CALIFORNIA RESOURCES CORPORATION
Estimated
Future Reserves
Attributable to Certain
Leasehold and Royalty Interests
SEC Parameters
As of
December 31, 2019
| \s\ Larry P. Connor | \s\ Eric A. Sepolio | |
| Larry P. Connor, P.E. | Eric A. Sepolio, P.E. | |
| TBPE License No. 58639 | TBPE License No. 128738 | |
| Executive Vice President | Vice President | |
[SEAL] [SEAL]
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849
1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191
January 10, 2020
California Resources Corporation
9200 Oakdale Avenue
Los Angeles, CA 91311
Ladies and Gentlemen:
At the request of California Resources Corporation (CRC), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2019 prepared by CRC’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 10, 2020 and presented herein, was prepared for public disclosure by CRC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent CRC’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by CRC and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2019. The properties reviewed by Ryder Scott incorporate CRC reserves determinations and are located in the state of California.
The properties reviewed by Ryder Scott account for a portion of CRC’s total net proved reserves as of December 31, 2019. Based on the estimates of total net proved reserves prepared by CRC, the reserves audit conducted by Ryder Scott addresses 40 percent of the total proved developed net liquid hydrocarbon reserves and 64 percent of the total proved developed net gas reserves or 44 percent of the total proved developed net reserves on a barrel of oil equivalent (BOE) basis. The report addresses 32 percent of the total proved undeveloped net liquid hydrocarbon reserves and 66 percent of the total proved undeveloped net gas reserves, or 36 percent of the total proved undeveloped net reserves on a BOE basis of CRC.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.
Based on our review, including the data, technical processes and interpretations presented by CRC, it is our opinion that the overall procedures and methodologies utilized by CRC in preparing their estimates of the proved reserves as of December 31, 2019 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by CRC are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.
SUITE 800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9 TEL (403) 262-2799 FAX (403) 262-2790
633 17TH STREET, SUITE 1700 DENVER, COLORADO 80202 TEL (303) 339-8110
California Resources Corporation
January 10, 2020
Page 2
The estimated reserves presented in this report are related to hydrocarbon prices. CRC has informed us that in the preparation of their reserves and income projections, as of December 31, 2019, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period and subject to adjustments for differentials, by geographic area where the hydrocarbons are sold; unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by CRC attributable to CRC's interest in properties that we reviewed and for those that we did not review are summarized below:
SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold and Royalty Interests of
California Resources Corporation
| As of December 31, 2019 |
| Proved | ||||||||
| Developed | Total | |||||||
| Producing | Non-Producing | Undeveloped | Proved | |||||
Audited by Ryder Scott Net Reserves | ||||||||
| Oil/Condensate – MMBarrels | 93 | 30 | 36 | 159 | ||||
| Plant Products – MMBarrels | 35 | 3 | 6 | 44 | ||||
| Gas – Bcf | 318 | 30 | 73 | 421 | ||||
| MMBOE | 181 | 38 | 54 | 273 | ||||
Not Audited by Ryder Scott Net Reserves | ||||||||
| Oil/Condensate – MMBarrels | 178 | 56 | 90 | 324 | ||||
| Plant Products – MMBarrels | 5 | 2 | 1 | 8 | ||||
| Gas – Bcf | 153 | 42 | 38 | 233 | ||||
| MMBOE | 209 | 65 | 97 | 371 | ||||
| Total Net Reserves | ||||||||
| Oil/Condensate – MMBarrels | 271 | 86 | 126 | 483 | ||||
| Plant Products – MMBarrels | 40 | 5 | 7 | 52 | ||||
| Gas – Bcf | 471 | 72 | 111 | 654 | ||||
| MMBOE | 390 | 103 | 151 | 644 | ||||
Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as millions of barrels (MMBarrels). The gas volumes are generally reported on an “as sold basis” expressed in billions of cubic feet (Bcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. These gas volumes do include volumes of gas consumed in operations; though these volumes are not material. The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MMBOE means million barrels of oil equivalent.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.
The various proved reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of behind pipe zones and volumes associated with certain recently completed projects not yet reflected in the producing category.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At CRC’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.
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…” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by CRC, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. The proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production and pressure data available through December 2019, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by CRC or obtained from public data sources and were considered sufficient for the purpose thereof.
The proved developed non-producing and undeveloped reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by CRC for our review or which we have obtained from public data sources that were available through December 2019. The data utilized from the analogs in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.
For the reserves audited by Ryder Scott, approximately 25 percent will be produced by steamflood and gas injection recovery processes, 10 percent will be produced by waterflood and water drive processes, and the remaining 65 percent will be produced by primary recovery. Approximately 5 percent of the reserves forecast are expected to be recovered from horizontal wells.
To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.
As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by CRC relating to hydrocarbon prices and costs as noted herein.
The hydrocarbon prices furnished by CRC for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
The initial SEC hydrocarbon prices in effect on December 31, 2019 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by CRC for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
The product prices which were actually used by CRC to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by CRC were reviewed by us for their reasonableness using information furnished by CRC for this purpose.
