April 14, 2022

VIA EDGAR AND HAND DELIVERY

Division of Corporation Finance

Office of Energy and Transportation

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549-6010

Attention: Ethan Horowitz

Jennifer O’Brien

John Hodgin

Sandra Wall

Re: Falcon Minerals Corporation

Form 10-K for Fiscal Year Ended December 31, 2021

Form 8-K dated March 10, 2022

File No. 001-38158

Ladies and Gentlemen:

On behalf of Falcon Minerals Corporation (the “Company”), set forth below are the Company’s responses to the comments of the Staff (the “Staff”) of the Division of Corporation Finance of the Securities and Exchange Commission (the “Commission”) relating to the Company’s Form 10-K for Fiscal Year Ended December 31, 2021 (the “Form 10-K”) and Form 8-K dated March 10, 2022 (the “Form 8-K”).

Set forth below are the responses of the Company to the comments on the Staff’s letter to the Company, dated April 8, 2022, relating to the Form 10-K and the Form 8-K. For convenience of reference, the text of the comments in the Staff’s letter has been reproduced in bold and italics herein. The Company has also provided its response immediately after each numbered comment. Capitalized terms used but not otherwise defined herein have the meanings assigned to such terms in the Form 10-K or the Form 8-K, as applicable.

Form 10-K

Business

Proved Undeveloped Reserves, page 9

1. You disclose that your 10,141 MBoe in proved undeveloped reserves will be converted to developed status over the next five years. You also disclose that you converted 628 MBoe of proved undeveloped reserves to developed status during the year ended December 31, 2021. At that rate of conversion, it appears that your proved undeveloped reserves will not be developed within five years. Expand your disclosure to discuss the progress made during fiscal 2021, and any factors that impacted progress in converting proved undeveloped reserves to developed status. Refer to Item 1203(c) of Regulation S-K.

Response: The Company advises the Staff that the Company owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests in oil and natural gas properties, but it does not have working interests in any acreage and does not operate any of its properties.

As described in the Form 10-K, the Company depends on third-party operators for all of the exploration, development, and production operations on its properties and ultimately third-party operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion. Accordingly, the primary factor impacting the conversation rate of reserves relating to our properties is the decision by the operator to develop such properties.¹

¹  The Company directs the Staff to the risk factors describing the Company’s reliance on third-party operators, and the challenges faced by such operators in converting reserves, on pages 19-20 of the Form 10-K under the headings “We depend on three third-party operators for substantially all of the exploration and production on the properties underlying our royalties. Substantially all of our revenue is derived from royalty payments made by these operators. Therefore, any reduction in production from the wells drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have a material adverse effect on our revenues, financial condition and results of operations. None of the operators of the properties underlying our royalties are contractually obligated to undertake any development activities, so any development and production activities will be subject to their discretion.” and “The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from our operators than we or they currently anticipate.”

April 14, 2022

Page 2

In deciding whether to develop such properties, our operators consider a variety of factors, including macroeconomic conditions and the ability to obtain capital or financing needed for development and exploration operations. As described in the Form 10-K, “[a]s of December 31, 2021, 58.8% of our total estimated proved reserves were proved undeveloped reserves and may not be ultimately developed or produced by our operators. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by our operators. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by our operators are required to develop such reserves.” Accordingly, in unfavorable macroeconomic environments, such as environments where the ability to obtain capital or financing on acceptable terms is limited or inaccessible, the ability of our operators to incur the capital expenditures and undertake the drilling operations necessary to convert proved undeveloped reserves to proved developed reserves will generally be adversely impacted.

As disclosed in our Annual Report on Form 10-K filed for the year ended December 31, 2019, our proved undeveloped reserves changed due to the conversion of 2,167 MBoe of proved undeveloped reserves into proved developed reserves and proved developed non-producing reserves in 2019. However, during 2020, macroeconomic factors, including significant declines in oil and natural gas prices, increased investor pressure on operators not to incur capital expenditures beyond cash flows and the pervasive, adverse economic effects of the COVID-19 pandemic negatively impacted the ability of operators to execute on their development plans. For example, our most significant operator, which accounted for approximately 47% of our revenue for the year ended December 31, 2021, as described in our Form 10-K, experienced significant variability in its publicly announced development plan. In its 2019 development plan, this operator publicly anticipated production increases in the geographic areas where our properties are located from approximately 215 MBoe/d to approximately 300 MBoe/d by 2023; however, actual production results for this geographic area declined to approximately 186 MBoe/d in 2020. In addition, another of our largest operators decreased its capital expenditure program in May 2020 by approximately 45%.

