Berry Petroleum Company 10Q 03-31-2005
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


[X]  Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act

For the quarterly period ended March 31, 2005
Commission file number 1-9735


BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)

 
DELAWARE
  
77-0079387
  
 
(State or other jurisdiction of
  
(I.R.S. Employer
  
 
incorporation or organization)
  
Identification No.)
  




5201 Truxtun Avenue, Suite 300, Bakersfield, California
93309-0640
(Address of principal executive offices)
(Zip Code)

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

Former name, Former Address and Former Fiscal Year, if Changed Since
Last Report:
 
NONE

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 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  (  )

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES  (X)  NO  ( )

The number of shares of each of the registrant’s classes of capital stock outstanding as of March 31, 2005, was 21,164,726 shares of Class A Common Stock ($.01 par value) and 898,892 shares of Class B Stock ($.01 par value). All of the Class B Stock is held by a shareholder who owns in excess of 5% of the outstanding stock of the registrant.
 

BERRY PETROLEUM COMPANY
MARCH 31, 2005
INDEX

.
 
Page No
 
   
 
   
3
   
4
   
4
   
5
   
6
   
9
   
16
   
17
   
PART II.  Other Information
  
   
18
   
18
   
18
   
18
   
18
   
Item 6. Exhibits
18
   
18
 
2

BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Balance Sheets
(In Thousands, Except Per Share Information)
   
March 31,
  
December 31,
  
   
2005
  
2004
  
   
(Unaudited)
      
ASSETS
          
Current Assets:
          
Cash and cash equivalents
  
$
18,150
  
$
16,690
  
Short-term investments available for sale
    
659
   
659
 
Accounts receivable
    
45,127
   
34,621
 
Deferred income taxes
    
13,999
   
3,558
 
Fair value of derivatives
    
4,281
   
3,243
 
Prepaid expenses and other
    
2,265
   
2,230
 
Total current assets
    
84,481
   
61,001
 
               
Oil and gas properties (successful efforts basis), buildings and equipment, net
    
462,407
   
338,706
 
Deposit on potential property acquisitions
    
3,322
   
10,221
 
Other assets
    
2,587
   
2,176
 
               
   
$
552,797
  
$
412,104
  
LIABILITIES AND SHAREHOLDERS' EQUITY
              
Current liabilities:
              
Accounts payable
  
$
30,992
  
$
27,750
  
Revenue and royalties payable
    
10,374
   
23,945
 
Accrued liabilities
    
7,680
   
6,132
 
Income taxes payable
    
2,124
   
1,067
 
Fair value of derivatives
    
34,458
   
5,947
 
Total current liabilities
    
85,628
   
64,841
 
               
Long-term liabilities:
              
Deferred income taxes
    
51,783
   
47,963
 
Long-term debt
    
138,000
   
28,000
 
Abandonment obligations
    
9,369
   
8,214
 
Fair value of derivatives
    
2,770
   
-
  
     
201,922
   
84,177
 
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; 21,164,726 shares issued and outstanding (21,060,420 in 2004)
    
212
   
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
    
61,051
   
60,676
 
Accumulated other comprehensive loss
    
(19,066
)
  
(987
)
Retained earnings
    
223,041
   
203,178
 
Total shareholders' equity
    
265,247
   
263,086
 
               
   
$
552,797
  
$
412,104
  
The accompanying notes are an integral part of these financial statements.

3
 
BERRY PETROLEUM COMPANY
Part I. Financial Information
Part 1. Financial Statements
Condensed Income Statements
Three Month Periods Ended March 31, 2005 and 2004
(In Thousands, Except Per Share Information)
(Unaudited)

   
2005
  
2004
  
Revenues:
          
Sales of oil and gas
  
$
75,391
  
$
45,205
  
Sales of electricity
    
12,456
    
11,934
  
Interest and other income, net
    
148
    
203
  
     
87,995
    
57,342
  
Expenses:
              
Operating costs - oil and gas production
    
23,407
    
16,782
  
Operating costs - electricity generation
    
13,358
    
12,403
  
Exploration costs
    
561
    
-
  
Depreciation, depletion and amortization - oil and gas production
    
8,527
    
6,354
  
Depreciation, depletion and amortization - electricity generation
    
772
    
855
  
General and administrative
    
4,820
    
7,344
  
Dry hole, abandonment and impairment
    
2,021
    
-
  
Interest
    
1,162
    
531
  
     
54,628
    
44,269
  
               
Income before income taxes
    
33,367
    
13,073
  
Provision for income taxes
    
10,862
    
2,709
  
               
Net income
  
$
22,505
  
$
10,364
  
               
Basic net income per share
  
$
1.02
  
$
.48
  
Diluted net income per share
  
$
1.00
  
$
.47
  
Cash dividends per share
  
$
.12
  
$
.11
  
Weighted average number of shares of capital stock outstanding used to calculate basic net income per share
    
