
44
Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003
44
Statements of Shareholders' Equity for the Years Ended December 31, 2005, 2004 and 2003
45
Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003
46
Notes to the Financial Statements
47
Supplemental Information About Oil & Gas Producing Activities (unaudited)
65

Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.



41

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 

To the Board of Directors and Shareholders of Berry Petroleum Company:
 
We have completed integrated audits of Berry Petroleum Company’s December 31, 2005 and 2004 financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its December 31, 2003 financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Financial statements
In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Berry Petroleum Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ PricewaterhouseCoopers LLP

Los Angeles, California
March 1, 2006



42

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 2005 and 2004
(In Thousands, Except Share Information)
 
 
2005
 
2004
 
ASSETS
           
 
Current assets:
             
Cash and cash equivalents
 
$
1,990
 
$
16,690
 
Short-term investments available for sale
 
 
661
 
 
659
 
Accounts receivable
 
 
59,672
 
 
34,621
 
Deferred income taxes
 
 
4,547
 
 
3,558
 
Fair value of derivatives
 
 
3,618
 
 
3,243
 
Prepaid expenses and other
 
 
4,398
 
 
2,230
 
Total current assets
 
 
74,886
 
 
61,001
 
Oil and gas properties (successful efforts basis), buildings and equipment, net
 
 
552,984
 
 
338,706
 
Deposits on potential property acquisitions
 
 
-
 
 
10,221
 
Long-term deferred income taxes
   
1,600
   
-
 
Other assets
 
 
5,581
 
 
2,176
 
 
 
$
635,051
 
$
412,104
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
Accounts payable
 
$
57,783
 
$
27,750
 
Revenue and royalties payable
 
 
34,920
 
 
23,945
 
Accrued liabilities
 
 
8,805
 
 
6,132
 
Line of credit
   
11,500
   
-
 
Income taxes payable
 
 
1,237
 
 
1,067
 
Fair value of derivatives
 
 
15,398
 
 
5,947
 
Total current liabilities
 
 
129,643
 
 
64,841
 
Long-term liabilities:
 
 
 
 
 
 
 
Deferred income taxes
 
 
55,804
 
 
47,963
 
Long-term debt
 
 
75,000
 
 
28,000
 
Abandonment obligation
 
 
10,675
 
 
8,214
 
Unearned revenue
   
866
   
-
 
Fair value of derivatives
 
 
28,853
 
 
-
 
 
 
 
171,198
 
 
84,177
 
Commitments and contingencies (Notes 10 and 11)
 
 
 
 
 
 
 
Shareholders' equity:
 
 
 
 
 
 
 
Preferred stock, $.01 par value, 2,000,000 shares authorized; no shares outstanding
 
 
-
 
 
-
 
Capital stock, $.01 par value:
 
 
 
 
 
 
 
Class A Common Stock, 50,000,000 shares authorized; 21,099,906 shares issued and outstanding (21,060,420 in 2004)
 
 
211
 
 
210
 
Class B Stock, 1,500,000 shares authorized; 898,892 shares issued and outstanding (liquidation preference of $899)
 
 
9
 
 
9
 
Capital in excess of par value
 
 
56,064
 
 
60,676
 
Accumulated other comprehensive loss
 
 
(24,380
)
 
(987
)
Retained earnings
 
 
302,306
 
 
203,178
 
Total shareholders' equity
 
 
334,210
 
 
263,086
 
 
 
$
635,051
 
$
412,104
 

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


43

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



BERRY PETROLEUM COMPANY
Statements of Income
Years ended December 31, 2005, 2004 and 2003
(In Thousands, Except Per Share Data)
 
 
2005
 
2004
 
2003
 
REVENUES
 
 
 
 
 
 
 
Sales of oil and gas
 
$
349,691
 
$
226,876
 
$
135,848
 
Sales of electricity
 
 
55,230
 
 
47,644
 
 
44,200
 
Interest and other income, net
 
 
1,804
 
 
426
 
 
816
 
 
 
 
406,725
 
 
274,946
 
 
180,864
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
Operating costs - oil and gas production
 
 
99,066
 
 
73,838
 
 
57,830
 
Operating costs - electricity generation
 
 
55,086
 
 
46,191
 
 
42,351
 
Production taxes
   
11,506
   
6,431
   
3,097
 
Exploration costs
   
3,649
   
-
   
-
 
Depreciation, depletion & amortization - oil and gas production
 
 
38,150
 
 
29,752
 
 
17,258
 
Depreciation, depletion & amortization - electricity generation
 
 
3,260
 
 
3,490
 
 
3,256
 
General and administrative
 
 
21,396
 
 
22,504
 
 
14,495
 
Interest
 
 
6,048
 
 
2,067
 
 
1,414
 
Dry hole, abandonment and impairment
 
 
5,705
 
 
745
 
 
4,195
 
Loss on disposal of assets
 
 
-
 
 
410
 
 
-
 
 
 
 
243,866
 
 
185,428
 
 
143,896
 
Income before income taxes
 
 
162,859
 
 
89,518
 
 
36,968
 
Provision for income taxes
 
 
50,503
 
 
20,331
 
 
4,605
 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
$
112, 356
 
$
69,187
 
$
32,363
 
 
 
 
 
 
 
 
 
 
 
 
Basic net income per share
 
$
5.10
 
$
3.16
 
$
1.49
 
 
 
 
 
 
 
 
 
 
 
 
Diluted net income per share
 
$
5.00
 
$
3.08
 
$
1.47
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share)
 
 
22,041
 
 
21,894
 
 
21,772
 
Effect of dilutive securities:
 
 
 
 
 
 
 
 
 
 
Stock options
 
 
390
 
 
523
 
 
215
 
Other
 
 
59
 
 
53
 
 
44
 
Weighted average number of shares of capital stock used to calculate diluted net income per share
 
 
22,490
 
 
22,470
 
 
22,031
 
 
 
 
 
 
 
 
 
 
 
 
Statements of Comprehensive Income
 
Years Ended December 31, 2005, 2004 and 2003
(In Thousands)
Net income
 
$
112,356
 
$
69,187
 
$
32,363
 
Unrealized gains (losses) on derivatives, net of income taxes of ($16,677), ($521), and ($2,421), respectively
 
 
(25,015
)
 
(781
)
 
(3,632
)
Reclassification of realized gains (losses) included in net income net of income taxes of $1,081, $2,284 and $1,712, respectively
 
 
1,622
 
 
3,426
 
 
2,569
 
Comprehensive income
 
$
88,963
 
$
71,832
 
$
31,300
 
 
The accompanying notes are an integral part of these financial statements. 



44

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



BERRY PETROLEUM COMPANY
Statements of Shareholders’ Equity
Years Ended December 31, 2005, 2004 and 2003
(In Thousands, Except Per Share Data)
 
 
Class A
 
Class B
 
Capital in Excess of Par Value
 
Deferred Stock-Based Compensation
 
Retained Earnings
 
Accumulated Other Comprehensive
Income (Loss)
 
Shareholders’ Equity
 
Balances at January 1, 2003
 
209
 
9
 
52,214
 
(346
)
123,257
 
(2,569
)
 $
172,774
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued compensation costs
 
 
-
 
 
-
 
 
3,319
 
 
-
 
 
-
 
 
-
 
 
3,319
 
Deferred director fees - stock compensation
 
 
-
 
 
-
 
 
169
 
 
-
 
 
-
 
 
-
 
 
169
 
Unearned stock-based compensation
 
 
-
 
 
-
 
 
773
 
 
(773
)
 
-
 
 
-
 
 
-
 
Amortization of deferred stock option compensation
 
 
-
 
 
-
 
 
-
 
 
11
 
 
-
 
 
-
 
 
11
 
Cash dividends declared - $.47 per share
 
 
-
 
 
-
 
 
-
 
 
-
 
 
(10,235
)
 
-
 
 
(10,235
)
Unrealized loss on derivatives
 
 
-
 
 
-
 
 
-
 
 
-
 
 
-
 
 
(1,063
)
 
(1,063
)
Net income
 
 
-
 
 
-
 
 
-
 
 
-
 
 
32,363
 
 
-
 
 
32,363
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2003
 
 
209
 
 
9
   
56,475
 
 
(1,108
)
 
145,385
 
 
(3,632
)
 
197,338
 
 
 
 
 
 
 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adoption of SFAS 123
 
 
-
 
 
-
   
(243
)
 
1,108
 
 
-
 
 
-
 
 
865
 
Stock-based compensation (155,269 shares)
 
 
1
 
 
-
   
3,451
 
 
-
 
 
-
 
 
-
 
 
3,452
 
Deferred director fees - stock compensation
 
 
-
 
 
-
   
993
 
 
-
 
 
-
 
 
-
 
 
993
 
Cash dividends declared - $.52 per share
 
 
-
 
 
-
   
-
 
 
-
 
 
(11,394
)
 
-
 
 
(11,394
)
Unrealized gain on derivatives
 
 
-
 
 
-
   
-
 
 
-
 
 
-
 
 
2,645
 
 
2,645
 
Net income
 
 
-
 
 
-
   
-
 
 
-
 
 
69,187
 
 
-
 
 
69,187
 
 
 
 
 
 
 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances at December 31, 2004
 
 
210
 
 
9
   
60,676
 
 
-
 
 
203,178
 
 
(987
)
 
263,086
 
                                             
Share repurchase (108,900 shares)
 
 
(2
)
 
-
   
(6,314
)
 
-
   
-
   
-
   
(6,316
)
Stock-based compensation (147,179 shares)
 
 
3
   
-
   
1,360
   
-
   
-
   
-
   
1,363
 
Deferred director fees - stock compensation
 
 
-
   
-
   
342
   
-
   
-
   
-
   
342
 
Cash dividends declared - $.60 per share
 
 
-
   
-
   
-
   
-
   
(13,228
)
 
-
   
(13,228
)
Unrealized loss on derivatives
 
 
-
   
-
   
-
   
-
   
-
   
(23,393
)
 
