July 15, 2009

Mr. H. Roger Schwall

Division of Corporation Finance

United States Securities and Exchange Commission

100 F St., N.E.

Washington D.C 20549

Re:           Berry Petroleum Company

Form 10-K for Fiscal Year Ended December 31, 2008

Filed February 25, 2009

Form 10-Q for Fiscal Year Ended March 31, 2009

Filed April 30, 2009

Definitive Proxy Statement on Schedule 14A

Filed May 13, 2009

File No. 001-09735

Dear Mr. Schwall:

On behalf of Berry Petroleum Company (“Berry” or the “Company), we are submitting responses to the comments relating to the above-referenced filings set forth in the letter from the staff (“Staff”) of the Securities Exchange Commission (“Commission”) dated June 30, 2009.  In this letter, the Company has reproduced your comments in italics typeface and has made responses in normal typeface.

Form 10-K for the Fiscal Year Ended December 31, 2008

Management’s Discussion and Analysis

Quantitative and Qualitative Disclosures about Market Risk, Page 44

1. We note the table summarizing your commodity hedge positions as of December 31, 2008 and your disclosure on page 45 stating that the collar strike prices will allow you to protect a significant portion of your future cash flow.  Please expand your disclosure to clarify the extent that your scheduled production volume is being covered by your hedging program strategy.

Response:

The Company notes the staff’s comment, and in future filings will expand our disclosure as follows:

The collar strike prices allow us to protect our cash flow if oil prices decline below our floor prices which range from $55.00 to $100.00 per barrel while still participating in any oil price increase up to the ceiling prices which range from $75.00 to $163.60 per barrel on the volumes

indicated above.  In total, we have approximately 90% and 45% of our expected 2009 and 2010 oil production hedged in the form of swaps and collars.  Our natural gas collars have a floor of $6.00 per MMbtu and ceilings ranging from $8.60 to $8.65 per MMBtu.  In total, we have approximately 25% and 5% of our 2009 and 2010 expected natural gas production hedged in the form of swaps and collars.

Evaluation of Disclosure Controls and Procedures, page 77

2. Please confirm that your disclosure controls and procedures for the relevant periods met all of the requirements of Rule 13a-15(e).  In addition to your current disclosure, please state, if true, that your controls and procedures are designed to ensure that information required to be disclosed in the reports that you file or submit under the Exchange Act is accumulated and communicated to your management, including your chief executive officer and chief financial officer, to allow timely decisions regarding the required disclosure.

Response:

We confirm that our disclosure controls and procedures for the relevant periods met all of the requirements of Rule 13a-15(e).  In addition, in future filings we will expand the discussion of our disclosure controls and procedures and will revise our disclosure in future filings as follows:

As of [balance sheet date], we have carried out an evaluation under the supervision of, and with the participation of, our 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 Exchange Act of 1934, as amended (the “Exchange Act”).

Our Chief Executive Officer and Chief Financial Officer have concluded that, as of [balance sheet date], our disclosure controls and procedures are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting that occurred during the period ended [balance sheet date] that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Financial Statements

Note 3 – Summary of Significant Accounting Policies, Page 54

3. We note you disclose on Page 57 that you have two subsidiaries that are accounted for using the equity method.  The term subsidiaries ordinarily refers to entities that are being consolidated.  Please revise your disclosure to indicate your level of ownership in and control or influence over these entities.  If these investments are accounted for using the equity method because you do not have the requisite level of control, please clarify.  Otherwise, explain why these entities are not consolidated.

Response:  We own less than a 50% interest in each of these entities and do not exercise control over either of these entities as outlined in ARB 51 and other relevant guidance. In addition, we are not the primary beneficiary of these entities as described in FIN 46R.  In future filings we will revise our disclosure as follows:

Equity method investments – We own interests in two entities which serve to gather and transport natural gas in our Lake Canyon and Brundage Canyon fields.  We own less than a 50% interest in both entities and these interests are accounted for using the equity method. Our net investment in these entities is included under the caption “Other assets” on our Balance Sheet.

Note 18- Hedging, Page 73

4. We note you disclose on page 74 that most of your oil hedges are based on the West Texas Intermediate (WTI) index, and that your California oil sales contract with Big West of California (BWOC) is tied to WTI which has allowed you to qualify for hedge accounting and effectively hedge your production.

