Crescent Energy (CRGY) 8-K Crescent Energy Announces Offering of $150 Million Private Placement of Additional 7.250% Senior Notes Due 2026

Exhibit 99.5

Mr. Brett Knight Director, Corporate Reserves Crescent Energy Company 600 Travis Street, Suite 7200 Houston, TX 77002 Dallas, January 20, 2022

Dear Mr. Knight:

In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of January 1, 2022, attributable to the Crescent Energy Company and its subsidiaries (Crescent) interests in certain hydrocarbon-producing properties located in Kansas, Louisiana, state and federal waters of the Gulf of Mexico off the coast of Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming. This report is based on unescalated prices and costs in accordance with the guidelines of the Securities and Exchange Commission (SEC). This evaluation was completed on January 20, 2022.

Reserves presented in this report are classified as proved and are further categorized as Proved Developed Producing (PDP), Proved Developed Not Producing (PDNP), Proved Developed Shut-In (PDSI) and Proved Un-Developed (PUD). Table 1 summarizes our estimate of the proved oil and gas reserves and their pre-federal income tax value undiscounted and discounted at ten percent using the year-end 2021 SEC price.

TABLE 1

CRESCENT ENERGY COMPANY

CRESCENT ENERGY COMPANY PROPERTIES

RESERVES AND CASH FLOW SUMMARY AS OF JANUARY 1,2022

YEAR-END 2021 SEC PRICE

	Net Reserves								Future Net Cash Flow
Reserves Category	Oil		Gas		NGL		Oil Equiv.		Undiscounted		Discounted @ 10% per Year
	(MBBL)		(MMcf)		(MBBL)		(MBOE)		(M$)		(M$)
Proved Developed		43,876		438,632		11,734		128,715		1,945,486		1,115,886
PDP—Producing		42,444		438,391		11,678		127,187		1,873,120		1,072,252
PDNP—Non Producing		1,432		241		56		1,527		72,366		43,634
PDSI—Shut-In		0		0		0		0		0		0
Proved Undeveloped		1,340		286		40		1,427		63,210		34,604
PUD—Undeveloped		1,340		286		40		1,427		63,210		34,604
TOTAL PROVED		45,215		438,919		11,773		130,142		2,008,696-		1,150,490

Values shown were determined utilizing constant oil and gas prices and well operating expenses. The discounted net present values of future income shown in Table 1 are not intended to represent an estimate of fair market value. These estimates were prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Certification Topic 932, Extraction Activities – Oil and Gas.

Oil and NGL volumes are expressed in thousand stock tank barrels (MBBL). A stock tank barrel is equivalent to 42 United States gallons. Gas volumes are expressed in million standard cubic feet (MMcf) as determined at 60° Fahrenheit and the legal pressure base for the specific location of the gas reserves.

Cobb & Associates reviewed 100 per cent of the properties included in this report. This report, which was prepared for Crescent’s use in filing with the SEC and will be filed with Crescent’s Form 10-K for fiscal year ending December 31, 2021 (the “Form 10-K”) and covers 22 percent of the total company present value discounted at ten percent (PV10) presented in Crescent’s Form 10-K. All assumptions, data, methods, and procedures considered necessary and appropriate were used to prepare this report.

DISCUSSION

The Crescent Energy Company properties are divided into four regions: Midcontinent, Permian, Rockies and Other. Cobb & Associates have reviewed 100% of the properties contained in this report, which constitutes 24% of the total proved reserves and 22% of the total Net Present Value for Crescent Energy Company.

The region with the largest net present value is the Rockies, which account for 42.6% of the total value. The Rockies region consists of properties in Montana and Wyoming. 35.9% of the total value is made up by the Midcontinent region and consists of properties in Kansas, Oklahoma and Texas. The Permian region makes up 20.4% of the total value from properties New Mexico and Texas. The remaining 1.0% of the total value comes from the Other region with properties in state and federal waters of the Gulf of Mexico off the coast of Louisiana, Louisiana, Mississippi and Texas.

Reserve estimates were prepared using generally accepted petroleum engineering principles and practices. The method, or combination of methods, utilized in the study of each property or reservoir included an assessment of the stage of reservoir development, quality of data, and length of production history. Geologic and engineering data was obtained from Crescent, public sources, and the non-confidential files of Cobb & Associates.

Performance data through September 2021 was used to forecast reserves for all producing properties where available. Reserve classification was based on the status of each well as of January 1, 2022 for operated wells, and on the most recently available information for non-operated wells.