The table below summarizes CRC’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as CRC’s “average realized prices.” The average realized prices shown in the table below were determined from CRC’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and CRC’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the following table is presented in accordance with SEC disclosure requirements for the geographic area reviewed by us.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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| Geographic Area | Product | Price Reference | Average Benchmark Prices | Average Realized Prices |
| North America | ||||
| Oil/Condensate | Brent Spot | $63.15/Bbl | $66.29/Bbl | |
| United States | NGLs | Brent Spot | $63.15/Bbl | $31.58/Bbl |
| Gas | Henry Hub | $2.58/MMBTU | $2.86/Mcf | |
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in CRC’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates reviewed. The proved gas volumes presented herein include volumes of gas consumed in operations as reserves; those volumes are not material.
Operating costs furnished by CRC are based on the operating expense reports of CRC and include only those costs directly applicable to the leases, contract areas, or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases, contract areas and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases, contract areas and wells under terms of operating agreements. The operating costs furnished by CRC were reviewed by us for their reasonableness using information furnished by CRC for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases, contract areas or wells.
Development costs furnished by CRC are based on authorizations for expenditure (AFE) for the proposed work or actual costs for similar projects. The development costs furnished by CRC were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by CRC. The estimated net cost of abandonment after salvage was included by CRC for properties where abandonment costs net of salvage were material. CRC’s estimates of the net abandonment costs were accepted without independent verification.
The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with CRC’s plans to develop these reserves as of December 31, 2019. The implementation of CRC’s development plans as presented to us is subject to the approval process adopted by CRC’s management. As the result of our inquiries during the course of our review, CRC has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by CRC’s management at the appropriate local, regional and corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to CRC. CRC has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, CRC has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Current costs used by CRC were held constant throughout the life of the properties.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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CRC’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Test data and other related information were used by CRC to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by CRC. Wells or locations that are not currently producing may start producing earlier or later than anticipated in CRC’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and recompleting wells and constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and operating conditions, producing market demand and allowables or other constraints set by regulatory bodies.
CRC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a review of the properties in which CRC owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by CRC for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Certain technical personnel of CRC are responsible for the preparation of reserves estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.
CRC has informed us that they have furnished or otherwise made available to us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of CRC’s forecast of future proved production, we have relied upon data furnished by CRC with respect to property interests owned or otherwise held, production and well tests from examined wells, normal direct costs of operating the wells or leases, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by CRC. We consider the factual data furnished to us by CRC to be appropriate and sufficient for the purpose of our review of CRC’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by CRC and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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Audit Opinion
Based on our review, including the data, technical processes and interpretations presented by CRC, it is our opinion that the overall procedures and methodologies utilized by CRC in preparing their estimates of the proved reserves as of December 31, 2019 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by CRC are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by CRC in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.
We were in reasonable agreement with CRC's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between CRC's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to CRC when its reserves estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by CRC.
Other Properties
Other properties, as used herein, are those properties of CRC which we did not review. The proved net reserves attributable to the other properties account for 62 percent of the total proved net liquid hydrocarbon reserves and 36 percent of the total proved net gas reserves or 58 percent of the total proved net reserves on an equivalent barrel, BOE, basis based on estimates prepared by CRC as of December 31, 2019.
The same technical personnel of CRC were responsible for the preparation of the reserves estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof,
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.
We are independent petroleum engineers with respect to CRC. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by CRC.
CRC makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, CRC has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Forms S-3 and S-8 of CRC, of the references to our name, as well as to the references to our third party report for CRC, which appears in the December 31, 2019 annual report on Form 10-K of CRC. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by CRC.
We have provided CRC with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by CRC and the original signed report letter, the original signed report letter shall control and supersede the digital version.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
California Resources Corporation
January 10, 2020
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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
\s\ Larry P. Connor
Larry P. Connor, P.E.
TBPE License No. 58639
Executive Vice President [SEAL]
\s\ Eric A. Sepolio
Eric A. Sepolio, P.E.
TBPE License No. 128738
Vice President [SEAL]
LPC-EAS (DCR)/pl
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Larry Connor was the primary technical person responsible for preparing the estimate of the reserves and future production included in this report.
Mr. Connor, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is the Executive Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Connor served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Connor’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
Mr. Connor earned a Bachelor of Science degree in Industrial Engineering from Texas A&M University in 1977 and is a licensed Professional Engineer in the State of Texas, and the Provinces of Alberta, British Columbia and Saskatchewan, Canada. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. Mr. Connor has served as the Chairman of the Houston Chapter of the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Connor fulfills. Mr. Connor attended an additional 25 hours of formalized in-house training during 2019 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. In addition to internal training, Mr. Connor has organized and participated in a total of 12 hours of industry training to professionals outside of Ryder Scott. Mr. Connor has served as course instructor for the formalized in-house training of PSA programming using PHDWinTM software to analyze prospect evaluations.
Based on his educational background, professional training and more than 42 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Connor has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves 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.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
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.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
| (1) | completion intervals that are open at the time of the estimate but which have not yet started producing; |
| (2) | wells which were shut-in for market conditions or pipeline connections; or |
| (3) | wells not capable of production for mechanical reasons. |
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
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 paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS