Significant Accounting Policies

Emerging Growth Company Status

As a company with less than $1.07 billion in revenues during its last fiscal year, Brigham Minerals qualifies as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements.

Brigham Minerals will remain an “emerging growth company” until as late as the last day of Brigham Minerals’ 2023 fiscal year, or until the earliest of (i) the last day of the fiscal year in which Brigham Minerals has $1.07 billion or more in annual revenues; (ii) the date on which Brigham Minerals becomes a “large accelerated filer” (the fiscal year-end on which the total market value of Brigham Minerals’ common equity securities held by non-affiliates is $700 million or more as of June 30); (iii) the date on which Brigham Minerals issues more than $1.0 billion of non-convertible debt over a three-year period.

As a result of Brigham Minerals’ election to avail itself of certain provisions of the JOBS Act, the information that Brigham Minerals provides may be different than the information provided by other public companies.

Use of Estimates

The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the consolidated and combined financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively.

The accompanying consolidated and combined financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGLs reserves that are the basis for the calculations of depreciation, depletion, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Brigham Minerals’ reserve estimates are audited by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of derivative instruments, share-based compensation and revenue accruals.

Cash and Cash Equivalents

Brigham Minerals considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash

Restricted cash includes cash that is contractually restricted for its use through an agreement with a non-related party.

In 2019, the Company adopted ASU 2016-18, Statement of Cash Flows, which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. The ASU requires entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows.

The adoption resulted in an increase in reported investing cash flow of $0.5 million for the year ended December 31, 2018 with a corresponding increase to the reported end of period cash balances. The December 31, 2018 accompanying statement of cash flow that was adjusted as a result of adoption of ASU 2016-18 is summarized below:



	Years Ended December 31,
	2018			2018
(In thousands)	As reported			As adjusted
Changes in restricted cash held in escrow for acquisitions	$	(474	)	$	—
Net cash provided by (used in) investing activities	(195,742		)	(195,268		)

Increase in cash, cash equivalents and restricted cash	$	25,099		$	25,573
Cash, cash equivalents and restricted cash, beginning of period	6,886			6,886
Cash, cash equivalents and restricted cash end of period	31,985			32,459

Accounts Receivables

Receivables consist of royalty income due from operators for oil and gas sales to purchasers. Those purchasers remit payment for production to the operator of our properties and the operator, in turn, remits payment to us. Receivables from third parties for which we did not receive actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. Volume estimates for wells with available historical actual data are based upon (i) the historical actual data for the months the data is available, or (ii) engineering estimates for the months the historical actual data is not available. We do not recognize revenues for wells with no historical actual data because we cannot conclude that it is probable that a significant revenue reversal will not occur in future periods. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.

Brigham Minerals routinely reviews outstanding balances, assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. We recorded an allowance for doubtful accounts of $0.6 million and $0.4 million for the year ended December 31, 2019 and December 31, 2018, which was included in general and administrative expenses.

At December 31, 2019 and 2018, accounts receivable was comprised of the following:



	December 31,
(In thousands)	2019			2018
Oil and gas sales	$	27,888		$	19,769
Allowance for doubtful accounts	(556		)	(382		)
Other	2,959			1,308
Total accounts receivables	$	30,291		$	20,695

Concentration of Credit Risk and Significant Customers

Financial instruments that potentially subject Brigham Minerals to concentrations of credit risk consist of cash, accounts receivable, commodity derivative financial instruments and its prior revolving credit facility. Cash and cash equivalents are held in a few financial institutions in amounts that may, at times, exceed federally insured limits. However, no losses have been incurred and management believes that counterparty risks are minimal based on the reputation and history of the institutions selected. Accounts receivable are concentrated among operators and purchasers engaged in the energy industry within the United States. Management periodically assesses the financial condition of these entities and institutions and considers any possible credit risk to be minimal. Concentrations of oil and gas sales to significant customers (operators) are presented in the table below.



	For the year ended December 31,
	2019		2018		2017
Occidental Petroleum Corp.	16	%	15	%	—
Continental Resources, Inc.	12	%	10	%	10	%
XTO Energy, Inc.	10	%	—		—
Noble Energy, Inc.	5	%	9	%	13	%

Management does not believe that the loss of any customer would have a long-term material adverse effect on our financial position or the results of operations.

Investments in Equity Securities

In January 2019, the Company adopted ASU 2016-01, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. The ASU changes to the current GAAP model primarily affects the accounting for equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. Under the new standard, all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) will generally be measured at fair value through earnings. There will no longer be an available-for-sale classification (changes in fair value reported in other comprehensive income) for equity securities with readily determinable fair values.

