ex99_3.htm

Pursuant to your request, we have prepared estimates of the extent and value of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2009, of certain properties owned by Berry Petroleum Company (Berry). The properties appraised, consisting of fee, leasehold, and royalty interests, are located in California, Colorado, Louisiana, Nevada, Oklahoma, Texas, Utah, and Wyoming, Berry has represented that these properties account for 100 percent of Berry’s net proved reserves as of December 31, 2009.

Estimates of proved reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). These reserves definitions are discussed in detail under the Definition of Reserves heading of this letter.

Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Berry after deducting all interests owned by others. Gas volumes shown herein are sales-gas volumes and are expressed at a temperature base of 60 degrees Fahrenheit and at the legal pressure base of the state in which the interest is located. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves are those attributed to the leasehold interests according to processing agreements.

Values of proved reserves shown herein are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated severance taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization.

Estimates of oil, condensate, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this report were obtained from reviews with Berry personnel, Berry files, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by Petroleum Information/Dwights LLC; Copyright 2009 Petroleum Information/Dwights LLC. In the preparation of this report we have relied, without independent verification, upon such information furnished by Berry with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Undeveloped reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Oil, condensate, NGL and natural gas prices were provided by Berry and are based on a 12-month average price (NYMEX price), calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Berry supplied differentials by certain geographic producing areas to a NYMEX Light Crude oil price of $61.18 per barrel and a NYMEX Contract Settlement gas price of $3.99 per million British thermal units. The prices were held constant thereafter and were not escalated for inflation.

Current operating expenses and capital costs, based on information provided by Berry were used in estimating future expenses and costs required to operate the properties. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions. Initial operating expenses were held constant for the lives of the properties and not escalated for inflation. Future capital costs were estimated using 2009 values and were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2009, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

The estimates of net proved reserves attributable to the properties appraised, as of December 31, 2009, are summarized by geographic area as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Oil and Condensate (Mbbl)	Natural Gas Liquids (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)

Proved Developed
California	75,912	0	0	75,912
Colorado	203	0	73,625	12,474
Utah	4,339	821	27,871	9,805
Texas	0	1,587	154,019	27,257
Wyoming	0	0	3	1
Various (LA, NV,OK)	8	0	2	8

Total Proved Developed	80,462	2,408	255,520	125,457

Proved Undeveloped
California	35,885	0	0	35,885
Colorado	711	0	284,159	48,071
Utah	8,491	1,115	21,158	13,133
Texas	0	868	71,341	12,758
Wyoming	0	0	0	0
Various (LA, NV,OK)	0	0	0	0

Total Proved Undeveloped	45,087	1,983	376,658	109,847

Total Proved	125,549	4,391	632,178	235,303

Note: Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent

The estimated revenue and expenditures attributable to Berry’s interests in the proved reserves, as of December 31, 2009, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows:

	Proved
	Developed Producing (M$)	Developed Nonproducing (M$)	Undeveloped (M$)	Total Proved (M$)

Future Gross Revenue	3,990,871	1,262,923	3,775,197	9,028,991
Production and Ad Valorem Taxes	145,981	49,893	173,638	369,513
Operating Expenses	1,617,581	472,736	1,367,002	3,457,319
Capital Costs	148,920	98,191	912,354	1,159,465
Future Net Revenue*	2,078,389	642,102	1,322,203	4,042,694
Present Worth at 10 Percent*	1,159,841	262,718	426,611	1,849,170

* Future income taxes have not been taken into account in the preparation of these estimates. Note: Numbers in tables may not add due to rounding.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Berry. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Berry and should not be used for purposes other than those for which it is intended. DeGolyer and MacNaughton has used all procedures and methods that it considers necessary to prepare this report.