21,981
    
21,817
  
Effect of dilutive securities:
              
Stock options
    
433
    
215
  
Other
    
56
    
51
  
               
Weighted average number of shares of capital stock used to calculate diluted net income per share
    
22,470
    
22,083
  
 
Condensed Statements of Comprehensive Income
Three Month Periods Ended March 31, 2005 and 2004
(In Thousands)
(Unaudited)

   
2005
  
2004
  
Net income
  
$
22,505
  
$
10,364
  
Unrealized gains (losses) on derivatives, (net of income taxes of $12,165and $1,135 in 2005 and 2004, respectively)
    
(18,831
)
  
(1,703
)
Reclassification of unrealized losses on derivatives included in net income (net of income taxes of ($501) and ($1,378) in 2005 and 2004, respectively)
    
752
   
2,067
 
Comprehensive income
  
$
4,426
  
$
10,728
  

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

4

BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Condensed Statements of Cash Flows
Three Month Periods Ended March 31, 2005 and 2004
(In Thousands)
(Unaudited)

   
2005
  
2004
  
Cash flows from operating activities:
          
Net income
  
$
22,505
  
$
10,364
  
Depreciation, depletion and amortization
    
9,299
   
7,209
 
Abandonment costs
    
(213
)
  
(105
)
Deferred income taxes, net
    
5,042
   
2,270
 
Stock-based compensation expense
    
376
   
3,240
 
Other, net
    
89
   
147
 
Increase in current assets other than cash, cash equivalents and short-term investments
    
(10,541
)
  
(4,490
)
Increase (decrease) in current liabilities
    
(7,305
)
  
931
 
               
Net cash provided by operating activities
    
19,252
   
19,566
 
               
Cash flows from investing activities:
              
Capital expenditures, excluding property acquisitions
    
(15,681
)
  
(18,440
)
Property acquisitions
    
(109,469
)
  
-
  
               
Net cash used in investing activities
    
(125,150
)
  
(18,440
)
               
Cash flows from financing activities:
              
Proceeds from issuance of long-term debt
    
116,000
   
-
  
Payment of long-term debt
    
(6,000
)
  
-
  
Dividends paid
    
(2,642
)
  
(2,401
)
               
Net cash provided by (used in) financing activities
    
107,358
   
(2,401
)
               
Net increase (decrease) in cash and cash equivalents
    
1,460
   
(1,275
)
               
Cash and cash equivalents at beginning of year
    
16,690
   
10,658
 
               
Cash and cash equivalents at end of period
  
$
18,150
  
$
9,383
  
               
Supplemental non-cash activity:
              
Increase (decrease) in fair value of derivatives:
              
Current (net of income taxes of $10,756 and $151 in 2005 and 2004, respectively)
  
$
(16,717
)
$
(227
)
Non-current (net of income taxes of $908 and ($394) in 2005 and 2004, respectively)
    
(1,362
)
  
591
 
               
Net (decrease) increase to accumulated other comprehensive income
  
$
(18,079
)
$
364
  

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

5
 
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 1. Financial Statements
Notes to Condensed Financial Statements
March 31, 2005
(Unaudited)
 
1. All adjustments which are, in the opinion of Management, necessary for a fair statement of the Company’s financial position at March 31, 2005 and December 31, 2004 and results of operations and cash flows for the three-month periods ended March 31, 2005 and 2004 have been included. All such adjustments are of a normal recurring nature. The results of operations and cash flows are not necessarily indicative of the results for a full year.

2. The accompanying unaudited condensed financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2004 financial statements. The December 31, 2004 Form 10-K should be read in conjunction herewith. The year-end condensed balance sheet was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

3. Fair value of derivatives. Due to the increase in NYMEX future strip crude oil prices at March 31, 2005 from December 31, 2004, the Company’s fair value of derivatives liability increased to $37.2 million at March 31, 2005 from $5.9 million at December 31, 2004. The unrealized loss, net of income taxes, of $18.8 million is recorded in other comprehensive income on the Company’s balance sheet at March 31, 2005. The deferred tax benefit of the unrealized loss is reflected as an addition to the deferred income tax asset on the Company’s balance sheet.