As economic conditions improved during 2021, our operators updated development plans in a manner that reflected greater confidence in their ability to economically convert proved undeveloped reserves to developed status. These improved revised development plans, together with a more favorable commodity price environment, improved our outlook with respect to development activity in 2021 and beyond. For example, our primary operator reported approximately 213 MBoe/d of production in the geographic areas where our properties are located in 2021, even though the most material commodity price increases of the year occurred in the second half. This operator also serves as the operator on certain properties where we have a significantly higher average net revenue interest relative to our average net revenue interest in the other properties we own, and during 2021 the operator indicated to us that it anticipates significant development of this property during the next five years. The increased development activity by our operators, coupled with improved commodity prices and macroeconomic factors in the oil and gas sector as a whole, improved our conversion outlook in 2021 relative to the prior year and in a manner that more closely aligns with the conversions in 2019 described above.

While the Company believes that the risk factor disclosure referenced above appropriately addresses the Company’s reliance on third-party operators and the challenges those operators face in executing on development plans and converting reserves, in the event the Merger does not close, the Company advises the Staff it will include in subsequent filings, including in the Company’s annual report on Form 10-K for the year ended December 31, 2022, additional disclosure with respect to: (i) the specific impact of permitting and development activity with respect to properties where we own a higher average net revenue interest on the Company’s conversion outlook (including identifying the new permits and well inventory waiting to be brought online on such properties), and (ii) the conversion of additional proved undeveloped reserves that were not reflected on the prior year reserve report to developed status.

In the event the Merger is completed, the Post-Combination Company is not expected to present proved undeveloped reserves in the same manner as the Company. As described in the proxy statement related to the Merger, the Post-Combination Company will present proved undeveloped reserves in the same manner as Desert Peak. Desert Peak’s proved undeveloped reserves relate solely to wells that were spud but not yet producing in paying quantities.

2. We note that you have a history of material changes to the development plan underlying your estimates of proved undeveloped reserves during each of the last three fiscal years. Expand your disclosure to describe the particular controls you have in place to ensure compliance with Rules 4-10(a)(22) and 4-10(a)(31) of Regulation S-X. As part of your expanded disclosure, additionally describe the steps that your management implemented to evaluate departures from previously adopted development plans in determining the level of certainty regarding the proved undeveloped reserves disclosed as of December 31, 2021.

Response: The Company acknowledges the Staff’s comment. The Company advises the Staff that the Company updates the development plan underlying its estimates of proved undeveloped reserves each year based on the prior year’s results in accordance with SEC rules.

April 14, 2022

Page 3

In evaluating reserves, the Company’s reservoir engineers review operator activity, permitting activity, well performance, commodity price changes, development risk and operator costs, among other factors. The Company’s development plan is dependent on Falcon’s reasonable estimates of the development plans of the third-party operators who perform the actual development of the Company’s acreage. Based on such review and considering public statements made by, and information received from, the third-party operators, the Company’s internal reservoir engineers develop an initial proposed development plan, which is reviewed with the Company’s Chief Operating Officer and revised as deemed appropriate. The proposed development plan is then reviewed and discussed with the Company’s independent third-party reserve engineers. Any revisions that result from such discussions are included in a revised proposed development plan. The Company implements controls over this process by having senior management of the Company, including the Chief Financial Officer, the Chief Operating Officer and the Chief Accounting Officer separately review the proposed development plan. Comments by these individuals are discussed with the Company’s internal reservoir engineers and independent third-party reserve engineers and modifications or clarifications to the proposed development plan are made if appropriate. Those members of management then jointly review and approve the proposed development plan. The Company directs the Staff’s attention to “Proved Reserves—Evaluation and Review of Reserves” on page 7 of the Form 10-K for additional information regarding such process.

The Company advises the Staff that, while the Company updated the development plan underlying its estimates of proved undeveloped reserves in each of the past three years, as described in response to Comment #1 significant macroeconomic factors outside of the Company’s control resulted in material changes to the development plans underlying the Company’s estimates of proved undeveloped reserves. As indicated above, the development plans of the Company’s third-party operators are critical in implementing the Company’s own development plan. During 2019 and 2020, significant macroeconomics factors heavily influenced operator development plans and the oil and gas sector as a whole. During each of 2019 and 2020, the Company adjusted its development plan because the key operators on the Company’s acreage reduced their operations and expected development activity. These reductions were, among other things, due to the macroeconomic factors impacting the oil and gas sector, including investor pressures for operators to reduce capital expenditures as well as a severe global economic recession resulting from COVID-19 and the related massive and unprecedented reductions in commodity prices. During the 2021 review, the Company reviewed each of the relevant factors cited above, and also evaluated the trending changes in macroeconomic and commodity markets that occurred throughout 2021, resulting in a contemporaneous risk calibration regarding the Company’s development plan.

The Company further advises the Staff that, following the completion of the Merger, the Post-Combination Company is not expected to account for proved undeveloped reserves in the same manner as the Company. As described in the proxy statement related to the Merger, the Post-Combination Company will present proved undeveloped reserves in the same manner as Desert Peak. Desert Peak’s proved undeveloped reserves relate solely to wells that were spud but not yet producing in paying quantities. However, in the event the Merger does not close, the Company advises the Staff it will include additional disclosure in subsequent filings, including the Company’s annual report on Form 10-K for the year ended December 31, 2022. As an example, applying such revised disclosure to the Form 10-K, the Company would modify the disclosure on page 7 of the Form 10-K, in the form below.

Proved Reserves

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2021 and 2020 were prepared by RSC. A reserve audit is not the same as a financial audit and is less vigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on its own.

April 14, 2022

Page 4

Under SEC rules, proved reserves are those quantities of oil and natural 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. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2021 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy, or a combination of both methods. Approximately 90% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 10% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, RSC considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical, and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Our petroleum engineers work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil, and gas production, well test data, commodity prices and operating and development costs. The Vice President–Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. The Vice President–Reservoir Engineering is a petroleum engineer with over 14 years of reservoir and operations experience. Our technical staff uses historical information for our properties such as ownership interest, oil, and gas production, well test data, commodity prices, and operating and development costs.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

• review and verification of historical production data, which data is based on actual production as reported by our operators;

• evaluation of operator activity, permitting activity, well performance, commodity price changes, development risk and operator costs, operator statements, among other factors;

• preparation of reserve estimates by the Vice President–Reservoir Engineering or under his direct supervision;

• review by the Vice President–Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

• direct reporting responsibilities by the Vice President–Reservoir Engineering to the Chief Operating Officer;

• individual review by the Chief Financial Officer, Chief Operating Officer and Chief Accounting Officer;

• approval of development plan by senior management;

April 14, 2022

Page 5

• verification of property ownership by our land department; and

• no employee’s compensation is tied to the amount of reserves booked.

Acreage, page 10

3. We note that undeveloped acreage represents a significant proportion of your total acreage. Please expand your disclosure to discuss the expiration dates of material amounts of your undeveloped acreage. Refer to Item 1208(b) of Regulation S-K.

Response: The Company respectfully advises the Staff that it owns royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests in oil and natural gas properties but does not have working interests in any acreage. Accordingly, the Company respectfully submits that it does not own any gross or net acres as defined by Item 1208(c) of Regulation S-K. As noted on page 5 of the Form 10-K, royalty interests expire upon the expiration of the oil and gas lease, mineral interests are perpetual real property rights, and overriding royalty interests that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest and, therefore, are typically subject to expiration upon the expiration or termination of the oil and gas lease.

Drilling Results, page 11

4. Please expand the disclosure of your present activities to additionally provide the total number of net wells that were in the process of being drilled, completed, dewatering or waiting on infrastructure at the end of December 31, 2021. Refer to Item 1206 of Regulation S-K.

Response: The Company respectfully directs the Staff’s attention to page 9 of the Form 10-K where the Company notes that it does not own any working interests in any wells. The Company respectfully advises the Staff that, accordingly, it does not own any net wells as such term is defined by Item 1208(c) of Regulation S-K. Page 11 of the Form 10-K discloses the number of wells that the operators associated with our interests had in the process of drilling, completing or dewatering or that are shut-in awaiting infrastructure. Nevertheless, in future filings, the Company will express an implied number of net wells based on its net revenue interest per well. As an example, applying such revised disclosure to the Form 10-K, the Company would revise the disclosure on page 10 of the Form 10-K as follows:

As of December 31, 2021, our operators associated with Royalties had 81 gross / 0.61 net wells in the process of drilling, completing, or dewatering or shut-in awaiting infrastructure that are not reflected in the table below.

