Document


CAWLEY, GILLESPIE & ASSOCIATES, INC.

	PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 1900
AUSTIN, TEXAS 78729-1107	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817-336-2461	713-651-9944
	www,cgaus.com

	January 27, 2022


						Re:			Audit Summary
									Brigham Minerals, LLC Interests
									Various Oil & Gas Properties in CO, WY,
									OK, MT, ND, TX and NM
									As of December 31, 2021

									Pursuant to the Guidelines of the
									Securities and Exchange Commission for
									Reporting Corporate Reserves and
									Future Net Revenue

As requested, this letter was prepared on January 27, 2022 for Brigham Minerals, LLC (“Brigham”) for the purpose of submitting our audit of your total proved, probable and possible reserves and forecasts of economics attributable to the above-captioned interests. We audited 100% of Brigham reserves, which are made up of certain Anadarko, Delaware, Denver-Julesburg (“DJ”), Midland and Williston Basin oil and gas properties located in the following states: Colorado, Wyoming, Oklahoma, Montana, North Dakota, Texas and New Mexico. This audit, effective December 31, 2021 and completed January 27, 2022, was prepared for the purpose of public disclosure by Brigham Minerals, LLC in filings made with the U.S. Securities and Exchange Commission (“SEC”) in accordance with the disclosure requirements set forth in SEC regulations. This evaluation was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the values prepared by Brigham by reserve category is presented below:


		Proved	Proved
		Developed	Developed	Proved	Total	Probable	Possible
		Producing	Non-Prod	Undeveloped	Proved	Undeveloped	Undeveloped
Net Reserves
Oil	- Mbbl	9,867.5	3,280.8	3,761.8	16,910.1	22,012.7	13,653.2
Gas	- MMcf	45,362.9	11,008.8	9,800.3	66,172.0	94,100.0	39,254.4
NGL	- Mbbl	4,857.0	1,510.1	1,499.2	7,866.3	10,697.8	5,800.0
MBOE/6	- Mbbl	22,285.0	6,625.7	6,894.4	35,805.1	48,393.8	25,995.6
Future Revenue
Oil	- M$	635,325.0	211,617.9	242,992.5	1,089,935.6	1,421,511.9	883,113.9
Gas	- M$	149,136.0	34,339.1	29,765.2	213,240.3	327,364.8	126,860.4
NGL	- M$	129,055.0	40,647.0	39,906.4	209,608.4	286,509.6	155,544.5
Severance Taxes	- M$	52,467.3	15,363.9	17,356.0	85,187.3	115,705.6	63,354.7
Ad Valorem Taxes	- M$	14,522.7	5,699.1	4,440.1	24,661.9	26,085.1	18,546.7
Operating Expenses	- M$	0.0	0.0	0.0	0.0	0.0	0.0
Investments	- M$	0.0	0.0	0.0	0.0	0.0	0.0
Future Net Cash Flow	- M$	846,526.2	265,541.1	290,867.9	1,402,935.3	1,893,595.5	1,083,617.5

Discounted @ 10%	- M$	446,864.6	160,314.3	147,624.3	754,802.8	582,712.9	192,243.1
(Present Worth)

Proved Developed (“PD”) reserves are the summation of the Proved Developed Producing (“PDP”) and Proved Developed Non-Producing (“PDNP”) reserve estimates. Proved Developed reserves were estimated at 13,148.3 Mbbl oil, 56,371.7 MMcf gas and 6,367.1 Mbbl NGLs (or 28,910.7 MBOE/6). Of the Proved Developed reserves, 22,285.0 MBOE/6 were attributed to producing zones in existing wells and 6,625.7 MBOE/6 were attributed to zones in existing wells not producing. Probable Undeveloped (“PROB”) and Possible Undeveloped (“POSS”) reserves and values are shown in the prior table and represent 100% of the Probable and Possible reserves reported herein, as no Probable Developed or Possible Developed reserves were audited in this report.

Future revenue was calculated prior to deducting state production taxes and ad valorem taxes; however, future net cash flow was calculated after deducting these taxes, future capital costs and operating expenses, but before federal income taxes. Future net cash flow has been discounted at an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine its “present worth”. Present worth indicates the time value of money and should not be construed to represent an estimate of the fair market value of the properties.