For most regions in the report, the PDP reserve estimates were based on decline curve analysis. Some of the properties have produced for only a short period of time and did not exhibit an identifiable performance decline trend. In these cases, reserve estimates were based primarily on geological interpretation, mapping, and analogy to offset producers. Past performance, and offsetting performance data were used to estimate behind pipe and undeveloped reserves. Fields where additional analysis or methodology was used for the reserve assignments are discussed in more detail. These fields include Eugene Island 11 and the Big Horn or Madden Deep gas field in Wyoming.

Offshore—Eugene Island 11

Eugene Island 11 is located in federal and Louisiana state waters of the Gulf of Mexico, at a water depth of approximately 13 feet. Production is primarily from a single CibOp sand, the JRM-1 sand, at a depth of approximately 15,000 feet. The field was discovered in September, 2006 by Crescent Energy Company’s Dutch 1 well. Crescent has since drilled four more wells, the Dutch 2, 3, 4 and 5, on Federal acreage. The Dutch 5 well is depleted and was abandoned in December 2021.

Crescent also has properties in Louisiana state waters in this field. These properties are referred to as the Mary Rose prospect. Five Mary Rose wells have been drilled to date. Four Mary Rose wells, numbers 1 through 4, have produced from the main CibOp sand. The Mary Rose 4 well is depleted and has been abandoned. The Mary Rose 3 is also depleted, with abandonment scheduled for May 2023.

The Mary Rose 5 well produced from a separate, and much smaller, CibOp reservoir that is now depleted. Abandonment of the Mary Rose 5 was completed in 2019.

Proved reserves for the Eugene Island 10 main CibOp sand are based on analysis of historical rate versus time decline curves and P/Z performance plots, supplemented by volumetric calculations of original-gas-in-place (OGIP) using all available well log and 3D seismic data. The reservoir has been effectively drilled to the lowest structural datum and no significant aquifer has been found. Performance to date indicates a depletion drive system.

All Dutch and Mary Rose wells now flow to compression on the ‘H’ platform, allowing for a decrease in producing flowing tubing pressures. This two-stage compression lowers line pressure to approximately 200 psi. There are no remaining capital or startup costs for compression on the ‘H’ platform. Abandonment costs were provided by Crescent and scheduled at the end-of-project life for all wells and the ‘H’ platform.

The Mary Rose 1 well suffered a failure during 2021. Well investigation work indicate that there is not an easy fix to bring the well back online. Should it be impossible to develop a cost effective method to recover the production capacity lost from Mary Rose 1, it will likely bring forward the abandonment of the entire field. For this report, it has been assumed that the Mary Rose 1 is permanently lost and that none of the other wells will be increasing their production as a result of Mary Rose 1 no longer producing.

Big Horn / Madden Deep Gas Field

The Madden Deep reservoir is located in the Wind River Basin in Wyoming and was discovered and developed by Burlington Resources in the early 1990s. The reservoir is a fractured dolomitized limestone with around 200 feet of net pay. The structure is a fault bounded, three way dip structure with a total closure of around 1,500 feet. The average reservoir permeability is 1-10 mD with high permeability streaks around 100 mD. The reservoir as well as the reservoir fluids are challenging, the reservoir is located at a depth of around 25,000 feet and the reservoir temperature is 435 degrees Fahrenheit. The gas in the reservoir consists of 67.4% methane, 20% CO2 and 12.6% H2S. None of the 9 wells penetrating the reservoir have tagged the gas water contact (GWC), so there is some uncertainty about the exact location of the GWC.

Conoco Phillips purchased the Asset from Burlington Resources in 2006 and owned it until it was purchased by Crescent in 2021.

The Gas in place for the field have been assessed using all available seismic data, static and dynamic well data. Three models have been constructed to model field performance:

1) 1 A Material Balance, Nodal Analysis, Surface Network model. The material balance portion of this model includes a detailed and history matched P/Z model using the measured P/Z data from the individual wells in the field.

2) A reservoir simulation model has been constructed and history matched and

3) A rate versus cumulative gas produced well by well production forecasting model.

The Gas Initially In Place numbers from the material balance and simulation models match well. The forecast used in the reserve report was taken from the rate versus cumulative gas model as this was best able to describe the production when one of the processing trains will be decommissioned in one of the coming years and the field experience higher deliverability than there is available processing capacity.

