BERRY PETROLEUM COMPANY FORM 10-Q FOR THE FIRST QUARTER ENDED 03-31-07


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

FORM 10-Q

x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2007
oTransition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from __to ___           
Commission file number 1-9735

BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
 
DELAWARE
 
77-0079387
 
 
(State of incorporation or organization)
 
(I.R.S. Employer Identification Number)
 
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



Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 April 18, 2007, the registrant had 42,196,896 shares of Class A Common Stock ($.01 par value) outstanding. The registrant also had 1,797,784 shares of Class B Stock ($.01 par value) outstanding on April 18, 2007 all of which is held by an affiliate of the registrant.
 

 
BERRY PETROLEUM COMPANY
FIRST QUARTER 2007 FORM 10-Q
TABLE OF CONTENTS
 
PART I. FINANCIAL INFORMATION
 
 
 
Page
     
 
Item 1. Financial Statements
 
     
 
Unaudited Condensed Balance Sheets at March 31, 2007 and December 31, 2006
3
     
 
Unaudited Condensed Statements of Income for the Three Month Periods Ended March 31, 2007 and 2006
4
     
 
Unaudited Condensed Statements of Comprehensive Income for the Three Month Periods Ended March 31, 2007 and 2006
4
     
 
Unaudited Condensed Statements of Cash Flows for the Three Month Periods Ended March 31, 2007 and 2006
5
     
 
Notes to Unaudited Condensed Financial Statements
6
     
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
10
     
 
Item 3. Quantitative and Qualitative Disclosures About Market Risk
18
     
 
Item 4. Controls and Procedures
20
     
     
     
     
     
PART II.
OTHER INFORMATION
   
     
 
Item 1. Legal Proceedings
21
     
 
Item 1A. Risk Factors
21
     
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
21
     
 
Item 3. Defaults Upon Senior Securities
21
     
 
Item 4. Submission of Matters to a Vote of Security Holders
21
     
 
Item 5. Other Information
21
     
 
Item 6. Exhibits
21

 


BERRY PETROLEUM COMPANY
Unaudited Condensed Balance Sheets
(In Thousands, Except Share Information)
     
March 31, 2007
   
December 31, 2006
 
ASSETS
             
Current assets:
             
Cash and cash equivalents
 
$
95
 
$
416
 
Short-term investments
 
 
665
 
 
665
 
Accounts receivable
 
 
77,893
 
 
67,905
 
Deferred income taxes
 
 
5,415
 
 
-
 
Fair value of derivatives
 
 
7,936
 
 
7,349
 
Assets held for sale
   
8,870
   
8,870
 
Prepaid expenses and other
 
 
15,813
 
 
13,604
 
Total current assets
 
 
116,687
   
98,809
 
Oil and gas properties (successful efforts basis), buildings and equipment, net
 
 
1,142,892
 
 
1,080,631
 
Fair value of derivatives
   
700
   
2,356
 
Other assets
 
 
16,618
 
 
17,201
 
 
 
$
1,276,897
 
$
1,198,997
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
   
 
 
 
Current liabilities:
 
 
   
 
 
 
Accounts payable
 
$
63,884
 
$
69,914
 
Property acquisition payable
   
54,400
   
54,400
 
Revenue and royalties payable
 
 
13,801
 
 
45,845
 
Accrued liabilities
 
 
24,848
 
 
20,415
 
Line of credit
   
7,000
   
16,000
 
Other current liabilities
 
 
1,691
 
 
-
 
Deferred income taxes
   
-
   
745
 
Fair value of derivatives
 
 
22,942
 
 
8,084
 
Total current liabilities
 
 
188,566
 
 
215,403
 
Long-term liabilities:
 
 
   
 
 
 
Deferred income taxes
 
 
102,758
 
 
103,515
 
Long-term debt
 
 
470,000
 
 
390,000
 
Abandonment obligation
 
 
30,958
 
 
26,135
 
Unearned revenue
   
1,133
   
1,437
 
Other long-term liabilities
   
9,290
   
-
 
Fair value of derivatives
 
 
39,936
 
 
34,807
 
 
 
 
654,075
 
 
555,894
 
Shareholders' equity:
 
 
   
 
 
 
Preferred stock, $.01 par value, 2,000,000 shares authorized; no shares outstanding
 
 
-
 
 
-
 
Capital stock, $.01 par value:
 
 
   
 
 
 
Class A Common Stock, 100,000,000 shares authorized; 42,191,896 shares issued and outstanding (42,098,551 in 2006)
 
 
422
 
 
421
 
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and outstanding (liquidation preference of $899)
 
 
18
 
 
18
 
Capital in excess of par value
 
 
53,594
 
 
50,166
 
Accumulated other comprehensive loss
 
 
(32,347
)
 
(19,977
)
Retained earnings
 
 
412,569
 
 
397,072
 
Total shareholders' equity
 
 
434,256
 
 
427,700
 
 
 
$
1,276,897
 
$
1,198,997
 
The accompanying notes are an integral part of these financial statements.




BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Income
Three Month Periods Ended March 31, 2007 and 2006
(In Thousands, Except Per Share Data)
           
Three months ended March 31,
 
           
2007
   
2006 (1)
 
REVENUES
                   
Sales of oil and gas
       
$
101,773
 
$
101,932
 
Sales of electricity
     
 
 
14,596
 
 
15,169
 
Interest and other income, net
     
 
 
1,110
 
 
493
 
 
     
 
 
117,479
 
 
117,594
 
EXPENSES
     
 
 
 
 
   
 
Operating costs - oil and gas production
     
 
 
33,610
 
 
25,738
 
Operating costs - electricity generation
     
 
 
14,170
 
 
14,332
 
Production taxes
         
3,815
   
3,233
 
Depreciation, depletion & amortization - oil and gas production
     
 
 
18,725
 
 
13,223
 
Depreciation, depletion & amortization - electricity generation
     
 
 
762
 
 
767
 
General and administrative
     
 
 
10,307
 
 
8,314
 
Interest
     
 
 
4,292
 
 
1,577
 
Commodity derivatives
         
-
   
4,828
 
Dry hole, abandonment, impairment and exploration
     
 
 
649
 
 
7,498
 
 
     
 
 
86,330
 
 
79,510
 
Income before income taxes
     
 
 
31,149
 
 
38,084
 
Provision for income taxes
     
 
 
12,294
 
 
14,833
 
 
     
 
 
 
 
   
 
Net income
     
 
$
18,855
 
$
23,251
 
 
     
 
 
 
 
 
 
 
Basic net income per share
     
 
$
.43
 
$
.53
 
 
     
 
 
 
 
 
 
 
Diluted net income per share
     
 
$
.42
 
$
.52
 
 
     
 
 
 
 
 
 
 
Dividends per share
     
 
$
.075
 
$
.065
 
 
     
 
 
 
 
 
 
 
Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share)
     
 
 
43,916
 
 
43,988
 
Effect of dilutive securities:
     
 
 
 
 
 
 
 
Equity based compensation
     
 
 
603
 
 
918
 
Director deferred compensation
     
 
 
112
 
 
98
 
Weighted average number of shares of capital stock used to calculate diluted net income per share
     
 
 
44,631
 
 
45,004
 
 
 
 
 
 
 
 
 
 
 
 
Unaudited Condensed Statements of Comprehensive Income
 
Three Month Periods Ended March 31, 2007 and 2006
(In Thousands)
Net income
       
$
18,855
 
$
23,251
 
Unrealized gains (losses) on derivatives, net of income taxes of ($7,885) and ($14,184), respectively
         
(11,828
)
 
(21,276
)
Reclassification of realized losses included in net income net of income taxes of ($361) and ($2,545), respectively
     
 
 
(542
 
(3,818
)
Comprehensive income
     
 
$
6,485
 
$
(1,843
)
The accompanying notes are an integral part of these financial statements. 

(1) The 2006 per share and share amounts have been restated to give retroactive effect to the two-for-one stock split that became effective on May 17, 2006. See Note 2.



BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of Cash Flows
Three Month Periods Ended March 31, 2007 and 2006
(In Thousands)
           
Three months ended March 31,
 
           
2007
   
2006
 
Cash flows from operating activities:
                   
Net income
       
$
18,855
 
$
23,251
 
Depreciation, depletion and amortization
         
19,487
   
13,990
 
Dry hole
         
188
   
5,209
 
Abandonment and impairment
         
(256
)
 
(224
)
Commodity derivatives
         
439
   
4,828
 
Stock-based compensation expense, net of taxes
         
1,792
   
1,014
 
Deferred income taxes, net
         
12,311
   
7,464
 
Other, net
         
209
   
52
 
(Increase) in current assets other than cash, cash equivalents and short-term investments
         
(13,289
)
 
(1,936
)
(Decrease) in current liabilities other than book overdraft, line of credit, property acquisition payable and fair value of derivatives
         
(28,119
)
 
(28,331
)
Net cash provided by operating activities
         
11,617
   
25,317
 
Cash flows from investing activities:
       
 
         
Exploration and development of oil and gas properties
       
 
(73,472
)
 
(41,345
)
Property acquisitions
       
 
(1,088
)
 
(159,016
)
Additions to vehicles, drilling rigs and other fixed assets
         
(1,018
)
 
(5,723
)
Deposit on potential sale of asset
         
3,000
   
-
 
Capitalized interest and other
         
(3,998
)
 
-
 
Net cash used in investing activities
       
 
(76,576
)
 
(206,084
)
Cash flows from financing activities:
       
 
   
 
 
 
Proceeds from issuance of line of credit
         
21,000
   
51,000
 
Payment of line of credit
         
(30,000
)
 
(53,000
)
Proceeds from issuance of long-term debt
       
 
90,000
   
219,750
 
Payment of long-term debt
       
 
(10,000
)
 
(45,750
)
Dividends paid
       
 
(3,295
)
 
(2,867
)
Change in book overdraft
         
(4,711
)
 
9,881
 
Repurchase of shares of common stock
         
-
   
(1,802
)
Proceeds from stock option exercises
         
1,148
   
1,144
 
Excess tax benefit and other
         
496
   
1,806
 
Net cash provided by financing activities
       
 
64,638
   
180,162
 
 
       
 
         
Net decrease in cash and cash equivalents
       
 
(321
)
 
(605
)
Cash and cash equivalents at beginning of year
       
 
416
   
1,990
 
Cash and cash equivalents at end of period
       
$
95
 
$
1,385
 
Supplemental non-cash activity:
       
 
   
 
   
(Decrease) in fair value of derivatives:
       
 
   
 
   
Current (net of income taxes of $5,358 and $5,468, respectively)
       
$
(8,037
)
$
(8,203
)
Non-current (net of income taxes of $2,889 and $11,261, respectively)
         
(4,333
)
 
(16,891
)
Net (decrease) to accumulated other comprehensive income
       
(12,370
)
(25,094
)
The accompanying notes are an integral part of these financial statements. 