(23,393
)
Net income
 
 
-
   
-
   
-
   
-
   
112,356
   
-
   
112,356
 
 
 
 
                                       
Balances at December 31, 2005
 
$
211
 
$
9
 
$
56,064
 
$
-
 
$
302,306
 
$
(24,380
)
$
334,210
 

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



45

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 2005, 2004 and 2003
(In Thousands)
 
 
2005
 
2004
 
2003
 
Cash flows from operating activities:
 
 
 
 
 
 
 
Net income
 
$
112,356
 
$
69,187
 
$
32,363
 
Depreciation, depletion and amortization
 
 
41,410
 
 
33,242
 
 
20,514
 
Dry hole, abandonment and impairment
 
 
4,324
 
 
(569
)
 
3,756
 
Stock-based compensation expense
 
 
1,703
 
 
5,309
 
 
2,872
 
Deferred income taxes, net
 
 
20,847
 
 
10,815
 
 
1,496
 
Other, net
 
 
278
 
 
794
 
 
400
 
Increase in current assets other than cash, cash equivalents and short-term investments
 
 
(26,717
)
 
(11,310
)
 
(9,034
)
Increase in current liabilities other than line of credit
 
 
33,579
 
 
17,145
 
 
12,458
 
Net cash provided by operating activities
 
 
187,780
 
 
124,613
 
 
64,825
 
Cash flows from investing activities:
 
 
   
 
 
 
 
 
 
Exploration and development of oil and gas properties
 
 
(118,718
)
 
(71,556
)
 
(41,061
)
Property acquisitions
 
 
(112,249
)
 
(2,845
)
 
(48,579
)
Additions to vehicles, drilling rigs and other fixed assets
   
(11,762
)
 
(669
)
 
(494
)
Deposits on potential acquisitions
 
 
-
 
 
(10,221
)
 
-
 
Proceeds from sale of assets
 
 
130
 
 
101
 
 
1,890
 
Other, net
 
 
-
 
 
3
 
 
521
 
Net cash used in investing activities
 
 
(242,599
)
 
(85,187
)
 
(87,723
)
Cash flows from financing activities:
 
 
   
 
 
 
 
 
 
Proceeds from issuance of line of credit
   
18,000
   
-
   
-
 
Payment of line of credit
   
(6,500
)
 
-
   
-
 
Proceeds from issuance of long-term debt
 
 
144,000
 
 
-
 
 
40,000
 
Payment of long-term debt
 
 
(97,000
)
 
(22,000
)
 
(5,000
)
Dividends paid
 
 
(13,228
)
 
(11,394
)
 
(10,235
)
Book overdraft
   
1,921
   
-
   
-
 
Repurchase of shares
   
(6,315
)
 
-
   
-
 
Other, net
 
 
(759
)
 
-
   
(1,075
)
Net cash provided by (used in) financing activities
 
 
40,119
 
 
(33,394
)
 
23,690
 
 
 
 
 
 
 
 
 
 
 
 
Net (decrease) increase in cash and cash equivalents
 
 
(14,700
 
6,032
 
 
792
 
Cash and cash equivalents at beginning of year
 
 
16,690
 
 
10,658
 
 
9,866
 
Cash and cash equivalents at end of year
 
$
1,990
 
$
16,690
 
$
10,658
 
Supplemental disclosures of cash flow information:
 
 
 
 
 
 
 
 
 
 
Interest paid
 
$
5,275
 
$
1,243
 
$
2,125
 
Income taxes paid
 
$
26,544
 
$
11,652
 
$
2,510
 
Supplemental non-cash activity:
 
 
 
 
 
 
 
 
 
 
Increase (decrease) in fair value of derivatives:
 
 
 
 
 
 
 
 
 
 
Current (net of income taxes of $(3,631), $1,202, and ($635), respectively)
 
$
(5,446
$
1,804
 
$
(952
)
Non-current (net of income taxes of $(11,965), $561, and ($74), respectively)
 
 
(17,947
 
841
 
 
(111
)
Net increase (decrease) to accumulated other comprehensive income
 
$
(23,393
$
2,645
 
$
(1,063
)

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



46

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

1. General

The Company is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. The Company has 74% of its oil and gas reserves in California and 26% in the Rocky Mountain and Mid-Continent region. Approximately 70% of the Company's production is in California, most of which is heavy crude oil and is sold to a Bakersfield, California refinery. The Company has invested in cogeneration facilities which provide steam required for the extraction of heavy oil and which generates electricity for sale. Production of light crude oil and natural gas in the Rocky Mountain and Mid-Continent region accounts for approximately 30% of the Company’s production.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 2. Summary of Significant Accounting Policies

Cash and cash equivalents - The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2005 is $1.9 million representing outstanding checks in excess of the bank balance (book overdraft).

Short-term investments - All short-term investments are classified as available for sale. Short-term investments consist principally of United States treasury notes and corporate notes with remaining maturities of more than three months at date of acquisition and are carried at fair value. The Company utilizes specific identification in computing realized gains and losses on investments sold.

Accounts receivable - Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company does not have any off-balance-sheet credit exposure related to its customers. The Company assesses credit risk and allowance for doubtful accounts on a customer specific basis. As of December 31, 2005 and 2004, the Company does not have an allowance for doubtful accounts.

Income taxes - Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on reported pre-tax financial statement income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting, and principally relate to differences in the tax bases of assets and liabilities and their reported amounts using enacted tax rates in effect for the year in which differences are expected to reverse. If it is more likely than not that some portion or all of a deferred tax asset will not be realized, a valuation allowance is recognized.

Hedging - SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. The hedging relationship between the hedging instruments and hedged items, such as oil and gas, must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. The Company measures hedge effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, or in the case of options based on the change in intrinsic value. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss, such as time value for option contracts, is recognized immediately in the statements of income. Gains and losses on hedging instruments and adjustments of the carrying amounts of hedged items are included in revenues for hedges related to the Company's crude oil and natural gas sales and in operating expenses for hedges related to the Company's natural gas consumption. The resulting cash flows are reported as cash flows from operating activities. See Note 15 - Hedging.




47

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

2. Summary of Significant Accounting Policies (Cont'd) 

Oil and gas properties, buildings and equipment - The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.

Depletion of oil and gas producing properties is computed using the units-of-production method. Depreciation of lease and well equipment, including cogeneration facilities and other steam generation equipment and facilities, is computed using the units-of-production method or on a straight-line basis over estimated useful lives ranging from 10 to 20 years. Buildings and equipment are recorded at cost. Depreciation is provided on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Estimated residual salvage value is considered when determining depreciation, depletion and amortization (DD&A) rates.

Assets are grouped at the field level and if it is determined that the book value of long-lived assets cannot be recovered by estimated future undiscounted cash flows, they are written down to fair value. When assets are sold, the applicable costs and accumulated depreciation and depletion are removed from the accounts and any gain or loss is included in income. Expenditures for maintenance and repairs are expensed as incurred.

Asset retirement obligations - The Company has significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and gas production operations. The computation of the Company's asset retirement obligations (ARO) is prepared in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. Under this standard, the Company records the fair value of the future abandonment as capitalized abandonment costs in Oil and Gas Properties with an offsetting abandonment liability. The Company obtains estimates from third parties and uses the present value of estimated cash flows related to its ARO to determine the fair value. The capitalized abandonment costs are amortized with other property costs using the units-of-production method. The Company increases the liability monthly by recording accretion expense using the Company’s credit adjusted interest rate. Accretion expense is included in DD&A in the Company’s financial statements.

Revenue recognition - Revenues associated with sales of crude oil, natural gas, and electricity are recognized when title passes to the customer, net of royalties, discounts and allowances, as applicable. Electricity and natural gas produced by the Company and used in the Company’s operations are not included in revenues. Revenues from crude oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of the Company's net working interest (entitlement method).

Conventional steam costs - The costs of producing conventional steam are included in “Operating costs - oil and gas production.”

Cogeneration operations - The Company’s investment in its cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam. The Company allocates steam costs to its oil and gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. Electricity used in oil and gas operations is allocated at cost. Electricity consumption included in oil and gas operating costs for the years ended December 31, 2005, 2004 and 2003 was $5.7 million, $5 million and $4.2 million, respectively.

Shipping and handling costs - Shipping and handling costs, which consist primarily of natural gas transportation costs, are included in both "Operating costs - oil and gas production" or "Operating costs - electricity generation,” as applicable. Natural gas transportation costs included in these categories were $5.8 million, $5.4 million and $4 million, for 2005, 2004 and 2003, respectively.




48

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



 
BERRY PETROLEUM COMPANY
Notes to the Financial Statements

2. Summary of Significant Accounting Policies (Cont'd) 

Production taxes - Consist primarily of severance and ad valorem taxes.

Stock-based compensation - Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plan as prescribed by SFAS 123, Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, the Company recognizes stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Stock option compensation expense is recognized from the date of grant to the vesting date.

From January 1, 2004 to July 29, 2004 a portion of the Company's stock option compensation was calculated under variable accounting; however, the majority of stock option compensation was accounted for under the fair value method. In accordance with variable plan accounting, the Company recognized a corresponding liability determined by a marked-to-market valuation of the Company's stock at each financial reporting date. The Company revised certain stock option exercise provisions of the plan and, subsequent to July 29, 2004, variable plan accounting was no longer required.

Had compensation cost for the Company’s stock-based compensation plan (see Note 12) been based upon the fair value at the grant dates for awards under the plan consistent with SFAS No. 123, the Company’s compensation cost, net of related tax effects, net income and earnings per share would have been recorded as the pro forma amounts indicated below (in thousands, except per share data):

 
 
2003
 
Net income, as reported
 
$
32,363
 
Plus compensation cost (net of tax), as reported
 
 
2,335
 
Less compensation cost (net of tax), pro forma
 
 
(1,323
)
Net income, pro forma
 
$
33,375
 
   
 
 
 
Basic net income per share:
 
 
 
 
As reported
 
$
1.49
 
Pro forma
 
 $
1.53
 
 
 
 
 
 
Diluted net income per share:
 
 
 
 
As reported
 
$
1.47
 
Pro forma
 
$
1.52
 
 
Under SFAS No. 123, compensation cost would be recognized for the fair value of the employee's option rights. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:
 
 
 
2003
 
Yield
 
 
2.87
%
Expected option life - years
 
 
7.0
 
Volatility
 
 
27.87
%
Risk-free interest rate
 
 
3.86
%
 
Comprehensive income (loss) - Comprehensive income (loss) includes net earnings (loss) as well as unrealized gains and losses on derivative instruments, recorded net of tax.
 



