EX-15.7 13 dp105023_ex1507.htm EXHIBIT 15.7

Exhibit 15.7

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

This is a digital representation of a DeGolyer and MacNaughton report.

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 23, 2019

CNOOC Limited

c/o Suite 2300, 500 Centre St. S.

Calgary, Alberta, Canada

T2G 1A6

Re:

Report of Third Party for CNOOC Limited’s interest in the Liza Field Offshore Guyana

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of the Liza field located offshore Guyana with interests represented to be held by CNOOC Limited (CNOOC). This evaluation was completed on January 23, 2019. CNOOC has represented that these properties account for approximately 1 percent on a net equivalent barrel basis of CNOOC’s net proved reserves as of December 31, 2018, and that 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. We have reviewed information provided by CNOOC Petroleum Guyana Limited (CPG), a subsidiary of CNOOC, that it represents to be CNOOC’s estimates of the net reserves, as of December 31, 2018, for the same properties as those which we evaluated. 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 CNOOC.

Reserves estimates included herein are expressed as net reserves as represented by CPG. Gross reserves are defined as the total estimated petroleum remaining to be produced from this field after December 31, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests held by CNOOC after deducting all interests held by others.

DeGolyer and MacNaughton

The Liza field in which CNOOC holds an interest is subject to the terms of a Petroleum Agreement between the Government of the Cooperative Republic of Guyana and the joint venture participants. The terms of these agreements generally allow for working interest participants to be reimbursed for portions of capital costs and operating expenses and to share in the profits. The reimbursements and profit proceeds are converted to a barrel of oil equivalent or cubic foot of gas equivalent by dividing by product prices to estimate the “entitlement reserves.” These entitlement reserves are equivalent in principle to net reserves and are used to calculate an equivalent net share, termed an “entitlement interest.” In this report, CNOOC reserves or interest in these properties subject to this production sharing agreement is the entitlement based on CNOOC’s working interest.

Estimates of reserves should be regarded only as estimates that may change as production history and additional information become available. Not only are such 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.

Information used in this evaluation was obtained from reviews with CPG personnel and from CPG files. In the preparation of this report we have relied upon such information furnished by CPG with respect to the property interests being evaluated, 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. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. In our opinion, the adequacy and quality of the data provided to us were sufficient for us to conduct this reserves evaluation. A field examination of the properties was not considered necessary for the purposes of this report.

DeGolyer and MacNaughton

Definition of Reserves

Petroleum reserves estimated by CNOOC included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by CNOOC 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.

DeGolyer and MacNaughton

(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 and operating 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.

DeGolyer and MacNaughton

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 Rule 4-10(a)(2) of Regulation S-X, or by other evidence using reliable technology establishing reasonable certainty.

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 the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and 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.

DeGolyer and MacNaughton

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

CPG has represented that CNOOC’s senior management is committed to the Liza phase 1 development plan provided by CPG on behalf of CNOOC and that CNOOC has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

The volumetric method was used to estimate the original oil in place (OOIP). Structure maps were prepared to delineate each reservoir, 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.

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 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 based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

For cases where history-matched dynamic models were available and applicable, model results were used to estimate recovery factors and reserves production forecasts.

Petroleum reserves estimated by CNOOC and evaluated by DeGolyer and MacNaughton are classified as proved and 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. Reserves were estimated only to the limit of economic production as defined under the Definitions of Reserves heading of this report and prior to the expiration of the 20-year production period of the Petroleum Agreement.

DeGolyer and MacNaughton

Data provided by CPG from wells drilled through December 31, 2018, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available through December 31, 2018. Cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves.

Oil reserves estimated herein are to be recovered by normal field separation and are expressed in thousands of barrels (10³bbl). In these estimates, 1 barrel equals 42 United States gallons.