Please tell us how you concluded that your hedges associated with the BWOC sales contract continue to be effective, given your disclosure on page 66 indicating that in December 2008, BWOC filed for Chapter 11 Bankruptcy protection and informed you that it was unable to receive your production.

We would like to understand how your position is consistent with the guidance in SFAS 133 paragraphs 66 and 67, and DIG Issue G10.

Response:

While the Company’s sales contract with BWOC was priced based on WTI allowing forecasted sales prices to correspond with the Company’s hedges, the Company’s contract with BWOC was not the derivative used to hedge the Company’s production.  The BWOC contract does not contain a notional amount and is therefore not accounted for as a derivative under SFAS No. 133 that we would review for risk of counterparty default under DIG issue G10.  The Company’s derivatives are held by financial counterparties from within the Company’s senior secured credit facility.  

The Company documented cash flows from crude oil sales in California as the "hedged item" in its hedge memos.  For each reporting period, ineffectiveness is measured utilizing “Method 2: Hypothetical Derivative Method” as outlined in DIG issue G7.  Under the hypothetical derivative method, we recorded the fair value of the actual derivative on our balance sheet and we adjusted accumulated OCI to the lesser of either the cumulative change in the fair value of the actual derivative or the cumulative change in the fair value of the "perfect" hypothetical derivative. For the quarter ended December 31, 2008, the lesser of the cumulative change in fair value was the "actual" derivative for the Company’s hedges, and thus no ineffectiveness was recorded.

In future filings we will clarify the role of sales contracts in our hedging activities.

Exhibits 31.1 and 31.2

5. We note that you have included your officer’s title in the opening line of each certification.  Please revise to provide the exact form of certification found in Item 601(b)(31) of Regulation S-K.

Response:

The Company notes the staff’s comment, and in future filings will revise exhibits 31.1 and 31.2 to provide the exact form of certification found in Item 601(b)(31) of Regulation S-K.

Engineering Comments

Business, page 3

Long Lived Reserves, page 4

6. We note your statement “Of our proved reserves 55% were proved developed, while proved undeveloped reserves make up 45% of our proved total.  The projected future capital to develop these proved undeveloped reserves is $950 million at an estimated cost of approximately $8.55 per BOE.  Approximately 61% of the capital to develop these reserves is expected to be expended in the next five years.”

With a view toward possible disclosure, please:

• Explain the circumstances that require the delay in monetizing these proved undeveloped reserves beyond five years.  Include your drilling schedule for these PUD properties/locations.

• Tell us whether you have PUD projects whose scheduled initiation is beyond the next five years.

• Address the difference between the $950 million capital referenced above and the $1.2 billion future development costs utilized in your computation of the standardized measure on page 77.

• Explain how you have addressed prior depletion in those PUD locations that are later in your schedule when estimating undeveloped reserves.

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Response:

The timing of development related to our proved undeveloped reserves is driven primarily by our estimated future cash flows as we generally develop our reserves from operating cash flow. As operator of all of our properties, we can control the pace of development to balance our cash flows with our development activities.

Of the $950 million of future capital that we estimate will be needed to develop our PUD reserves, we are scheduled to spend $577 million, or 61%, in the next five years and approximately 80% of the capital will be spent during the first seven years.  Two-thirds of our capital which extends beyond five years, as noted in the table below, is in our Piceance basin and Uinta basin assets. Over the last three years, we have drilled a total of 230 wells in the Piceance basin and 210 wells in the Uinta basin and have spent $500 million developing these reserves.  Our projections provide for continuous drilling of these projects through their full development.

Detail of the scheduled capital expenditures to develop our proved undeveloped reserves for the total Company and the two properties which make up two-thirds of the capital beyond five years are as follows:

Year	Capital Expenditures $(000’s)	Piceance Basin, CO $(000’s)	Uinta Basin, UT $(000’s)
2009 - 2013	$ 577,745	$ 91,347	$ 73,081
2014	86,612	15,429	20,694
2015	103,644	54,213	30,965
2016	52,022	30,731	8,678
2017	42,166	22,559	3,036
2018	47,821	31,293	-
beyond 2018	$ 39,979	$ 31,519	$  1,785

While completion of the drilling programs for certain of our projects may extend beyond five years, only one of our projects, which accounts for approximately 2 million BOE of our total of 246 million BOE of proved reserves is scheduled to begin in the sixth year.   The timing of development for this project in our Placerita field, which is located in California, is based on the priority of the project in the overall drilling portfolio.