49

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

2. Summary of Significant Accounting Policies (Cont'd) 

Net income per share - Basic net income per share is computed by dividing income available to shareholders (the numerator) by the weighted average number of shares of capital stock outstanding (the denominator). The Company’s Class B Stock is included in the denominator of basic and diluted net income. The computation of diluted net income per share is similar to the computation of basic net income per share except that the denominator is increased to include the dilutive effect of the additional common shares that would have been outstanding if all convertible securities had been converted to common shares during the period.

Environmental expenditures - The Company reviews, on a quarterly basis, its estimates of costs of the cleanup of various sites, including sites in which governmental agencies have designated the Company as a potentially responsible party. When it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. Any liabilities arising hereunder are not discounted.

Accounting for business combinations - The Company has accounted for all of its business combinations using the purchase method, which is the only method permitted under SFAS 141, Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. The Company has not recognized any goodwill from any business combinations.

Recent accounting developments - In December 2004, SFAS No. 123(R), Share-Based Payment, was issued which establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. This standard requires an issuer to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This eliminates the exception to account for such awards using the intrinsic method previously allowable under Accounting Principles Board (APB) Opinion No. 25. In April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for annual reporting periods beginning on or after June 15, 2005. As a result, the Company expects to adopt this statement on January 1, 2006. The Company previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Accordingly the Company believes SFAS No. 123(R) will not have a material impact on its financial statements; however, it continues to assess the potential impact that the adoption of SFAS No. 123(R) will have on the classification of tax deductions for stock-based compensation in the statements of cash flows.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for the fiscal year end December 31, 2005. The adoption of FIN 47 by the Company did not have an impact on the financial statements.

On April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1 Accounting for Suspended Well Costs that amends SFAS 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, to permit the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. In accordance with the guidance in the FSP, the Company applied the requirements prospectively in its second quarter of fiscal 2005. The adoption of FSP 19-1 by the Company did not have an effect on the financial statements. However, it could impact the timing of the recognition of expenses for exploratory well costs in future periods.



50

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

2. Summary of Significant Accounting Policies (Cont'd) 

In May 2005, SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date.

In February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 was issued. This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS No. 155 will become effective for the Company’s fiscal year after September 15, 2006. The impact of SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.

Revisions to the classification of technical labor costs and production taxes - In connection with the preparation of the 2005 financial statements the Company is reclassifying technical labor between general and administrative expenses and operating costs-oil and gas and reclassifying production taxes out of operating costs-oil and gas into a separate line. These reclassifications had no impact on net income or net cash provided by operating activities and did not effect previously reported total revenues, total operating expenses, net income or net cash provided by operating activities. Accordingly, the Company has revised prior classifications for the year ended December 31, 2004 as follows (in thousands):
 
 
 
2004
 
2003
 
Operating costs - oil and gas
 
 
 
   
As previously reported
 
$
82,419
$
62,554
 
As revised
 
 
73,838
 
57,830
 
Difference
 
$
8,581
$
4,724
 
 
 
         
Production taxes
 
 
 
 
   
As previously reported
 
$
-
$
-
 
As revised
 
 
6,431
 
3,097
 
Difference
 
$
(6,431)
$
(3,097)
 
             
G&A expenses
 
 
 
 
   
As previously reported
 
$
20,354
$
12,868
 
As revised
 
 
22,504
 
14,495
 
Difference
 
$
(2,150)
$
(1,627)
 
 
3. Fair Value of Financial Instruments

Cash equivalents consist principally of commercial paper investments. Cash equivalents of $2 million and $16.7 million at December 31, 2005 and 2004, respectively, are stated at cost, which approximates market.

The Company’s short-term investments available for sale at December 31, 2005 and 2004 consist of United States treasury notes that mature in less than one year and are carried at fair value. For the three years ended December 31, 2005, realized and unrealized gains and losses were insignificant to the financial statements. A United States treasury note with a market value of $.7 million is pledged as collateral to the California State Lands Commission as a performance bond on the Company’s Montalvo properties. The carrying value of the Company’s long-term debt approximates its fair value since the interest rate is variable.




51

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

4. Concentration of Credit Risks

The Company sells oil, gas and natural gas liquids to pipelines, refineries and oil companies and electricity to utility companies. Credit is extended based on an evaluation of the customer’s financial condition and historical payment record. 

Because of the Company’s ability to deliver significant volumes of crude oil over a multi-year period, the Company secured a thirty-nine month sales agreement, beginning in late 2002, with a major California refiner whereby the Company sold over 90% of its California production under a negotiated pricing mechanism. This contract ended on January 31, 2006. Pricing in this agreement was based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential near $6.00 per barrel. Both methods were calculated using a monthly determination. In addition to providing a premium above field postings, the agreement effectively eliminated the Company’s exposure to the risk of widening WTI to California heavy crude price differentials and allowed the Company to effectively hedge its production based on WTI pricing. 

On November 21, 2005, the Company entered into a new crude oil sales contract for its California production for deliveries beginning February 1, 2006. 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 $8.15, or 2) heavy oil field postings plus a premium of approximately $1.35. The initial term of the contract is for four years with a one-year renewal at the Company’s option.

For the three years ended December 31, 2005, the Company has experienced no credit losses on the sale of oil, gas and natural gas liquids.

The Company places its temporary cash investments with high quality financial institutions and limits the amount of credit exposure to any one financial institution. For the three years ended December 31, 2005, the Company has not incurred losses related to these investments. With respect to the Company’s hedging activities, the Company utilizes more than one counterparty on its hedges and monitors each counterparty’s credit rating.

The following summarizes the accounts receivable balances at December 31, 2005 and 2004 and sales activity with significant customers for each of the years ended December 31, 2005, 2004 and 2003 (in thousands). The Company does not believe that the loss of any one customer would impact the marketability of its California crude oil, gas, natural gas liquids or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the current crude oil sales customer could impact the marketability of a portion of the Company’s Utah crude oil volumes. The Company is investigating its market opportunities for this Utah crude oil.

 
 
 Accounts Receivable   
 
Sales
 
 
 
 For the Year Ended December 31,
 
For the Year Ended December 31,
 
Customer
 
2005 
 
 2004
 
2005
 
2004
 
2003    
 
Oil & Gas Sales:
 
  
 
  
 
 
 
 
 
 
 
A
 
$
24,389
 
$
18,391
 
$
291,093
 
$
202,966
 
$
142,422
 
B
 
 
6,929
 
 
5,465
 
 
81,342
 
 
58,807
 
 
5,566
 
C
 
 
1,086
 
 
670
 
 
11,863
 
 
9,138
 
 
6,524
 
 
 
$
32,404
 
$
24,526
 
$
384,298
 
$
270,911
 
$
154,512
 
Electricity Sales:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
D
 
$
4,375
 
$
3,402
 
$
24,391
 
$
21,755
 
$
20,334
 
E
 
 
7,806
 
 
2,764
 
 
30,893
 
 
26,524
 
 
24,616
 
 
 
$
12,181
 
$
6,166
 
$
55,284
 
$
48,279
 
$
44,950
 
 
Sales amounts will not agree to the Statements of Income due primarily to the effects of hedging and price sensitive royalties paid on a portion of the Company’s crude oil sales, which are netted in “Sales of oil and gas” on the Statements of Income.




52

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

5. Oil and Gas Properties, Buildings and Equipment

Oil and gas properties, buildings and equipment consist of the following at December 31 (in thousands):

 
 
2005
 
2004
 
Oil and gas:
 
 
 
 
 
Proved properties:
 
 
 
 
 
Producing properties, including intangible drilling costs
 
$
437,032
 
$
260,566
 
Lease and well equipment(1)
 
 
275,346
 
 
236,932
 
 
 
 
712,378
 
 
497,498
 
Unproved properties
 
 
 
 
 
 
 
Properties, including intangible drilling costs
 
 
36,440
 
 
5,569
 
Lease and well equipment
 
 
267
 
 
2,498
 
 
 
 
36,707
 
 
8,067
 
 
 
 
749,085
 
 
505,565
 
Less accumulated depreciation, depletion and amortization
 
 
208,597
 
 
168,994
 
 
 
 
540,488
 
 
336,571
 
Commercial and other:
 
 
 
 
 
 
 
Land
 
 
496
 
 
297
 
Buildings and improvements
 
 
4,351
 
 
3,703
 
Machinery and equipment
 
 
17,016
 
 
6,681
 
 
 
 
21,863
 
 
10,681
 
Less accumulated depreciation
 
 
9,367
 
 
8,546
 
 
 
 
12,496
 
 
2,135
 
 
 
$
552,984
 
$
338,706
 
(1)Includes cogeneration facility costs.
 
 
 
 
 
 
 
 
The following sets forth costs incurred for oil and gas property acquisition, development and exploration activities, whether capitalized or expensed (in thousands):
 
 
 
2005
 
2004
 
2003
 
Property acquisitions (1)
 
 
 
 
 
 
 
Proved properties
 
$
97,348
 
$
440
 
$
49,326
 
Unproved properties
 
 
24,566
 
 
2,405
 
 
853
 
Development (2)
 
 
112,255
 
 
66,664
 
 
42,391
 
Exploration
 
 
7,661
 
 
5,506
 
 
788
 
 
 
$
241,830
 
$
75,015
 
$
93,358
 
(1) Costs incurred for proved and unproved property acquisitions in 2005 include the reclassification of 2004 deposits of $5,505 and $4,716, respectively..
(2) Development costs include $.6 million, $.7 million and $.9 million that were charged to expense during 2005, 2004 and 2003, respectively.