The oil reserves include oil and condensate. Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. BOE (barrels of oil equivalent) is expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels.

The base SEC oil and gas prices calculated for December 31, 2021 were $66.56 per bbl and $3.64 per MMBtu respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of each first-day-of-the-month price 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 2021 and the base gas price is based upon Henry Hub spot prices (EIA) during 2021.

Adjustments to oil and gas prices were applied based upon calculations derived from regional averages or provided by Brigham. Oil price differentials may include adjustments for basis differential, transportation and/or crude quality corrections. Gas price differentials include adjustments for basis differential and the BTU heating value of the gas. Gas shrinkage includes compression and processing losses, flaring and contract allocations.

After these pricing adjustments, the net realized prices over the life of the proved properties was estimated to be $64.455 per bbl for oil, $3.223 per MCF for gas and $26.646 per bbl for NGLs. All economic factors were held constant in accordance with SEC guidelines.

Expenses: Routine lease operating expenses (“LOE”) were applied to all wells, and were derived from regional averages and operator assumptions. Although LOE is not paid by the mineral owner, it was applied in this evaluation to assist in proper economic limit determinations. Different LOE averages were applied to vertical and horizontal wells, although the vertical wells were not evaluated for this report. Expenses were not escalated in this report, as per SEC guidelines.

Investments: Drilling and completion investments (“future development costs”) were estimated by lateral length, based on the drilling unit acreage for each basin. Future development costs are not paid by the mineral owner and therefore not included in this evaluation. However, future development costs was used to assist in proper commerciality determinations of each new drill. Wells that did not meet minimum economic requirements were dropped from the analysis. Investments were not escalated in this report as per SEC guidelines.

The methods employed in estimating reserves are industry standards and appropriate for this analysis. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Monthly production data from the various state commission web sites and other public data outlets were used in this evaluation, with data typically updated through October 2021.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and undeveloped reserves for Brigham’s properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

New drills on the Brigham acreage include planned (AFE’d) drills, wells currently drilling, permitted wells and/or wells expected to be drilled based on operator information or regional activity. For each new drill, a reserve category of PDNP, PUD, PROB, or POSS was assigned based upon the proximity to production and geologic control. Reserves for each location were assigned based on offset analogy to production, with preference given to modern completions.

The drill schedules for each basin were determined based on spud and completion rates, proximity to drilling rig activity, well status, well reserve category, and gross estimated reserves within each basin. First, known completed and spud locations were developed in chronological order based on state filings or publicly sourced completion data. The development schedule for these locations begins before the effective date of this report to more appropriately estimate the turn-in-line rate of these locations due to production data lag. Second, spud locations with unknown completion status were scheduled based on the historical spud to completion time within each basin. Third, permitted locations, without development data, were scheduled in chronological order by filing date. Last, undeveloped wells were scheduled in order of decreasing gross estimated reserves, with PUD properties scheduled first, followed by PROB and then POSS properties. The drill schedules applied for each basin were found to be reasonable and appropriate for the purposes of this report

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This audit includes 997 commercial proved undeveloped locations, targeting various productive reservior in the seven (7) state outlined previously. Each of these drilling locations proposed as part of Brigham’s development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the operators of these drills have indicated they have reasonably certain intent to complete this development plan within the next five (5) years. Furthermore, Brigham and the other operators have demonstrated through their actions that they have the proper company staffing, financial backing and prior development success to ensure this development plan will be fully executed.

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications.

such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not 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 have not been included in this evaluation.

It should be understood that our audit and the development of our reserves forecasts do not constitute a complete reserve study of the oil and gas properties of Brigham. Furthermore, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

Please be advised that, based upon the foregoing, in our opinion the above-described estimates of Brigham’s Total Proved, Probable and Possible reserves and discounted cash flows are, in the aggregate and independently, reasonable within (+ or -) 5%, which supersedes the established audit tolerance guidelines of (+ or –) 10%. Also, these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and as mandated by the SEC.

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 60 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 Brigham Minerals, 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 utilized in the preparation of these estimates are available in our office.