5. Please expand the disclosure of your drilling activities to additionally provide the total number of net productive development wells drilled and completed during each of the last three fiscal years and clarify the number of gross and net productive and/or dry exploratory wells, if any, drilled during each of the last three fiscal years. Refer to Item 1205 of Regulation S-K.

April 14, 2022

Page 6

Response: The Company respectfully advises the Staff that, as noted in the response to Comment #4 above, the Company does not own any working interests in any wells. Because it does not own working interests, the Company has not been responsible for, nor has it contributed to, any exploratory or development activities on its acreage during the last three fiscal years. The Company has disclosed on page 11 of the Form 10-K the number of net productive and dry development wells completed on the acreage in which the Company holds an interest for each of the last three fiscal years. The Company respectfully advises the Staff that it does not separately track the number of exploratory wells drilled on its acreage and, as such, the Company cannot present the requested information.

Notes to Consolidated Financial Statements

Note 17 Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Oil and Natural Gas Reserves, page F-22

6. Please expand the disclosure of the net quantities of proved developed and undeveloped reserves, by individual product type, as of the beginning of the initial period in the reserves reconciliation, e.g. December 31, 2018. Refer to FASB ASC 932-235-50-4.

Response: The Company acknowledges the Staff’s comment and respectfully advises the Staff that it will include additional disclosure in the Company’s annual report on Form 10-K for the year ended December 31, 2022 regarding the net quantities of proved developed and undeveloped reserves, by individual product type, as of the beginning of the initial period in the reserves reconciliation. As an example, applying such revised disclosure to the Form 10-K, the Company would modify the table on page F-23 of the Form 10-K, in the form below:

							Natural Gas
	Oil			Natural Gas			Liquids			Total
	(MBbls)			(MMcf)			(MBbls)			(MBOE)
Proved Developed and Undeveloped Reserves:
As of December 31, 2018		15,212			56,185			3,163			27,740
Purchase of reserves in place		32			70			12			56
Extensions and discoveries		215			553			71			378
Revisions of previous estimates		(1,984	)		(6,950	)		(230	)		(3,373	)
Production		(879	)		(3,588	)		(297	)		(1,774	)
As of December 31, 2019		12,596			46,270			2,719			23,027
Purchase of reserves in place		62			62			—			72
Extensions and discoveries		34			797			12			179
Revisions of previous estimates		(2,114	)		4,935			(298	)		(1,590	)
Production		(836	)		(3,528	)		(247	)		(1,671	)
As of December 31, 2020		9,742			48,536			2,186			20,017
Purchase of reserves in place		22			34			5			33
Extensions and discoveries		326			1,777			122			744
Revisions of previous estimates		(1,571	)		(3,109	)		159			(1,930	)
Production		(756	)		(3,801	)		(230	)		(1,620	)
As of December 31, 2021		7,763			43,437			2,242			17,245
Proved Developed Reserves
December 31, 2018		3,857			18,700			1,293			8,267
December 31, 2019		3,900			18,016			1,230			8,133
December 31, 2020		3,291			19,755			1,164			7,747
December 31, 2021		2,738			19,098			1,183			7,104
Proved Undeveloped Reserves:
December 31, 2018		11,355			37,485			1,870			19,473
December 31, 2019		8,696			28,254			1,489			14,894
December 31, 2020		6,451			28,781			1,022			12,270
December 31, 2021		5,025			24,339			1,059			10,141

April 14, 2022

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7. The discussion of the changes that occurred in total proved reserves indicates the line item entry representing negative revisions in the previous estimates of reserves is the result of an aggregation of several separate and unrelated factors, e.g. changes in development timing and lower commodity prices. We also note the explanation for the negative revisions of the previous estimates of 1,930 MBoe for the year ended December 31, 2021 resulted primarily due to a change in development timing; however, this figure appears to be inconsistent with the disclose on page 9 indicating negative revisions of 1,569 MBoe in proved undeveloped reserves due to a change in development timing.