The difference between the $950 million of capital required to develop our proved undeveloped reserves and the $1.2 billion of capital from our standardized measure is the capital associated with proved developed reserves. Approximately $120 million of the difference relates to the completion costs of wells associated with our proved developed non-producing reserves.  The remainder of the capital represents major maintenance projects for existing production facilities and asset retirement obligations.

The Company and its third party reserve engineers review estimates of proved reserves each year based on production, performance and geologic data.  Our calculations of estimated ultimate recovery and remaining reserves are revised such that the estimate of proved undeveloped reserves reflects performance and production data from our proved developed reserves.  This process ensures that proved undeveloped reserves do not reflect depletion from offsetting producing wells.

While the Company has a process to ensure depletion is considered when estimating proved undeveloped reserves, Berry’s proved reserves are heavy oil produced using tertiary recovery and natural gas produced from tight reservoir formations and depletion of PUD reserves from existing wells is minimal.  For instance, in California Berry’s reserves can be categorized as heavy oil produced from shallow reservoirs which require steam injection to both reduce the viscosity of the oil to enable subsurface flow and to add pressure to the reservoir due to the lack of natural reservoir pressure at these shallow depths.   Wells are tightly spaced ranging from fifty feet (horizontal wells) to half-acre spacing (vertical wells) as oil will not flow without the pressure and temperature from steam injection.  In our Piceance basin and East Texas developments we produce from reservoir formations with low permeability and the lack of connectivity between wells allows for well spacing ranging from 10 acres in the Piceance basin to 40 acres in East Texas.

Acreage and Wells, page 12

7. Please disclose material undeveloped acreage subject to expiration in each of the next three years to comply with paragraph 5 of the SEC industry Guide 2.

Response:

The undeveloped acreage subject to expiration in each of the next three years is not material.  We will add this disclosure in future filings.

Management’s Discussion and Analysis of Financial Condition and Results of Operation, page 28

N. Midway, Page 29

8. We note your statement “We began the full scale development of our N. Midway diatomite asset in late 2006 and have drilled 190 wells on this property.  The delineation drilling in 2008 increased our original oil in place estimates by 35% to 330 million barrels.  We are targeting ultimate recovery between 23% and 40% similar to other diatomite developments in California”

The phrase “original oil in place” is not prescribed for recoverable quantities of hydrocarbons and is not defined in Rule 4-10(a) of regulation S-X.  Please remove this and any similar disclosures to comply with Instruction 5 to Item 102 of Regulation S-K.

Response:

The Company notes the staff’s comment, and in future filings will remove this disclosure and any similar disclosures to comply with Instruction 5 to Item 102 of Regulation S-K.

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Financial Statements

Note 23 – Supplemental Information About Oil & Gas Producing Activities Unaudited), page 75

Changes in estimated reserve quantities, page 76

9. The guidance in SFAS 69, paragraph 11 requires “appropriate explanation of significant changes’ to your estimates of proved reserves.  Please explain each of the changes due to revisions, drilling and acquisitions in 2008.  Specifically, address the revisions due to performance separately from those due to year-end price changes.

Response:

The Company notes the staff’s comment, and in future filings will expand our disclosure similar to the following:

Excluding the effect of production, reserves increased 88.5 million BOE between 2007 and 2008.  55 million BOE of the increase related to the purchase of our East Texas Asset which occurred July 15, 2008.  An increase of 43 million BOE resulted from extension and discoveries from our drilling activities with significant contributions of 20 million BOE in the Piceance, 12 million BOE in the Diatomite and 4 million BOE in South Midway.  Improved recovery increases were primarily from the diatomite where 7.2 million BOE was added due to the performance of our development.  Revisions to previous estimates were  a decrease of 17.1 million BOE, primarily from 11 million BOE of price related revisions in our California properties and 4.0 million BOE of revisions in East Texas due to lack of performance data from certain zones.

Standardized measure of discounted future cash flows from estimated production of proved oil and gas reserves (in thousands), Page 77

10. We note the 2008 estimated unit of production cost is $11.87/BOE (=$2921 million /246 million BOE).  After subtraction of estimate future production tax (@4.3% of revenue), the estimated future unit operation cost is $10.58/BOE.  This is 38% lower than the historical 2008 unit operating cost, $17.10/BOE with production tax excluded, disclosed on page 12.  Please explain the details of this difference and the reasons the 2008 estimated future operating cost is lower than the 2008 historical figures, while the 2007 estimated future operating cost is higher than the 2007 historical figures.  If the 2008 gas acquisition has a significant effect, please submit the documentation pertaining to the respective differences between estimated and realized costs.

