Acquisitions and Divestitures

In 2019, Brigham Minerals adopted ASU 2017-01, Clarifying the Definition of a Business, using a prospective approach. This guidance assists in determining whether a transaction should be accounted for as an acquisition of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. The adoption of the new standard did not have a material impact on the consolidated and combined financial statements.

During the years ended December 31, 2019 and 2018, Brigham Minerals entered into a number of individually insignificant acquisitions of mineral and royalty interests from various sellers in Texas, Oklahoma, Colorado, New Mexico, and North Dakota, as reflected in the table below. The change in the oil and natural gas property balance is comprised of payments for acquisitions of minerals, land brokerage costs and capitalized general and administrative expenses that were funded with borrowings under its Owl Rock credit facility, our revolving credit facility and proceeds from the IPO.



	Assets Acquired				Cash Consideration Paid
(In thousands)	Evaluated		Unevaluated		Cash Consideration Paid
Twelve months ended December 31, 2019	$	140,025	$	78,093	$	218,118
Twelve months ended December 31, 2018	$	115,589	$	81,367	$	196,956

In August 2017, Brigham Minerals acquired certain mineral and royalty interests in the Delaware Basin for $29.2 million. Brigham Minerals funded the acquisition with capital contributions. The allocation of the purchase price was $20.5 million to unevaluated properties and $8.7 million to evaluated properties.

In addition, during 2017, Brigham Minerals entered into a number of individually insignificant acquisitions. The change in the oil and natural gas property balance is comprised of individually insignificant payments for acquisitions of minerals, land brokerage costs and capitalized general and administrative capital expenditures.

On February 28, 2017, Brigham Operating and Brigham Resources Midstream, LLC, wholly owned subsidiaries of Brigham Resources, closed on the sale of substantially all of their Southern Delaware Basin leasehold and related assets, including certain mineral and royalty interests owned by Brigham Resources, to a third-party public entity. The proceeds for mineral and royalty interests represented $156.7 million of the net adjusted sales price and consisted of cash of $111.1 million and shares valued at $45.6 million The mineral and royalty interests sold represented approximately 12% in aggregate of Brigham Minerals’ total proved reserves as of December 31, 2016. As a result of the sale, the relationship between capitalized costs and proved reserves was altered significantly and Brigham Minerals recorded a gain of $94.6 million.

Reserve and Related Financial Data (SMOG) -Unaudited

Oil and Natural Gas Reserves

Proved reserves represent quantities of oil, natural gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

The reserves at December 31, 2019 and December 31, 2018 presented below were audited by CG&A and the reserves at December 31, 2017 presented below were prepared by CG&A. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in various fields in Texas, New Mexico, Oklahoma, Colorado, Wyoming, North Dakota, Montana and Pennsylvania. All of the proved reserves are located in the continental United States.



	Crude Oil (MBbl)		Natural Gas (Mmcf)		NGL (MBbl)		Total (MBoe)
Proved reserve quantities, December 31, 2016	7,174		22,991		2,356		13,363
Sales of minerals-in-place	(1,291	)	(815	)	(200	)	(1,627	)
Extensions and discoveries	1,548		6,012		709		3,259
Acquisitions	2,141		9,380		1,116		4,820
Revisions of previous estimates	(394	)	2,601		108		147
Production	(454	)	(1,768	)	(109	)	(858	)
Proved reserve quantities, December 31, 2017	8,724		38,401		3,980		19,104
Sales of minerals-in-place	—		—		—		—
Extensions and discoveries	1,765		5,285		562		3,208
Acquisitions	3,669		13,862		1,374		7,354
Revisions of previous estimates	(390	)	(3,245	)	(577	)	(1,508	)
Production	(777	)	(2,507	)	(222	)	(1,417	)
Proved reserve quantities, December 31, 2018	12,991		51,796		5,117		26,741
Sales of minerals-in-place	(182	)	(697	)	(110	)	(409	)
Extensions and discoveries	1,997		7,780		817		4,110
Acquisitions	4,256		13,053		1,218		7,651
Revisions of previous estimates	(586	)	(5,495	)	(797	)	(2,299	)
Production	(1,515	)	(4,707	)	(407	)	(2,706	)
Proved reserve quantities, December 31, 2019	16,961		61,730		5,838		33,088
Proved reserve quantities at December 31, 2019 attributable to temporary equity	6,812		24,792		2,345		13,289

Proved developed reserve quantities:
December 31, 2017	2,804		13,028		1,185		6,160
December 31, 2018	6,067		21,735		1,898		11,588
December 31, 2019	9,924		33,232		2,494		17,957
Proved developed reserves at December 31, 2019 attributable to temporary equity	3,986		13,346		1,002		7,212

Proved undeveloped reserve quantities:
December 31, 2017	5,920		25,373		2,795		12,944
December 31, 2018	6,924		30,061		3,219		15,153
December 31, 2019	7,037		28,498		3,344		15,131
Proved undeveloped reserves at December 31, 2019 attributable to temporary equity	2,826		11,445		1,343		6,077

Changes in proved reserves that occurred during 2019 were primarily due to:


•	the acquisition of additional mineral interests located in the Permian, Anadarko, DJ and Williston Basins in multiple transactions, which included 7,242 MBoe of additional proved reserves which is comprised of 7,651 MBoe of acquired proved reserves and divestiture of 409 MBoe of proved reserves within the year;


•	well additions extensions and discoveries of approximately 4,110 MBoe, as approximately 900 gross horizontal well locations were converted from probable, possible and contingent resources to proved, due to continuous activity and delineation of additional zones on our mineral and royalty interests; and


•	net volume revisions of approximately 2,299 MBoe. These revisions were comprised of 902 MBoe of negative revisions attributable to pricing as well as approximately 1,397 MBoe attributable to operator development timing, unit configuration and EUR adjustments to existing proved locations.