4. Asset Retirement Obligations. The Company follows SFAS No. 143, Accounting for Asset Retirement Obligations, for recording future site restoration costs related to its oil and gas properties. Under SFAS 143, the following table summarizes the change in abandonment obligation for the three months ended March 31, 2005 and 2004, respectively, (in thousands):
 
   
2005
  
2004
  
           
Beginning balance at January 1
  
$
8,214
  
$
7,311
  
Liabilities incurred
    
1,153
   
-
 
Liabilities settled
    
(213
)
  
(105
)
Accretion expense
    
215
   
163
 
               
Ending balance at March 31
  
$
9,369
  
$
7,369
  
 
6

5. Certain amounts in the condensed income statement for the three months ended March 31, 2004 have been reclassified to conform to the 2005 presentation. In the fourth quarter of 2004, the Company concluded that it was appropriate to revise its allocation of cogeneration costs to oil and gas operations. The revised allocation is based on the thermal efficiency (of fuel to electricity and steam) of the Company’s cogeneration facilities. In addition, in 2005 the Company is reclassifying technical labor between general and administrative expenses and operating costs - oil and gas. Accordingly, the Company has revised prior classifications for the three months ended March 31, 2004 as follows (in thousands):
 
   
2004
  
Operating costs - oil and gas
      
As previously reported
 
$
18,020
  
As revised
    
16,782
 
Difference
  
$
1,238
  
         
Operating costs - electricity generation
        
As previously reported
 
$
11,934
  
As revised
    
12,403
 
Difference
  
$
(469
)
         
DD&A - oil and gas
        
As previously reported
 
$
7,209
  
As revised
    
6,354
 
Difference
  
$
855
  
         
DD&A - electricity generation
        
As previously reported
 
$
-
  
As revised
    
855
 
Difference
  
$
(855
)
         
G&A expenses as previously reported
  
$
6,575
  
As revised
    
7,344
 
Difference
  
$
(769
)


6. Acquisitions. On January 27, 2005, the Company acquired certain interests (J-W Acquisition) in the Niobrara field in northeastern Colorado for approximately $105 million. The properties consist of approximately 127,000 gross (69,500 net) acres. Current production is approximately 9 MMcf of natural gas per day, with estimated proved reserves of 87 Bcf. The acquisition also includes approximately 200 miles of a pipeline gathering system and gas compression facilities for delivery into interstate gas lines. In 2005, the Company plans to drill approximately 60 gross wells and complete 23 workovers as part of the development of this asset. The Company borrowed $105 million under its $200 million credit facility to fund this acquisition.

7. Dry hole, abandonment and impairment. 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. Costs of $.5 million which were incurred as of December 31, 2004 were charged to expense in 2004. The remaining costs related to these wells were approximately $2.0 million and were charged to expense during the first quarter of 2005 and are reflected on the Company’s condensed income statement under dry hole, abandonment and impairment.

7

8. Pro Forma Results

The unaudited pro forma results presented below for the three months ended March 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:


   
Three Months Ended
  
   
March 31,
      
   
2005
  
2004
  
Pro forma:
  
(in thousands, except per share data)
  
Revenue
  
$
89,358
  
$
61,903
  
Income from operations
  
 
40,016
  
 
22,223
  
Net income
  
 
22,809
  
 
10,980
  
Basic earnings per share
  
 
1.04
  
 
0.50
  
Diluted earnings per share
    
1.02
   
0.50
 
 
8
 
BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations
 
Overview

The following discussion provides information on the results of operations for each of the three month periods ended March 31, 2005, December 31, 2004 and March 31, 2004 and the financial condition, liquidity and capital resources as of March 31, 2005 and December 31, 2004. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion.

The profitability of the Company's operations in any particular accounting period will be directly related to the average realized prices of oil, gas and electricity sold, the type and volume of oil and gas produced and electricity generated and the results of development, exploitation, acquisition and exploration activities. The average realized prices for natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will be predominantly influenced by world supply and demand. The aggregate amount of oil and gas produced may fluctuate based on the success of development and exploitation of oil and gas reserves pursuant to current reservoir management. The cost of natural gas used in the Company's steaming operations and electrical generation, production rates, labor, equipment costs, maintenance expenses and production taxes are expected to be the principal influences on operating costs. Accordingly, the results of operations of the Company may fluctuate from period to period based on the foregoing principal factors, among others.