BERRY PETROLEUM COMPANY
Notes to the Unaudited Condensed Financial Statements

1. General

All adjustments which are, in the opinion of Management, necessary for a fair statement of Berry Petroleum Company’s (the “Company”) financial position at March 31, 2007 and December 31, 2006 and results of operations and cash flows for the three month periods ended March 31, 2007 and 2006 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.

The accompanying unaudited condensed financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2006 financial statements. The December 31, 2006 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.

Our cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at March 31, 2007, December 31, 2006 and March 31, 2006 is $12.5 million, $17.2 million and $11.8 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

In December 2004, Statement of Financial Accounting Standards (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. As a result, we adopted this statement beginning January 1, 2006. This standard requires us 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. Accordingly, the adoption of SFAS No. 123(R) using the modified prospective method did not have a material impact on our condensed financial statements for the year ended December 31, 2006. We previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation effective January 1, 2004. The modified prospective method was selected as described in SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, we 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.

2. Stock Split

On March 1, 2006, our Board of Directors approved a two-for-one stock split to shareholders of record on May 17, 2006, subject to obtaining shareholder approval of an increase in our authorized shares. On May 17, 2006 our shareholders approved the authorized share increase and on June 2, 2006 each shareholder received one additional share for each share owned on May 17, 2006. This did not change the proportionate interest a shareholder maintained in Berry Petroleum Company on May 17, 2006. All historical shares, equity awards and per share amounts have been restated for the two-for-one stock split.

 3. Recent Accounting Developments

In June 2006, the FASB issued Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109, Accounting for Income Taxes. This interpretation requires that realization of an uncertain income tax position must be “more likely than not” (i.e. greater than 50% likelihood of receiving a benefit) before it can be recognized in the financial statements. Further, this interpretation prescribes the benefit to be recorded in the financial statements as the amount most likely to be realized assuming a review by tax authorities having all relevant information and applying current conventions. This interpretation also clarifies the financial statement classification of tax-related penalties and interest and sets forth new disclosures regarding unrecognized tax benefits. This interpretation is effective for fiscal years beginning after December 15, 2006, and we adopted this interpretation in the first quarter of 2007. See Note 6.

In September 2006, SFAS No. 157, Fair Value Measurements was issued by the Financial Accounting Standards Board (FASB). This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 will become effective for our fiscal year beginning January 1, 2008, and we are currently assessing the potential impact of this Statement on our financial statements.

In September 2006, Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. Registrants must quantify the impact on current period financial statements of correcting all misstatements, including both those occurring in the current period and the effect of reversing those that have accumulated from prior periods. This SAB was adopted at December 31, 2006. The adoption of SAB No. 108 had no effect on our financial position or on the results of our operations.




 
BERRY PETROLEUM COMPANY
Notes to the Unaudited Condensed Financial Statements

3. Recent Accounting Developments (Cont’d)

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. This statement is effective beginning January 1, 2008 and we are evaluating this pronouncement.

4. Hedging
 
The related cash flow impact of all of our hedges are reflected in cash flows from operating activities. At March 31, 2007, our net fair value of derivatives liability was $54.2 million as compared to $33.2 million at December 31, 2006. At March 31, 2007, Accumulated Other Comprehensive Loss consisted of $32.3 million, net of tax, of unrealized losses from our crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at March 31, 2007. Deferred net losses recorded in Accumulated Other Comprehensive Loss at March 31, 2007 and subsequent marked-to-market changes in the underlying hedging contracts are expected to be reclassified to earnings over the life of these contracts. Our liability is primarily related to the time value of the underlying instruments and based on current prices the amount expected to be reclassified to earnings over the next 12 months is not significant.

As of February 28, 2007, we have converted 2,000 Bbl/D of our 2007 oil collars beginning on March 1, 2007 to a swap with a strike price of $60 West Texas Intermediate (WTI). This swap is considered to be an effective cash flow hedge. Additionally, we entered into oil swaps for 1,000 Bbl/D at $64.55 from March 2007 through December 2007 and entered into oil collars for 1,000 Bbl/D at $60 floor and $75 ceiling prices for 2010.

Additionally, on June 8, 2006 and July 10, 2006, we entered into five year interest rate swaps for a fixed rate of approximately 5.5% on $100 million of our outstanding borrowings under our credit facility for five years. These interest rate swaps have been designated as cash flow hedges.

5. Asset Retirement Obligations

Inherent in the fair value calculation of the asset retirement obligation (ARO) are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In 2007, we reassessed our estimate as costs have increased due to demand for related services, resulting in an increase in the ARO balance at quarter end.

Under SFAS 143, the following table summarizes the change in abandonment obligation for the quarter ended March 31, 2007 (in thousands):

 
 
 
 
   
Beginning balance at January 1
 
$
26,135
       
Liabilities incurred
 
 
1,274
       
Liabilities settled
 
 
(256
)
     
Revisions in estimated liabilities
   
3,272
       
Accretion expense
 
 
533
       
 
 
 
         
Ending balance at March 31
 
$
30,958
       





BERRY PETROLEUM COMPANY
Notes to the Unaudited Condensed Financial Statements

6. Income Taxes

The effective tax rate was 39% for the first quarter of 2007 compared to 38% for the fourth quarter of 2006 and 39% for the first quarter of 2006.

In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109, Accounting for Income Taxes. The Interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN No. 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

We adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no material adjustment to retained earnings. As of the date of adoption, we had a gross liability for uncertain tax benefits of $14.6 million of which $10.8 million if recognized, would affect the effective tax rate. We recognize potential accrued interest and penalties related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. As of January 1, 2007, we had accrued approximately $.9 million of interest related to our uncertain tax positions.

We have not had any material changes to our unrecognized tax benefits since adoption, nor do we anticipate significant changes to the total amount of unrecognized tax benefits within the next 12 months.

As of January 1, 2007, we remain subject to examination in the following major tax jurisdictions for the tax years indicated below:

Jurisdiction:
Tax Years Subject to Exam:
Federal
2003 - 2006
California
2002 - 2006
Colorado
2002 - 2006
Utah
2003 - 2006

7. Long-term and Short-term Obligations

Long-term debt
In October 2006, we issued in a public offering $200 million of 8.25% senior subordinated notes due 2016 (the Notes). The deferred costs of approximately $5 million associated with the issuance of this debt are being amortized over the ten year life of the Notes. The net proceeds from the offering were used to 1) repay approximately $145 million of borrowings under the bank credit facility, which were $170 million as of the issuance date after the application of this payment, and 2) approximately $50 million was used to pay the November 1, 2006 installment under the joint venture agreement to develop properties in the Piceance basin.

In April 2006, we completed a new unsecured five year bank credit facility agreement (the Agreement) with a banking syndicate and extended the term by one year to July 2011. The Agreement is a revolving credit facility for up to $750 million and replaces the previous $500 million facility. The current borrowing base was established at $500 million, as compared to the previous $350 million. This transaction was accounted for in accordance with Emerging Issues Task Force, (EITF) 98-14, Debtor’s Accounting for Changes in Line-of-Credit or Revolving-Debt Arrangements.

The total outstanding debt under the credit facility’s borrowing base was $270 million and the short-term line of credit was $7 million at March 31, 2007, leaving $223 million in borrowing capacity available. Interest on amounts borrowed under this debt is charged at LIBOR plus a margin of 1.00% to 1.75% or the prime rate, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. We are required under the Agreement to pay a commitment fee of .25% to .375% on the unused portion of the credit facility annually.
 




BERRY PETROLEUM COMPANY
Notes to the Unaudited Condensed Financial Statements

7. Long-term and Short-term Obligations (Cont’d)

The Agreement contains restrictive covenants which, among other things, require us to maintain a certain debt to EBITDA ratio and a minimum current ratio, as defined. The $200 million Notes are subordinated to our credit facility indebtedness. Our Notes covenants limit debt to the greater of $750 million or 40% of Adjusted Consolidated Net Tangible Assets (as defined). Additionally, as long as the interest coverage ratio (as defined) is met, we may incur additional debt. We were in compliance with all such covenants as of March 31, 2007. The weighted average interest rate on the long-term outstanding credit facility borrowings at March 31, 2007 was 6.6%.

Short-term debt
In November 2005, we completed an unsecured uncommitted money market line of credit (Line of Credit). Borrowings under the Line of Credit may be up to $30 million for a maximum of 30 days. The Line of Credit may be terminated at any time upon written notice by either us or the lender. At March 31, 2007 the outstanding balance under this Line of Credit was $7 million. Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The weighted average interest rate on outstanding borrowings on the Line of Credit at March 31, 2007 was 6.2%.

8.  Contingencies and Commitments   

We have no accrued environmental liabilities for our sites, including sites in which governmental agencies have designated us as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be accrued. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not require substantial accruals. We are involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of our business. In the opinion of management, the resolution of these matters will not have a material effect on our financial position, or on the results of operations or liquidity.

On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly Corporation (Holly) for a portion of our Uinta basin crude oil. Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase total purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum number of delivered units (“base daily volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery upgrade. Holly may, but is not obligated to, purchase volumes in excess of the base daily volumes when notified by us at the beginning of any contract year.

9. Assets Held for Sale

Net oil and gas properties and equipment classified as held for sale is $8.9 million at March 31, 2007 in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. On March 19, 2007 we announced that we have entered into an agreement to sell our non-core West Montalvo assets, near Ventura, California. We estimate a sales price of approximately $63 million before adjustments and expect to transfer the properties in the second quarter of 2007. The completion of the transaction is subject to certain conditions and there is no assurance that all such conditions will be satisfied.