Prior to January 2019, Brigham Minerals classified its equity securities as available-for-sale, and as such, they were carried at fair value. Changes in fair value of available-for-sale securities were reported as a component of other comprehensive income. Losses were recognized within the consolidated and combined statement of operations when a decline in value is determined to be other-than-temporary. Brigham Minerals used the average cost method to determine the realized gain or loss for each sale or distribution of available-for-sale securities.

Financial Instruments

Brigham Minerals’ financial instruments consist of cash and cash equivalents, receivables, payables, derivative assets and liabilities, investments in equity securities and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The equity securities are publicly traded and are valued using quoted market prices.

The fair values of Brigham Minerals’ derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments.

The carrying amount of long-term debt associated with borrowings outstanding under Brigham Minerals’ revolving credit facility approximates fair value as borrowings bear interest at variable market rates. See “Note 5.—Derivative Instruments,” “Note 6.—Fair Value Measurements” and “Note 7.—Long-Term Debt.”

Derivative Instruments

In the normal course of business, Brigham Minerals is exposed to certain risks, including changes in the prices of oil, natural gas and NGLs and interest rates. Brigham Minerals has occasionally entered into derivative contracts to manage its exposure to these risks. Brigham Minerals’ risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. Brigham Minerals does not enter into derivative instruments for speculative purposes. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated and combined balance sheets. Brigham Minerals does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated and combined statements of operations within (loss) gain on derivative instruments, net.

Oil and Gas Properties

Brigham Minerals uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition costs incurred for the purpose of acquiring mineral and royalty interests and certain related employee costs are capitalized into a full cost pool. Costs associated with general corporate activities are expensed in the period incurred.

Capitalized costs are amortized using the units-of-production method. Under this method, the provision for depletion is calculated by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base by net equivalent proved reserves at the beginning of the period.

Costs associated with unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated properties are reviewed periodically to determine whether the costs incurred should be reclassified to the full cost pool and subjected to amortization. The costs associated with unevaluated properties primarily consist of acquisition costs and capitalized general and administrative costs. Unevaluated properties are assessed for impairment on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: expectation of future drilling activity; past drilling results and activity; geological and geophysical evaluations; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative acquisition costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. There was no impairment recorded for unevaluated properties in 2019, 2018 and 2017.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustments would significantly alter the relationship between capitalized costs and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.

Natural gas volumes are converted to barrels of oil equivalent (Boe) at the rate of six thousand cubic feet (Mcf) of natural gas to one barrel (Bbl) of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depletion, may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties (the ceiling limitation). A ceiling limitation is calculated at each reporting period. If total capitalized costs, net of accumulated DD&A are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a noncash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using the 12-month first day of the month oil and natural gas average prices, as adjusted for basis or location differentials, held constant over the life of the reserves (net wellhead prices). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas.

As of December 31, 2019, 2018 and 2017, the full cost ceiling value of our reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the twelve months ended December 31, 2019, 2018 and 2017 of $55.65, $65.66, and $51.34, respectively, per barrel for oil, adjusted by area for energy content, transportation fees and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the twelve months ended December 31, 2019, 2018 and 2017 of $2.60, $3.12, and $2.99, respectively, per MMBtu for natural gas, adjusted by area for energy content, transportation fees and regional price differentials. Using these prices, the net book value of oil and natural gas was below the ceiling limitation and no write-off was necessary.

Share-Based Compensation

Brigham Minerals accounts for its share-based compensation including grants of the Incentive Units, restricted stock awards, time-based restricted stock units and performance-based stock units in the consolidated and combined statements of operations based on their estimated fair values at grant date. Brigham Minerals uses a Monte Carlo simulation to determine the fair value of performance-based stock units. Brigham Minerals recognizes expense on a straight-line basis over the vesting period of the respective grant, which is generally the requisite service period. Brigham Minerals capitalizes a portion of the share-based compensation cost to oil and gas properties on the consolidated and combined balance sheets. Share-based compensation expense is included in general and administrative expenses in Brigham Minerals’ consolidated and combined statements of operations included within this Annual Report. There was approximately $19.3 million of unamortized compensation expense relating to outstanding awards at December 31, 2019, a portion of which will be capitalized. The unrecognized share-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards. Brigham Minerals accounts for forfeitures as they occur.

Earnings Per Share

Brigham Minerals uses the “if-converted” method to determine the potential dilutive effect of its Class B common stock and the treasury stock method to determine the potential dilutive effect of outstanding Incentive Units, RSAs, RSUs, and PSUs.