53

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

5. Oil and Gas Properties, Buildings and Equipment (Cont'd)

In 2005, the Tri-State area is comprised of the following three acquisitions totaling approximately 315,000 net acres:
·  
Niobrara gas producing assets in Yuma County in northeastern Colorado in which the Company has approximately 52% working interest were purchased for approximately $105 million.
·  
Eastern Colorado, western Kansas and southwestern Nebraska assets in which the Company has approximately 50% working interest were purchased for approximately $5 million.
·  
Colorado’s Phillips and Sedgwick Counties in which the Company has approximately 50% working interest were purchased for approximately $.9 million. This Niobrara leasehold position is adjacent to and immediately north of Berry’s producing natural gas assets in Yuma County.

In 2005, the Company completed several transactions whereby it now has working interests in 186,000 gross acres (46,000 net) located in the Williston Basin in North Dakota. These lease acquisitions, totaling approximately $11 million, cover several contiguous blocks located primarily on the eastern flank of the Nesson Anticline.

In July 2004, the Company purchased approximately 169,000 gross acres with an industry partner in the Lake Canyon prospect in Utah, of which 124,500 gross (62,250 net) acres are leased from the Ute Tribe and 44,500 gross (22,250 net) acres are fee lands. Total cost to Berry was approximately $2 million. The Company will drill and operate shallow wells which target light oil in the Green River formation and retain a 75% working interest. The Company’s partner will drill and operate deeper wells and the Company will retain a 25% working interest. The Ute Tribe has the option to participate in all wells and retain up to a 25% working interest. As of December 31, 2005, the Company's minimum obligation under its agreement is $9.6 million through 2009. 

In 2003, the Company purchased leases totaling 45,380 acres in the Brundage Canyon field in Utah for approximately $45 million and the McVan property totaling 560 acres in the Poso Creek field in Kern County, California for approximately $2.6 million. The Company capitalized approximately $2.6 million in future abandonment obligations related to the 2003 acquisitions.

Results of operations from oil and gas producing
 
2005
 
2004
 
2003
 
and exploration activities (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales to unaffiliated parties
 
$
349,691
 
$
226,876
 
$
135,848
 
Production costs
 
 
(110,572
)
 
(80,269
)
 
(60,927
)
Depreciation, depletion and amortization
 
 
(38,150
)
 
(29,752
)
 
(17,258
)
Dry hole, abandonment and impairment
 
 
(5,705
)
 
(745
)
 
(4,195
)
 
 
 
195,264
 
 
116,110
 
 
53,468
 
Income tax expenses
 
 
(59,664
)
 
(33,840
)
 
(9,340
)
 
 
 
   
 
 
 
 
 
 
Results of operations from producing and exploration activities
 
$
135,600
 
$
82,270
 
$
44,128
 

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period of greater than one year since the completion of drilling (in thousands, except number of projects):
 
 
2005
 
2004
 
2003
 
Capitalized exploratory well costs that have been capitalized for a period of one year or less
 
$
6,037
 
$
2,941
 
$
511
 
Capitalized exploratory well costs that have been capitalized for a period greater than one year
 
 
-
 
 
511
 
 
-
 
Balance at December 31
 
$
6,037
 
$
3,452
 
$
511
 
 
 
 
 
 
 
 
 
 
 
 
Number of projects that have exploratory well costs that have been capitalized for a period of greater than one year
 
 
-
 
 
1
 
 
-
 



54

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements
 
5. Oil and Gas Properties, Buildings and Equipment (Cont'd)

The following table reflects the net changes in capitalized exploratory well costs during the years ended 2005, 2004 and 2003 (in thousands):
 
 
 
2005
 
2004
 
2003
 
Beginning balance at January 1
 
$
3,452
 
$
511
 
$
1,684
 
Additions to capitalized exploratory well costs pending the determination of proved reserves
 
 
8,840
 
 
3,420
 
 
1,081
 
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
 
 
(3,369
 
-
 
 
-
 
Capitalized exploratory well costs charged to expense
 
 
(2,886
 
479
 
 
2,254
 
Ending balance at December 31
 
$
6,037
 
$
3,452
 
$
511
 

In 2004, included in the amount of exploratory well costs that have been capitalized for a period of greater than one year since completion of drilling are costs of $.5 million that have been capitalized since 2003. These costs are related to the Company's diatomite project in the Midway-Sunset field and have been reclassified from exploratory well costs in 2005.

Dry hole, abandonment and impairment. 
The $5.7 million reflected on the Company’s income statement under dry hole, abandonment and impairment is made up of the following three items:
·  
At December 31, 2004, the Company was in the process of drilling one exploratory well on its Midway-Sunset property and one exploratory well on its Coyote Flats prospect. These two wells were determined non-commercial in February 2005 and $2.2 million was incurred and expensed in 2005.
·  
Two exploratory wells at northern Brundage Canyon were expensed for $.6 million.
·  
Finally, the Company impaired the remaining carrying value of its Illinois and eastern Kansas prospective CBM acreage acquired in 2002 by $2.9 million.

Costs of $.7 million which were incurred on the Midway-Sunset property and the exploratory well on the Coyote Flats prospect as of December 31, 2004 were charged to expense. During 2003, the Company recorded a pre-tax write down of $4.2 million related to two CBM pilot projects.

6. Long-term and Short-term Debt Obligations

 
 
2005
 
2004
 
Long-term debt for the years ended December 31 (in thousands):
 
 
 
 
 
Revolving bank facility
 
$
75,000
 
$
28,000
 
 
Long-term debt
In June 2005, the Company completed a new unsecured five year bank credit agreement (the Agreement) with a banking syndicate. The Agreement is a revolving credit facility for up to $500 million with nine banks and replaces the previous $200 million facility which was due to mature in 2006. Initial borrowings were $125 million which represented an amount equal to the borrowings outstanding under the previous credit facility and the initial borrowing base was established as $350 million. This transaction is considered a modification of a debt instrument due to modification of terms in accordance with Emerging Issues Task Force, (EITF) 98-14, Debtor’s Accounting forChanges in Line of Credit or Revolving Debt Arrangements.

The credit available under the Agreement is $264 million at December 31, 2005 without any increase to the borrowing base. The maximum amount available is subject to an annual redetermination of the borrowing base in accordance with the lender's customary procedures and practices. Both the Company and the banks have bilateral rights to one additional redetermination each year.




55

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements
 
6. Long-term and Short-term Debt Obligations (Cont’d)

The Agreement matures on July 1, 2010. Interest on amounts borrowed is charged at LIBOR plus a margin of 1.00% to 1.75%, or the higher of the lead bank’s prime rate or the federal funds rate plus .50% plus a margin of 0% to .50% at the Company’s option, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. The Company is required under the Agreement to pay an annual commitment fee of .25% to .38% on the unused portion of the credit facility.

The weighted average interest rate on outstanding borrowings at December 31, 2005 and 2004 was 4.9% and 3.37%, respectively. The Agreement contains restrictive covenants which, among other things, require the Company to maintain a certain debt to EBITDA ratio and a minimum current ratio, as defined. The Company was in compliance with all such covenants as of December 31, 2005.

Short-term debt
In November 2005, the Company completed a new 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 the Company or the lender. At December 31, 2005 the outstanding balance under this Line of Credit was $11.5 million. Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The weighted average interest rate on outstanding borrowings at December 31, 2005 was 5.4%.

7. Shareholders’ Equity

Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $1.00 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.

The Company's Capital Stock activity follows (in number of shares):
 
 
 
Class A
 
Class B
 
December 31, 2002
 
 
20,852,695
   
898,892
 
Shares issued from option exercises
 
 
51,683
   
-
 
Shares repurchased and retired
 
 
(6
)
 
-
 
December 31, 2003
 
 
20,904,372
   
898,892
 
Shares issued from option exercises
 
 
155,269
   
-
 
Shares issued under Director deferred compensation plan
 
 
797
   
-
 
Shares repurchased and retired
 
 
(18
)
 
-
 
December 31, 2004
 
 
21,060,420
   
898,892
 
Shares issued from option exercises
 
 
147,179
   
-
 
Shares issued under Director deferred compensation plan
 
 
1,207
   
-
 
Shares repurchased and retired
 
 
(108,900
)
 
-
 
December 31, 2005
 
 
21,099,906
   
898,892
 

In June 2005, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate of $50 million of the Company's outstanding Class A Common Stock. Through December 31, 2005, the Company repurchased 108,900 shares for approximately $6.3 million.

In December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities Exchange Act of 1934 to facilitate the repurchase of its shares of common stock. Rule 10b5-1 allows a company to purchase its shares at times when it would not normally be in the market due to possession of nonpublic information, such as the time immediately preceding its quarterly earnings releases. This 10b5-1 plan is authorized under, and is administered consistent with, the Company's $50 million share repurchase program. All repurchases of common stock are made in compliance with regulations set forth by the SEC and are subject to market conditions, applicable legal requirements and other factors.



56

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements
 
7. Shareholders’ Equity (Cont'd)

This program does not obligate the Company to acquire any particular amount of common stock and the plan may be suspended at any time at the Company's discretion.

Dividends
In 2005, the Company paid a special dividend of $.10 per share on September 29, 2005 and increased its regular quarterly dividend by 8%, from $.12 to $.13 per share beginning with the September 29, 2005 dividend. The Company's annual dividend is currently $.52 per share, paid quarterly in March, June, September and December.

In 2004, the Company paid a special dividend of $.06 per share on September 29, 2004 and increased its regular quarterly dividend by 9%, from $.11 to $.12 per share beginning with the September 2004 dividend. In 2003, the Company paid a special dividend of $.04 per share on May 2, 2003 and increased its regular quarterly dividend by 10%, from $.10 to $.11 per share beginning with the June 2003 dividend.

As of December 31, 2005, dividends declared on 3,984,080 shares of certain Common Stock are restricted, whereby 37.5% of the dividends declared on these shares are paid by the Company to the surviving member of a group of individuals, the B Group, as long as this remaining member shall live.

