VIPER ENERGY, INC. The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto presented in this Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See " Item 1A. Risk Factors " and " Cautionary Statement Regarding Forward-Looking Statements ."
Overview
We are a publicly tradedDelaware limited partnership formed by Diamondback to own and acquire mineral and royalty interests in oil and natural gas properties primarily in thePermian Basin . We operate in one reportable segment.
As of
The following discussion includes a comparison of our results of operations, including changes in our operating income, and liquidity and capital resources for fiscal year 2021 and fiscal year 2020. A discussion of changes in our results of operations from fiscal year 2019 to fiscal year 2020 has been omitted from this report, but may be found in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year endedDecember 31 , 20 20 , filed with theSEC onFebruary 25, 2021 , and is incorporated by reference in this report from such prior Annual Report on Form 10-K.
2021 Transactions and Recent Developments
COVID-19 and Effects on Commodity Prices
In earlyMarch 2020 , oil prices dropped sharply and continued to decline, briefly reaching negative levels, as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken byOPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the COVID-19 pandemic. Demand for oil and natural gas increased during 2021, as many restrictions on conducting business implemented in response to the COVID-19 pandemic were lifted due to improved treatments and availability of vaccinations in theU.S. and globally. As a result, oil and natural gas market prices have improved during 2021 in response to the increase in demand. During 2021 and 2020, the posted price forWest Texas intermediate light sweet crude oil, or NYMEX WTI, has ranged from$(37.63) to$84.65 Bbl, and the NYMEX Henry Hub price of natural gas has ranged from$1.48 to$6.31 per MMBtu. OnJanuary 18, 2022 , the closing NYMEX WTI price for crude oil was$85.43 per Bbl and the closing NYMEX Henry Hub price of natural gas was$4.28 per MMBtu. The emergence of the Delta COVID-19 variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant, however, continued to contribute to economic and pricing volatility, as industry and market participants evaluated industry conditions and production outlook. Further, onJanuary 4, 2021 ,OPEC and its non-OPEC allies, known collectively as OPEC+, agreed to continue their program (commenced inAugust 2021 ) of gradual monthly output increases inFebruary 2022 , raising its output target by 400,000 Bbl per day, which move is expected to further boost oil supply in response to rising demand. In its report issued onFebruary 10, 2022 ,OPEC noted its expectation that world oil demand will rise by 4.15 million Bbls per day in 2022, as the global economy continues to post a strong recovery from the COVID-19 pandemic. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high inFebruary 2022 , we cannot predict any future volatility in commodity prices or demand for crude oil. Although demand for oil and natural gas and commodity prices have recently increased, Diamondback and certain of our other operators have kept production on our acreage relatively flat during 2021, using excess cash flow for debt repayment and/or return to their stockholders rather than expanding their drilling programs. Diamondback also indicated that it intends to continue exercising capital discipline and seeks to maintain its fourth quarter 2021 exit oil production flat in 2022. We cannot reasonably predict whether production levels will remain at current levels or the impact the full extent of the events above and subsequent recovery may have on our industry and our business. 31 -------------------------------------------------------------------------------- Table of Content Due to the improved commodity prices and industry conditions, based on the results of the quarterly ceiling tests, we were not required to record an impairment on our proved oil and natural gas interests during the year endedDecember 31, 2021 . If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows may be adversely impacted. Our business may also be adversely impacted by any pipeline capacity and storage constraints.
Acquisitions and Divestitures Update
Swallowtail Acquisition
OnOctober 1, 2021 , we completed the Swallowtail Acquisition for approximately 15.25 million of our common units and approximately$225.3 million in cash. The mineral and royalty interests acquired represent approximately 2,313 net royalty acres primarily in theNorthern Midland Basin , of which approximately 62% are operated by Diamondback. We funded the cash portion of the purchase price for the Swallowtail Acquisition through a combination of cash on hand and approximately$190.0 million of borrowings under theOperating Company's revolving credit facility. The Swallowtail Acquisition has an effective date ofAugust 1, 2021 . Other 2021 Acquisitions Additionally during the year endedDecember 31, 2021 , we acquired, from unrelated third party sellers, mineral and royalty interests representing 1,277 gross (392 net royalty) acres in thePermian Basin for an aggregate purchase price of approximately$55.1 million , after post-closing adjustments. We funded these acquisitions with cash on hand and borrowings under theOperating Company's revolving credit facility.