Results of Operations

 
The Company earned net income of $22.5 million, or $1.00 per share (diluted), on revenues of $88 million in the first quarter of 2005, up 116% from net income of $10.4 million, or $.47 per share (diluted), on revenues of $57.3 million in the first quarter of 2004, but down 11% from net income of $25.3 million, or $1.13 per share (diluted), on revenues of $80.4 million in the fourth quarter of 2004. In the fourth quarter of 2004, the Company recorded a non-recurring 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.
 
9
 
The following table presents certain operating data for the three month periods:
 
   
Mar 31
2005
   %   
Dec 31
2004
   %   
Mar 31
2004
   %   
Oil and Gas
                          
Oil Production (Bbl/D)
    
19,156
   
87
   
19,896
   
93
   
18,392
   
95
 
Natural Gas Production (Mcf/D)
    
17,347
   
13
   
9,084
   
7
   
6,019
   
5
 
Total (BOE/D)
    
22,047
   
100
   
21,410
   
100
   
19,395
   
100
 
                                       
Per BOE:
                                      
Average sales price before hedging
  
$
40.89
        
$
39.54
        
$
28.26
        
Average sales price after hedging
    
37.81
         
34.62
         
25.58
       
                                       
Oil, per Bbl:
                                      
Average WTI price
  
$
49.85
        
$
48.28
        
$
35.15
        
Less:
                                      
Price sensitive royalties
    
3.12
         
3.18
         
2.38
       
Gravity differential
    
5.22
         
5.88
         
4.95
       
Crude oil hedges
    
3.54
         
5.29
         
2.78
       
Average sales price
  
$
37.97
        
$
33.93
        
$
25.04
        
                                       
Gas, per Mmbtu:
                                      
Average Henry Hub price
  
$
6.27
        
$
7.15
        
$
5.71
        
Less:
                                      
Location differentials
    
0.79
         
1.56
         
0.89
       
Average sales price
  
$
5.48
        
$
5.59
        
$
4.82
        
                                       
Electricity
                                      
Electric power produced - MWh/D
    
2,117
         
2,148
         
2,167
       
Electric power sold - MWh/D
    
1,918
         
1,944
         
1,956
       
Average sales price/MWh
  
$
68.87
        
$
70.20
        
$
67.05
        
Fuel gas cost/MMBtu (excluding transportation)
  
$
5.74
        
$
5.98
        
$
5.09
        
 
 
Bbl 
One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or condensate.
BOE 
Barrel of oil equivalent, measured as 6,000 cubic feet of natural gas equal to one barrel of crude oil.
Btu 
British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Mcf 
One thousand cubic feet.
MWh 
One million watts (megawatt)/hour.
/D
per day.
 
 

Oil and Gas Production. The Company’s revenues may vary significantly from period to period as a result of changes in commodity prices and/or production volumes. Sales of oil and gas were $75.4 million in the first quarter of 2005, up 12% from $67.4 million in the fourth quarter of 2004 and up 67% from $45.2 million in the first quarter of 2004. This improvement was due to increases in both oil and gas prices and production levels. The average sales price per BOE, net of hedging, of the Company’s oil and gas was $37.81 in the first quarter of 2005, up 9% from $34.62 in the fourth quarter of 2004 and up 48% from $25.58 in the first quarter of 2004. Oil and gas production volumes in the first quarter of 2005 averaged 22,047 BOE/D, up 3% from 21,410 BOE/D in the fourth quarter of 2004 and up 14% from 19,395 BOE/D in the first quarter of 2004 due primarily to the acquisition of the Niobrara field in January 2005 and recent development activities. For all of 2005, the Company anticipates production to average approximately 23,000 BOE/D.

10

In December 2004, certain royalty owners converted their royalty interest into a working interest on the Company’s Formax property in the Midway-Sunset field which resulted in a net production decrease to the Company of approximately 450 BOE/D.

In 2004, approximately 94% of the Company’s oil and gas sales volumes were crude oil. In the first quarter of 2005, crude oil represented 87% of the Company’s oil and gas production. The Company’s objective is to diversify its predominantly heavy crude oil base with light crude oil and natural gas. With the Company’s continued development of its Brundage Canyon assets and the development of its other newly acquired properties in the Niobrara fields in northeastern Colorado, the Company anticipates natural gas production in all of 2005 to more than double its 2004 level of 7,757 Mcf/D and represent a continuing higher percentage of its production mix going forward.