Dividend payments are limited by a covenant in the Company's credit facility to the greater of $20 million or 75% of net income.

Shareholder Rights Plan
In November 1999, the Company adopted a Shareholder Rights Agreement and declared a dividend distribution of one Right for each outstanding share of Capital Stock on December 8, 1999. Each Right, when exercisable, entitles the holder to purchase one one-hundredth of a share of a Series B Junior Participating Preferred Stock, or in certain cases other securities, for $38.00. The exercise price and number of shares issuable are subject to adjustment to prevent dilution. The Rights would become exercisable, unless earlier redeemed by the Company, 10 days following a public announcement that a person or group has acquired, or obtained the right to acquire, 20% or more of the outstanding shares of Common Stock or 10 business days following the commencement of a tender or exchange offer for such outstanding shares which would result in such person or group acquiring 20% or more of the outstanding shares of Common Stock, either event occurring without the prior consent of the Company.

The Rights will expire on December 8, 2009 or may be redeemed by the Company at $.01 per Right prior to that date unless they have theretofore become exercisable. The Rights do not have voting or dividend rights, and until they become exercisable, have no diluting effect on the earnings of the Company. A total of 250,000 shares of the Company’s Preferred Stock has been designated Series B Junior Participating Preferred Stock and reserved for issuance upon exercise of the Rights.

8. Asset Retirement Obligations

Under SFAS 143, the following table summarizes the change in abandonment obligation for the years ended December 31 (in thousands):

 
 
2005
 
2004
 
Beginning balance at January 1
 
$
8,214
 
$
7,311
 
Liabilities incurred
 
 
2,952
 
 
769
 
Liabilities settled
 
 
(1,382
)
 
(570
)
Accretion expense
 
 
891
 
 
704
 
 
 
 
   
 
 
 
Ending balance at December 31
 
$
10,675
 
$
8,214
 




57

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

9. Income Taxes

The provision for income taxes consists of the following (in thousands):
 
 
 
2005  
 
2004  
 
2003  
 
Current:
 
 
 
 
 
 
 
Federal
 
$
22,666
 
$
7,073
 
$
2,490
 
State
 
 
6,990
 
 
2,443
 
 
619
 
 
 
 
29,656
 
 
9,516
 
 
3,109
 
Deferred:
 
 
   
 
 
 
 
 
 
Federal
 
 
20,640
 
 
11,959
 
 
2,027
 
State
 
 
207
 
 
(1,144
)
 
(531
)
 
 
 
20,847
 
 
10,815
 
 
1,496
 
Total
 
$
50,503
 
$
20,331
 
$
4,605
 

The current deferred tax assets and liabilities are offset and presented as a single amount in the financial statements. Similarly, the non-current deferred tax assets and liabilities are presented in the same manner. The following table summarizes the components of the total deferred tax assets and liabilities before such financial statement offsets. The components of the net deferred tax liability consist of the following at December 31 (in thousands):
 
 
 
2005
 
2004
 
Deferred tax asset:
 
 
 
 
 
Federal benefit of state taxes
 
$
2,712
 
$
1,308
 
Credit carryforwards
 
 
31,929
 
 
26,478
 
Stock option costs
 
 
2,352
 
 
1,700
 
Derivatives
 
 
16,253
 
 
658
 
Other, net
 
 
139
 
 
1,610
 
 
 
 
53,385
 
 
31,754
 
Deferred tax liability:
 
 
   
 
 
 
Depreciation and depletion
 
 
(102,754
)
 
(76,311
)
Other, net
 
 
(289
)
 
152
 
 
 
 
   
 
 
 
 
 
 
(103,043
)
 
(76,159
)
 
 
 
   
 
 
 
Net deferred tax liability
 
$
(49,658
)
$
(44,405
)
 
At December 31, 2005, the Company's net deferred tax assets and liabilities were recorded as a current asset of $4.5 million and a net long-term liability of $54.2 million. At December 31, 2004, the Company's net deferred tax assets and liabilities were recorded as a current asset of $3.6 million and a long-term liability of $48 million.




58

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

9. Income Taxes (Cont’d)
 
Reconciliation of the statutory federal income tax rate to the effective income tax rate follows:
 
 
 
 
2005
 
 
2004
 
 
2003
 
Tax computed at statutory federal rate
 
 
35
%
 
35
%
 
35
%
 
 
 
 
 
 
 
 
 
 
 
State income taxes, net of federal benefit
 
 
3
 
 
1
 
 
1
 
Tax credits
 
 
(7
)
 
(9
)
 
(24
)
Recognition of tax basis of properties
 
 
-
 
 
(5
)
 
-
 
Other
 
 
-
 
 
1
 
 
-
 
Effective tax rate
 
 
31
%
 
23
%
 
12
%
 
The Company has approximately $23 million of federal and $17 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2024 and 2015 for federal and California, respectively.

10. Commitments

The Company's contractual obligations as of December 31, 2005 are as follows (in thousands):

Contractual Obligations
 
 
Total
 
2006
 
2007
 
2008
 
2009
 
2010
 
Thereafter
Long-term debt and interest
 
$
79,500
$
-
$
-
$
-
$
79,500
$
-
$
-
Abandonment obligations
 
 
10,675
 
315
 
360 
 
539
 
556
 
556
 
8,349
Operating lease obligations
 
 
802
 
538
 
 138
 
108
 
18
 
-
 
-
Drilling and rig obligations
 
 
16,698
 
8,948
 
2,400 
 
2,950
 
2,400
 
-
 
-
Firm natural gas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
transportation contracts
 
 
36,454
 
3,706
 
4,574 
 
4,398
 
4,386
 
4,386
 
15,004
Total
 
$
144,129
$
13,507
$
7,472
$
7,995
$
86,860
$
4,942
$
23,353

Long-term debt and interest - Long-term debt and related interest of approximately 6% on the long-term debt borrowings can be paid before its maturity date without significant penalty.

Operating leases - The Company leases corporate and field offices in California and in Denver. Rent expense with respect to the Company's lease commitments for the years ended December 31, 2005, 2004 and 2003 was $.6 million, $.6 million, and $.5 million, respectively.
 
Drilling obligation - The Company intends to participate in the drilling of over 16 gross wells on its Lake Canyon prospect over the next four years. The Company's minimum obligation under its exploration and development agreement is $9.6 million.

Drilling rig obligation - The Company is obligated in operating lease agreements for two drilling rigs, each for one year ending in 2006.

Firm natural gas transportation - The Company entered into several firm transportation contracts which provide the Company additional flexibility in securing its natural gas supply and allows the Company to potentially benefit from lower natural gas prices in the Rocky Mountains compared to natural gas prices in California.




59

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

11. Contingencies

The Company has accrued environmental liabilities for all sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, where it is probable that a loss will be incurred and the minimum cost or amount of loss can 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 higher than the liability currently accrued. Amounts currently accrued are not significant to the financial position of the Company and Management believes, based upon current site assessments, that the ultimate resolution of these matters will not require substantial additional accruals. The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of Management, the resolution of these matters will not have a material effect on the Company’s financial position, results of operations or liquidity.

12. Equity Compensation Plans

On December 2, 1994, the Board of Directors of the Company adopted the Berry Petroleum Company 1994 Stock Option Plan which was restated and amended in December 1997 and December 2001 (the 1994 Plan or Plan) and approved by the shareholders in May 1998 and May 2002, respectively. The 1994 Plan provided for the granting of stock options to purchase up to an aggregate of 3,000,000 shares of Common Stock. All options, with the exception of the formula grants to non-employee Directors, were granted at the discretion of the Compensation Committee of the Board of Directors. The term of each option did not exceed ten years from the date the options were granted. The 1994 Plan expired on December 2, 2004, and the shareholders approved a new equity incentive plan in May 2005.

The 2005 Equity Incentive Plan (the 2005 Plan) provides for granting of equity compensation to purchase up to an aggregate of 1,450,000 shares of Common Stock. All equity grants are at market value on the date of grant and at the discretion of the Compensation Committee or the Board of Directors. The term of each employee grant did not exceed ten years from the grant date and vest 25% per year for 4 years. The 2005 Plan also allows for grants to non-employee Directors. During 2005, each of the non-employee Directors received 5,000 options at the market value on the date of grant. The options granted to the non-employee Directors vest immediately.

Stock Options
Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plans as prescribed by SFAS 123, Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, the Company recognized stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Compensation expense under the fair value method for the years ended December 31, 2005 and 2004 was $2.9 million and $1.5 million, respectively. Additionally, the Company recorded $4.4 million and $3.9 million for the years ended December 31, 2004 and 2003, respectively, in compensation expense under the variable method of accounting prior to the modification of certain exercise provisions of the Company's 1994 Plan on July 29, 2004.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of the Company's stock. The Company uses historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; the range given below results from certain groups of employees exhibiting different exercise behavior. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.