Please expand your disclosure to reconcile the overall change in the line item by separately identifying and quantifying the net amount attributable to each factor, including offsetting factors, so that the change in net reserves between periods is fully explained. In particular, disclosure relating to revisions in previous estimates should identify such underlying factors as changes caused by commodity prices, costs, ownership interests, well performance, improved recovery or changes resulting from the removal of proved undeveloped locations due to changes in a previously adopted development plan. Refer to FASB ASC 932-235-50-5.

Response: The Company acknowledges the Staff’s comment and respectfully advises the Staff that the negative revisions of 1,569 MBoe disclosed on page 9 of the Form 10-K relate to revisions in proved undeveloped reserves only as a result of the removal of certain locations to the drilling schedule as part of a revised development plan. The negative revisions of 1,930 MBoe disclosed on page F-23 of the Form 10-K, in contrast, also include revisions to proved developed producing and proved developed non-producing reserves.

The Company advises the Staff that it will include in the supplemental information on oil and natural gas operations note to the Company’s financial statements to be included in the Company’s annual report on Form 10-K for the year ended December 31, 2022 the revisions to each of the proved undeveloped reserves, proved developed producing reserves and proved-developed non-producing reserves in order to provide additional clarity to investors as to its reserve revisions. For example, the 1,930 MBoe reduction in proved developed and proved undeveloped reserves resulted from (i) an approximate 361 MBoe reduction in proved developed reserves, primarily due to actual production from our wells exceeding the conversion of proved undeveloped reserves to proved producing reserves, and (ii) an approximate 1,569 MBoe reduction in proved undeveloped reserves as a result of the removal of certain locations to the drilling schedule as part of a revised development plan, as described on page 9 of the Form 10-K. The Company will also further explain the changes in the line item by separately identifying and quantifying the net amount of the change attributable to each factor.

Item 2.02 Form 8-K dated March 10, 2022

Non-GAAP Financial Measures, page 8

8. We note your presentation of Adjusted EBITDA and Pro-Forma Free Cash Flow and your statement on page 8 that management also uses these measures “to evaluate cash flow available to pay dividends to our common shareholders.” Tell us how you considered reconciling these measures to Net cash provided by operating activities as the most directly comparable GAAP-basis measure per Item 10(e)(1)(i)(B) of Regulation S-K. Please also tell us how you considered Questions 102.05 and 103.02 of the Compliance & Disclosure Interpretations for Non-GAAP Financial Measures as it relates to the presentation of these measures on a per share basis.

April 14, 2022

Page 8

Response: The Company acknowledges the Staff’s comment and respectfully advises the Staff that it believes that Adjusted EBITDA is a performance measure as it is used to evaluate the performance of the Company and compare its results of operations period to period without regard to financing methods or capital structure. In future disclosures of Adjusted EBITDA, the Company will clarify its description of Adjusted EBITDA as shown below and will continue to reconcile Adjusted EBITDA to net income, the most directly comparable GAAP-basis measure. In future disclosures of Pro-Forma Free Cash Flow, the Company will amend its description of such metric and include a reconciliation of such metric to Net cash provided by operating activities, the most directly comparable GAAP-basis measure, as set forth below. The Company also advises the Staff that it will not present any liquidity measure on a per share basis in future filings.

Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders, and rating agencies. We believe Adjusted EBITDA is useful because it allows us to evaluate our performance and compare the results of our operations period to period without regard to our financing methods or capital structure. We define Adjusted EBITDA as net income before interest expense, net, depletion and depreciation expense, provision for income taxes, change in fair value of warrant liability, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and other charges that are not reflective of our ongoing operations.

Pro-forma Free Cash Flow is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders, and rating agencies. We believe Pro-forma Free Cash Flow is useful to evaluate whether we are generating sufficient cash flow to service our indebtedness obligations and maintain our operations. We define Pro-forma Free Cash Flow as Adjusted EBITDA less interest expense and pro-forma cash taxes.

Adjusted EBITDA and Pro-forma Free Cash Flow are not measures of net income or cash flow from operating activities as determined by GAAP. We exclude the items listed above from net income and net cash provided by operating activities in calculating Adjusted EBITDA and Pro-forma Free Cash Flow because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA and Pro-forma Free Cash Flow are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA or Pro-forma Free Cash Flow. Adjusted EBITDA and Pro-forma Free Cash Flow should not be considered an alternative to, or more meaningful than, net income, royalty income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Our computations of Adjusted EBITDA and Pro-forma Free Cash Flow may not be comparable to other similarly titled measures of other companies.