As a result of hedging activities, the Company’s oil and gas sales, on a per BOE basis, were reduced by $3.08 in the first quarter of 2005, $4.92 in the fourth quarter of 2004 and $2.68 in the first quarter of 2004. The Company has hedged approximately 7,750 barrels per day of its crude oil production at prices averaging $40.75 per barrel for 2005. See “Item 3. Quantitative and Qualitative Disclosure About Market Risk”.

Electricity Generation. Total electricity revenues were $12.5 million in the first quarter of 2005, down 5% from $13.1 million in the fourth quarter of 2004 and up 5% from $11.9 million in the first quarter of 2004. The Company produced 2,117 MWh/D of electricity in the first quarter of 2005 comparable to 2,148 MWh/D in the fourth quarter of 2004 and 2,167 MWh/D in the first quarter of 2004. The Company received an average sales price per MWh of $68.87 in the first quarter of 2005, compared to $70.20 in the fourth quarter of 2004 and $67.05 in the first quarter of 2004.

The Company consumes natural gas as fuel to operate its cogeneration facilities. The Company sells its electricity to utilities under Standard Offer contracts, under which its revenues are linked to the cost of natural gas. Thus, the cost of natural gas is the primary determinant of the Company’s electricity sales price. The correlation between electricity sales and natural gas prices allows the Company to more effectively manage its cost of producing steam for use in heavy oil production.

11

Oil and Gas Expenses. The following table presents information comparing the Company’s operating expenses for each of the quarters ended March 31, 2005 and March 31, 2004:

   
Amount Per BOE
  
Amount (in thousands)
  
                           
   
Mar 31,
2005
  
Mar 31,
2004
  
%
Change
  
Mar 31,
2005
  
Mar 31,
2004
  
%
Change
  
Operating costs
  
$
11.80
  
$
9.51
    
24
%
$
23,407
  
$
16,782
    
39
%
DD&A
    
4.30
    
3.60
    
19
%
  
8,527
    
6,354
    
34
%
G&A
    
2.43
    
4.16
    
(42
)%
  
4,820
    
7,344
    
(34
)%
Interest expense
    
.59
    
.30
    
97
%
  
1,162
    
531
    
119
%

 
·
Operating costs for the first quarter of 2005, on a per BOE basis, increased 24% to $11.80 in the first quarter of 2005 from $9.51 in the first quarter of 2004. The cost of the Company’s steaming operations on its heavy oil properties represents a significant portion of the Company’s operating costs and will vary depending on the cost of natural gas used as fuel and the volume of steam injected during the period. Steam costs were higher in the first quarter of 2005 compared to the first quarter of 2004 because the cost of natural gas increased 13% to $5.74 per MMBtu in the first quarter of 2005 from $5.09 per MMBtu in the first quarter of 2004 and the volume of steam injected increased 10% to 70,440 barrels per day in the first quarter of 2005 from 64,060 barrels per day in the first quarter of 2004. Steam injection was higher as the Company commenced several new pilot projects and steam drives on its heavy-oil properties with peak oil response not expected for six to twelve months. Also contributing to the increase were increased cost of well servicing and other activities on the Company’s properties.

 
·
DD&A increased 19% to $4.30 per BOE in the first quarter of 2005 from $3.60 per BOE in the first quarter of 2004 due to higher acquisitions, increased capital investment and finding and development costs. Competition for drilling rigs has increased dramatically over the last year and, thus, rig rates are continuing to increase which has contributed to higher development costs.

 
·
G&A expense decreased 42% to $2.43 per BOE in the first quarter of 2005 from $4.16 per BOE in the first quarter of 2004. The 2004 expenses included significant non-recurring non-cash stock-based compensation charges.

 
·
Interest expense in the first quarter of 2005 was $.59 per BOE, up from $.30 per BOE in the first quarter of 2004. The Company’s borrowings at March 31, 2004 were $50 million. The Company’s borrowings were reduced during the latter half of 2004 to a level of $28 million at year-end. Interest expense was higher in the first quarter of 2005 compared to 2004 because the Company’s borrowings increased to $138 million during the first quarter of 2005 primarily due to the Niobrara and Tri-State acquisitions.