OIL AND GAS PRICING

Projections of proved reserves contained in this report utilize constant product prices of $65.56 per barrel of oil and $3.598 per MMBTU of gas. These are the so called SEC prices, which are the average first-of-the-month prices for the prior 12-month period for West Texas Intermediate (WTI) oil and Henry Hub gas. Appropriate oil and gas pricing differentials, residue gas shrink, NGL yields, and NGL pricing as a fraction of WTI were calculated for each field using 12 months of revenue data where available. After applying appropriate differentials for each property, the weighted average realized product prices for 2021 were $63.87 per barrel of oil and $3.321 per MCF of gas, resulting in average 2021 differentials of negative $1.69 per barrel of oil and negative $0.277 per MCF of gas.

OPERATING COSTS

Future operating costs for each of the Crescent wells are held constant at current values for the life of the property. These costs were calculated using 12-month lease operating expense (LOE) statements provided by Crescent. In general, the LOE statements for each of the properties were analyzed by production area. LOE data was available for most areas through August 2021. In general, each well was assigned a fixed monthly operating cost, variable costs for oil and gas, and water handling costs per barrel of water produced. Oil, gas and NGL transportation and processing fees were also assigned to each well by area using net revenue data in a similar manner that product differentials were determined.

LOE data for the Eugene Island 11 properties was analyzed by cost centre. Fixed operating costs were divided into three categories: producing well, non-producing well and platform expenses. Non-producing wells are wells that are no longer producing and awaiting abandonment in 2022 or beyond and had costs attributable to insurance. Platform expenses include shared compression equipment rental and operating costs, pipeline costs, and other costs that were assigned to platform cost centers.

CAPITAL & ABANDONMENT COSTS

Capital expenditures to recomplete behind-pipe zones in existing wells, re-activate or work over existing wells, drill new wells and install production facilities were provided by Crescent and appear to be reasonable.

Abandonment costs for Eugene Island 11 were included for each well and the platform expense case as it was supplied to Cobb & Associates by Crescent. Cobb & Associates have not done a field visit or in any other way attempted to verify the abandonment estimates apart from determining that the numbers looked reasonable.

Abandonment costs for all other properties in the report were been included by area. Yearly estimates of abandonment costs and equipment salvage values were scheduled based on current well status and life estimations.

PROFESSIONAL GUIDELINES

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years, from known reservoirs under expected economic and operating conditions. Reserves are considered proved if economic productivity is supported by either actual production or conclusive formation tests.

Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves, but more certain to be recovered than possible reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

The reserve estimates shown in this report are those estimated to be recoverable in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X and the guidelines specified in Item 1202 (a)(8) of Regulation S-K of the U.S. Securities and Exchange Commission (SEC), and with the exception of the exclusion of future income taxes, conforms to the FASB Accounting Standards Codification Topic 932, Extractive Industries—Oil and Gas. The definitions for oil and gas reserves in accordance with SEC Regulation S-X are set forth in this report.

The reserves included in this report are estimates only and should not be construed as being exact quantities. Governmental policies, uncertainties of supply and demand, the prices actually received for the reserves, and the costs incurred in recovering such reserves, may vary from the price and cost assumptions in this report. Estimated reserves using price escalations may vary from values obtained using constant price scenarios. In any case, estimates of reserves, resources, and revenues may increase or decrease as a result of future operations.

Cobb & Associates has not examined titles to the appraised properties nor has the actual degree of interest owned been independently confirmed. The data used in this evaluation were obtained from Crescent Energy Company and the non-confidential files of Cobb & Associates and were considered accurate.

We have not made a field examination of the Crescent properties. Therefore, operating ability and condition of the production equipment have not been considered. Also, environmental liabilities, if any, caused by Crescent or any other operator have not been considered, nor has the cost to restore the property to acceptable conditions, as may be required by regulation, been taken into account.

In evaluating available information concerning this appraisal, Cobb & Associates has excluded from its consideration all matters as to which legal or accounting interpretation, rather than engineering, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and conclusions necessarily represent only informed professional judgments.

William M. Cobb & Associates, Inc. is an independent consulting firm founded in 1983. Its compensation is not contingent on the results obtained or reported. Frank J. Marek, a Registered Texas Professional Engineer and a senior technical advisor of William M. Cobb & Associates, Inc., is primarily responsible for overseeing the preparation of the reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelor of Science degree in Petroleum Engineering from Texas A&M University 1977; member of the Society of Petroleum Engineers; member of the Society of Petroleum Evaluation Engineers; and over 40 years of experience in estimating and evaluating reserve information and estimating and evaluating reserves.

William M. Cobb & Associates, Inc. appreciate the opportunity to be of service to Crescent Energy Company on this project. Please contact us if there are any questions regarding this report.

Sincerely,

WILLIAM M. COBB & ASSOCIATES, INC.

Texas Registered Engineering Firm F-84