 
2005
 
2004
Expected volatility
28% - 32%
 
25%
Weighted-average volatility
32%
 
25%
Expected dividends
.92% - 1.3%
 
1.27% - 2.45%
Expected term (in years)
4 - 5
 
4 - 7
Risk-free rate
3.8% - 4.4%
 
3.4% - 4.4%



60

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



 
BERRY PETROLEUM COMPANY
Notes to the Financial Statements

12. Equity Compensation Plans (Cont'd)

The following table summarizes information related to stock options outstanding and exercisable as of December 31, 2005:
 
 
 
 
 
 
 
Weighted
 
 
 
 
 
 
 
 
Weighted
 
Average
 
 
 
Weighted
Range of
 
 
 
Average
 
Remaining
 
 
 
Average
Exercise
 
Options
 
Exercise
 
Contractual
 
Options
 
Exercise
Prices
 
Outstanding
 
Price
 
Life
 
Exercisable
 
Price
$10.63 - $23.76
 
707,575
 
$17.27
 
6.61
 
514,475
 
$16.80
$23.77 - $36.90
 
103,500
 
28.79
 
8.47
 
25,875
 
28.79
$36.91 - $50.04
 
479,875
 
43.21
 
8.94
 
131,188
 
43.26
$50.05 - $63.18
 
264,463
 
61.25
 
9.95
 
40,000
 
61.29
     Total
 
1,555,413
 
$33.52
 
8.02
 
711,538
 
$24.61

Weighted average option exercise price information for the years ended December 31 is as follows:
 
 
 
2005
 
2004
 
2003
 
Outstanding at January 1
 
$
25.41
 
$
16.50
 
$
15.17
 
Granted during the year
 
 
59.13
 
 
40.60
 
 
19.31
 
Exercised during the year
 
 
16.80
 
 
15.73
 
 
13.15
 
Cancelled/expired during the year
 
 
37.36
 
 
18.02
 
 
16.55
 
Outstanding at December 31
 
 
33.52
 
 
25.41
 
 
16.50
 
Exercisable at December 31
 
 
24.61
 
 
17.61
 
 
15.62
 

The following is a summary of stock option activity for the years ended December 31 is as follows:

 
 
2005
 
2004
 
2003
 
Balance outstanding, January 1
 
 
1,565,625
 
 
1,701,925
 
 
1,604,575
 
Granted
 
 
299,463
 
 
567,750
 
 
411,500
 
Exercised
 
 
(302,600
)
 
(581,550
)
 
(294,150
)
Canceled/expired
 
 
(7,075
)
 
(122,500
)
 
(20,000
)
Balance outstanding, December 31
 
 
1,555,413
 
 
1,565,625
 
 
1,701,925
 
 
 
 
 
 
 
 
 
 
 
 
Balance exercisable at December 31
 
 
711,538
 
 
688,275
 
 
1,037,275
 
 
 
 
 
 
 
 
 
 
 
 
Available for future grant
 
 
1,150,537
 
 
-
 
 
615,600
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average remaining contractual life (years)
 
 
8
 
 
8
 
 
7
 
Weighted average fair value per option granted during the year based on the Black-Scholes pricing model
 
$
19.16
 
$
10.10
 
$
5.11
 



61

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

12. Equity Compensation Plans (Cont'd)

The total intrinsic value of options exercised during the years ended December 31, 2005, 2004 and 2003, was $12.6 million, $7.2 million and $1.6 million, respectively. At December 31, 2005, the intrinsic value of options outstanding was $36.8 million and the intrinsic value of exercisable options was $26.2 million.

As of December 31, 2005, there was $8.2 million of total unrecognized compensation cost related to stock options granted under the Plan. This cost is expected to be recognized over a weighted-average period over 4 years.

Restricted Stock Units
Under the 2005 Equity Incentive Plan, the Company began a long-term incentive program whereby restricted stock units (RSUs) are available for grant to certain employees and vest 25% per year over 4 years. In 2005, 70,950 RSUs were granted with a weighted average fair value per unit granted during the year of $61.29. As of December 31, 2005, there was $3.7 million of total unrecognized compensation cost related to RSUs granted under the Plan. This cost is expected to be recognized over a weighted-average period of 4 years, which is also the weighted average remaining contractual life. Unearned compensation under the restricted stock award plan is amortized over the vesting period. The Company will pay cash compensation on the RSUs in an equivalent amount of actual dividends paid on a per share basis of the Company’s outstanding common stock.

13. 401(k) Plan

The Company sponsors a defined contribution thrift plan under section 401(k) of the Internal Revenue Code to assist all eligible employees in providing for retirement or other future financial needs. Employee contributions (up to 6% of earnings) were matched by the Company at a range of $1 for $1 up to a maximum of $1.50 for $1 based on monthly profit levels for the Company. Effective November 1, 1992, the 401(k) Plan was modified to provide for increased Company matching of employee contributions whereby the monthly Company matching contributions will range from 6% to 9% of eligible participating employee earnings, if certain financial targets are achieved. The Company's contributions to the 401(k) Plan were $1.1 million, $.8 million and $.5 million in 2005, 2004 and 2003, respectively. Approximately 99% of full-time employees participate in the Plan. In December 2005, the 401(k) Plan was amended whereby effective January 1, 2006, the Company’s matching contribution will be $1 for $1 up to a maximum of 8% of an employee’s eligible compensation.

14. Director Deferred Compensation Plan

The Company established a non-employee director deferred stock and compensation plan to permit eligible directors, in recognition of their contributions to the Company, to receive fees as compensation and defer recognition of their compensation in whole or in part to a Stock Unit Account or an Interest Account. When the eligible director ceases to be a director, the distribution from the Stock Unit Account shall be made in shares using an established market value date and the distribution from the Interest Account shall be made in cash. The aggregate number of shares which may be issued to eligible directors under the plan shall not exceed 250,000, subject to adjustment for corporate transactions that change the amount of outstanding stock. The plan may be amended at any time, not more than once every six months, by the Compensation Committee or the Board of Directors and shall terminate, unless extended, on May 31, 2008.

Amounts allocated to the Stock Unit Account have the right to receive an amount equal to the dividends per share declared by the Company on the applicable dividend payment date and this “dividend equivalent” shall be treated as reinvested in an additional number of units and credited to their account using an established market value date. Amounts allocated to the Interest Account are credited with interest at an established interest rate.

Shares earned and deferred in accordance with the plan as of December 31, 2005, 2004 and 2003 were 6,885, 7,481 and 11,037, respectively.




62

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents




BERRY PETROLEUM COMPANY
Notes to the Financial Statements

15. Hedging

From time to time, the Company enters into crude oil and natural gas hedge contracts, the terms of which depend on various factors, including Management’s view of future crude oil and natural gas prices and the Company’s future financial commitments. This hedging program is designed to moderate the effects of a severe crude oil price downturn and protect certain operating margins in the Company's California operations. Currently, the hedges are in the form of swaps and collars, however, the Company may use a variety of hedge instruments in the future. Management regularly monitors the crude oil and natural gas markets and the Company’s financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate. All of these hedges have historically been deemed to be cash flow hedges with the marked-to-market valuations provided by external sources, based on prices that are actually quoted.

In June 2005, the Company entered into derivative instruments (zero-cost collars) for approximately 10,000 Bbl/D for the period January 1, 2006 through December 31, 2009. Based on WTI pricing, the floor is $47.50 and the ceiling is $70 per barrel. Upon entering into the new crude oil sales contract for California production in November 2005, the Company redesignated its existing crude oil collars as cash flow hedges related to California crude oil production, and there was no related effect to Other Comprehensive Income with regard to this redesignation. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. With respect to the Company’s hedging activities, the Company utilizes multiple counterparties on its hedges and monitors each counterparty’s credit rating. After the June hedge transaction, a significant credit risk concentration existed in one broker. In July 2005, the Company reduced the concentration as the hedges were transferred to multiple counterparties. The Company is not required to issue collateral on these hedging transactions.

At December 31, 2005 and 2004, Accumulated Other Comprehensive Loss consisted of $24.4 million and $1 million, respectively, net of tax of unrealized losses from the Company's crude oil and natural gas swaps and collars. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2005 are expected to be reclassified to earnings over the life of the underlying hedging contracts.

16.  
Pro Forma Results (unaudited)

On January 27, 2005, the Company acquired certain interests in the Niobrara field in northeastern Colorado for approximately $105 million (J-W Acquisition) to increase natural gas reserves and production. Assets purchased include $93 million of gas properties, $6 million of pipeline, and $ 5 million of compression equipment. Liabilities assumed included $1 million of asset retirement obligations.

The unaudited pro forma results presented below for the year ended December 31, 2005 and 2004 have been prepared to give effect to the J-W Acquisition on the Company’s results of operations under the purchase method of accounting as if it had been consummated on January 1, 2004. 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. (in thousands, except per share data):

     
2005
 
2004
Proforma Revenue
   
$ 408,088
 
$ 295,243
Proforma Income from operations
190,970
 
121,688
Proforma Net income
   
112,660
 
72,393
Proforma Basic earnings per share
5.11
 
3.31
Proforma Diluted earnings per share
5.01
 
3.22




63

Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Table of Contents



BERRY PETROLEUM COMPANY
Notes to the Financial Statements

17.  
Lease Receivable

Canyon Drilling LLC (“Canyon”), a 100% owned Colorado entity, was dissolved in the third quarter of 2005. Canyon owned a drilling rig which was leased to a third party. After the dissolution, the drilling rig is 100% owned by the Company. Concurrent with the dissolution of Canyon, the original lease was terminated and a revised three-year lease agreement was executed which has similar terms to the original lease. The revised lease includes a three year purchase option. The total net investment in the revised lease is approximately $3.4 million and is accounted for as a direct financing lease as defined by SFAS No. 13, Accounting for Leases. Net investment in this lease as of December 31, 2005 is as follows (in thousands):
 
Net minimum lease payments receivable
$ 4,781
 
Unearned income
(1,382
)
Net investment in direct financing lease
$ 3,399
 

Estimated future minimum lease payments, including the purchase option, to be received as of December 31, 2005 are as follows (in thousands):
 
2006
 
$ 504
 
2007
 
504
 
2008
 
3,773
 
Total
 
$ 4,781
 

Drilling Rigs
During 2005, the Company purchased two drilling rigs. The first rig is leased to a drilling company under a three-year contract (see above), while the second rig is currently being refurbished in preparation for leasing under a similar drilling contract. Both rigs carry purchase options available to the drilling company.


18. Quarterly Financial Data (unaudited)

The following is a tabulation of unaudited quarterly operating results for 2005 and 2004 (in thousands, except per share data).
 