April 14, 2022

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Reconciliation of Net Income to Adjusted EBITDA and Pro-forma Free Cash Flow to cash flows from operating activities for the periods indicated (in thousands):

	Three Months			Year
	Ended			Ended
	December 31, 2021			December 31, 2021
Net income	$	9,251		$	27,492
Interest expense		473			1,924
Depletion and depreciation		4,177			15,338
Share-based compensation		417			232
Unrealized gain on commodity derivatives		(2,577	)		(694	)
Change in fair value of warrant liability		(1,207	)		(467	)
Income tax expense		1,035			4,059
One-time transaction expenses		2,163			2,163
Adjusted EBITDA	$	13,732		$	50,047
Interest expense		(473	)		(1,924	)
Pro-forma cash taxes		(210	)		(615	)
Pro-forma free cash flow	$	13,049		$	47,508
Changes in operating assets and liabilities		(1,915	)		(3,747	)
Other non-cash adjustments		396			1,387
One-time transaction expenses		(2,163	)		(2,163	)
Net cash provided by operating activities	$	9,367		$	42,985

9. Please revise to provide a reconciliation of the measures of Adjusted EBITDA for full year 2021 consistent with Item 10(e)(1)(i)(B) of Regulation S-K.

Response: The Company acknowledges the Staff’s comment and directs the Staff’s attention to the Company’s response to comment #8 above, in which the Company has set forth the requested reconciliation. The Company will include such reconciliation alongside future disclosure of Adjusted EBITDA.

10. We note your presentation of Pro-forma Free Cash Flow and Net cash available for distribution as non-GAAP measures. As these measures appear to be calculated in the same manner, please explain whether there are any substantive differences and why both are presented. With your response, tell us how you considered Question 102.07 of the Compliance & Disclosure Interpretations for Non-GAAP Financial Measures which states that free cash flow is typically calculated as cash flows from operating activities less capital expenditures and why the measure you present is characterized as pro forma.

Response: The Company acknowledges the Staff’s comment and respectfully advises the Staff that Pro-forma Free Cash Flow and Net cash available for distributions are the same measure. The Company will only present Pro-forma Free Cash Flow in its future disclosures. The Company also advises the Staff that it presents free cash flow on a pro forma basis in order to reflect the estimated cash taxes on net income inclusive of non-controlling interests.

11. Revise your statement that management uses Pro-forma Free Cash Flow to evaluate cash flow available to pay dividends to your common shareholders as Question 102.07 of the Compliance & Disclosure Interpretations for Non-GAAP Financial Measures states that free cash flow should not be used to imply it represents the residual cash flow available for discretionary expenditures.

April 14, 2022

Page 10

Response: The Company acknowledges the Staff’s comment and directs the Staff’s attention to its response to comment #8 above, in which the Company has set forth revised disclosure regarding the manners in which the Company’s management uses the Pro-forma Free Cash Flow metric to evaluate whether the Company is generating sufficient cash flow to service it its indebtedness obligations and maintain its operations. The Company will disclose such revised uses alongside future disclosure of the Pro-forma Free Cash Flow metric and will not state that the Company uses the metric in its evaluation of cash available for dividends in such future disclosure.

12. It appears that Pro-forma Free Cash Flow excluding expenses associated with the Desert Peak transaction is a non-GAAP measure. Revise to provide disclosure consistent with Item 10(e)(1)(i) of Regulation S-K.

Response: The Company acknowledges the Staff’s comment and respectfully advises the Staff that it will not present the measure referenced in the Staff’s comment in its future filings. The Company directs the Staff’s attention to its response to comment #8 above, in which the Company has set forth a revised definition of Adjusted EBITDA that includes the one-time expenses associated with the transaction with Desert Peak that were excluded from the metric referenced in the Staff’s comment.

*********

Any comments or questions regarding the foregoing should be directed to the undersigned at +1.713.546.7409. Thank you in advance for your cooperation in connection with this matter.

Very truly yours,

/s/ Nick S. Dhesi

Nick S. Dhesi

of LATHAM & WATKINS LLP

Enclosures

cc: (via e-mail)

William N. Finnegan IV, Latham & Watkins LLP

Ryan J. Lynch, Latham & Watkins LLP

Jeffrey F. Brotman, Falcon Minerals Corporation