12

The following table presents information comparing the Company’s operating expenses for each of the quarters ended March 31, 2005 and December 31, 2004:

   
Amount Per BOE
  
Amount (in thousands)
  
 
Mar 31,
2005
  
Dec 31,
2004
  
%
Change
  
Mar 31,
2005
  
Dec 31,
2004
  
%
Change
  
Operating costs
  
$
11.80
  
$
11.09
    
6
%
$
23,407
  
$
21,847
    
7
%
DD&A
    
4.30
    
4.19
    
3
%
  
8,527
    
8,256
    
3
%
G&A
    
2.43
    
2.82
    
(14
)%
  
4,820
    
5,548
    
(13
)%
Interest expense
    
.59
    
.23
    
157
%
  
1,162
    
455
    
155
%

 
·
Operating costs for the first quarter of 2005 of $11.80 per BOE increased 6% from $11.09 per BOE in the quarter ended December 31, 2004. This increase was primarily related to a $2.1 million increase in severance taxes resulting from higher tax credits received in the fourth quarter of 2004 related to drilling operations at Brundage Canyon. Based on current crude oil and natural gas prices, the Company anticipates operating costs to average between $11.75 and $12.75 per BOE for all of 2005.

 
·
DD&A in the first quarter of 2005 of $4.30 per BOE increased slightly from $4.19 per BOE in the fourth quarter of 2004 due primarily to acquisitions, increased capital investment and higher finding and development costs. The Company anticipates DD&A to average between $4.25 and $4.75 per BOE for all of 2005.

 
·
G&A expenses of $2.43 per BOE in the first quarter of 2005 decreased 14% from $2.82 incurred in the fourth quarter of 2004. The Company anticipates G&A to average between $1.75 and $2.25 per BOE in the full year of 2005. The Company expects G&A to trend lower during the year, on a per barrel basis, due to higher production levels anticipated upon completion of the Company’s extensive development activities planned for 2005.

 
·
Interest expense of $.59 per BOE in the first quarter of 2005 increased from $.23 per BOE in the fourth quarter of 2004. The Company’s borrowings totaled $28 million at December 31, 2004 and increased to $138 million at March 31, 2005. The Company anticipates interest expense to stay in the $.45 to $.60 per BOE range for all of 2005.

Electricity Operating Costs. Operating costs from electricity generation were $13.4 million in the first quarter of 2005, up 5% from $12.8 million in the fourth quarter of 2004 and up 8% from $12.4 million in the first quarter of 2004. Operating costs from electricity generation in the first quarter of 2005 were higher than the first quarter of 2004 since the cost of natural gas increased to $5.74 per MMBtu in the 2005 period from $5.09 per MMBtu in the first quarter of 2004.

Income Taxes. The Company experienced an effective tax rate of 33% for the first quarter of 2005 compared to 21% for the same period last year and 15% for the fourth quarter 2004. The Company benefits from EOR (enhanced oil recovery) credits on development activities on its heavy oil properties. However, with higher crude oil prices and the increasing investment in its light crude oil and natural gas properties, the Company’s effective income tax rate has been trending higher. Based on current oil prices, the Company anticipates an effective tax rate for 2005 between 30% and 35%.

13

Dry Hole, Abandonment and Impairment. At December 31, 2004, the Company was in the process of drilling one exploratory well on its Midway-Sunset property in California and one exploratory well on its Coyote Flats, Utah prospect. These two wells were determined non-commercial in February 2005. Costs of $.5 million which were incurred as of December 31, 2004 were charged to expense in 2004. The remaining costs incurred on these wells were approximately $2.0 million and were charged to expense during the first quarter of 2005. These costs are reflected on the Company's income statement under dry hole, abandonment and impairment.

Acquisitions. On January 27, 2005, the Company acquired certain interests in the Niobrara field in northeastern Colorado for approximately $105 million. The properties consist of approximately 127,000 gross (69,500 net) acres. Current production is approximately 9 MMcf of natural gas per day, with estimated proved reserves of 87 Bcf. The acquisition also includes approximately 200 miles of a pipeline gathering system and gas compression facilities for delivery into interstate gas lines. In the first quarter of 2005, the Company drilled 4 new wells on this acreage and plans to drill a total of approximately 60 wells and complete 23 workovers as part of the development of this asset in 2005.

