EX-99.1

/s/ Gregory K. Graves

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

EX-99.1 32 d479531dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

Report as of December 31, 2017

of DeGolyer and MacNaughton

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 31, 2018

Berry Petroleum Company, LLC

5201 Truxton Avenue, Suite 100

Bakersfield, CA 93309

Ladies and Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the net proved oil, condensate, natural gas liquids (NGL), and gas reserves, as of December 31, 2017, of certain properties in which Berry Petroleum Company, LLC (Berry) has represented that it owns an interest. This evaluation was completed on January 31, 2018. Berry has represented that these properties account for 100 percent of Berry’s net proved reserves as of December 31, 2017. The properties are located in California, Colorado, Texas, and Utah. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Berry.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2017. 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.

Estimates of oil, condensate, NGL, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue 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 evaluation were obtained from reviews with Berry personnel, from Berry files, from records on file with the appropriate regulatory agencies, and from public sources. 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.

METHODOLOGY AND PROCEDURES

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” 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.

Based on the current stage of field development, production performance, the development plans provided by Berry, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP). Structure maps were utilized to delineate each reservoir, and isopach maps were utilized to estimate the reservoir volume. Electric 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.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the fluid and rock properties, and the production histories. An analysis of the reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. Most of the properties in California evaluated herein are produced using thermal recovery methods involving either cyclic steam injection or continuous steamflood operation. Therefore, steam-oil ratios and steam volumes were analyzed and projected and were used in the estimation of reserves when applicable.

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 based on existing economic conditions.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

Gas reserves estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel use and shrinkage resulting from field separation and processing. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit and at the pressure base of the state in which the reserves are located. Gas reserves included herein are expressed in thousands of cubic feet (Mcf). Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the leasehold interests according to processing agreements. Oil, condensate, and NGL reserves included in this report are expressed in barrels (bbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

DEFINITION OF RESERVES

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.

(i) The area of the reservoir considered as proved includes:

(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.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas 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.

The development status shown herein represents the status applicable on December 31, 2017. In the preparation of this study, data available from wells drilled on the evaluated properties through December 31, 2017, were used in estimating gross ultimate recovery. When applicable, gross production estimated through December 31, 2017, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves. In some fields this required that the production rates be estimated for up to 6 months, since production data from certain properties were available only through June 2017.

PRIMARY ECONOMIC ASSUMPTIONS

Values of proved reserves in this report 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 evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, capital costs, and abandonment 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 of future net revenue is calculated by discounting the future net revenue at the arbitrary rate of 10 percent per year compounded annually over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The assumptions used for estimating future prices and expenses are as follows:

Oil, Condensate, and NGL Prices

Oil, condensate, and NGL price differentials for each property were provided by Berry. The prices were calculated using these differentials to a posted Europe Brent oil price of $54.42 per barrel and were held constant for the lives of the properties. The Brent oil price of $54.42 per barrel is the 12-month average 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 December 31, 2017. The volume-weighted average prices over the lives of the properties were $48.20 per barrel of oil and condensate and $28.25 per barrel of NGL.

Gas Prices

Gas price differentials for each property were provided by Berry. The prices were calculated using these differentials to a Henry Hub price of $2.98 per million British thermal units (MMBtu) and were held constant for the lives of the properties. The Henry Hub gas price of $2.98 per MMBtu is the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to December 31, 2017. British thermal unit factors were provided by Berry and used to convert prices from dollars per MMBtu to dollars per thousand cubic feet ($/Mcf). The volume-weighted average price over the lives of the properties was $2.935 per thousand cubic feet of gas.

Production and Ad Valorem Taxes

Production taxes were calculated using the tax rates for the state in which the property is located, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were calculated using rates provided by Berry that were based on recent payments.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by Berry and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2017 values, provided by Berry, and were not adjusted for inflation. Abandonment costs, net of salvage where applicable, were provided by Berry for all properties and include all reclamation and restoration costs associated with abandonment. The abandonment costs were provided by Berry in aggregate at the district level except for wells drilled in 2017 and for proposed undeveloped wells, where they are shown with the individual property.

The estimates of Berry’s net proved reserves attributable to the reviewed properties were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

Estimated by DeGolyer and MacNaughton
Net Proved Reserves
as of
December 31, 2017

Oil and
Condensate
(Mbbl)

NGL
(Mbbl)

Sales
Gas
(MMcf)

Oil
Equivalent
(Mboe)

Proved

Developed Producing

62,615

1,263

99,997

80,544

Developed Non-Producing

5,875

387

5,947

Total Proved Developed

68,490

1,271

100,384

86,491

Undeveloped

32,106

136,720

54,893

Total Proved

100,596

1,271

237,104

141,384

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

The estimated future revenue and costs attributable to the production and sale of Berry’s net proved reserves, as of December 31, 2017, of the properties reviewed under the aforementioned assumptions concerning future prices and costs are summarized in thousands of dollars (M$) as follows:


	Proved Developed Producing (M$)		Proved Developed Non-Producing (M$)		Total Proved Developed (M$)		Proved Undeveloped (M$)		Total Proved (M$)
Future Gross Revenue		3,268,939		292,456		3,561,395		2,019,053		5,580,448
Production Taxes		66,914		3,316		70,230		13,186		83,416
Ad Valorem Taxes		85,610		9,520		95,130		62,336		157,466
Operating Expenses		1,692,989		96,657		1,789,646		696,019		2,484,665
Capital Costs		49,872		9,971		59,843		487,888		547,731
Abandonment Costs		92,700		286		92,986		37,596		130,582
Future Net Revenue		1,280,854		173,706		1,454,560		722,028		2,176,588
Present Worth at 10 Percent		762,313		89,447		851,760		262,399		1,114,159

Note: Future income tax expenses have not been taken into account in the preparation of these estimates.