10. Subsequent Event

We paid the third and final installment of approximately $54 million utilizing our credit facility on May 1, 2007 for the North Parachute Ranch property located in the Piceance basin.



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General. The following discussion provides information on the results of operations for the three month periods ended March 31, 2007 and 2006 and our financial condition, liquidity and capital resources as of March 31, 2007. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion.

The profitability of our operations in any particular accounting period will be directly related to the realized prices of oil, gas and electricity sold, the type and volume of oil and gas produced and electricity generated and the results of development, exploitation, acquisition, exploration and hedging activities. The realized prices for natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will be predominantly influenced by 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 our steaming operations and electrical generation, production rates, labor, equipment costs, maintenance expenses, and production taxes are expected to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period based on the foregoing principal factors, among others.

Overview. Our mission is to increase shareholder value through consistent growth in our production and reserves, both through the drill bit and acquisitions. We strive to operate our properties in an efficient manner to maximize the cash flow and earnings of our assets. The strategies to accomplish these goals include:
·  
Developing our existing resource base
·  
Acquiring additional assets with significant growth potential
·  
Utilizing joint ventures with respected partners to enter new basins
·  
Accumulating significant acreage positions near our producing operations
·  
Investing our capital in a disciplined manner and maintaining a strong financial position

Notable First Quarter Items.
·  
Production averaged 25,490 BOE/D, up 9% from the first quarter of 2006
·  
Entered into a long-term crude oil sales contract for our Uinta basin, Utah production
·  
Restored Uinta basin production to approximately 6,000 BOE/D from a low of 3,800 BOE/D in January 2007
·  
Production at Midway-Sunset diatomite averaged 600 Bbl/D compared to 400 Bbl/D in the fourth quarter of 2006
·  
Improvements made in the Piceance basin program in personnel, services, rigs, drilling and completions
·  
Entered into an agreement to sell our non-core West Montalvo assets, near Ventura, California for an estimated sales price of approximately $63 million cash before adjustments

Notable Items and Expectations for the Second Quarter of 2007.
·  
Completing over 20 Piceance basin wells with total Piceance net production estimated at 9.6 MMcf/D
·  
Production at Midway-Sunset diatomite is approaching 1,000 BOE/D and the steam to oil ratio is improving
·  
Accelerating Poso Creek development by drilling 40 wells and installing an additional steam generator
·  
Transferring Montalvo properties with proceeds estimated at $63 million before adjustments
·  
Production is projected to average between 26,500 BOE/D and 27,500 BOE/D for the second quarter of 2007

Overview of the First Quarter of 2007. In the first quarter we were unable to sell all of our Uinta basin production due to a refinery shutdown. On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. This contract will allow us to stabilize our basis differentials on these barrels beginning on July 1, 2007 and assures us of the ability to sell this regional crude oil. Our activities in the Piceance basin included completion of a pipeline. Eleven wells have been connected since the pipeline was completed, allowing production to rise to over 8.5 net MMcf/D in April from 6.4 net MMcf/D in the first quarter of 2007.

View to the Second Quarter. Our 2007 drilling program will continue to drive our production growth. Operationally, we are focused on executing our drilling program on our Piceance basin asset where we expect to drill 16 wells during the second quarter of 2007. Furthermore, based on higher than expected performance at Poso Creek, we are planning to accelerate development there by drilling 40 wells and installing a third steam generator during the second quarter. On May 1, 2007, the final installment for our Piceance basin joint venture was paid.
 




Results of Operations. The following companywide results are in millions (except per share data) for the three months ended:

 
 
March 31, 2007
(1Q07)
 
March 31, 2006
(1Q06)
1Q07 to 1Q06 Change
December 31, 2006
(4Q06)
1Q07 to 4Q06 Change
Sales of oil
 
$
80.9
 
$
83.3
(3%)
$
84.2
(4%)
Sales of gas
   
20.9
   
18.6
12%
 
17.6
19%
Total sales of oil and gas
 
$
101.8
 
$
101.9
-%
$
101.8
-%
Sales of electricity
   
14.6
 
 
15.2
(4%)
 
13.4
9%
Interest and other income, net
   
1.1
 
 
.5
120%
 
1.0
10%
Total revenues and other income
 
$
117.5
 
$
117.6
-%
$
116.2
1%
Net income
 
$
18.9
 
$
23.3
(19%)
$
19.1
(1%)
Net income per share (diluted)
 
$
.42
 
$
.52
(19%)
$
.43
(2%)

Our revenues may vary significantly from period to period as a result of changes in commodity prices and/or production volumes. For the three months ended March 31, 2007, gas sales improved while oil sales declined when compared to three months ended March 31, 2006. Improvement to gas sales is due to higher production primarily from our Piceance basin acquisition, partially offset by lower gas prices. Oil sales decreased due to lower prices partially offset by higher volumes primarily from our NMWSS and Poso Creek properties.

Similarly, for the three months ended March 31, 2007 compared to the three months ended December 31, 2006, gas sales improved while oil sales declined. Improvement in realized gas prices during the first three months of 2007 were due to increased weather related demand and a tighter supply and demand balance, while oil sales declined primarily due to lower production.

 




Operating data. The following table is for the three months ended:
 
     
March 31, 2007
%
 
March 31, 2006
%
 
December 31, 2006
%
Oil and Gas
                   
Heavy Oil Production (Bbl/D)
   
16,140
63
 
15,407
66
 
16,833
63
Light Oil Production (Bbl/D)
   
3,233
13
 
3,303
14
 
3,363
13
Total Oil Production (Bbl/D)
 
 
19,373
76
 
18,710
80
 
20,196
76
Natural Gas Production (Mcf/D)
 
 
36,704
24
 
28,507
20
 
40,157
24
Total (BOE/D)
 
 
25,490
100
 
23,461
100
 
26,889
100
 
 
 
 
 
 
 
 
 
 
 
Per BOE:
 
 
 
 
 
 
 
 
 
 
Average sales price before hedging
 
$
43.62
 
$
50.04
 
$
41.53
 
Average sales price after hedging
 
 
43.84
 
 
48.45
 
 
42.00
 
 
 
 
   
 
   
 
   
Oil, per Bbl:
                   
Average WTI price
 
$
58.23
 
$
63.48
 
$
60.17
 
Price sensitive royalties
   
(3.74
)
 
(5.41
)
 
(4.28
)
Quality differential and other
   
(8.78
)
 
(6.36
)
 
(9.06
)
Crude oil hedges
   
.03
   
(2.04
)
 
(.01
)
Average oil sales price after hedging
 
$
45.74
 
$
49.67
 
$
46.82
 
                     
Gas, per MMBtu:
                   
Average Henry Hub price
 
$
7.18
 
$
7.92
 
$
7.24
 
Natural gas hedges
   
.13
   
(.03
)
 
.33
 
Location, quality differentials and other
   
(.70
)
 
(1.05
)
 
(2.68
)
Average gas sales price after hedging
 
$
6.61
 
$
6.84
 
$
4.89
 

Gas Basis Differential. The gas prices in the Rockies continue to be volatile due to various factors, including takeaway pipeline capacity, supply volumes, and regional demand issues. We expect the basis differential to narrow upon the startup of the Rockies Express pipeline which is anticipated in 2008. We have contracted 10,000 Mcf/D on this pipeline to provide assurance of gas delivery. The Colorado Interstate Gas (CIG) basis differential averaged $1.18 below Henry Hub (HH) and ranged from $.51 to $1.67 below HH in the first quarter. Although related to CIG, the actual basin price varies. Gas from the DJ basin was sold slightly above the CIG price, Piceance basin gas was slightly below the CIG price while Uinta basin gas sold for approximately $.40 below CIG pricing.
 
 



Oil Contracts. Utah - As of March 31, 2007, our Utah light crude oil is sold under multiple contracts with different purchasers for varying pricing terms and ranging from one month to six months. In April 2007, contracts were in place to sell approximately 5,000 BOE/D during the month. These contracts have marginally improved since December 31, 2006 and are currently priced at approximately $12 to $17 per barrel below WTI with certain volumes tied to field posting, and in some cases our realized price is further reduced by transportation charges. As operator we deliver all produced volumes pursuant to these contracts, although our working interest partners or royalty owners have the right to take their respective volumes in kind and market their own volumes. Our net volumes from our Brundage Canyon properties approximate 80% of the total gross volumes. Assuming all the Brundage Canyon wells are producing, the gross production could exceed these contracted volumes. Our Utah crude oil is a paraffinic crude and can be processed efficiently by only a limited number of refineries.

On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007. Holly has begun to take delivery of approximately 1,000 Bbl/D in the first quarter of 2007, which stabilizes our realized sales price and reduces our transportation costs. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase total purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes transportation, is a fixed percentage of WTI and approximates our expected field posted price of $13 to $16 below WTI. This contract provides the pricing assurance we need to proceed with the long-term development of our Uinta basin assets. From October 1, 2003 through April 30, 2006 we were able to sell our Utah crude oil at approximately $2.00 per barrel below WTI and from May 1, 2006 through September 30, 2006, we were selling the majority of our Utah crude at approximately $9.00 per barrel below WTI. We may adjust our capital expenditures in the Uinta basin due to various factors, including the timing of refinery demand for the Uinta basin barrels and the actual or expected change in our realized price.

