Document

As requested, Haas Petroleum Engineering Services, Inc. (hereinafter referred to as “Haas Engineering”) has performed an Audit of the provided economics and databases prepared by Crescent Energy Company (hereinafter referred to as “Crescent”), as of December 31, 2021. The properties contained in this Audit are the Gardendale, Newark, and Renee areas, which are located in Texas and Wyoming. These areas have been combined into a single report, at the request of Crescent. Production data was generally available through August 31, 2021. It is the understanding of Haas Engineering that this evaluation comprises approximately 34% of the Proved Reserves of Crescent.

Haas Engineering has completed this audit in accordance with the definitions of the Securities and Exchange Commission (“SEC”) Regulation S-X Rule 4-10(a). This estimate of Reserves was completed on or about the date of this report. This report has been prepared for the purposes of Crescent’s SEC filing. It is Haas Engineering’s opinion that the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for this purpose. As of December 31, 2021, Crescent’s net Reserves, future net income (“FNI”), and net present worth discounted at 10 percent per annum (“NPV”) have been estimated to be as follows:


TABLE 1
		As of 12/31/2021
		Net Reserves		Sales Volumes
		Oil &	Wet Gas (Mcf)			Residue Gas (Mcf)		NPV
		Condensate			NGL		FNI	Disc. @ 10%
	Reserve Class/Cat	(bbl)			(bbl)		($)	($)
	Proved Producing	36,849,153	662,589,450		21,599,062	593,726,063	1,667,635,376	948,673,440
	Proved Non-Producing	4,658,952	76,291,127		1,221,794	70,801,026	281,281,613	121,575,999
	Proved Undeveloped	4,372,374	2,517,986		309,712	1,699,640	159,535,376	70,982,260
	Total Proved	45,880,479	741,398,563		23,130,568	666,226,729	2,108,452,365	1,141,231,699

In this unqualified audit of Crescent’s Reserves, Haas Engineering noted some variances from our internal estimations including forecast differences, price adjustments, taxes, recoveries, and operating expenses. However, these differences, in aggregate, did not exceed the 10 percent tolerance of auditing standards.

It is the opinion of Haas Engineering that the Reserves, FNI, and NPV estimates listed in Table 1 are, in the aggregate, reasonable and meet Audit standards for the top 80% of value in the portfolio. FNI is after deducting estimated operating and future development costs, severance and ad valorem taxes, but before Federal income taxes. Total net Proved Reserves are defined as those natural gas and hydrocarbon liquid Reserves to Crescent’s interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All Reserves estimates have been prepared using standard engineering practices

generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC. All hydrocarbon liquid Reserves are expressed in United States barrels (“bbl”) of 42 gallons. Natural gas Reserves are expressed in thousand standard cubic feet (“Mcf”) at the contractual pressure and temperature bases and include shrinkage adjustment related to field and plant losses.

It is the opinion of Haas Engineering that the Reserves estimates contained in this report have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining Reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing Reserves were estimated by volumetric analysis, research of analogous reservoirs, probabilistic methods, or a combination of methods. The appropriate methodology was used, as deemed necessary, to estimate Reserves in conformance with SEC regulations. The maximum remaining Reserves life assigned to wells included in this report is 48 years for Gardendale, 50 years for Newark, and 39 years for Renee. This report does not include any gas sales imbalances.

It is the opinion of Haas Engineering that the Reserves estimates contained in this report conform to guidelines specified by the SEC. For more information regarding Reserves classification definitions see Appendix A. A complete discussion of the Reserves classification definitions can be found on the United States Securities and Exchange Commission website (www.sec.gov). It should be noted that this evaluation contains cases with negative FNI, due to the inclusion of abandonment costs, or expense modeling (G&A, expense capital, etc.). All volumes are related to commercial production.

The SEC requires a development plan be in place for these assets. This Audit report defines a budget for that development plan, but Haas Engineering makes no representation about the company’s ability to fund this development. All Proved Undeveloped (“PUD”) locations are developed within 5 years. Please note that, as of the effective date of this report, no wells were being drilled, completed, or are waiting on completion.

It is the opinion of Haas Engineering that, pursuant to SEC guidelines, the cash flow projections in this report utilize the unweighted 12-month arithmetic average of the first-day-of month benchmark prices for January 2021 through December 2021. The benchmark price for natural gas is taken to be the price received at Henry Hub and the benchmark price for hydrocarbon liquids is taken to be the price received for West Texas Intermediate (“WTI”) crude oil at the Cushing, OK sales point.