As a result of the Swallowtail Acquisition and other acquisitions, our footprint
of mineral and royalty interests increased to a total of 27,027 net royalty
acres at
Divestiture
In the first quarter of 2022, we divested 325 net royalty acres of third party operated acreage located entirely inUpton andReagan counties in theMidland Basin for an aggregate sales price of$29.3 million , subject to post-closing adjustments. Cash Distribution Update OnFebruary 16, 2022 , the board of directors of ourGeneral Partner declared a cash distribution for the three months endedDecember 31, 2021 of$0.47 per common unit, maintaining our distribution from the second quarter of 2021 of 70% of cash available for distribution. The distribution is payable onMarch 11, 2022 to eligible common unitholders of record at the close of business onMarch 4, 2022 . We expect to continue to generate robust amounts of free cash flow and subsequently use that cash to both reduce debt and increase our return on capital to unitholders.
Production and Operational Update
Our business has rebounded strongly from the unprecedented volatility experienced throughout 2020 as commodity prices have increased and activity has returned to our acreage. There are currently 39 rigs operating on our mineral and royalty acreage, six of which are operated by Diamondback. Looking ahead, with minimal capital requirements and limited operating costs, royalty companies are expected to have an advantage in 2022 and not face inflationary cost pressures. As our defensive hedges placed in 2020 rolled off at the end of 2021, our industry leading cash margins will now be further enhanced by strength in commodity prices. Our production and free cash flow outlook is expected to be driven by Diamondback's continued focus on developing our acreage, as well as our exposure to other well-capitalized operators in thePermian Basin . We continue to have a high level of visibility into Diamondback's expected forward development plan and expect additional upside from third-party operators that continue to exceed our conservative activity and timing assumptions, all of which is expected to bolster oil production for us not only for the next several quarters, but in the coming years. 32
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The following table summarizes our gross well information as of the dates
indicated:
Third Party
Diamondback Operated Operated TotalHorizontal wells turned to production (fourth quarter 2021)(1): Gross wells
40 139 179
Net 100% royalty interest wells 3.7 1.4 5.1
Average percent net royalty interest 9.3 % 1.0 % 2.9 %
Horizontal wells turned to production (year ended
December 31 , 2021)(2):
Gross wells 158 562 720
Net 100% royalty interest wells 10.2 3.8 14.0
Average percent net royalty interest 6.5 % 0.7 % 1.9 %
Horizontal producing well count (fourth quarter 2021): Gross wells
1,335 4,371 5,706
Net 100% royalty interest wells 101.8 59.4 161.2
Average percent net royalty interest 7.6 % 1.4 % 2.8 %
Horizontal active development well count (as of
106 512 618
Net 100% royalty interest wells 6.8 3.8 10.6
Average percent net royalty interest 6.4 % 0.7 % 1.7 %
Line of sight wells (as of January 27 , 2022)(4):
Gross wells 135 428 563
Net 100% royalty interest wells 7.8 3.8 11.6
Average percent net royalty interest 5.8 % 0.9 % 2.1 %
(1) Average lateral length of 10,048.
(2) Average lateral length of 9,823.
(3) The total 618 gross wells currently in the process of active development are
those wells that have been spud and are expected to be turned to production
within approximately the next six to eight months.
(4) The total 563 line-of-sight wells are those that are not currently in the
process of active development, but for which Viper has reason to believe that
they will be turned to production within approximately the next 15 to 18 months.
The expected timing of these line-of-sight wells is based primarily on
permitting by third party operators or Diamondback's current expected completion
schedule. Existing permits or active development of our net royalty acreage does
not ensure that those wells will be turned to production given the volatility in
oil prices.