Hedging. See Note 4 to the unaudited condensed financial statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Electricity. We consume natural gas as fuel to operate our three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the economic production of heavy oil. Revenue and operating costs for the three months ended March 31, 2007 were down from the three months ended March 31, 2006 due to 6% lower electricity prices and 12% lower fuel gas cost, respectively. Conversely, revenue and operating costs in the three months ended March 31, 2007 were up from the three months ended December 31, 2006 due to 8% higher electricity prices and 4% higher natural gas prices, respectively. The following table is for the three months ended:

     
March 31, 2007
   
March 31, 2006
   
December 31, 2006
 
Electricity
                   
Revenues (in millions)
 
$
14.6
 
$
15.2
 
$
13.4
 
Operating costs (in millions)
 
$
14.2
 
$
14.3
 
$
12.1
 
Electric power produced - MWh/D
 
 
2,117
 
 
2,080
 
 
2,093
 
Electric power sold - MWh/D
 
 
1,914
 
 
1,884
 
 
1,861
 
Average sales price/MWh
 
$
81.08
 
$
85.93
 
$
75.05
 
Fuel gas cost/MMBtu (including transportation)
 
$
6.70
 
$
7.65
 
$
6.44
 

Oil and Gas Operating, Production Taxes, G&A and Interest Expenses. The following table presents information about our operating expenses for each of the three month periods ended:
 
   
Amount per BOE
 
Amount (in thousands)
 
 
 
March 31, 2007
 
March 31, 2006
 
December 31, 2006
 
March 31, 2007
 
March 31, 2006
 
December 31, 2006
 
Operating costs - oil and gas production
 
$
14.65
 
$
12.19
 
$
13.69
 
$
33,610
 
$
25,738
 
$
33,804
 
Production taxes
   
1.66
   
1.53
   
1.15
   
3,815
   
3,233
   
2,840
 
DD&A - oil and gas production
 
 
8.16
 
 
6.26
   
8.24
   
18,725
 
 
13,223
 
 
20,335
 
G&A
 
 
4.49
 
 
3.94
 
 
4.55
   
10,307
 
 
8,314
 
 
11,231
 
Interest expense
 
 
1.69
   
.75
 
 
1.27
   
4,292
 
 
1,577
 
 
3,503
 
Total
 
$
30.65
 
$
24.67
 
28.90
 
$
70,749
 
$
52,085
 
$
71,713
 
 



 
Our total operating costs, production taxes, G&A and interest expenses for the three months ended March 31, 2007, stated on a unit-of-production basis, increased 24% over the three months ended March 31, 2006 and increased 6% over the three months ended December 31, 2006. The changes were primarily related to the following items:

 
·
Operating costs: Operating costs per BOE in the first quarter of 2007 were 20% higher than the first quarter of 2006 primarily due to an increase in steam costs, company and contract labor as well as transportation, compression and gathering costs. Similarly, operating costs per BOE were 7% higher in the first quarter of 2007 as compared to the fourth quarter of 2006, as production volumes were down. Cost pressures do remain, but we are working to offset them with improved efficiencies. The cost of our steaming operations on our heavy oil properties in California varies depending on the cost of natural gas used as fuel and the volume of steam injected. The following table presents steam information:

 
March 31, 2007
March 31, 2006
 
1Q07 to 1Q06 Change
December 31, 2006
 
1Q07 to 4Q06 Change
Average volume of steam injected (Bbl/D)
86,132
75,138
15%
85,349
1%
Fuel gas cost/MMBtu (including transportation)
$ 6.70
$ 7.65
(12%)
$ 6.44
4%

As we remain in a strong commodity price environment, we anticipate that cost pressures within our industry may continue due to greater field activity and rising service costs in general. Based on current plans, we are targeting average steam injection in 2007 of approximately 90,000 to 95,000 barrels of steam per day (BSPD). Natural gas prices impact our cost structure in California by approximately $1.60 per California BOE for each $1.00 change in natural gas price.

·  
Production taxes: Our production taxes have increased over 2006 as the value of our oil and natural gas assets has increased. Severance taxes, which are prevalent in Utah and Colorado, are directly related to the cost of the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves. We expect production taxes, in general, to track the commodity price.

·  
Depreciation, depletion and amortization: DD&A increased per BOE in the three months ended March 31, 2007 compared to the same period in the prior year due to an increase in capital spending over the last year and particularly more extensive development in fields with higher drilling costs and leasehold acquisition costs. Our capital program is also experiencing cost pressures in our labor and for goods and services commensurate with other energy developers. As these costs increase, our DD&A rates per BOE will also increase.

·  
General and administrative: Approximately 70% of our G&A is compensation or compensation related costs. To remain competitive in workforce compensation and achieve our growth goals, our general and administrative cost increased significantly due to additional staffing, higher compensation levels, bonuses, stock compensation and benefit costs. We also incurred higher employee travel and other G&A costs associated with our growth activities.

·  
Interest expense: Our outstanding borrowings, including our senior unsecured money market line of credit and senior subordinated notes, was $477 million at March 31, 2007 compared to $406 million at December 31, 2006. Our average borrowings increased during the three months ended March 31, 2007 as a result of our capital expenditure program and due to the annual payment of a price-based royalty for $38 million. Beginning in 2006, a certain portion of our interest cost related to our Piceance basin acquisition and joint venture has been capitalized into the basis of the assets, and we anticipate a portion will continue to be capitalized until the remainder of our probable reserves have been recategorized to proved developed reserves. For the quarter ended March 31, 2007, $4 million has been capitalized and we expect to capitalize approximately $20 million of interest cost during the full year of 2007.
 




Estimated 2007 Oil and Gas Operating, G&A and Interest Expenses.
 
 
 Anticipated range
 
 
 
   
 
 
in 2007 per BOE
 
       
Operating costs-oil and gas production (1)
 
$
14.50 to 15.50
 
           
Production taxes
   
1.50 to 2.00
             
DD&A
 
 
7.75 to 8.75
 
           
G&A
 
 
3.50 to 4.00
 
           
Interest expense
 
 
1.00 to 2.00
 
           
Total
 
$
28.25 to 32.25
 
           
(1) Assuming natural gas prices of approximately NYMEX HH $7.50 MMBtu, we plan to inject approximately 15% greater steam levels in 2007 compared to 2006 levels.

Income Taxes. See Note 6 to the unaudited condensed financial statements. Our effective tax rate will be similar in 2007 as compared to 2006. We experienced an effective tax rate in the three months ended March 31, 2007 of 39%, which is in line with our projections.

Development, Exploitation and Exploration Activity. We drilled 124 gross (88 net) wells during the first quarter of 2007, realizing a gross success rate of 99 percent. Excluding any future acquisitions, our targeted 2007 developmental capital budget is between $227 million and $267 million. As of March 31, 2007, we have five rigs drilling on our properties under long-term contracts and have one more rig scheduled to begin in mid-2007.

Drilling Activity. The following table sets forth certain information regarding drilling activities for the three months ended March 31, 2007:
 
           
       
Gross Wells
   
Net Wells
       
SMWSS
     
20
   
20
       
NMWSS
   
 
11
   
11
     
 
Socal
   
 
18
   
18
     
 
Piceance
     
18
   
5
       
Uinta
   
 
15
   
13
     
 
DJ (1)
     
42
   
21
       
Totals
   
 
124
   
88
     
 
 
(1)
Includes 1 gross well (.5 net well) that was a dry hole in Yuma County, Colorado.

Production
California’s three asset teams are South Midway-Sunset (SMWSS, which has been realigned to include Ethel D), North Midway-Sunset (NMWSS) (which includes diatomite) and Southern California (Socal) (which includes Poso Creek, Placerita and Montalvo). The Rocky Mountain/Mid-Continent region’s three asset teams are Piceance, Uinta and DJ basins.

SMWSS, San Joaquin Valley Basin (SJVB) - During the three months ended March 31, 2007, production averaged approximately 9,900 Bbl/D compared to approximately 10,800 Bbl/D and 10,700 Bbl/D during the three month periods ended March 31, 2006 and December 31, 2006, respectively. During the three months ended March 31, 2007, we completed four horizontal infill wells and improved subsurface steam monitoring to determine best heat placement into the remaining oil column to maximize recovery and value. Additionally, a number of horizontal wells were pulled off production for cyclic steaming. Cyclic steaming of these horizontal wells is necessary to place steam effectively into the remaining oil column. In the second quarter of 2007, we plan to drill approximately 14 infill horizontal wells. Increased production from these activities is expected to slow the natural decline. We expect to manage our decline rate to approximately 6% to 7% for 2007.

We have completed our 2007 drilling program on our Ethel D property and production has increased by over 200 Bbl/D. We may expand our program depending on reservoir performance.
 




NMWSS, SJVB - Our Midway-Sunset diatomite oil project is performing above expectations due to a more aggressive approach in our use of steam. During the three months ended March 31, 2007, production from the diatomite project averaged approximately 600 Bbl/D up from approximately 200 Bbl/D and 400 Bbl/D during the three month periods ended March 31, 2006 and December 31, 2006, respectively. Our 2007 capital is focused on drilling the diatomite first phase development wells and adding steam generation equipment and various facilities. Diatomite wells will not begin to be drilled until the third quarter of 2007.

Socal, SJVB and Los Angeles Basin - Poso Creek is performing solidly above plan due to strong steam flood performance and our infill drilling. During the three months ended March 31, 2007, production averaged approximately 1,500 Bbl/D up from approximately 600 Bbl/D and 1,400 Bbl/D during the three month periods ended March 31, 2006 and December 31, 2006, respectively. We are planning to accelerate development drilling with over 70 infill producing wells this year, expanding the steam drive by 14 patterns and installing a third steam generator in the second quarter of 2007.
 
Piceance Basin, Colorado - We currently have four drilling rigs operating in the basin and expect to maintain this level for the remainder of the year. Newly constructed pipelines to the mesa plateaus were completed late in the first quarter and since completion, three North Parachute Ranch wells and eight Garden Gulch wells have been put into production. Twelve additional wells are forecasted to be drilled and connected by the end of the second quarter of 2007. Average daily production in the Piceance basin for the first quarter was 6.4 net MMcf/D. The recent well connects have increased April monthly production to over 8.5 net MMcf/D. Significant progress has been made to lower the days required to drill wells. Construction has begun on the Garden Gulch road extension, which, coupled with the mountain road, will greatly improve access to our operations on the Garden Gulch acreage.

Uinta Basin, Utah - Our 2007 capital is directed at additional Brundage Canyon 40-acre development wells, drilling the Ashley Forest extension to the south of Brundage Canyon, continued Lake Canyon assessment and drilling 20-acre infill wells in Brundage Canyon. During the first quarter, we drilled 13 net wells in Brundage Canyon. Well performance results continue to be positive and preliminary results from four 20-acre pilot wells indicate the possibility of new production opportunities.

