Document/ExhibitDescriptionPagesSize
1: 10-K Annual Report HTML 2.72M
2: EX-10.11(D) Material Contract HTML 52K
3: EX-10.11(E) Material Contract HTML 67K
4: EX-21.1 Subsidiaries List HTML 30K
5: EX-23.1 Consent of Expert or Counsel HTML 30K
6: EX-23.2 Consent of Expert or Counsel HTML 32K
10: EX-97 Clawback Policy re: Recovery of Erroneously HTML 51K
Awarded Compensation
11: EX-99.1 Miscellaneous Exhibit HTML 62K
7: EX-31.1 Certification -- §302 - SOA'02 HTML 34K
8: EX-31.2 Certification -- §302 - SOA'02 HTML 34K
9: EX-32.1 Certification -- §906 - SOA'02 HTML 33K
17: R1 Cover Page HTML 100K
18: R2 Audit Information HTML 36K
19: R3 Consolidated Balance Sheet HTML 137K
20: R4 Consolidated Balance Sheet (Parenthetical) HTML 37K
21: R5 Consolidated Statement of Operations HTML 132K
22: R6 Consolidated Statement of Comprehensive Income HTML 65K
23: R7 Consolidated Statement of Comprehensive Income HTML 40K
(Parenthetical)
24: R8 Consolidated Statement of Cash Flows HTML 128K
25: R9 Consolidated Statement of Stockholders' Equity HTML 119K
26: R10 Consolidated Statement of Stockholders' Equity HTML 34K
(Parenthetical)
27: R11 Summary of Significant Accounting Policies HTML 72K
28: R12 Acquisitions HTML 44K
29: R13 Properties and Equipment, Net HTML 45K
30: R14 Long-Term Debt and Credit Agreements HTML 54K
31: R15 Derivative Instruments HTML 173K
32: R16 Fair Value Measurements HTML 103K
33: R17 Asset Retirement Obligations HTML 51K
34: R18 Commitments and Contingencies HTML 98K
35: R19 Revenue Recognition HTML 49K
36: R20 Income Taxes HTML 121K
37: R21 Employee Benefit Plans HTML 44K
38: R22 Capital Stock HTML 89K
39: R23 Stock-Based Compensation HTML 162K
40: R24 Earnings per Common Share HTML 59K
41: R25 Restructuring Costs HTML 44K
42: R26 Additional Balance Sheet Information HTML 78K
43: R27 Interest Expense HTML 43K
44: R28 Supplemental Cash Flow Information HTML 44K
45: R29 Pay vs Performance Disclosure HTML 43K
46: R30 Insider Trading Arrangements HTML 37K
47: R31 Summary of Significant Accounting Policies HTML 117K
(Policies)
48: R32 Acquisitions (Tables) HTML 41K
49: R33 Properties and Equipment, Net (Tables) HTML 43K
50: R34 Long-Term Debt and Credit Agreements (Tables) HTML 50K
51: R35 Derivative Instruments (Tables) HTML 199K
52: R36 Fair Value Measurements (Tables) HTML 102K
53: R37 Asset Retirement Obligations (Tables) HTML 51K
54: R38 Commitments and Contingencies (Tables) HTML 87K
55: R39 Revenue Recognition (Tables) HTML 44K
56: R40 Income Taxes (Tables) HTML 120K
57: R41 Capital Stock (Tables) HTML 85K
58: R42 Stock-Based Compensation (Tables) HTML 156K
59: R43 Earnings per Common Share (Tables) HTML 61K
60: R44 Restructuring Costs (Tables) HTML 43K
61: R45 Additional Balance Sheet Information (Tables) HTML 78K
62: R46 Interest Expense (Tables) HTML 43K
63: R47 Supplemental Cash Flow Information (Tables) HTML 44K
64: R48 Summary of Significant Accounting Policies HTML 56K
(Details)
65: R49 Acquisitions - Narrative (Details) HTML 39K
66: R50 Acquisitions - Post-Acquisition Operating Results HTML 36K
(Details)
67: R51 Acquisitions - Pro Forma Information (Details) HTML 41K
68: R52 Properties and Equipment, Net (Details) HTML 55K
69: R53 Long-Term Debt and Credit Agreements - Schedule of HTML 73K
Long-term Debt (Details)
70: R54 Long-Term Debt and Credit Agreements - Narrative HTML 115K
(Details)
71: R55 Derivative Instruments - Outstanding Financial HTML 57K
Commodity Derivatives (Details)
72: R56 Derivative Instruments - Effect of Derivative HTML 62K
Instruments on the Consolidated Balance Sheet
(Details)
73: R57 Derivative Instruments - Offsetting Derivative HTML 75K
Assets and Liabilities in Consolidated Balance
Sheet (Details)
74: R58 Derivative Instruments - Effect of Derivative HTML 46K
Instruments on the Consolidated Statement of
Operations (Details)
75: R59 Fair Value Measurements - Financial Assets and HTML 75K
Liabilities, Recurring (Details))
76: R60 Fair Value Measurements - Reconciliation of HTML 47K
Changes in Fair Value of Financial Assets and
Liabilities (Details)
77: R61 Fair Value Measurements - Narrative (Details) HTML 32K
78: R62 Fair Value Measurements - Fair Value of Other HTML 44K
Financial Instruments (Details)
79: R63 Asset Retirement Obligations (Details) HTML 49K
80: R64 Commitments and Contingencies - Future Minimum HTML 56K
Obligations (Details)
81: R65 Commitments and Contingencies - Narrative HTML 54K
(Details)
82: R66 Commitments and Contingencies - Future HTML 50K
Undiscounted Minimum Cash Payment Obligations for
Operating Lease Liabilities (Details)
83: R67 Commitments and Contingencies - Future HTML 41K
Undiscounted Minimum Cash Payment Obligations for
Financing Lease Liabilities (Details)