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Results of Operations
The following table summarizes our income and expenses for the periods
indicated:
Year Ended December 31,
2021 2020
(In thousands)
Operating income: Oil income$ 397,513 $ 217,859 Natural gas income 49,197 9,024 Natural gas liquids income 54,824 20,098 Royalty income 501,534 246,981 Lease bonus income 2,763 2,585 Other operating income 620 1,060 Total operating income 504,917 250,626 Costs and expenses: Production and ad valorem taxes 32,558 19,844 Depletion 102,987 100,501 Impairment - 69,202 General and administrative expenses 7,800 8,165 Total costs and expenses 143,345 197,712 Income (loss) from operations 361,572 52,914 Other income (expense): Interest expense, net (34,044) (33,000) Gain (loss) on derivative instruments, net (69,409) (63,591) Gain (loss) on revaluation of investment - (8,556) Other income, net 79 1,286 Total other expense, net (103,374) (103,861) Income (loss) before income taxes 258,198 (50,947) Provision for (benefit from) income taxes 1,521 142,466 Net income (loss) 256,677 (193,413) Net income (loss) attributable to non-controlling interest 198,738 (1,109) Net income (loss) attributable to Viper Energy Partners LP$ 57,939 $ (192,304) 34
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The following table summarizes our production data, average sales prices and
average costs for the periods indicated:
Year Ended December 31,
2021 2020
(In thousands)
Production data:
Oil (MBbls) 6,068 5,956
Natural gas (MMcf) 13,672 11,486
Natural gas liquids (MBbls) 1,913 1,848
Combined volumes (MBOE)(1) 10,260 9,718
Average daily oil volumes (BO/d) 16,625 16,272
Average daily combined volumes (BOE/d) 28,110 26,551
Average sales prices:
Oil ($/Bbl) $ 65.51 $ 36.58
Natural gas ($/Mcf) $ 3.60 $ 0.79
Natural gas liquids ($/Bbl) $ 28.66 $ 10.88
Combined ($/BOE)(2) $ 48.88 $ 25.41
Oil, hedged ($/Bbl)(3) $ 50.25 $ 32.00
Natural gas, hedged ($/Mcf)(3) $ 3.60 $ 0.02
Natural gas liquids ($/Bbl)(3) $ 28.66 $ 10.88
Combined price, hedged ($/BOE)(3) $
39.86
Average costs ($/BOE): Production and ad valorem taxes $
3.17
General and administrative - cash component(4) 0.65 0.71 Total operating expense - cash $
3.82
General and administrative - non-cash unit compensation expense$ 0.11 $ 0.13 Interest expense, net$ 3.32 $ 3.40 Depletion$ 10.04 $ 10.34 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. (2)Realized price net of all deducts for gathering, transportation and processing. (3)Hedged prices reflect the impact of cash settlements on our matured commodity derivative transactions on our average sales prices. (4)Excludes non-cash unit compensation for the respective periods presented. 35 -------------------------------------------------------------------------------- Table of Content Comparison of the Years EndedDecember 31, 2021 and 2020
Royalty Income
Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.
Royalty income increased$254.6 million during the year endedDecember 31, 2021 compared to 2020. Higher average prices contributed approximately$248.0 million of the total increase, due largely to the recovery in oil prices, and to a lesser extent, natural gas and natural gas liquids prices from historic lows experienced in the 2020 as discussed in "- Overview ." The 6% increase in production volumes during the year endedDecember 31, 2021 compared to 2020 contributed approximately$6.5 million of the total increase in royalty income. The increase in production was primarily attributable to new well additions between periods.
Production and Ad Valorem Taxes
The following table presents production and ad valorem taxes for the years ended
Year Ended December 31,
2021 2020
Amount Percentage of Amount Percentage of
(In thousands) Per BOE Royalty Income (In thousands) Per BOE Royalty Income
Production taxes $ 25,966 $ 2.53 5.2 % $ 12,101 $ 1.25 4.9 %
Ad valorem taxes 6,592 0.64 1.3 7,743 0.79 3.1
Total production and ad
valorem taxes $ 32,558 $ 3.17 6.5 % $ 19,844 $ 2.04 8.0 %
In general, production taxes are directly related to production revenues and are
based upon current year commodity prices. Production taxes as a percentage of
royalty income for 2021 remained consistent with 2020. Ad valorem taxes are
based, among other factors, on property values driven by prior year commodity
prices. Ad valorem taxes as a percentage of royalty income for the same period
in 2021 compared to 2020 decreased primarily due to improved average sales
prices, while the tax valuation of oil and natural gas interests declined. We
expect production and ad valorem taxes for 2022 to be approximately 7% to 8% of
revenue.