Average daily production during the first quarter from all Uinta basin assets was 4,800 net BOE/D. In the fourth quarter of 2006, oil sales were interrupted due to refinery and trucking limitations. The refinery resumed operations in mid-January 2007. Improved market conditions late in the first quarter resulted in a daily production exit rate of 6,100 net BOE/D for the quarter. We continue to have one drilling rig operating in the basin. In February 2007, we signed a six year oil contract with Holly for 3,200 BOE/D starting in July 2007 with up to 5,000 BOE/D through June 30, 2013 upon the certified completion of their refinery upgrade. This contract along with our other oil marketing arrangements provides us the ability to sell all of our crude oil production in the Uinta basin.

Post winter season access to our Ashley Forest acreage and Lake Canyon area will open up in May of 2007, with our second and third quarter drilling focusing in these areas. Six drilling permits have been received for Ashley Forest and four permits received for Lake Canyon wells with an additional 16 permits anticipated in the second quarter to support the mid-May to December drilling window.

In December 2004, we entered into a development agreement with an industry partner to develop their Coyote Flats prospect. In the first and early second quarter of 2006, we established gas sales from three Ferron wells. The combined net production from the three wells is approximately 1.0 MMcf/D. We will continue the production tests to further assess the Ferron’s potential at Coyote Flats. As the result of establishing production in the three wells, we were assigned a 50% interest in approximately 43,700 gross acres from our industry partner.

DJ Basin - Our first quarter activity in the DJ basin has focused on Niobrara development drilling in Yuma County, Colorado. Production early in the quarter was hampered by severe snow on Colorado’s eastern plains. Average daily production in the DJ for the first quarter was 17.4 net MMcf/D and by the end of the quarter, production has recovered to approximately 18 MMcf/D.

We drilled 41 Niobrara wells during the first quarter of 2007. In addition, 28.5 square miles of 3-D seismic data was acquired in the quarter. This 3-D data and the existing drilling location inventory supports the 2007 drilling program of 168 wells.

Company Owned Drilling Rigs. During 2005 and 2006, we purchased three drilling rigs, two of which are drilling for us. Owning these rigs allows us to successfully meet a portion of our drilling needs in the Uinta and Piceance basins.

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. In the second quarter of 2006, we revised our senior unsecured revolving credit facility to increase





our maximum credit amount under the facility to $750 million and increased our current borrowing base to $500 million. On October 24, 2006, we completed the sale of $200 million of ten year 8.25% senior subordinated notes and paid down our borrowings under our facility by $141 million. As of March 31, 2007, we had total borrowings under the senior unsecured revolving credit facility and senior unsecured money market line of credit of $277 million and $200 million under our senior subordinated ten year notes.

Capital Expenditures. We establish a capital budget for each calendar year based on our development opportunities and the expected cash flow from operations for that year. Acquisitions are typically debt financed. We may revise our capital budget during the year as a result of acquisitions, drilling outcomes and/or changes in commodity prices that influence our decision to change capital expenditures to closely match operating cash flows. Excess cash generated from operations is expected to be applied toward capital expenditures, debt reduction or other corporate purposes.

Management is closely monitoring the capital development program in relation to estimated cash flows and expects to commit capital in the $227 million to $267 million range, excluding acquisitions. The capital development program may be revised due to lower commodity price expectations, timing of crude deliveries out of the Uinta basin, equipment availability, permitting or other factors. We have reevaluated the development plan in the Piceance basin to maximize capital efficiency by minimizing rig moves. Consequently, we estimate that companywide proved reserves will approximate 170 to 180 million BOE at year end 2007, including the effect of the expected sale of the Montalvo assets which consist of 7 million BOE of reserves. During the three months ended March 31, 2007, capital expenditures totaled $75.5 million of which $28 million related to the 2007 capital budget and $47.5 million related to the 2006 capital budget.

Our 2007 expenditures will be directed toward developing reserves, increasing oil and gas production and exploration opportunities. For 2007, we plan to invest up to approximately $176 million, or 66%, in our Rocky Mountain/Mid-Continent region assets, and up to $91 million, or 34%, in our California assets.

On March 19, 2007 we announced that we have entered into an agreement to sell our non-core West Montalvo assets, near Ventura, California. We estimate a sales price of approximately $63 million before adjustments and expect to transfer the assets in the second quarter of 2007. Production from the property is approximately 700 BOE/D, which is less than 3% of current production and, as of December 31, 2006, the property had 7 million BOE of proved reserves which is less than 5% of the 2006 year end total of 150 million BOE. The completion of the transaction is subject to certain conditions and there is no assurance that all such conditions will be satisfied.

Dividends. Our annual dividend is currently $.30 per share, payable quarterly in March, June, September and December.

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. Combined crude oil and natural gas prices increased in the first three months of 2007 (see graphs on page 11) and production decreased since December 2006 by 5%.

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 senior unsecured revolving 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.

The table below compares financial condition, liquidity and capital resources changes for the three month periods ended (in millions, except for production and average prices):
 
March 31, 2007
(1Q07)
March 31, 2006
(1Q06)
 
1Q07 to 1Q06 Change
December 31, 2006
(4Q06)
 
1Q07 to 4Q06 Change
Average production (BOE/D)
25,490
23,461
9%
26,889
(5%)
Average oil and gas sales prices, per BOE after hedging
$ 43.84
$ 48.45
(10%)
$ 42.00
4%
Net cash provided by operating activities
$ 12
$ 25
(52%)
$ 58
(79%)
Working capital, excluding line of credit
$ (65)
$ (50)
(30%)
$ (101)
36%
Sales of oil and gas
$ 102
$ 102
-%
$ 102
-%
Long-term debt, including line of credit
$ 477
$ 259
84%
$ 406
17%
Capital expenditures, including acquisitions and deposits on acquisitions
$ 76
$ 206
(63%)
$ 127
(40%)
Dividends paid
$ 3.3
$ 2.9
14%
$ 3.3
-%





Contractual Obligations. Our contractual obligations as of March 31, 2007 are as follows (in millions):

 
   
Total
 
2007
 
2008
 
2009
 
2010
 
2011
 
Thereafter
Long-term debt and interest
 
$
715.1
$
34.3
$
34.3
$
34.3
$
34.3
$
295.4
$
282.5
Abandonment obligations
 
 
30.9
 
.7
 
.9
 
1.0
 
1.0
 
1.0
 
26.3
Property acquisition payable
   
54.4
 
54.4
 
-
 
-
 
-
 
-
 
-
Operating lease obligations
 
 
13.9
 
1.4
 
1.7
 
1.4
 
1.4
 
1.4
 
6.6
Drilling and rig obligations
 
 
89.8
 
19.6
 
25.3
 
42.7
 
2.2
 
-
 
-
Firm natural gas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  transportation contracts
 
 
72.7
 
3.6
 
7.6
 
8.5
 
8.7
 
8.7
 
35.6
Total
 
$
976.8
$
114.0
$
69.8
$
87.9
$
47.6
$
306.5
$
351.0

Long-term debt and interest - Our credit facility borrowings and related interest of approximately 6.6% can be paid before its maturity date without significant penalty on borrowings under our credit facility. Our 8.25% senior subordinated notes mature in November 2016, but are not redeemable until November 1, 2011 and are not redeemable without any premium until November 1, 2014.

Operating leases - We lease corporate and field offices in California, Colorado and Texas. We lease an airplane for business travel under a ten year operating lease beginning December 2006.
 
Drilling obligation - We intend to participate in the drilling of over 16 gross wells on our Lake Canyon prospect over the four year contract, beginning in 2006. Our minimum expenditure obligation under our exploration and development agreement is $9.6 million. Also included above, under our June 2006 joint venture agreement in the Piceance basin, we must have 120 wells drilled by 2010 to avoid penalties of $.2 million per well or a maximum of $24 million.

Drilling rig obligation - We are obligated in operating lease agreements for the use of multiple drilling rigs.

Firm natural gas transportation - We have one firm transportation contract which provides us additional flexibility in securing our natural gas supply for California operations. This allows us to potentially benefit from lower natural gas prices in the Rocky Mountains compared to natural gas prices in California. We also have several long-term transportation contracts which provide us with physical access to interstate pipelines to move gas from our producing areas to markets.

On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase their total purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum number of delivered units (“base daily volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery upgrade. Holly may, but is not obligated to, purchase volumes in excess of the base daily volumes when notified by us at the beginning of any contract year. 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

As discussed in Note 4 to the unaudited condensed financial statements, to minimize the effect of a downturn in oil and gas prices and protect our profitability and the economics of our development plans, from time to time we enter 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, acquisition economics on purchased assets and our future financial commitments. This price hedging program is designed to moderate the effects of a severe crude oil and natural gas price downturn while allowing us to participate in any commodity price increases. In California, we benefit from lower natural gas pricing as we are a consumer of natural gas in our operations and elsewhere, we benefit from higher natural gas pricing. We have hedged, and may hedge in the future both natural gas purchases and sales as determined appropriate by management. Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate in accordance with policy established by our board of directors.
 




Currently, our hedges are in the form of swaps and collars. However, we may use a variety of hedge instruments in the future to hedge WTI or the index gas price. We have 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 we sell our produced gas in Colorado and Utah at CIG and Questar index prices, respectively.

