Crescent Energy (CRGY) S-4 Registration of securities issued in business combination transactions

Exhibit 99.9

April 6, 2021

Mr. Warren D. Miller

Venado Oil & Gas, LLC

13501 Galleria Circle, Suite 350

Austin, TX 78738

Re: Evaluation Summary – SEC Pricing

Venado Oil & Gas, LLC Interests

Total Proved Reserves

Various Properties in Texas – Palo Verde Assets –

As of December 31, 2020

Dear Mr. Miller:

As requested by Venado Oil & Gas, LLC (“Venado”), we are submitting our estimates of total proved reserves and forecasts of economics attributable to the Venado ownership interests in various “Palo Verde” oil and gas properties located in Texas. This report includes results for a year-end 2020 U.S. Securities and Exchange Commission (“SEC”) price scenario. The results of this evaluation are presented in the accompanying tabulations, with a composite summary of each reserve category presented below:

		Proved Developed Producing		Proved Developed Shut-In		Proved Undeveloped		Total Proved
Net Reserves
Oil	- Mbbl		23,662.4		82.0		48,552.0		72,296.4
Gas	- MMcf		12,739.4		20.9		19,636.1		32,396.3
NGL	- Mbbl		2,510.8		4.0		3,971.7		6,486.6
BOE	- Mbbl		28,296.4		89.5		55,796.4		84,182.4
Net Revenue
Oil	- M$		899,644.3		3,119.3		1,845,946.8		2,748,710.8
Gas	- M$		23,758.9		38.9		36,621.3		60,419.1
NGL	- M$		34,773.9		55.9		55,006.6		89,836.4
Severance Taxes	- M$		43,798.6		147.3		88,768.2		132,714.1
Ad Valorem Taxes	- M$		16,636.4		55.2		34,234.4		50,926.0
Operating Expenses	- M$		244,779.9		954.6		234,412.6		480,147.1
Workover Expenses	- M$		0.0		0.0		0.0		0.0
Other Deductions	- M$		81,509.9		219.6		185,782.0		267,511.5
Investments	- M$		23,368.3		330.0		722,009.2		745,707.4
Net Operating Income (BFIT)	- M$		548,084.2		1,507.4		672,368.3		1,221,959.6
Discounted @ 10%	- M$		336,256.0		762.5		213,536.1		550,554.5

Future net revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow (Net Operating Income – BFIT) is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties by Cawley, Gillespie & Associates, Inc. (“CG&A”).

Presentation

This report is divided into four reserve category sections: Total Proved (“TP”), Proved Developed Producing (“PDP”), Proved Developed Shut-In (“PDSI”) and Proved Undeveloped (“PUD”). Within each reserve category section are grand total Table I cash flow tables and Table II “oneline” summaries. The Table I presents composite reserve estimates and economic forecasts for the particular reserve category. The Table II “oneline” summaries present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow for the individual properties that make up the corresponding Table I.

Venado Palo Verde SEC Price Scenario

Venado Oil and Gas Interests

April 6, 2021

For a more detailed description of the report layout, please refer to the Table of Contents following this letter. The data presented in each Table I is explained in page one (1) of the Appendix. The methods employed in estimating reserves are described in page two (2) of the Appendix.

Hydrocarbon Pricing

As requested, oil and gas prices were adjusted to the year-end 2020 SEC price deck. The base SEC oil and gas prices calculated for December 31, 2020 were $39.57/bbl and $1.985/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average 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. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2020 and the base gas price is based upon Henry Hub spot prices (Gas Daily) during 2020.

As provided, oil and gas price differentials were applied and may include adjustments for local basis differentials, treating costs, transportation charges, gas heating value (BTU content) and/or crude quality and gravity corrections. Gas shrinkage factors were applied to each property against gross gas volumes to account for line losses and plant processing. Natural gas liquid (NGL) prices were determined to be approximately 36.4% of WTI-Cushing oil prices based upon data provided by Venado.

Expenses, Investments and Taxes

Lease operating expenses (LOE), workover expenses and investments were provided by Venado and audited by us at a summary level. Our audit determined that the commercial parameters being applied were reasonable and appropriate, and therefore no changes were made to cost parameters. All costs applied in this evaluation were held constant for the life of the properties. Severance tax values were determined by applying normal state severance tax rates. Ad valorem tax rates were forecast as provided at approximately 1.7% of revenue. Fixed LOE costs are shown in the attached tables as Operating Expense (column 22). Variable expenses were applied to all wells to capture gas and/or liquids transportation costs plus water disposal costs, which can be seen in the attached tables as Other Deductions (column 27).

For the non-producing PUD properties, LOE was also scheduled as provided by production lift type and type curve area. Investment capital information was provided by Venado based upon their significant drilling and completion activities in recent years. The drill and complete (D&C) costs were applied by lateral length and completions type for all Eagle Ford locations.

Reserves and Drilling Locations

Reserves assigned to each producing well were based on a combination of forecasting methods including decline curve analysis (DCA), regional type curve fitting and analogy to offset production. For PUD drilling locations, reserves were assigned based on regional type curves and offset analogy.

We evaluated 358 PDP properties for this report, each with daily production data through 11/30/2020 as provided by Venado. This report also includes nine (9) PDSI properties, of which one (1) is scheduled to return to production.

This report also includes 239 PUD locations, all targeting the Eagle Ford reservoir. All PUD drills were modeled as horizontal wells offsetting production from existing horizontal producers. In general, up to eight (8) PUD locations were assigned around a single horizontal producer assuming Venado owned the acreage in all surrounding offset units. This was accomplished by assigning PUD locations “straddling” the producer with three (3) PUDs on each side and with a PUD on the “toe” and “heel” of the producer. However, it should be noted that the abundance of existing commercial horizontal producers allowed many of the PUD locations to be directly offset by production. Reserves for each PUD location were assigned by type curve area depending upon the region and nearby analogous production.

Venado Oil and Gas Interests

April 6, 2021

Miscellaneous

An on-site field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment has been included, as provided by Venado.

The reserve classifications and the economic considerations used herein were based upon the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date, except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. All reserve estimates represent our best judgment based on data available at the time of preparation, and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. Ownership information and economic factors such as liquid and gas prices, price differentials and expenses were furnished by Venado. To some extent, information from public records was used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or Venado Oil & Gas, LLC and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work papers and related data are available for inspection and review by authorized, interested parties.

Yours very truly,

/s/ W. Todd Brooker

W. Todd Brooker, P.E.

President

CAWLEY, GILLESPIE & ASSOCIATES, INC.

TEXAS REGISTERED ENGINEERING FIRM F-693

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22) 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 a 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.

“(6) 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.

“(31) 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.

“(18) 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.

“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(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 (22)(iii) of this section (above), 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.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26) 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 (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).”