Employee Benefit Plan

We sponsor a 401(k) tax-deferred savings plan for our employees. We match 100% of each employee’s contributions, up to 6% of the employee’s total compensation. Brigham Resources may also contribute additional amounts at its discretion. Brigham Resources contributed $0.3 million, $0.2 million and $0.1 million, to the 401(k) plan for each of the years ended December 31, 2019, 2018, and 2017.

Income Taxes

Brigham Minerals accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Brigham Minerals periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, Brigham Minerals considers all available positive and negative evidence and makes certain assumptions. Brigham Minerals considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends and its outlook for future years.

Temporary Equity

Brigham Minerals accounts for the Original Owners’ 40.2% interest in Brigham LLC as temporary equity as a result of certain redemption rights held by the Original Owners as discussed in “Note 9.—Temporary Equity.” As such, the Company adjusts temporary equity to its maximum redemption amount at the balance sheet date, if higher than the carrying amount. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) of Class A shares at the end of the reporting period. Changes in the redemption value are recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to additional paid-in capital.

Revenue from Contracts with Customers

On December 31, 2019, the Company adopted Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, ("ASC 606") using the modified retrospective approach, which only applied to contracts that were in effect as of the date of adoption. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and did not impact the Company’s previously reported results of operations, nor its ongoing consolidated and combined balance sheets, statements of cash flow or statements of changes in shareholders' and members' equity. Overall, there were no material changes in the timing of the satisfaction of the Company’s performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP.

Oil and natural gas sales

Oil, natural gas and NGLs sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Company’s oil, natural gas and NGL sales are made under contracts with customers (operators). The performance obligations for the Company’s contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The Company typically receives payment for oil, natural gas and NGL sales within 60 days of the month of delivery, which can extend up to 9 months after initial production from the well. The Company’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, Brigham Minerals recognizes revenue from oil and natural gas sales using the allocation exception for variable consideration in ASC 606.

Lease bonus and other income

Brigham Minerals also earns revenue from lease bonuses, delay rentals, and right-of-way payments. We generate lease bonus revenue by leasing our mineral interests to exploration and production companies. A lease agreement represents our contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants us a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. The Company recognizes lease bonus revenues when the lease agreement has been executed, payment has been received, and the Company has no further obligation to refund the payment. At the time Brigham Minerals executes the lease agreement, Brigham Minerals expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that Brigham Minerals has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. Brigham Minerals also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and we have no further obligation to refund the payment. Right-of-way payments are recorded by the Company when the agreement has been executed, payment is determined to be collectable, and the Company has no further obligation to refund the payment.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

Brigham Minerals’ right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of our royalty income contracts.

Lease bonus and other income

Given that Brigham Minerals does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, Brigham Minerals does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Prior-period performance obligations

Brigham Minerals records revenue in the month production is delivered to the purchaser. As a non-operator, Brigham Minerals has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, Brigham Minerals is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated and combined balance sheets. The difference between the Company’s estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the years ended December 31, 2019, 2018 and 2017, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

Debt Issuance Cost

Other assets include capitalized debt issuance costs of $1.2 million, net of accumulated amortization of $0.2 million as of December 31, 2019. As of December 31, 2018, capitalized debt issuance costs of $4.3 million, net of accumulated amortization of $0.3 million, was included in long-term debt on the consolidated and combined balance sheets. Debt issuance costs were incurred in connection with establishing and amending credit facilities for Brigham Resources and are amortized over the term of the credit facilities using the straight-line method, which approximates the effective interest rate method. Amortization expense for debt issue costs was $0.4 million, $0.7 million and $0.1 million for the years ended December 31, 2019, 2018, and 2017. On July 27, 2018, the prior revolving credit facility was terminated and replaced with a new term loan facility. See further discussion in "Note 7.—Long-Term Debt" in our consolidated and combined financial statements.

Recently Issued Accounting Standards Not Yet Adopted

Brigham Minerals’ status as an emerging growth company under Section 107 of the JOBS Act permits it to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. Brigham Minerals is choosing to take advantage of this extended transition period and, as a result, it will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

In February 2016, the FASB issued ASU 2016-02, Leases, which requires all leasing arrangements to be presented in the balance sheet as liabilities along with a corresponding asset. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. The ASU will replace most existing lease guidance in GAAP when it becomes effective. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11 Leases (Topic 842): Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The new standard becomes effective for us during the fiscal year ending December 31, 2021 and interim periods within the fiscal year ending December 31, 2022 and early adoption is permitted. We are currently evaluating the impact that the adoption of this update will have on our consolidated and combined financial statements and related disclosures.