The following table summarizes our hedge position as of March 31, 2007:
 
   
Average
         
Average
   
 
 
Barrels
 
Floor/Ceiling
 
 
 
MMBtu
 
Floor/Ceiling
Term
 
Per Day
 
Prices
 
Term
 
Per Day
 
Prices
Crude Oil Sales
(NYMEX WTI)
 
 
 
 
 
Natural Gas Sales
(NYMEX HH)
 
 
 
 
Collars
       
 
Collars
       
Full year 2007
 
8,000
 
$47.50 / $70.00
 
2nd Quarter 2007
 
13,000
 
$8.00 / $8.82
Full year 2008
 
10,000
 
$47.50 / $70.00
 
3rd Quarter 2007
 
14,000
 
$8.00 / $9.10
Full year 2009
 
10,000
 
$47.50 / $70.00
 
4th Quarter 2007
 
15,000
 
$8.00 / $11.39
Full year 2010
 
5,000
 
$56.00 / $78.95
 
1st Quarter 2008
 
16,000
 
$8.00 / $15.65
Full year 2010
 
1,000
 
$60.00 / $75.00
 
2nd Quarter 2008
 
17,000
 
$7.50 / $8.40
         
 
3rd Quarter 2008
 
19,000
 
$7.50 / $8.50
           
4th Quarter 2008
 
21,000
 
$8.00 / $9.50
                     
         
 
Natural Gas Sales (NYMEX HH TO CIG) 
 
 
 
 
Swaps
     
Price
 
Basis Swaps
 
 
 
Price
2nd through 4th quarter 2007
 
1,000
 
$64.55
 
April 2007
 
13,000
 
$1.77
2nd through 4th quarter 2007
 
2,000
 
$60.00
 
May 2007
 
13,000
 
$1.70
           
June 2007
 
13,000
 
$1.69
           
July 2007
 
14,000
 
$1.56
           
August 2007
 
14,000
 
$1.51
           
September 2007
 
14,000
 
$1.58
           
October 2007
 
15,000
 
$1.63
           
November & December 2007
 
15,000
 
$1.71
           
1st Quarter 2008
 
16,000
 
$1.74
           
2nd Quarter 2008
 
17,000
 
$1.43
           
3rd Quarter 2008
 
19,000
 
$1.40
         
 
4th Quarter 2008
 
21,000
 
$1.46

The collar strike prices will allow us to protect a significant portion of our future cash flow if 1) oil prices decline below $47.50 per barrel while still participating in any oil price increase up to $78.95 per barrel on these volumes and if 2) gas prices decline below approximately $8 per MMBtu. These hedges improve our financial flexibility by locking in significant revenues and cash flow upon a substantial decline in crude oil or natural gas prices. It also allows us to develop our long-lived assets and pursue exploitation opportunities with greater confidence in the projected economic outcomes and allows us to borrow a higher amount under our senior unsecured revolving credit facility.

While we have designated our 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, we may have some ineffectiveness in our natural gas hedges 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 we believe 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 our hedges, when marked-to-market, could have a material impact on earnings in any given quarter and, thus, add increased volatility to our 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.





We entered into derivative contracts (natural gas swaps and collar contracts) on March 1, 2006 that did not qualify for hedge accounting under SFAS 133 because the price index for the location in the derivative instrument did not correlate closely with the item being hedged. These contracts were recorded in the first quarter of 2006 at their fair value on the balance sheet and we recognized an unrealized net loss of approximately $4.8 million on the income statement under the caption “Commodity derivatives.” We entered into natural gas basis swaps on the same volumes and maturity dates as the previous hedges in May 2006 which allowed for these derivatives to be designated as cash flow hedges going forward, causing an unrealized net gain of $5.6 million to be recognized in the second quarter of 2006. The difference of $.8 million was recorded in other comprehensive income at the date the hedges were designated.

On June 8, 2006 and July 10, 2006 we entered into five year interest rate swaps for a fixed rate of approximately 5.5% on $100 million of our outstanding borrowings under our credit facility. These interest rate swaps have been designated as cash flow hedges.

The related cash flow impact of all of our derivative activities are reflected as cash flows from operating activities.

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.

Based on NYMEX futures prices as of March 31, 2007, (WTI $68.72; HH $8.50) we would expect to make pre-tax future cash payments or to receive payments over the remaining term of our crude oil and natural gas hedges in place as follows: 

           
Impact of percent change in futures prices
 
     
March 31, 2007
   
on earnings
 
     
NYMEX Futures
   
 -20%
   
-10%
   
+ 10%
   
+ 20%
 
Average WTI Futures Price (2007 - 2010)
 
$
68.72
 
$
54.98
 
$
61.85
 
$
75.59
 
$
82.46
 
Crude Oil gain/(loss) (in millions)
 
 
(5.7
)
 
11.6
 
 
.1
 
 
(69.6
)
 
(147.6
)
Average HH Futures Price (2007 - 2008)
 
 
8.50
   
6.80
 
 
7.65
 
 
9.35
   
10.2
 
Natural Gas gain (in millions)
   
5.7
   
16.1
   
8.8
   
3.3
   
(2.2
)
 
                               
Net pre-tax future cash (payments) and receipts by year (in millions):
                               
2007 (WTI $68.27; HH $8.24)
 
$
.6
 
$
16.8
 
$
8.3
 
$
(16.6
)
$
(38.6
)
2008 (WTI $69.97; HH $8.70)
   
(.6
)
 
5.0
   
.6
   
(28.0
)
 
(57.7
)
2009 (WTI $69.05)
   
-
   
-
   
-
   
(21.7
)
 
(46.9
)
2010 (WTI $67.49)
   
-
   
5.9
   
-
   
-
   
(6.6
)
Total
 
 $
-
 
 $
27.7
 
$
8.9
 
$
(66.3
)
$
(149.8

Interest Rates. Our exposure to changes in interest rates results primarily from long-term debt. On October 24, 2006, we issued $200 million of 8.25% senior subordinated notes due 2016 in a public offering. Total long-term debt outstanding including our short-term line of credit, at March 31, 2007 was $477 million. Interest on amounts borrowed under our revolving credit facility is charged at LIBOR plus 1.0% to 1.75%, with the exception of the $100 million of principal for which we have a hedge in place to fix the interest rate at approximately 5.5% plus the senior unsecured revolving credit facility’s margin through June 30, 2011. Based on March 31, 2007 credit facility borrowings, a 1% change in interest rates would have an annual $1.1 million after tax impact on our financial statements.

Item 4. Controls and Procedures

As of March 31, 2007, we have carried out an evaluation under the supervision of, and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our 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, 2007, our Chief Executive Officer and Chief Financial Officer have concluded that our 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 in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
 
There was no change in our internal control over financial reporting during the most recently completed calendar quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 




Forward Looking Statements

“Safe harbor under the Private Securities Litigation Reform Act of 1995:” Any statements in this Form 10-Q that are not historical facts are forward-looking statements that involve risks and uncertainties. Words such as “will,” “intend,” “continue,” “target(s),” “expect,” “achieve,” “future,” “may,” “could,” “goal(s),”, “forecast,” “anticipate,” 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 15 of our Form 10-K filed with the Securities and Exchange Commission, under the heading “Risk Factors” and all material changes are updated in Part II, Item 1A within this 10-Q.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings
None.

Item 1A. Risk Factors

 We may not be able to deliver minimum crude oil volumes required by our sales contract. Production volumes from our Uinta properties over the next six years are uncertain and there is no assurance that we ill be able to consistently meet the minimum requirement. On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. Under the agreement, we will begin delivering 3,200 Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase their total purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum number of delivered units (“base daily volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery upgrade.  

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
10.1*    Purchase and sale agreement between the Company and Venoco, Inc. dated March 19, 2007.
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.

* Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
 




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/ Shawn M. Canaday
Shawn M. Canaday
Controller
(Principal Accounting Officer)


Date:  May 2, 2007
 

PURCHASE AND SALE AGREEMENT BETWEEN THE COMPANY AND VENOCO, INC.


Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
 
 
PURCHASE AND SALE AGREEMENT

between

BERRY PETROLEUM COMPANY,

as Seller,
 
 
and
 
 
VENOCO, INC.,

as Buyer,
 
 
Ventura County, California
 
 
 
Dated March 19, 2007

Effective January 1, 2007
 
 
CONFIDENTIAL
 



Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
TABLE OF CONTENTS
 
   
Page
 
TABLE OF CONTENTS
 
     
ARTICLE 1
PURCHASE AND SALE
1
     
1.1
Purchase and Sale
1
     
1.2
Assets
1
     
1.3
Effective Time
2
     
ARTICLE 2
PURCHASE PRICE
2
     
2.1
Purchase Price
2
     
2.2
Deposit
2
     
2.3
Adjustments to Purchase Price
3
     
2.4
Allocated Values
4
     
ARTICLE 3
DUE DILIGENCE INSPECTION
4
     
3.1
Access to Records
4
     
3.2
No Representation or Warranty
5
     
3.3
Access to the Assets and Indemnity
5
     
3.4
PRC 3314.1 LEASE
5
     
ARTICLE 4
TITLE MATTERS
5
     
4.1
Defensible Title
5
     
4.2
Permitted Encumbrances
6
     
4.3
Title Defect
7
     
4.4
Notice of Title Defects
7
     
4.5
Seller’s Right to Cure
7
 
i

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
TABLE OF CONTENTS
(continued)
 
   
Page
     
4.6
Remedies for Title Defects
7
     
4.7
Title Thresholds
8
     
4.8
Title Dispute Resolution
8
     
4.9
Depletion and Depreciation of Personal Property
8
     
4.10
Consents
9
     
4.11
Casualty Loss
9
     
ARTICLE 5
ENVIRONMENTAL MATTERS
9
     
5.1
Definitions
9
     
5.2
Spills and NORM
10
     
5.3
Environmental Assessment
10
     
5.4
Notice of Environmental Defects
11
     
5.5
Remedies for Environmental Defects
11
     
5.6
Environmental Thresholds
12
     
5.7
Environmental Dispute Resolution
12
     
5.8
“As Is, Where Is” Purchase
12
     
5.9
Disposal of Materials, Substances and Wastes
13
     
5.10
Buyer’s Indemnity
13
     
5.11
Seller’s Indemnity
14
     
ARTICLE 6
SELLER’S REPRESENTATIONS AND WARRANTIES
14
     
6.1
Existence
14
     
6.2
Power
14
     
6.3
Authorization
15
 
ii

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
TABLE OF CONTENTS
(continued)
 