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 reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2017, estimated reserves.

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, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. 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. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

CERTIFICATE of QUALIFICATION

I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Berry dated January 31, 2018, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 33 years of experience in oil and gas reservoir studies and reserves evaluations.

ADDENDUM

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

June 28, 2018

Berry Petroleum Company, LLC

5201 Truxton Avenue, Suite 100

Bakersfield, CA 93309

Ladies and Gentlemen:

Pursuant to your request, we have prepared this letter to serve as an addendum, as of December 31, 2017, to our report of third party dated January 31, 2018, containing our opinion of the proved reserves and revenue, as of December 31, 2017, of Berry Petroleum Company, LLC (the ROTP) to present additional information as an extension of the ROTP. This letter was completed on June 28, 2018. The purpose of this letter is to prepare a Price Sensitivity Case on the properties evaluated in the ROTP. This letter is subject to the terms, definitions, assumptions, explanations, conclusions, and conditions described in the ROTP. However, the future price forecast for this Price Sensitivity Case does not meet the guidelines established by the United States Securities and Exchange Commission (SEC); therefore, the reserves and revenue presented herein should not be used to meet the requirements of the SEC.

Oil, condensate, natural gas liquids (NGL), and gas prices in the Price Sensitivity Case differ from the fixed prices in the ROTP. The price forecast for this sensitivity was provided by Berry and has been represented by Berry as reflective of the futures market price of Brent Oil on May 31, 2018, and the futures market price of Henry Hub Gas on May 31, 2018.

The price differentials used herein for each product differ from those used in the ROTP. The price differentials used for this sensitivity were provided by Berry and were represented by Berry as reflective of the price differentials calculated for the properties evaluated in the ROTP during the month of May 2018.

For this letter, the as-of date of this Price Sensitivity Case, December 31, 2017, is the same as that used for the ROTP, and the prices in the following table were applied to the production forecast estimates previously prepared for the properties evaluated in the ROTP. However, the production forecast estimates in this letter were allowed to run until a new economic limit, based on the respective Price Sensitivity Case, was reached. As such, the projections of estimated proved production and revenue present alternative outcomes to the projections of estimated proved production and revenue presented in the ROTP. Except as noted above concerning the price differentials, all other economic components of the evaluation for the Price Sensitivity Case are the same as contained in the ROTP. Even though this Price Sensitivity Case was completed on June 28, 2018, no additional data beyond that used for the ROTP were incorporated herein. A detailed explanation of these economic assumptions is contained under the Primary Economic Assumptions heading of the ROTP.

The Price Sensitivity Case oil, condensate, NGL, and gas prices used in this letter are as follows, expressed in dollars per barrel ($/bbl) and dollars per million British thermal units ($/MMBtu):


Year	Oil, Condensate, and NGL Price ($/bbl)		Gas Price ($/MMBtu)
2018		74.59		2.94
2019		72.98		2.75
2020		69.15		2.68
2021 and thereafter		66.49		2.66

The volume-weighted average prices over the lives of the properties were $61.67 per barrel of oil and condensate, $19.49 per barrel of NGL, and $1.943 per thousand cubic feet of gas.

The estimates of Berry’s net proved reserves attributable to the properties evaluated under the Price Sensitivity Case described herein are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

Price Sensitivity Case

Estimated by DeGolyer and MacNaughton

Net Proved Reserves

as of

December 31, 2017

Oil and

Sales

Oil

Condensate

NGL

Gas

Equivalent

(Mbbl)

(MMcf)

(Mboe)

Proved

Developed Producing

64,277

1,117

66,937

76,551

Developed Non-Producing

6,013

392

6,086

Total Proved Developed

70,290

1,125

67,329

82,637

Undeveloped

32,102

Total Proved

102,392

1,125

67,329

114,739

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

The estimated future revenue and costs attributable to the production and sale of Berry’s net proved reserves, as of December 31, 2017, of the properties reviewed under the Price Sensitivity Case described herein are summarized in thousands of dollars (M$) as follows:


	Proved		Proved		Total
	Developed		Developed		Proved		Proved		Total
	Producing		Non-Producing		Developed		Undeveloped		Proved
	(M$)		(M$)		(M$)		(M$)		(M$)
Future Gross Revenue		4,028,481		379,021		4,407,502		2,059,708		6,467,210
Production Taxes		65,737		3,514		69,251		11,621		80,872
Ad Valorem Taxes		106,156		12,337		118,493		64,163		182,656
Operating Expenses		1,666,065		98,698		1,764,763		525,438		2,290,201
Capital Costs		49,872		9,971		59,843		347,654		407,497
Abandonment Costs		92,700		286		92,986		34,936		127,922
Future Net Revenue		2,047,951		254,215		2,302,166		1,075,896		3,378,062
Present Worth at 10 Percent		1,205,255		135,557		1,340,812		520,804		1,861,616

Note: Future income tax expenses have not been taken into account in the preparation of these estimates.

DeGolyer and MacNaughton

Apart from the main body of the ROTP, this letter may be subject to misunderstanding or misinterpretation. The ROTP should be relied upon solely as the source of authoritative final results.


		Submitted,

		/s/ DeGolyer and MacNaughton

		DeGOLYER and MacNAUGHTON
		Texas Registered Engineering Firm F-716

		/s/ Gregory K. Graves
		Gregory K. Graves, P.E.
[SEAL]		Senior Vice President
		DeGolyer and MacNaughton

DeGolyer and MacNaughton