Response:

Between one-third and one-half of our total operating costs are steam related, depending on the price of natural gas.  The average natural gas price for the full year 2008 was approximately $8.00 per MMBtu compared to the year-end price of $5.50 per MMBtu which was used to calculate steam prices as part of our standardized measure calculation. Reduced steam costs, primarily from lower natural gas costs, accounts for an approximate $3.00 per BOE decrease in operating costs from 2008 levels.

The precipitous drop in commodity prices at the end of 2008 resulted in reduced costs from both service and materials vendors due to the reduced demand for their products and services. Additionally, the Company evaluated field operating costs in light of lower commodity prices. As part of this evaluation, marginal high cost wells were shut-in, workover rig prices were renegotiated, and non-essential overtime costs were eliminated. The balance of lower operating costs per BOE when compared to 2008 resulted from the reductions noted above.

Changes in standardized measure of discounted future net cash flows for proved oil and gas reserves (in thousands): page 77

11. The guidance in paragraph 33(g) of SFAS 69 requires the disclosure of “previously estimated developed costs incurred during the period” in reconciling the overall change in the standardized measure for each period presented.  It is unclear whether the amounts you present on the line item “Development costs incurred for the period” are only those development costs incurred that were previously estimated or are the actual costs incurred, as these are very close to the historical costs that you report on page 75.  Please clarify and tell us the extent to which the reconciling amounts would need to change to reflect only the previously estimated development costs contemplated in SFAS 69.

Response:

The amount shown for “Development costs incurred during the period” reflected actual 2008 expenditures rather than previously estimated costs incurred during the period.  The table below shows the reported and revised presentation of the change in standardized measure.  The decrease in development costs is offset in changes in estimated future development costs and in other to reflect changes in timing with the total standardized measure remaining unchanged.  We respectfully request to make the changes noted below in future fillings.

Changes in standardized measure of discounted future net cash flows from proved oil and gas reserves (in thousands):

	2008 As Reported			2008 Revised
Standardized measure - beginning of year	$	2,419,506		$	2,419,506
Sales of oil and gas produced, net of production costs		(497,866	)		(497,866	)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs		(2,686,941	)		(2,686,941	)
Revisions of previous quantity estimates		(144,466	)		(144,466	)
Improved recovery		64,058			64,058
Extensions and discoveries		362,435			362,435
Change in estimated future development costs		(493,778	)		(352,061	)
Purchases of reserves in place		667,862			667,862
Sales of reserves in place		-			-
Development costs incurred during the period		397,601			173,184
Accretion of discount		354,672			354,672
Income taxes		631,372			631,372
Other		61,126			143,826
Net increase (decrease)		(1,283,925	)		(1,283,925	)
Standardized measure - end of year	$	1,135,581		$	1,135,581

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Form 10-Q for the Fiscal Quarter Ended March 31, 2009

Exhibits 31.1 and 31.2

12. As stated in comment 5 [11 sic] above, ensure that you provide the exact form of certification in Item 601(b)(31).

Response:

The Company notes the staff’s comment, and in future filings will revise exhibits 31.1 and 31.2 to provide the exact form of certification found in Item 601(b)(31) of Regulation S-K.

Definitive Schedule 14A

Compensation Discussion and Analysis

Setting Executive Compensation, page 12

13. Please describe in more detail the series of non-executive employee compensation surveys in which you participated.  Explain whether these were internal or external surveys, the general nature of the surveys, and the conclusions you state that you drew from them.

Response:

The Company notes the staff’s comment, and in future filings will provide disclosure similar to the following:

To evaluate non-executive compensation, in 2008 we utilized two external compensation surveys for the upstream oil and gas industry from Effective Compensation, Inc. (ECI) which focuses on both non-executive and executive positions and Towers Perrin Oil & Gas Survey (TP) which focuses primarily on field hourly positions. We understand that both ECI and TP develop their data by anonymously collecting data from participating companies and then publishing that data for all the participants to use to assist in compensation decisions. We used this information to evaluate whether or not our compensation was consistent with that disclosed by the survey for non-executive positions.