   
Page
     
6.4
Execution and Delivery
15
     
6.5
Liabilities for Brokers’ Fees
15
     
6.6
Liens
15
     
6.7
Taxes
15
     
6.8
Litigation
15
     
6.9
COMPLIANCE WITH LAWS
15
     
6.10
Contracts
15
     
6.11
Governmental Authorizations
16
     
6.12
Consents and Preference Rights
16
     
ARTICLE 7
BUYER’S REPRESENTATIONS AND WARRANTIES
17
     
7.1
Existence
17
     
7.2
Power and Authority
17
     
7.3
Authorization
17
     
7.4
Execution and Delivery
17
     
7.5
Liabilities for Brokers’ Fees
17
     
7.6
Litigation
17
     
7.7
Independent Evaluation
17
     
7.8
Qualification
18
     
7.9
Funds
18
     
ARTICLE 8
COVENANTS AND AGREEMENTS
18
     
8.1
Covenants and Agreements
18
 
iii

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
TABLE OF CONTENTS
(continued)
 
   
Page
     
8.2
Financial Statements
19
     
ARTICLE 9
CONDITIONS TO CLOSING
20
     
9.1
Seller’s Conditions
20
     
9.2
Buyer’s Conditions
20
     
ARTICLE 10
RIGHT OF TERMINATION AND ABANDONMENT
21
     
10.1
Termination
21
     
10.2
Liabilities Upon Termination
21
     
ARTICLE 11
CLOSING
22
     
11.1
Date of Closing
22
     
11.2
Closing Obligations
22
     
ARTICLE 12
POST-CLOSING OBLIGATIONS
23
     
12.1
Post-Closing Adjustments
23
     
12.2
Suspense Accounts
23
     
12.3
Dispute Resolution
24
     
12.4
Records
24
     
12.5
Further Assurances
24
     
12.6
Disclaimers of Representations and Warranties
24
     
ARTICLE 13
TAXES
25
     
13.1
Apportionment of Ad Valorem and Property Taxes
25
     
13.2
Transfer Taxes and Recording Fees
25
     
13.3
Other Taxes
25
     
13.4
Tax Reports and Returns
25
 
iv

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
TABLE OF CONTENTS
(continued)
 
   
Page
     
ARTICLE 14
ASSUMPTION AND RETENTION OF OBLIGATIONS; INDEMNIFICATION
26
     
14.1
Buyer’s Assumption of Liabilities and Obligations
26
     
14.2
Seller’s Retention of Liabilities and Obligations
26
     
14.3
Buyer’s Plugging and Abandonment Obligations
26
     
14.4
Indemnification
27
     
14.5
Procedure
27
     
14.6
No Insurance; Subrogation
29
     
14.7
Reservation as to Non-Parties
29
     
ARTICLE 15
MISCELLANEOUS
29
     
15.1
Exhibits
29
     
15.2
Expenses
29
     
15.3
Notices
29
     
15.4
Amendments
30
     
15.5
Assignment
30
     
15.6
Confidentiality
30
     
15.7
Press Releases
30
     
15.8
Headings
30
     
15.9
Counterparts
31
     
15.10
References
31
     
15.11
Governing Law
31
     
15.12
Removal of Signs
31
 
v

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
TABLE OF CONTENTS
(continued)
 
   
Page
     
15.13
Binding Effect
31
     
15.14
Survival
31
     
15.15
No Third-Party Beneficiaries
31
     
15.16
Limitation on Damages
31
     
15.17
Severability
31
     
15.18
Knowledge
31
     
ARTICLE 16
EXCHANGE RIGHT
32
     
16.1
Exchange Cooperation
32
 
vi

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
EXHIBITS

Exhibit/Schedule
Description
Section Where Defined
     
A-1
Leases and Lands
1.2.a
     
A-2
Wells
1.2.b
     
A-3
Rights-of-Way and Surface Leases
1.2.e
     
A-4
Equipment and Facilities
1.2.e
     
B
Material Agreements
1.2.d
     
C
Allocated Values
2.4
     
D
Temporary Access Agreement
3.3
     
E
Form of Assignment and Bill of Sale
11.2.a
     
F
Form of Assumption Agreement
11.2.a
     
G
Seller’s Wire Instructions
2.2
     
H
Seller’s Officer’s Certificate
11.2.e
     
I
Buyer’s Officer’s Certificate
11.2.f
     
J
Non-Foreign Affidavit
11.2.g
     
K
Suspense Accounts
12.2
     
6.12
Consents and Preference Rights
6.12
 
-vii-

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
PURCHASE AND SALE AGREEMENT
 
This PURCHASE AND SALE AGREEMENT (“Agreement”), dated March 19, 2007, is by and between Berry Petroleum Company, a Delaware corporation, 5201 Truxtun Avenue, Suite 300, Bakersfield, California 93309-0640 (“Seller”) and Venoco, Inc., a Delaware corporation, whose address is 370 17th Street, Suite 3900, Denver, Colorado 80202-1370 (“Buyer”).
 
RECITALS
 
A.    Seller owns and desires to sell certain real and personal property interests located in Ventura County, California, as more fully described in Section 1.2 below (the “Assets”).
 
B.    Buyer desires to purchase the Assets upon the terms and conditions set forth in this Agreement.
 
AGREEMENT
 
In consideration of the mutual promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller and Buyer agree as follows:
 
ARTICLE 1
PURCHASE AND SALE
 
1.1   Purchase and Sale. Seller agrees to sell and convey to Buyer, and Buyer agrees to purchase and receive from Seller, all of Seller’s right, title and interest in the Assets, pursuant to the terms and conditions of this Agreement.
 
1.2   Assets. The “Assets” are all of Seller’s right, title, and interest in and to the following real and personal property interests located in Ventura County, California:
 
a.   The oil and gas leases described on Exhibit A-1 (the “Leases”), insofar and only insofar as the Leases cover the lands described on Exhibit A-1 (the “Lands”); and the oil, gas and all other hydrocarbons (“Hydrocarbons”), in, on or under or that may be produced from the Lands.
 
b.   The oil and gas wells located on the Leases and Lands, or lands pooled or unitized therewith, including without limitation the oil and gas wells described on Exhibit A-2 (the “Wells”), all injection and disposal wells on the Leases and Lands, and all personal property and equipment associated with the Wells as of the Effective Date.
 
c.   The rights, to the extent transferable, in and to all existing and effective unitization, pooling and communitization agreements, declarations and orders, to the extent that they relate to or affect any of the interests described in Sections 1.2.a. and 1.2.b. or the post-Effective Time production of Hydrocarbons from the Leases and Lands.
 
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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
d.   The rights, to the extent transferable, in and to Hydrocarbon, gathering and processing contracts, operating agreements, balancing agreements, joint venture agreements, partnership agreements, farmout agreements and other contracts, agreements and instruments relating to the interests described in Sections 1.2.a., 1.2.b. and 1.2.c, including without limitation the agreements described on Exhibit B (the “Material Agreements”), but specifically excluding any marketing or production sales agreements.
 
e.   All of the personal property, fixtures, improvements (including without limitation the equipment and facilities described on Exhibit A-4) (the “Equipment and Facilities”) and permits, licenses, approvals, servitudes, rights-of-way, easements, surface leases (including without limitation the rights-of-way easements and surface leases described on Exhibit A-3) and other surface rights, tanks, boilers, buildings, improvements, injection facilities, saltwater disposal facilities, other appurtenances and facilities located on and used in connection with or otherwise related to the exploration for or production, gathering, treatment, processing, storing, or transporting of Hydrocarbons or water produced from the Assets described in Sections 1.2.a. through 1.2.d.
 
f.   Seller’s Lease and well files; gas processing files; division order files; abstracts; title opinions; land surveys; well logs; maps; engineering data and reports; reserve studies and evaluations (insofar as they cover and exist within the boundaries of the Lands), geological and geophysical data (including seismic data) and all technical evaluations, interpretive data and technical data and information relating to the Assets; provided, however, the foregoing shall not include any files, records, data or information which is attorney work product or subject to attorney client privilege or any files, data or information which by agreement Seller is required to keep confidential except and to the extent a waiver in writing is obtained of any such confidential requirements or any files, data or information related to any events concerning or related to an oil spill that occurred on the Assets in December 1993 (the “1993 Oil Spill”) (the “Records”).
 
1.3   Effective Time. The purchase and sale of the Assets shall be effective as of January 1, 2007 at 12:01 a.m., Pacific Time (the “Effective Time”).
 
ARTICLE 2
PURCHASE PRICE
 
2.1   Purchase Price. The purchase price for the Assets shall be SIXTY-THREE MILLION DOLLARS ($63,000,000.00) (the “Purchase Price”). At Closing, Buyer shall pay Seller the Purchase Price as adjusted pursuant to Sections 2.2 and 2.3 below by wire transfer of immediately available funds to Seller or as directed by Seller.
 
2.2   Deposit. Concurrently with the execution of this Agreement, Buyer shall wire to Seller in immediately available funds the amount of Three Million Dollars ($3,000,000.00) (the “Deposit”) as directed on Exhibit G. The Deposit shall be held by Seller and, subject to the terms of Article 10 of this Agreement, either (i) applied against the Purchase Price (without interest) in the event the Closing is consummated, (ii) returned to Buyer with interest at the rate of the average of the daily commercial paper overnight repurchase rate as published in The Wall Street Journal for the period from the time the Deposit is paid to Seller until it is returned to Buyer (“Interest”) if (x) Seller refuses to close after all conditions specified in Section 9.1 have been satisfied (or waived by Seller) and Buyer certifies to Seller in writing that it is ready, willing and able to perform under Article 11 or (y) the conditions specified in Section 9.2 have not been satisfied (or waived by Buyer), or (iii) retained by Seller if all conditions specified in Section 9.2 have been satisfied and Seller certifies to Buyer in writing that Seller is ready, willing and able to perform under Article 11.
 