84: R68 Commitments and Contingencies - Supplemental Cash HTML 35K
Flow Information Related to Leases (Details)
85: R69 Commitments and Contingencies - Information HTML 40K
Regarding Weighted-Average Remaining Lease Term
and Weighted-Average Discount Rate for Operating
Leases (Details)
86: R70 Revenue Recognition - Disaggregation of Revenue HTML 47K
(Details)
87: R71 Revenue Recognition - Narrative (Details) HTML 41K
88: R72 Income Taxes - Summary of Income Tax Expense HTML 54K
(Benefit) (Details)
89: R73 Income Taxes - Schedule of Reconciliation of HTML 77K
Income Tax Expense (Benefit) Computed by Applying
Statutory Federal Income Tax Rate (Details)
90: R74 Income Taxes - Schedule of Composition of Net HTML 63K
Deferred Tax Liabilities (Details)
91: R75 Income Taxes - Narrative (Details) HTML 67K
92: R76 Income Taxes - Schedule of Reconciliation of HTML 38K
Unrecognized Tax Benefits (Details)
93: R77 Employee Benefit Plans - Narrative (Details) HTML 53K
94: R78 Capital Stock - Dividends Common Stock (Details) HTML 41K
95: R79 Capital Stock - Narrative (Details) HTML 72K
96: R80 Capital Stock - Conversions of Stock (Details) HTML 49K
97: R81 Stock-Based Compensation - Narrative (Details) HTML 116K
98: R82 Stock-Based Compensation - Summary of Share-Based HTML 60K
Compensation Expense Income Tax Benefit Awards
Issued Under Incentive Plans (Details)
99: R83 Stock-Based Compensation - Summary of Restricted HTML 65K
Stock Award Activity (Details)
100: R84 Stock-Based Compensation - Summary of Restricted HTML 52K
Stock Unit Activity (Details)
101: R85 Stock-Based Compensation - Schedule of Performance HTML 54K
Share Awards Activity (Details)
102: R86 Stock-Based Compensation - Reflects Certain HTML 45K
Balance Sheet Information (Details)
103: R87 Stock-Based Compensation - Cash Payments Related HTML 42K
to the Vesting (Details)
104: R88 Stock-Based Compensation - Assumptions Used to HTML 63K
Determine Grant Date Fair Value of Equity and
Liability Component (Details)
105: R89 Stock-Based Compensation - Summary of Share-Based HTML 48K
Compensation, Aggregative Fair Value of Awards and
Units Vested, Activity (Details)
106: R90 Stock-Based Compensation - Summary of Share-Based HTML 51K
Compensation, Weighted-Average Recognition Period
Associated with Unvested Awards and Units ,
Activity (Details)
107: R91 Stock-Based Compensation - Summary of Stock Option HTML 62K
Awards (Details)
108: R92 Earnings per Common Share - Schedule of EPS HTML 78K
(Details)
109: R93 Earnings per Common Share - Calculation of HTML 35K
Weighted-Average Shares Excluded from Diluted EPS
(Details)
110: R94 Restructuring Costs - Narrative (Details) HTML 33K
111: R95 Restructuring Costs - Restructuring Liabilities HTML 39K
(Details)
112: R96 Additional Balance Sheet Information (Details) HTML 124K
113: R97 Interest Expense (Details) HTML 43K
114: R98 Supplemental Cash Flow Information (Details) HTML 42K
116: XML IDEA XML File -- Filing Summary XML 211K
119: XML XBRL Instance -- cog-20231231_htm XML 2.87M
115: EXCEL IDEA Workbook of Financial Report Info XLSX 206K
13: EX-101.CAL XBRL Calculations -- cog-20231231_cal XML 326K
14: EX-101.DEF XBRL Definitions -- cog-20231231_def XML 794K
15: EX-101.LAB XBRL Labels -- cog-20231231_lab XML 2.51M
16: EX-101.PRE XBRL Presentations -- cog-20231231_pre XML 1.52M
12: EX-101.SCH XBRL Schema -- cog-20231231 XSD 227K
117: JSON XBRL Instance as JSON Data -- MetaLinks 679± 1.03M
118: ZIP XBRL Zipped Folder -- 0000858470-24-000019-xbrl Zip 616K
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2023, of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves
of certain properties in which Coterra Energy Inc. (Coterra) has represented it holds an interest. The properties evaluated herein are located in New Mexico, Oklahoma, Pennsylvania, and Texas. This evaluation was completed on January 26, 2024. Coterra has represented that these properties account for greater than 90 percent of the total future net revenue discounted at 10 percent attributable to the total interests held by Coterra, as well as greater than 91 percent on a net equivalent barrel basis of net proved reserves attributable to the interests held by Coterra, as of December 31, 2023, and that the net proved reserves estimates were prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). It is our opinion that the procedures and methodologies employed by Coterra
for the preparation of its proved reserves estimates as of December 31, 2023, comply with the current requirements of the SEC. We have reviewed information provided to us by Coterra that it represents to be Coterra’s estimates of the net reserves, as of December 31, 2023, 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 Coterra.