14. We note that the compensation committee “begins its comparisons of the competitive data at the 50th percentile of the peer group and then determines what, if any, individual performance warrants compensation awards above or below that level.”  For each element of compensation paid during 2008, please disclose the percentile represented by actual compensation for each named executive officer.  To the extent actual compensation differs from the targeted percentile, you should explain the reasons for the difference, including what factors, if any, you considered in raising or lowering awards.  See Item 402(b)(2)(xiv) of Regulation S-K.

Response:

The competitive data at the 50th percentile is only one of the pieces of information considered by the Compensation Committee and the Board of Directors in exercising their discretion to determine each element of compensation for the named executive officers.  While the Compensation Committee uses the 50th percentile as a guide for reviewing compensation for executives, the Committee does not set a specific percentile target for each named executive officer. In future filings we will clarify the purpose of the 50th percentile as only one piece of information used by the compensation committee as part of their subjective analysis.

15. Please clarify your disclosure regarding the companies against which you benchmark compensation.  For example, you state that you do an internal analysis of a fifteen-company peer group.  In addition, you strive to set salaries at “competitive market levels,” and you review “external market data” in connection with awards under your short-term incentive plan.  In your discussion of long-term incentive awards, you reference comparisons to “competitive compensation data.’ Explain whether these statements refers to your peer group, and if they do not, identify what constitutes the “market” for purposes of your compensation decisions, including the component companies.

Response:

These statements refer to our fifteen-company peer group. In future filings we will clarify these statements by using consistent terminology when referring to our peer group.

2008 Short Term Incentive Compensation Plan

16. For each named executive officer, please disclose the 2008 targeted payout for awards.

Response:

The Company notes the staff’s comments, and in future filings we will provide disclosure similar to the following:

Pursuant to Mr. Heinemann’s Amended and Restated Employment Agreement, his targeted payout for cash bonuses for 2008 was 100% of base salary, but could range from 50% to 200% of base salary (though in certain circumstances it may be less) as determined in the discretion of the Compensation Committee and the Board of Directors.  For 2008 pursuant to his employment agreement, the targeted payout of discretionary cash bonus for Mr. Wolf was 50% of his base salary.  Subsequent to 2008, Mr. Wolf’s targeted payout of cash bonus pursuant to his employment contract is between 50% and 200% of his base salary (though in certain circumstances it may be less) as determined in the discretion of the Compensation Committee and the Board of Directors.   Pursuant to his employment agreement, the targeted payout of cash bonus for 2008 for Mr. Duginski was between 50% and 200% of his base salary (though in certain circumstances it may be less) as determined in the discretion of the Compensation Committee and the Board of Directors.  Under the 2008 ICP, the targeted payout of cash bonuses for 2008 for each of Mr. Anderson, Mr. Kelso and Mr. Canaday was 50% of base salary.  No targeted payout for cash bonus was established in 2008 for Mr. Goehring.

17. Please disclose the environmental health and safety performance metric, which appears to be a material performance measure under your short term incentive plan.

Response:

The Company notes the staff’s comment, and in future filings will include a discussion of the environmental health and safety performance metric as follows:

Additionally, there is an overall modifier based on our environmental health and safety (EHS) performance which is applied companywide based on companywide performance.  EHS performance for this purpose is evaluated by a committee of management and non-management employees, the appointment of which is approved by the Compensation Committee, and whose report is supplied to the Compensation Committee.  The employees’ committee establishes the criteria for the evaluation.  In 2008 the EHS multiplier was 101% which resulted in the companywide bonus applicable to any individual being increased by a factor of 1%.  The minimum and maximum adjustments for the EHS multiplier are generally between 95% and 105%, respectively.

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18. Describe in sufficient detail the adjustments made to your performance targets in connection with the East Texas acquisition.

Response:

The Company notes the staff’s comment, and in future filings will include a disclosure similar to the following related to adjustments of performance targets:

In connection with our East Texas acquisition, we increased our production and net income targets to match our expected operational and financial performance from the acquired assets.

In connection with this response, the Company acknowledges that:

· the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

· staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

· the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Additionally, we confirm that we will comply with the preceding comments in all future filings substantially in the manner described in the response to each comment.

Should you or your staff have any questions concerning the enclosed materials, please contact me at (303) 999-4036.

Sincerely,

/s/ David D. Wolf

David D. Wolf

Executive Vice President and

Chief Financial Officer

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