In January 2005, the Company acquired a working interest in approximately 390,000 gross (172,250 net) prospective acres, located in eastern Colorado, western Kansas and southwestern Nebraska for approximately $5 million, from Bill Barrett Corporation (BBC). The Company and BBC will jointly explore and develop shallow Niobrara biogenic natural gas, Sharon Springs Shale gas and deeper Pennsylvanian formation oil assets on the acreage. The Company believes the potential of the Tri-State area can be exploited by using new drilling techniques and 3-D seismic technology to assess structural complexity, estimate potentially recoverable oil and gas and determine drilling locations. To this end, in the second quarter of 2005, the Company plans to spend approximately $.8 million, its net share, for 530 miles of 2D seismic data on this acreage. Additionally, the Company and BBC are presently evaluating the results of a well drilled in April 2005 on this acreage. This represents the first of a total of 8 new wells planned in 2005 on this acreage.

Other Exploration and Development Activities. In the Coyote Flats prospect, the Company is presently identifying a location to drill the second of three test wells in the Ferron sands. The Company plans to drill this well in the summer of 2005 to be followed by a 6 well coal bed methane program on this prospect.

In Brundage Canyon, Utah the Company has budgeted development costs of $44.9 million, including the drilling of 59 new wells and performing 20 workovers in 2005. In the first quarter of 2005, the Company drilled 14 new wells and completed 3 workovers.

The Company has two Green River wells permitted for May 2005 drilling at its Lake Canyon acreage. These initial drill sites will be approximately three miles west of the Company’s Brundage Canyon field. The Company will also participate in the acquisition of 50 square miles of 3D seismic at Lake Canyon this summer. Drilling of the first deep Mesaverde natural gas test well in Lake Canyon is scheduled for late 2005.

In California, the Company has budgeted $37.9 million in capital development projects. The Company continues to monitor its diatomite exploitation project in the Midway-Sunset field. Production from this project has been gradually improving to a current level of approximately 100 B/D of crude oil. The Company is considering expanding this pilot and a decision as to the commerciality of this project is expected before the end of 2005. On the Company’s other California properties, the Company has drilled 17 new wells and completed 16 workovers of a planned 70 new wells and 61 workover program in 2005.

14
 
Financial Condition, Liquidity and Capital Resources
Substantial capital is required to replace and grow reserves. The Company achieves 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 the Company's cash flow from operating activities. The net long-term growth in the Company's cash flow from operating activities is the result of growth in production as affected by period to period fluctuations in commodity prices.
 
The Company establishes a capital budget for each calendar year based on its development opportunities and the expected cash flow from operations for that year. The Company may revise its 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.

Working Capital and Cash Flows. Cash flow from operations is dependent upon the Company's ability to increase production through development, acquisitions, exploration activities and the price of crude oil and natural gas. The Company's working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its credit arrangements. Generally, the Company uses excess cash to pay down borrowings under its credit arrangement. As a result, the Company often has a working capital deficit or a relatively small amount of positive working capital. Working capital as of March 31, 2005 was negative ($1.1) million, up from a negative ($3.8) million at December 31, 2004. Sales of oil and gas increased $30.2 million during the first quarter 2005 compared to the first quarter 2004, with oil and gas prices, net of hedges, increasing 48% and production increasing 14% in 2005 compared to the first quarter of 2004. Net cash provided by operating activities was $19.3 million, down 2% from $19.6 million in the first quarter 2004. The decrease in 2005 was a direct result of a $10.5 million increase in accounts receivable resulting from higher oil and gas prices and higher production volumes, not collected until April 2005, and an annual price-based royalty of $19 million paid in February 2005, up from $10 million paid in February 2004. The Company increased its borrowing on its credit line by $110 million during the first quarter 2005. Cash was used to fund $109.5 million in property acquisitions, $15.7 million of capital expenditures (15% of the total $107 million 2005 capital budget), and to pay dividends of $2.6 million.

15

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

       
Less than
  
1-3
 
3-5
  
More than
  
Contractual Obligations
  
Total
  
1 year
  
years
  
years
  
5 years
  
                       
Long-term debt
  
$
138,000
  
$
-
  
$
138,000
  
$
-
  
$
-
  
Abandonment obligations
    
9,369
   
304
   
922
   
1,166
   
6,977
 
Operating lease obligations
    
1,396
   
621
   
676
   
99
   
-
 
Drilling obligation
    
10,525
   
925
   
4,250
   
5,350
   
-
 
Firm natural gas
                               
transportation contract
    
22,745
   
2,814
   
5,628
   
5,628
   
8,675
 
Total
  
$
182,035
  
$
4,664
  
$
149,476
  
$
12,243
  
$
15,652
  

BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company enters into various financial contracts to hedge its exposure to commodity price risk associated with its crude oil and natural gas production and natural gas volumes purchased for its steaming operations. These contracts related to crude oil and natural gas are generally in the form of swaps. The Company generally attempts to hedge between 25% and 50% of its anticipated crude oil and natural gas production each year and up to 30% of its anticipated net natural gas purchased each year. All of these hedges have historically been deemed to be cash flow hedges with the mark-to-market valuations provided by external sources, based on prices that are actually quoted.