 
 
 
 
 
 
 
 
Basic Net
 
Diluted Net
 
 
 
Operating
 
Gross
 
Net
 
Income
 
Income
 
2005
 
Revenues
 
Profit (2)
 
Income
 
Per Share
 
Per Share
 
First Quarter
 
$
87,847
 
$
41,931
 
$
22,505
 
$
1.02
 
$
1.00
 
Second Quarter
 
 
92,339
 
 
45,092
 
 
25,260
 
 
1.14
 
 
1.13
 
Third Quarter
 
 
109,372
 
 
59,880
 
 
34,219
 
 
1.55
 
 
1.52
 
Fourth Quarter
 
 
115,363
 
 
52,754
 
 
30,372
 
 
1.39
 
 
1.35
 
 
 
$
404,921
 
$
199,657
 
$
112,356
 
$
5.10
 
$
5.00
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2004
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter
 
$
57,139
 
$
20,948
 
$
10,364
 
$
0.48
 
$
0.47
 
Second Quarter
 
 
64,046
 
 
25,591
 
 
15,278
 
 
0.70
 
 
0.68
 
Third Quarter
 
 
72,904
 
 
31,716
 
 
18,229
 
 
0.83
 
 
0.82
 
Fourth Quarter (1)
 
 
80,431
 
 
36,989
 
 
25,316
 
 
1.15
 
 
1.11
 
 
 
$
274,520
 
$
115,244
 
$
69,187
 
$
3.16
 
$
3.08
 
(1) During the fourth quarter of 2004, the Company recorded a net tax benefit of approximately $2.3 million, primarily due to the recognition of deferred tax assets related to certain properties and other tax items.
(2) Information has been revised in 2004 to reflect the Company's change in allocation of technical labor as disclosed in Note 2.

 

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BERRY PETROLEUM COMPANY
Notes to the Financial Statements

19. Subsequent Events

On January 27, 2006 the Company announced that it had entered into an agreement with a private seller to acquire a 50% working interest in natural gas assets in the Piceance Basin of western Colorado for approximately $159 million to increase natural gas reserves and production. The acquisition was funded under the Company's existing credit facility. The effective date of the transaction is October 1, 2005. The Company purchased 100% interests in Piceance Operating Company (which owns a 50% working interest in the acquired assets). The Company will finalize its purchase price allocation after determining the post-closing adjustments. The transaction closed on February 28, 2006.
In February 2006, the Company purchased a third drilling rig for approximately $5 million for use in its Piceance Basin development program.

On March 1, 2006, the Board of Directors of the Company approved a two-for-one split of the Company's Class A Common Stock (Common Stock) and Class B Stock, subject to shareholder approval of an increase in authorized shares.The stock split will require that shareholders authorize the issuance of new shares at the Company’s May 17, 2006 annual meeting. Berry's shareholders will be asked to approve an increase in the Company's authorized shares of Common Stock to 100 million from the current 50 million shares and the Class B Stock to 3.0 million shares from 1.5 million shares. If approved, Berry’s transfer agent will distribute to each holder of record as of the close of business on May 17, 2006, one additional share for every share of stock held. The split will be in the form of a stock dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should begin trading on a post-split basis June 5, 2006. Based on shares outstanding on March 1, 2006, Berry would have approximately 42.2 million shares of Common Stock and 1.8 million shares of Class B Stock outstanding following the proposed stock split.

Supplemental Information About Oil & Gas Producing Activities (Unaudited)

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by the Company located solely within the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.

Disclosures of oil and gas reserves which follow are based on estimates prepared by independent engineering consultants as of December 31, 2005, 2004 and 2003. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. The information provided does not represent Management's estimate of the Company's expected future cash flows or value of proved oil and gas reserves.




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BERRY PETROLEUM COMPANY

Supplemental Information About Oil & Gas Producing Activities (Unaudited)(Cont'd)

Changes in estimated reserve quantities

The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2005, 2004 and 2003, and changes in such quantities during each of the years then ended were as follows (in thousands):
 
 
 
2005
 
2004
 
2003
 
 
 
Oil
 
Gas
 
 
 
Oil
 
Gas
 
 
 
Oil
 
Gas
 
 
 
 
 
Mbbls
 
Mmcf
 
BOE
 
Mbbls
 
Mmcf
 
BOE
 
Mbbls
 
Mmcf
 
BOE
 
Proved developed and Undeveloped reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of year
 
 
105,549
   
25,724
   
109,836
 
 
106,640
 
 
19,680
 
 
109,920
 
 
100,744
 
 
5,850
 
 
101,719
 
Revision of previous estimates
 
 
(681
)
 
4,084
   
-
 
 
2,975
 
 
8,246
 
 
4,349
 
 
(82
)
 
293
 
 
(33
)
Improved recovery
 
 
753
   
-
   
753
 
 
2,021
 
 
-
 
 
2,021
 
 
1,271
 
 
-
 
 
1,271
 
Extensions and discoveries
 
 
6,228
   
24,605
   
10,329
 
 
2,736
 
 
714
 
 
2,855
 
 
1,853
 
 
2,005
 
 
2,187
 
Property sales
 
 
(1,035
)
 
-
   
(1,035
)
 
(127
)
 
(77
)
 
(140
)
 
-
 
 
-
 
 
-
 
Production
 
 
(7,081
)
 
(7,919
)
 
(8,401
)
 
(7,044
)
 
(2,839
)
 
(7,517
)
 
(5,827
)
 
(1,277
)
 
(6,040
)
Purchase of reserves in place (1)
 
 
-
   
88,817
   
14,803
 
 
132
 
 
-
 
 
132
 
 
8,681
 
 
12,809
 
 
10,816
 
Royalties converted to working interest
 
 
-
   
-
   
-
 
 
(1,784
)
 
-
 
 
(1,784
)
 
-
 
 
-
 
 
-
 
End of year
 
 
103,733
   
135,311
   
126,285
 
 
105,549
 
 
25,724
 
 
109,836
 
 
106,640
 
 
19,680
 
 
109,920
 
 
 
 
               
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
               
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of year
 
 
78,207
   
20,048
   
81,549
 
 
78,145
 
 
12,207
 
 
80,180
 
 
72,889
 
 
3,252
 
 
73,431
 
End of year
 
 
78,308
   
70,519
   
90,061
 
 
78,207
 
 
20,048
 
 
81,549
 
 
78,145
 
 
12,207
 
 
80,180
 
(1) Refer to Note 16 to the financial statements.

The standardized measure has been prepared assuming year end sales prices adjusted for fixed and determinable contractual price changes, current costs and statutory tax rates (adjusted for tax credits and other items), and a ten percent annual discount rate. No deduction has been made for depletion, depreciation or any indirect costs such as general corporate overhead or interest expense. Cash outflows for future production and development costs include cash flows associated with the ultimate settlement of the asset retirement obligation.

Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands):

 
 
2005
 
2004
 
2003
 
Future cash inflows
 
$
6,088,170
 
$
3,281,155
 
$
2,845,767
 
Future production costs
 
 
(2,297,638
)
 
(1,405,432
)
 
(1,246,340
)
Future development costs
 
 
(333,722
)
 
(216,859
)
 
(198,279
)
Future income tax expenses
 
 
(1,115,516
)
 
(355,764
)
 
(324,097
)
Future net cash flows
 
 
2,341,294
 
 
1,303,100
 
 
1,077,051
 
10% annual discount for estimated timing of cash flows
 
 
(1,089,914
)
 
(616,352
)
 
(548,831
)
Standardized measure of discounted future net cash flows
 
$
1,251,380
 
$
686,748
 
$
528,220
 
Average sales prices at December 31:
 
 
   
 
 
 
 
 
 
Oil ($/Bbl)
 
$
48.38
 
$
29.49
 
$
25.77
 
Gas ($/Mcf)
 
$
7.91
 
$
6.61
 
$
4.94
 
BOE Price
 
$
48.21
 
$
29.87
 
$
25.89
 



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BERRY PETROLEUM COMPANY

Supplemental Information About Oil & Gas Producing Activities (Unaudited)(Cont'd)

Changes in standardized measure of discounted future net cash flows from proved oil and gas reserves (in thousands):
 
 
2005
 
2004
 
2003
 
 
 
 
 
 
 
 
 
Standardized measure - beginning of year
 
$
686,748
 
$
528,220
 
$
449,857
 
 
 
 
   
 
 
 
 
 
 
Sales of oil and gas produced, net of production costs
 
 
(240,039
)
 
(144,457
)
 
(75,143
)
Revisions to estimates of proved reserves:
 
 
   
 
 
 
 
 
 
Net changes in sales prices and production costs
 
 
702,867
 
 
190,861
 
 
45,292
 
Revisions of previous quantity estimates
 
 
5
 
 
40,419
 
 
(229
)
Improved recovery
 
 
12,267
 
 
18,787
 
 
9,400
 
Extensions and discoveries
 
 
168,291
 
 
26,541
 
 
16,171
 
Change in estimated future development costs
 
 
(157,068
)
 
(56,314
)
 
(75,841
)
Purchases of reserves in place
 
 
103,150
 
 
962
 
 
47,700
 
Sales of reserves in place
 
 
(9,613
)
 
(1,043
)
 
 -
 
Development costs incurred during the period
 
 
111,613
 
 
65,971
 
 
41,461
 
Accretion of discount
 
 
87,650
 
 
68,312
 
 
59,983
 
Income taxes
 
 
(392,886
)
 
(16,890
)
 
(8,896
)
Other
 
 
178,395
 
 
(21,430
)
 
18,465
 
Royalties converted to working interest
 
 
-
 
 
(13,191
)
 
-
 
 
 
 
   
 
 
 
 
 
 
Net increase (decrease)
 
 
564,632
 
 
158,528
 
 
78,363
 
 
 
 
   
 
 
 
 
 
 
Standardized measure - end of year
 
$
1,251,380
 
$
686,748
 
$
528,220
 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of December 31, 2005, the Company has carried out an evaluation under the supervision of, and with the participation of, the Company's Management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1034, as amended.

Based on their evaluation as of December 31, 2005, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.




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Management’s Report on Internal Control Over Financial Reporting

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers, or persons performing similar functions, and effected by the Company's Board of Directors, Management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

· pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company's assets;
· provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of the Company's Management and Directors; and
· provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of Management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control - Integrated Framework, Management concluded that its internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company's internal control over financial reporting that occurred during the three months ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. The Company may make changes in its internal control procedures from time to time in the future.