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include C₅₊ and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions. NGL reserves are the result of low-temperature plant processing. Oil, condensate, and NGL reserves estimates included in this report are expressed in thousands of barrels (10³bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Currently, there are no plans to process produced gas to recover condensate or NGL; therefore, condensate and NGL reserves were estimated herein to be zero.

Gas quantities 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 usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas and are expressed in millions of cubic feet (10⁶ft³). Gas reserves estimated herein are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.7 pounds per square inch absolute (psia).

DeGolyer and MacNaughton

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. All gas quantities estimated herein are associated solution gas.

Currently, there is no market for gas sales from the Liza field; therefore, sales gas reserves were estimated herein to be zero.

At the request of CPG on behalf of CNOOC, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by CPG on behalf of CNOOC.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by CPG on behalf of CNOOC in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Oil Prices

CPG, on behalf of CNOOC, has represented that the oil prices were based on a reference 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 agreements. To account for quality and transportation costs, CPG, on behalf of CNOOC, provided price differentials to a Brent reference price of U.S.$71.88 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the life of the field was U.S.$70.44 per barrel of oil.

DeGolyer and MacNaughton

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by CPG on behalf of CNOOC and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were

estimated using 2018 values, provided by CPG on behalf of CNOOC, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment, were provided by CPG on behalf of CNOOC and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of undeveloped reserves estimated herein.

In our opinion, the information relating to estimated 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, and 932-235-50-9, 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), (5), (8), and 1203(a) of Regulation S–K of the SEC, provided however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

DeGolyer and MacNaughton

Summary of Conclusions

CPG, on behalf of CNOOC, has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definition of proved reserves of the SEC. The CNOOC net proved reserves attributable to the Liza field offshore Guyana, as of December 31, 2018, and which represent approximately 1 percent of total CNOOC net reserves on a net equivalent barrel basis, are summarized as follows, expressed in expressed in thousands of barrels (10³bbl), millions of cubic feet (10⁶ft³), and thousands of barrels of oil equivalent (10³boe):

	Estimated by CNOOC Net Proved Reserves as of December 31, 2018
	Oil and Condensate (10³bbl)	NGL (10³bbl)	Sales Gas (10⁶ft³)	Oil Equivalent (10³boe)
Proved
Developed	0	0	0	0
Undeveloped	39,651	0	0	39,651

Total	39,651	0	0	39,651

Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by CNOOC, differences have been found, both positive and negative, when compared on the basis of net equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by CNOOC on the properties evaluated and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable because they reflect a difference of not more than plus or minus 10 percent from those prepared by DeGolyer and MacNaughton.

CNOOC’s reserves have been estimated assuming the continuation of the current regulatory environment. Changes in the regulatory environment by host governments may impact the operating environment and oil and gas reserves estimates of industry participants. Such regulatory changes could include increased mandatory government participation in producing contracts, changes in royalty terms, cancellation or amendment of contract rights, or expropriation or nationalization of property. While the industry is subject to regulatory changes 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, 2018, estimated reserves.

DeGolyer and MacNaughton

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. This report does not constitute a legal or accounting opinion. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in CNOOC or CPG. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of CPG on behalf of CNOOC. 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





	/s/ Thomas C. Pence, P.E
	Thomas C. Pence, P.E. Senior Vice President DeGolyer and MacNaughton

CC:

Mr. Michael Guardia, Sr. Manager – Subsurface Technical, International Development (CNOOC International Limited)
Mr. Keith Henderson, VP – International Developments, Global Exploration and International Developments (CNOOC International Limited)
Ms. Cassidy Fuller, Deloitte LLP

CERTIFICATE of QUALIFICATION

I, Thomas C. Pence, 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 of DeGolyer and MacNaughton, which firm did prepare the report of third party dated January 23, 2019, on the proved reserves evaluation of certain properties attributable to CNOOC Limited, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and that I have in excess of 36 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Thomas C. Pence, P.E

Thomas C. Pence, P.E.

Senior Vice President

DeGolyer and MacNaughton