Depletion
The $2.5 million , or 2%, increase in depletion expense for 2021 compared to 2020
was due primarily to an increase in production, partially offset by a decrease
in the depletion rate to $10.04 from $10.34 , respectively. The rate decrease
largely resulted from higher SEC oil prices utilized in the reserve calculations
in the 2021 period, lengthening the economic life of the reserve base and
resulting in higher projected remaining reserve volumes on our wells.
Impairment
There was no impairment recorded for the year ended
Net Interest Expense
Net interest expense for 2021 and 2020 was$34.0 million and$33.0 million , respectively. The increase of$1.0 million was due to increased borrowings during 2021 compared to 2020, as approximately$190.0 million of the Swallowtail Acquisition was funded with additional borrowings under theOperating Company's revolving credit facility inOctober 2021 as discussed in "- 2 021
Transactions and Recent Developments " above. This increase was partially
offset by repayments of borrowings under the
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Derivative Instruments
The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:
Year Ended December 31,
2021 2020
(In thousands)
Gain (loss) on derivative instruments
We recorded losses on our derivative instruments for the year endedDecember 31, 2021 and 2020 primarily due to market prices being higher than the strike prices on our derivative contracts. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our condensed consolidated statements of operations under the line item captioned "Gain (loss) on derivative instruments, net."
Gain (Loss) on Revaluation of Investment
We did not record a gain or loss on revaluation of investment for the year endedDecember 31, 2021 , as we fully divested our equity interest in a limited partnership during 2020. We recorded loss on revaluation of investment of$8.6 million for the year endedDecember 31, 2020 primarily due to recording the remaining investment at its fair value during that period.
Provision for (Benefit from) Income Taxes
We recorded an income tax expense of$1.5 million and$142.5 million for the years endedDecember 31, 2021 and 2020, respectively. The change in our income tax provision was primarily due to the impact of recording a valuation allowance on our deferred tax assets during the first quarter of 2020. The total income tax provision for the year endedDecember 31, 2021 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of maintaining a valuation allowance on our deferred tax assets. See Note 9- Income Taxes of the notes to the consolidated financial statements included elsewhere in this Annual Report for further details.
Liquidity and Capital Resources
Overview of Sources and Uses of Cash
As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. Our primary sources of liquidity have been cash flows from operations, proceeds from sales of non-core assets and investments, equity and debt offerings and borrowings under theOperating Company's credit agreement. Our primary uses of cash have been distributions to our unitholders, repayment of debt, capital expenditures for the acquisition of our mineral interests and royalty interests in oil and natural gas properties and repurchases of our common units. AtDecember 31, 2021 , we had approximately$235.4 million of liquidity consisting of$39.4 million in cash and cash equivalents and$196.0 million available under theOperating Company's credit agreement. Our working capital requirements are supported by our cash and cash equivalents and theOperating Company's credit agreement. We may draw on theOperating Company's credit agreement to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our acquisitions of mineral and royalty interests, distributions, debt service obligations and repayment of debt maturities, common unit repurchase program and any amounts that may ultimately be paid in connection with contingencies. 37 -------------------------------------------------------------------------------- Table of Content In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts as discussed further in Item 7A. Quantitative and Qualitative Disclosures About Market Risk-Commodity Price Risk . Continued prolonged volatility in the capital, financial and, or credit markets due to the COVID-19 pandemic, the depressed commodity markets and, or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although the Partnership expects that its sources of funding will be adequate to fund its short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.