Based on NYMEX futures prices as of March 31, 2005, (WTI $56.00; Henry Hub (HH) $7.93) the Company would expect to make pre-tax future cash payments or receipts over the remaining term of its crude oil and natural gas hedges in place as follows:


   
March 31,
2005
NYMEX
Futures
  
Impact of percent change in futures prices
on earnings
  
       
20%
  
10%
  
+10%
  
+20%
  
Average WTI Price
  
$
56.00
  
$
44.80
  
$
50.40
  
$
61.60
  
$
67.20
  
Crude Oil gain/(loss) (in thousands)
    
(38,013
)
  
(8,119
)
  
(23,066
)
  
(52,959
)
  
(67,906
)
Average HH Price
    
7.93
    
6.35
    
7.14
    
8.73
    
9.52
  
Natural Gas gain/(loss) (in thousands)
    
5,931
    
,071
    
4,984
    
6,808
    
7,720
 
Net pre-tax future cash payments (in thousands)
    
(32,082
)
  
(4,048
)
  
(18,082
)
  
(46,151
)
  
(60,186
)

The Company attempts to minimize credit exposure to counterparties through monitoring procedures and diversification. The Company’s exposure to changes in interest rates results primarily from long-term debt. Total debt outstanding at March 31, 2005 and March 31, 2004 was $138 million and $28 million, respectively. Interest on amounts borrowed is charged at LIBOR plus 1.25% to 2.0%, or the higher of the lead bank’s prime rate or the federal funds rate plus 50 basis points plus a margin of 0.0% to 0.75%, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. Based on these borrowings, a 1% change in interest rates would not have a material impact on the Company’s financial statements.
 
16
 

Based on the Company’s hedges in place (swaps) associated with its natural gas sales volumes, a $1 increase in natural gas prices per MMBtu would reduce revenues by $ 1.6 million since the hedges are out-of-the money at March 31, 2005. Similarly, based on the Company’s hedges in place associated with its natural gas purchased volumes used in its steaming operations, if natural gas prices increased $1per MMBtu, the Company would collect an additional $2.8 million from its counterparties which would be reflected as a reduction to operating costs - oil & gas.

 During 2004 and through early 2005, the differential between California heavy crude oil and WTI widened and averaged approximately $14.50 for the first quarter of 2005. While the Company is confident that it will be able to secure a contract for its California heavy crude oil in future periods, it is unlikely that the Company will be able to obtain terms similar to the current contract pricing in the existing agreement which is based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential approximating $6.00 per barrel. This contract expires on December 31, 2005. In the first quarter of 2005, the Company estimates that its revenues benefited from this contract by approximately $11 million, and at a current differential of approximately $14.00 per barrel, the Company estimates that its revenues in 2005 will benefit from the contract by approximately $45 million.



BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 4. Controls and Procedures 

As of March 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 and Exchange Act of 1934, as amended.

Based on their evaluation as of March 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.


Forward Looking Statements

"Safe harbor under the Private Securities Litigation Reform Act of 1995:” With the exception of historical information, the matters discussed in this Form 10-Q are forward-looking statements that involve risks and uncertainties. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for oil, gas and electricity, a limited marketplace for electricity sales within California, counterparty risk, competition, environmental risks, litigation uncertainties, drilling, development, exploration and operating risks, the availability of drilling rigs and other support services, legislative and/or judicial decisions and other government or Tribal regulations.

17


BERRY PETROLEUM COMPANY
Part II. Other Information

Item 1. Legal proceedings
None
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 5. Other Information
None

Item 6. Exhibits

Exhibit No.
Description of Exhibit
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *
32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *

* Filed herewith


SIGNATURE

Pursuant to the requirements 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.

BERRY PETROLEUM COMPANY



/s/ Donald A. Dale
Donald A. Dale
Controller
(Principal Accounting Officer)

Date: May 3, 2005
 
18