Reserves estimates included herein are expressed as net reserves as represented by Coterra. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2023. Net reserves are defined as that portion of the gross reserves attributable
to the interests held by Coterra after deducting all interests held by others.
Estimates of reserves should be regarded only as estimates that may change as further 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 the preparation of this report was obtained from Coterra and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Coterra 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. A field examination was not considered necessary for the purposes of this report.
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.
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 (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. 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 Coterra, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
The proved undeveloped reserves estimates were based on opportunities identified in the plan
of development provided by Coterra.
Coterra has represented that its senior management is committed to the development plan provided by Coterra and that Coterra has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.
For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).
Characteristic
rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.
In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.
In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.
Data provided by Coterra from wells drilled through December 31, 2023, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of daily and monthly production data available through December 2023. Cumulative production, as of December 31, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves.
Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves
included in this report are expressed in thousands of barrels (Mbbl). 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.
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. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the quantities are located. Gas quantities included in this report are expressed in millions of cubic feet (MMcf).
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 is 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. Gas quantities estimated herein include both associated and nonassociated gas.
At the request of Coterra, 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.
Primary Economic Assumptions
This report has been prepared using initial prices, expenses, and costs provided by Coterra. 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 and Condensate Prices
Coterra has represented that the oil and condensate 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. Coterra applied differentials by property to a West Texas Intermediate reference price of $78.22 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties for only those properties evaluated by DeGolyer and MacNaughton was $75.05 per barrel of oil and condensate.
NGL
Prices
Coterra has represented that the NGL prices were based on a reference price of $27.90 per barrel. Coterra supplied differentials by property to the reference price and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties for only those properties evaluated by DeGolyer and MacNaughton was $18.39 per barrel of NGL.
Gas Prices
Coterra has represented that the gas 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. Coterra applied differentials
by property to a Henry Hub reference price of $2.64 per million Btu and held constant thereafter. Btu factors provided by Coterra were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume‑weighted
average price attributable to the estimated proved reserves over the lives of the properties for only those properties evaluated by DeGolyer and MacNaughton was $2.04 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 reserves are located. Ad valorem taxes were calculated using rates provided by Coterra based on recent payments.
Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses and future capital expenditures, provided by Coterra and based on existing economic conditions, were held constant for the lives of the properties 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 wells, and reclamation and restoration associated with the abandonment, were provided by Coterra for all properties
and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.
In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas of the properties evaluated by us 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 FASB 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 SEC; provided, however, that estimates of 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.
Summary of Conclusions
DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, NGL, and gas reserves of certain properties in which Coterra has represented it holds an interest. Coterra has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definition of proved reserves of the SEC. Coterra’s estimates of the net proved reserves, as of December 31,
2023, attributable to these properties, which represent greater than 91 percent of the reserves attributable to the interests held by Coterra on a net equivalent basis and greater than 90 percent of the total future net revenue discounted at 10 percent attributable to the interests held by Coterra, are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):
Notes: 1. All reserves estimates shown herein were prepared by Coterra. 2. 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 Coterra,
differences have been found, both positive and negative, resulting in an aggregate difference of less than 10 percent when compared on the basis of net equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by Coterra on the properties evaluated by DeGolyer and MacNaughton and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by DeGolyer and MacNaughton.
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, 2023, estimated reserves.
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 Coterra. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Coterra. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary
to prepare this report.
I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
1.That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare this report of third party addressed to Coterra Energy Inc. dated January 26, 2024, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.
2.That
I attended Istanbul Technical University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005, and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010; 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 13 years of experience in oil and gas reservoir studies and reserves evaluations.