Item 9B. Other Information

On March 1, 2006, the Board of Directors of the Company approved a two-for-one split of the Company's Class A Common Stock (Common Stock) and Class B Stock, subject to shareholder approval of an increase in authorized shares.The stock split will require that shareholders authorize the issuance of new shares at the Company’s May 17, 2006 annual meeting. Berry's shareholders will be asked to approve an increase in the Company's authorized shares of Common Stock to 100 million from the current 50 million shares and the Class B Stock to 3.0 million shares from 1.5 million shares. If approved, Berry’s transfer agent will distribute to each holder of record as of the close of business on May 17, 2006, one additional share for every share of stock held. The split will be in the form of a stock dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should begin trading on a post-split basis June 5, 2006. Based on shares outstanding on March 1, 2006, Berry would have approximately 42.2 million shares of Common Stock and 1.8 million shares of Class B Stock outstanding following the proposed stock split.

On February 28, 2006 the Company completed the acquisition of a 50% working interest in natural gas assets in the Grand Valley field in the Piceance Basin of western Colorado for approximately $159 million. The purchase was funded under the Company's existing credit facility. Berry is the operator and owns a 50% working interest in 6,314 gross acres targeting gas in the Williams Fork section of the Mesaverde formation. Estimated daily production, net to Berry's interest, is approximately 1 million cubic feet of natural gas per day (MMcf/D) from three producing wells. The Company internally estimates 330 billion cubic feet of proved and probable


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reserves, none of which are included in Berry's 2005 year-end proved reserves of 126 million barrels of oil equivalent (BOE). With this acquisition, the Company's current estimate of its total proved reserves is over 130 million BOE. Berry is increasing its 2006 capital budget by an additional $18 million to $208 million for 2006 to accelerate the development of this resource. Seven wells are currently awaiting completion which is expected by April 1, 2006.

On January 31, 2006 the Company paid cash bonuses to employees related to the Company's and each individual's performance in 2005.  Mr Heinemann was paid $500,000, Mr. Goehring $185,500, Mr. Duginski $212,000, Mr. Magruder $212,000 and Mr. Crawford $96,300.  Effective January 1, 2006 Mr. Heinemann's salary was increased to $500,000, Mr. Goehring's to $250,000, Mr. Duginski's to $250,000, Mr. Magruder's to $250,000 and Mr. Crawford's to $200,000.

Effective in January 2006 the compensation of the Chairman of the Board, Mr. Martin H. Young, Jr., was increased by providing that he be paid the same meeting fees as all other directors in addition to the annual retainer of $125,000 and a special award of $40,000 was made to Mr. Young in recognition of extraordinary commitment of time and resources by him on behalf of the Company in 2005.  Mr. Young has elected to receive all compensation paid for his service to the Company in the form of Company stock under the terms of the Non-Employee Director Deferred Compensation Plan.

PART III

Item 10. Directors and Executive Officers of the Registrant

The information called for by Item 10 is incorporated by reference from information under the captions “Corporate Governance and Board Matters” and “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year. Information regarding Executive Officers is contained in this report in Part I, Item 1 Business.

Item 11. Executive Compensation

The information called for by Item 11 is incorporated by reference from information under the caption "Executive Compensation" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by Item 12 is incorporated by reference from information under the captions "Security Ownership of Directors and Management" and "Principal Shareholders" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.

Item 13. Certain Relationships and Related Transactions

The information called for by Item 13 is incorporated by reference from information under the caption "Certain Relationships and Related Transactions" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.

Item 14. Principal Accounting Fees and Services

The information called for by Item 14 is incorporated by reference from the information under the caption “Fees to Independent Accountants for 2005 and 2004” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.

PART IV

Item 15.  Exhibits, Financial Statement Schedules

A. Financial Statements and Schedules

See Index to Financial Statements and Supplementary Data in Item 8.



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B. Exhibits

Exhibit No.
Description of Exhibit
 
 
3.1
Registrant's Restated Certificate of Incorporation
3.2*
Registrant's Restated Bylaws dated July 1, 2005 (filed as Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005, File No. 1-09735)
4.1*
Registrant's Certificate of Designation, Preferences and Rights of Series B Junior Participating Preferred Stock (filed as Exhibit A to the Registrant's Registration Statement on Form 8-A12B on December 7, 1999, File No. 778438-99-000016)
4.2*
Rights Agreement between Registrant and ChaseMellon Shareholder Services, L.L.C. dated as of December 8, 1999 (filed by the Registrant on Form 8-A12B on December 7, 1999, File No. 778438-99-000016)
10.1
Description of Cash Bonus Plan of Berry Petroleum Company
10.2*
Form of Salary Continuation Agreement dated as of December 5, 1997, by and between Registrant and selected employees of the Company (filed as Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-9735)
10.3*
Form of Salary Continuation Agreements dated as of March 20, 1987, as amended August 28, 1987, by and between Registrant and selected employees of the Company (filed as Exhibit 10.12 to the Registration Statement on Form S-1 filed on June 7, 1989, File No. 33-29165)
10.4*
Instrument for Settlement of Claims and Mutual Release by and among Registrant, Victory Oil Company, the Crail Fund and Victory Holding Company effective October 31, 1986 (filed as Exhibit 10.13 to Amendment No. 1 to the Registrant's Registration Statement on Form S-4 filed on May 22, 1987, File No. 33-13240)
10.5*
Credit Agreement, dated as of June 27, 2005, by and between the Registrant and Wells Fargo Bank, N.A. and other financial institutions (filed as Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005, File No. 1-9735)
10.6
First Amendment to Credit Agreement, dated as of December 15, 2005 by and between the Registrant and Wells Fargo Bank, N.A. and other financial institutions
10.7*
Amended and Restated 1994 Stock Option Plan (filed as Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8 filed on August 20, 2002, File No. 333-98379)
10.8*
Berry Petroleum Company 2005 Equity Incentive Plan (filed as Exhibit 4.2 to the Registrant’s Form S-8 filed on July 29, 2005, File No. 333-127018)
10.9*
Form of the Stock Option Agreement, by and between Registrant and selected employees, directors, and consultants (filed as Exhibit 4.3 to the Registrant’s Form S-8 filed on July 29, 2005, File No. 333-127018)
10.10*
Form of the Stock Appreciation Rights Agreement, by and between Registrant and selected employees, directors, and consultants (filed as Exhibit 4.4 to the Registrant’s Form S-8 filed on July 29, 2005, File No. 333-127018)"
10.11*
Form of Stock Award Agreement, by an between Registrant and selected employees, directors, and consultants (filed as Exhibit 99.1 on Form 8-k filed on December 22, 2005, File No. 1-9735)
10.12*
Crude oil purchase contract, dated November 14, 2005 between Registrant and Big West of California, LLC (filed as Exhibit 99.2 on Form 8-k filed on November 22, 2005, File No. 1-9735)
10.13
Non-Employee Director Deferred Stock and Compensation Plan (as amended effective January 1, 2006)
10.14*
Employment Contract dated as of June 16, 2004 by and between the Registrant and Robert F. Heinemann (filed as Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-9735)
10.15*
Salary Continuation Agreement dated as of June 16, 2004 by and between the Registrant and Robert F. Heinemann (filed as Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-9735)
10.16*
Purchase and sale agreement between the Registrant and J-W Operating Company (filed as Exhibit 99.2 to the Registrant's Current Report on Form 8-K/A filed on February 15, 2005, File No. 1-9735)
10.17
Amended and Restated Purchase and Sale Agreement between Registrant and Orion Energy Partners, LP.
23.1
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm
23.2
Consent of DeGolyer and MacNaughton
31.1
Certification of Chief Executive Officer pursuant to SEC Rule 13(a)-14(a)
31.2
Certification of Chief Financial Officer pursuant to SEC Rule 13(a)-14(a)
32.1
Certification of Chief Executive Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32.2
Certification of Chief Financial Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
99.1*
Form of Indemnity Agreement of Registrant (filed as Exhibit 99.1 in Registrant's Annual Report on Form 10-K filed on March 31, 2005, File No. 1-9735)
99.2*
Form of "B" Group Trust (filed as Exhibit 28.3 to Amendment No. 1 to Registrant's Registration Statement on Form S-4 filed on May 22, 1987, File No. 33-13240)
*   Incorporated by reference



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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized on March 1, 2006.

BERRY PETROLEUM COMPANY

/s/ Robert F. Heinemann
/s/ Ralph J. Goehring
/s/ Donald A. Dale
ROBERT F. HEINEMANN
RALPH J. GOEHRING
DONALD A. DALE
President, Chief Executive Officer
Executive Vice President and
Controller
and Director
Chief Financial Officer
(Principal Accounting Officer)
 
(Principal Financial Officer)
 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the dates so indicated.

Name
Office
Date
 
 
 
/s/ Martin H. Young, Jr.
Chairman of the Board,
March 1, 2006
Martin H. Young, Jr.
Director
 
     
/s/ Robert F. Heinemann
President, Chief Executive Officer
March 1, 2006
Robert F. Heinemann
and Director
 
 
 
 
/s/ William F. Berry
Director
March 1, 2006
William F. Berry
 
 
 
 
 
/s/ Joseph H. Bryant
Director
March 1, 2006
Joseph H. Bryant
 
 
 
 
 
/s/ Ralph B. Busch, III
Director
March 1, 2006
Ralph B. Busch, III
 
 
 
 
 
/s/ William E. Bush, Jr.
Director
March 1, 2006
William E. Bush, Jr.
 
 
 
 
 
/s/ Stephen L. Cropper
Director
March 1, 2006
Stephen L. Cropper
 
 
 
 
 
/s/ J. Herbert Gaul, Jr.
Director
March 1, 2006
J. Herbert Gaul, Jr.
 
 
 
 
 
/s/ Thomas J. Jamieson
Director
March 1, 2006
Thomas J. Jamieson
 
 
     
/s/ J. Frank Keller
Director
March 1, 2006
J. Frank Keller
 
 
 
 
 



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