The unweighted arithmetic average cash market price for natural gas delivered at Henry Hub during this time period is $3.598 per MMBTU. The Henry Hub price was held constant throughout the life of the wells and is adjusted for BTU content, basis differentials, and marketing costs, resulting in a weighted average net price of $3.33 per Mcf for Gardendale, $3.44 per Mcf for Newark, and $3.27 per Mcf for Renee. Please note that transportation costs for natural gas have been included as expense.

The unweighted arithmetic average cash market price for WTI crude oil sold at Cushing, OK during this time period is $66.56 per bbl. For natural gas liquids (“NGL”), the WTI crude oil price was held constant throughout the life of the wells and is adjusted for BTU content, plant processing fees and basis differentials, resulting in a weighted average net price of $28.62 per bbl for Gardendale, $23.97 per bbl for Newark, $31.50 per bbl for Renee. For crude oil, the WTI crude oil price was held constant throughout the life of the wells and is adjusted for crude quality, marketing fees, BS&W, transportation

costs, purchaser bonuses and basis differentials, resulting in a weighted average net price of $66.16 per bbl for Gardendale, $63.85 per bbl for Newark, and $66.02 per bbl for Renee.

Summary level revenue accounting data for the period of August 1, 2020 through July 31, 2021 was generally used in this evaluation. The pricing adjustments were provided by Crescent and reviewed for the top 80 percent of the NPV. Haas Engineering verified the reasonableness of Crescent’s pricing models and differentials using accounting data furnished by Crescent.

It is the opinion of Haas Engineering that, in most cases, the lease operating costs used in this evaluation represent the average of recent historical monthly operating costs. In cases where historical costs were not available or deemed to be unreliable, operating costs were estimated based on knowledge of analogous wells producing under similar conditions. The lease operating expenses in this report represent field level operating costs and do not include COPAS charges for operated properties.

It is the opinion of Haas Engineering that capital costs were estimated using recent historical information reported for analogous expenditures. Where recent historical information was not available, Authority for Expenditure (“AFE”) documents, or supplemental documentation was provided by the operator and used to estimate capital costs. AFE and supplemental documents provided by the operator have been checked for reasonableness. It should also be understood that abandonment costs have been included at both the field and well level. The abandonment costs used are Crescent’s estimates of the costs to abandon the wells and production facilities, net of salvage value, and have been reviewed for reasonableness.

Operating expenses for the period of August 1, 2020 through July 31, 2021 was generally used in this evaluation. Operating expenses, capital costs, and abandonment costs were not escalated in this evaluation.

It should also be clear that abandonment costs have been included at the field and well level. The abandonment costs used are Crescent’s estimates of the costs to abandon the wells and production facilities, net of salvage value, and have been reviewed for reasonableness.

The Proved Reserves presented in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered; and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the product prices and the costs incurred in recovering these Reserves may vary from the price and cost assumptions in this report. Because these estimates are based on existing governmental regulations, changes could affect the ability to recover these Reserves. In any case, quantities of Reserves may increase or decrease as a result of future operations.

Reserves estimates for individual properties included in this report are only valid when considered within the context of the overall report and should not be considered independently. The future net income and net present value estimates contained in this report do not represent an estimate of fair market value.

All information pertaining to the operating expenses, prices, and the interests of Crescent in the properties appraised has been accepted as represented. It was not considered necessary to make a field examination of the appraised properties. Data used in performing this appraisal were obtained from Crescent, public sources, and our own files. Supporting work papers pertinent to the appraisal are retained in our files and are available to you or designated parties at your convenience.

It was beyond the scope of this Haas Engineering report to evaluate the potential environmental liability costs from the operation and abandonment of these properties. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the forecasts presented herein.

The technical persons primarily responsible for conducting this Audit meets the requirements regarding qualifications, independence, objectivity, and confidentiality, as defined by the SPE Standards. Michael A. Link, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas Engineering since 2015 and has over 20 years of industry experience. Franklin Stagg, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas Engineering since 2016 and has over 7 years of industry experience.

Haas Engineering is independent with respect to Crescent as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Attached are summary tables of economic analysis of predicted future performance. Other tables identify the properties appraised with summary Reserves and the economic factors applicable to each. A list of tables is included.

The list of definitions below were compiled by HPESI. They represent selected definitions from the Securities and Exchange Commission’s Rule 4-10 document. This document was amended on January 14, 2009, and the definitions below reflect the changes resulting from the amendment. Comprehensive versions of Rule 4-10 and the amendments to Rule 4-10 can be obtained online at https://www.sec.gov/info/smallbus/secg/oilgasreporting-secg.htm

(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

(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(3)Probable reserves. 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.

(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(4)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.

(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

(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.

(5)Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(6)Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(7)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).

(8)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 paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.


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