Changes in proved reserves that occurred during 2018 were primarily due to:


•	the acquisition of additional mineral and royalty interests located in the Permian, DJ, Anadarko and Williston Basins in multiple transactions, which included 7,354 MBoe of additional proved reserves;


•	well additions, extensions and discoveries of approximately 3,208 MBoe, as 555 gross horizontal well locations were converted from probable, possible and contingent resources to proved, due to continuous activity and delineation of additional zones on our mineral and royalty interests; and


•	net negative volume revisions of approximately 1,508 MBoe. These revisions were comprised of 536 MBoe of positive revisions attributable to pricing and were offset by negative revisions of 1,100 MBoe attributable to operator development timing as well as 944 MBoe of revisions associated with unit configuration and EUR adjustments to existing proved locations.

Changes in proved reserves that occurred during 2017 were primarily due to:


•	the acquisition of additional mineral and royalty interests located in the Permian, DJ, Anadarko and Williston Basins in multiple transactions, which included 4,820 MBoe of additional proved reserves;


•	well additions, extensions and discoveries of approximately 3,259 MBoe, as 854 horizontal well locations were converted from probable, possible and contingent resources to proved, due to continuous activity and delineation of additional zones on our mineral and royalty interests;


•	the divestiture of 1,627 MBoe through one sale of mineral and royalty interests located in the Permian Basin; and


•	positive volume revisions of approximately 2,581 MBoe attributable primarily to increased recovery in close proximity to our mineral and royalty interests, partially offset by negative revisions of approximately 2,434 MBoe, attributable primarily to operator development timing and revision of existing proved locations.

Standardized Measure of Discounted Future Net Cash Flows

Guidelines prescribed in FASB’s Accounting Standards Codification (“ASC”) Topic 932 Extractive Industries—Oil and Gas, have been followed for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil, natural gas and NGLs to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect Brigham Resources’ expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following summary sets forth the future net cash flows relating to proved oil and gas reserves based on

the standardized measure prescribed in ASC Topic 932:



	For the Year Ended December 31,
(In thousands)	2019			2018			2017
Future crude oil, natural gas, and NGL sales	$	1,042,118		$	1,049,141		$	595,874
Future severance tax and ad valorem taxes	(73,627		)	(70,248		)	(40,225		)
Future income tax expense	(143,599		)	(144,421		)	(1,151		)
Future net cash flows	824,892			834,472			554,498
10% annual discount	(359,258		)	(391,013		)	(238,030		)
Standardized measure of discounted future net cash flows	$	465,634		$	443,459		$	316,468
Standardized measure of discounted future net cash flows attributable to temporary equity	$	186,999		$	—		$	—

The following prices were used in the determination of standardized measure:



	For the Year Ended December 31,
	2019		2018		2017
Oil (per Bbl)	$	51.01	$	61.31	$	47.80
Natural gas (per Mcf)	1.51		2.51		2.74
NGLs (per Bbl)	14.39		23.98		18.56

These prices were based on the 12-month arithmetic average first-of-month West Texas Intermediate (“WTI”) price of oil and Henry Hub price of natural gas. The NGL pricing varied by basin at 13% to 30% of WTI. All prices have been adjusted for transportation, quality, basis differentials and post-production costs.

The principal sources of change in the standardized measure of discounted future net cash flows are:



	For the Year Ended December 31,
(In thousands)	2019			2018			2017
Standardized measure of discounted future net cash flows, beginning of the year	$	443,459		$	316,468		$	185,752
Changes in the year resulting from:
Sales, less production costs	(86,492		)	(52,278		)	(26,711		)
Revisions of previous quantity estimates	(41,539		)	(22,942		)	4,894
Extensions, discoveries, and other additions	69,057			71,668			56,511
Net change in prices and production costs	(99,660		)	71,770			30,565
Accretion of discount	51,949			31,713			18,612
Purchase of reserves in place	137,819			148,580			79,190
Divestitures of reserves in place	(5,783		)	—			(26,742		)
Net change in taxes	(5,739		)	(75,369		)	(298		)
Timing differences and other	2,563			(46,151		)	(5,305		)
Standardized measure of discounted future net cash flows, end of the year	$	465,634		$	443,459		$	316,468

Capitalized oil and natural gas costs

The aggregate amounts of costs capitalized for oil and natural gas producing activities and related aggregate amounts of accumulated depletion follow:



	For the Year Ended December 31,
(In thousands)	2019			2018			2017
Oil and gas properties, at cost, using full cost method of accounting:
Not subject to depletion	$	291,664		$	228,151		$	168,691
Subject to depletion	449,061			289,851			152,354
Total oil and gas properties, at cost	740,725			518,002			321,045
Less accumulated depreciation, depletion, and amortization	(61,103		)	(27,628		)	(14,210		)
Total oil and gas properties, net	$	679,622		$	490,374		$	306,835

Costs incurred in oil and natural gas activities

The following costs were incurred in oil and natural gas producing activities:



	For the Year Ended December 31,
(In thousands)	2019		2018		2017
Acquisition of properties
Unevaluated	$	78,093	$	59,460	$	50,224
Evaluated	140,025		137,496		51,862
Total	$	218,118	$	196,956	$	102,086