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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
2.3   Adjustments to Purchase Price. The Purchase Price shall be adjusted according to this Section without duplication. For all adjustments known as of Closing, the Purchase Price shall be adjusted at Closing pursuant to a “Preliminary Settlement Statement” approved by Seller and Buyer on or before Closing. A draft of the Preliminary Settlement Statement will be prepared by Seller and provided to Buyer two (2) business days prior to Closing. The Preliminary Settlement Statement shall set forth the Purchase Price as adjusted as provided in this Section using the best information available at the Closing Date which amount shall be paid at Closing and is referred to as the “Closing Amount.” The Closing Amount shall be paid at Closing by wire transfer of immediately available funds in accordance with the wiring instructions set forth in Section 2.1. After Closing, final adjustments to the Purchase Price shall be made pursuant to the Final Settlement Statement to be delivered pursuant to Section 12.1. For the purposes of this Agreement, the term “Property Expenses” shall mean all capital expenses, joint interest billings, lease operating expenses, lease rental and maintenance costs, royalties, overriding royalties, Taxes (as defined and apportioned as of the Effective Time pursuant to Article 13), drilling expenses, workover expenses, geological, geophysical and any other exploration or development expenditures chargeable under applicable operating agreements or other agreements consistent with the standards established by the Council of Petroleum Accountant Societies of North America that are attributable to the maintenance and operation of the Assets during the period in question.
 
a.   Upward Adjustments. The Purchase Price shall be adjusted upward by the following:
 
(i)   An amount equal to all Property Expenses, including prepaid expenses, attributable to the Assets after the Effective Time that were paid by Seller (all to be apportioned as of the Effective Time except as otherwise provided), including without limitation, prepaid utility charges, prepaid rentals and royalties, including lease rentals, and prepaid drilling and completion costs (to be apportioned as of the Effective Time based on drilling days).
 
(ii)   The proceeds of production attributable to the Assets occurring before the Effective Time (including production from the Assets that occurred before the Effective Time but, because such production is in pipelines or in processing, had not been sold as of the Effective Time times the price for which production from the Assets was sold immediately prior to the Effective Time) and received by Buyer, net of royalties and taxes measured by production.
 
(iii)   To the extent that there are any pipeline imbalances, if the net of such imbalances is an overdelivery imbalance (that is, at the Effective Time, Seller has delivered more gas to the pipeline than the pipeline has redelivered for Seller), the Purchase Price shall be adjusted upward by the product of the price received by Seller times the net overdelivery imbalance in MMbtus.
 
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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
(iv)   An amount equal to Seller’s share of any oil or condensate in tanks or storage facilities produced from or credited to the Leases and Lands prior to the Effective Time based upon the quantities in oil or condensate tanks or storage facilities as measured by and reflected in Seller’s records multiplied by the price in effect for such inventory on the Closing Date; and
 
(v)    Any other amount provided in this Agreement or agreed upon by Seller and Buyer.
 
b.   Downward Adjustments. The Purchase Price shall be adjusted downward by the following:
 
(i)     An amount equal to the sum of all Title Purchase Price Adjustments as defined in Section 4.7;
 
(ii)    An amount equal to Environmental Purchase Price Adjustment, as defined in Section 5.6;
 
(iii)   The proceeds of production attributable to the Assets occurring on or after the Effective Time and received by Seller, net of royalties and taxes measured by production;
 
(iv)   To the extent that there are any pipelines imbalances, if the net of such imbalances is an underdelivery imbalance (that is, at the Effective Time, Seller has delivered less gas to the pipeline than the pipeline has redelivered for Seller), the Purchase Price shall be adjusted downward by the product of the price received by Seller times the net underdelivery balance in MMbtus.
 
(v)    An amount equal to the Seller Property Tax, as defined in Section 13.1;
 
(vi)   An amount equal to the Suspense Accounts, as defined in Section 12.2; and
 
(vii)      Any other amount provided in this Agreement or agreed upon by Seller and Buyer.
 
2.4   Allocated Values. Seller and Buyer agree to allocate the Purchase Price among the Assets as set forth in Exhibit C.
 
ARTICLE 3 
DUE DILIGENCE INSPECTION
 
3.1   Access to Records. Subject to the provisions of the Confidentiality Agreement dated December 4, 2006 between Seller and Buyer, Seller will disclose and make available to Buyer and its representatives at Seller’s offices and during Seller’s normal business hours, all Records in Seller’s possession or control relating to the Assets for the purpose of permitting Buyer to perform its due diligence review including, but not limited to, all well, leasehold, unit and title files and title opinions. Seller agrees to reasonably cooperate with Buyer in Buyer’s efforts to obtain, at Buyer’s sole expense, such additional information relating to the Assets as Buyer may reasonably desire. Buyer may inspect the Records only to the extent it may so do without violating any obligation, confidence or contractual commitment of Seller to a third party. Seller shall use reasonable efforts to obtain the necessary consents to allow Buyer’s examination of any confidential information that is material to this transaction, but shall not be required to incur any costs or additional liabilities to obtain any such consents.
 
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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
 
3.2   No Representation or Warranty. Seller makes no representation or warranty as to the accuracy, completeness, or content of the Records maintained by Seller and made available to Buyer, including, without limitation, any seismic, geological, or geophysical data or interpretations, as well as any engineering or reserve studies and evaluations.  Buyer agrees that any conclusions drawn from the Records shall be the result of its own independent review and judgment. Seller further makes no representations or warranties, express or implied, as to the condition of the Assets, or their fitness for Buyer’s intended use or operations.
 
3.3   Access to the Assets and Indemnity. Prior to Closing, Seller shall permit Buyer, and the officers, employees, agents and advisors of Buyer access to the Assets upon Buyer’s execution of a Temporary Access Agreement dated March 19, 2007 between Seller and Buyer (the “Temporary Access Agreement”) which is attached as Exhibit D. 
 
3.4   PRC 3314.1 Lease. Buyer acknowledges that Seller has disclosed to Buyer that in connection with certain of the Leases (PRC 3314.1) comprising a portion of the Assets, Seller obtained drilling deferments from the California State Lands Commission. The last deferment was granted by the California State Lands Commission in 2001 and expired in 2002. Since that time, while outside of any formally approved period of drilling deferment, Seller has worked with California State Lands Commission staff to develop a drilling and production program, and on June 26, 2006, the California State Lands Commission approved Seller’s application to re-drill two idle onshore wells into the offshore lease. Buyer acknowledges that it has been provided a copy of the approved drilling and production program, together with related correspondence with the California State Lands Commission in connection therewith, and Buyer further acknowledges that operations must be undertaken on the lease in accordance with such drilling and production program (or other programs that may be approved by the California State Lands Commission) to ensure that operations are in compliance with the terms of the lease.
 
ARTICLE 4
TITLE MATTERS
 
4.1   Defensible Title. The term “Defensible Title” means such title of Seller in and to the Assets that, subject to and except for the Permitted Encumbrances: (i) entitles Seller to receive not less than the net revenue interest described on Exhibit A-2 (“NRI”); (ii) obligates Seller to bear costs and expenses relating to the Assets in an amount not greater than the working interest described on Exhibit A-2 (“WI”); and (iii) is free and clear of material liens, taxes, encumbrances, mortgages, claims and production payments and any defects that would create a material impairment of use and enjoyment of or loss of interest in the affected Asset.
 
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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
4.2   Permitted Encumbrances. The term “Permitted Encumbrances” shall mean:
 
a.   Lessors’ royalties, overriding royalties, net profits interests, production payments, reversionary interests and similar burdens if the net cumulative effect of such burdens does not operate to reduce the NRIs below those set forth on Exhibit A-2;
 
b.   Any required governmental or third-party consents to assignment of the Assets and preferential purchase rights which are handled exclusively under Sections 4.10, 4.11 and 9.2d below;
 
c.   Liens for taxes or assessments not yet due or not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, provided, however, that Seller shall be responsible for the prompt payment of all taxes attributable to the Assets for all pre-Effective Time periods. This Section 4.2c does not change the apportionment of taxes under Article 13 of this Agreement;
 
d.   Rights of reassignment, to the extent any exist as of the date of this Agreement, prior to the surrender or expiration of any lease;
 
e.   Easements, rights-of-way, servitudes, permits, surface leases and other rights with respect to surface operations, on, over or in respect of any of the properties or any restriction on access thereto which are of record or which do not materially interfere with the operation of the affected property;
 
f.   Materialmen’s, mechanics’, repairmen’s, employees’, contractors’, operators’ or other similar liens or charges arising in the ordinary course of business incidental to construction, maintenance or operation of the Assets (i) if they have not been filed pursuant to law and the time for filing them has expired, (ii) if filed, they have not yet become due and payable or payment is being withheld as provided by law, or (iii) if their validity is being contested in good faith by appropriate action. Provided, however, that it shall be Seller’s responsibility to promptly discharge and remove all such liens or charges at Seller’s sole expense;
 
g.   Rights reserved to or vested in any municipality or governmental, statutory, or public authority to control or regulate any of the Assets in any manner; and all applicable laws, rules, regulations and orders of general applicability in the area;
 
h.   Liens for post-Effective Time operations arising under operating agreements, unitization and pooling agreements securing amounts not yet accrued or due or;
 
i.    The terms of the Material Agreements and any and all other agreements that are ordinary and customary in the oil, gas, sulfur and other mineral exploration, development or extraction business, or in the business of processing of gas and gas condensate for the extraction of products therefrom.
 
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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.
 
j.   Any encumbrance, encroachment, irregularity, defect in or objection to real property title which would otherwise constitute a “Title Defect” under Section 4.3 below, but which is of record, or which is disclosed or reasonably discernible by a review of the Records or an inspection of the Assets.
 
4.3   Title Defect. The term “Title Defect” means any encumbrance, encroachment, irregularity, defect in or objection to real property title, excluding Permitted Encumbrances, that alone or in combination with other defects:
 
a.   Renders title to an Asset less than Defensible Title;
 
b.   Reduces, impairs or prevents Buyer from receiving payment from the purchasers of production from an Asset; and/or
 
c.   Restricts or extinguishes Buyer’s right to use an Asset as owner, lessee, licensee or permittee, as applicable.
 
4.4   Notice of Title Defects. Buyer shall deliver to Seller a written “Notice of Title Defects” on or before April 12, 2007, 5:00 p.m., Pacific Time. The Notice of Title Defects shall (i) describe the Title Defect, (ii) describe the basis of the Title Defect and (iii) describe Buyer’s good faith estimate of the reduction in the Asset’s Allocated Value caused by the Title Defect (“Title Defect Value”) and all calculations and documentation substantiating the existence of the Title Defect. Buyer will be deemed to have conclusively waived any Title Defect about which it fails to so notify Seller in writing prior to April 12, 2007 at