Cash Flows
The following table presents our cash flows for the period indicated:
Year Ended December 31,
2021 2020
(In thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities $ 307,114 $ 196,556
Net cash provided by (used in) investing activities (281,176) (16,283)
Net cash provided by (used in) financing activities (5,611)
(164,754)
Net increase (decrease) in cash and cash equivalents
$ 15,519 Operating Activities Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volume of oil and natural gas sold by our producers as discussed in " - Results of Operations " above. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. The increase in net cash provided by operating activities during the year endedDecember 31, 2021 compared to the same period in 2020 was primarily driven by higher royalty income in 2021, which was largely offset by (i) changes in our working capital accounts, most notably through an increase in our royalty income accounts receivable in 2021 compared to 2020 due primarily to an increase in oil and gas prices on production sold in the fourth quarter of 2021 compared to the fourth quarter of 2020, the Swallowtail Acquisition, and the timing of our receipt of royalty income payments from our operators, (ii) an increase in cash paid for derivative settlements and (iii) an increase in production and ad valorem expenses due to the corresponding increase in royalty income. Investing Activities
Net cash used in investing activities during the years ended
Financing Activities
Net cash used in financing activities during the year endedDecember 31, 2021 , was primarily related to net borrowings of$220.0 million under theOperating Company's revolving credit facility to fund the Swallowtail Acquisition, distributions of$176.6 million to our unitholders and$46.0 million of repurchases of our common units during the fourth quarter of 2021 as discussed below. Net cash used in financing activities during the year endedDecember 31, 2020 , was primarily related to distributions of$108.0 million to our unitholders,$24.0 million of common units repurchased as part of our unit repurchase program, repurchases of the Notes totaling$19.7 million , net of discounts during the second quarter of 2020, and net payments for borrowings under theOperating Company's revolving credit facility of$12.5 million . 38 -------------------------------------------------------------------------------- Table of Content Capital Resources
The Operating Company's credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of$2.0 billion , with a borrowing base of$580.0 million as ofDecember 31, 2021 , based on theOperating Company's oil and natural gas reserves and other factors. AtDecember 31, 2021 , theOperating Company had elected a commitment amount of$500.0 million on its credit agreement with$304.0 million of outstanding borrowings. During the year endedDecember 31, 2021 , the weighted average interest rate on borrowings under theOperating Company's revolving credit facility was 2.35%.
As of
See Note 6- Debt of the notes to the consolidated financial statements
included elsewhere in this Annual Report for additional discussion of our
outstanding debt at
Capital Requirements
Senior Notes
The outstanding Notes obligations total$479.9 million as ofDecember 31, 2021 . There are no principal amounts due until 2027. AtDecember 31, 2021 , we have a remaining aggregate interest expense obligation of$154.8 million on the Notes with$25.8 million being due each year from 2023 to 2027. The Notes are not subject to any mandatory redemption or sinking fund requirements. See Note 6- Debt of the notes to the consolidated financial statements included elsewhere in this Annual Report for further information on the Notes.
Unit Repurchase Program
OnNovember 15, 2021 , the board of directors of ourGeneral Partner approved an increase of the authorization of its common unit repurchase program to$150.0 million of the Partnership's outstanding common units and extended the authorization indefinitely. During the year endedDecember 31, 2021 , the Partnership repurchased approximately$46.0 million of common units under the repurchase program. As ofDecember 31, 2021 ,$80.0 million remains available for use to repurchase units under the repurchase program. See Note 7- Unitholders' Equity and Distributions of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of the unit repurchase program.
Cash Distributions
We paid total distributions of$176.5 million and$108.0 million on our common units and theOperating Company's Class B units during 2021 and 2020, respectively. Beginning with the first quarter of 2020, the board of directors of ourGeneral Partner revised the distribution policy to provide that theOperating Company would distribute a percentage of its available cash to its unitholders (including Diamondback and us) rather than all of its available cash as it had previously done. The distribution for the fourth quarter of 2021 is payable onMarch 11, 2022 to common unitholders of record at the close of business onMarch 4, 2022 . Based on the common units andOperating Company units held by Diamondback onFebruary 22, 2022 , the distribution payable to Diamondback for the fourth quarter of 2021 onMarch 11, 2022 will be approximately$43.1 million . See Note 7- Unitholders' Equity and Distributions of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of our distributions. We expect to continue paying quarterly cash distributions in respect of our common units. The board of directors of the General Partner may change the distribution policies at any time. We are not required to pay distributions to its common unitholders on a quarterly or other basis. 39 -------------------------------------------------------------------------------- Table of Content Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Accounting estimates are considered to be critical if (i) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (ii) the impact of the estimates and assumptions on financial condition or operating performance is material. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.
Royalty Interest and Revenue Recognition
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales from third party operators other than Diamondback may not be received for 30 to 90 days after the date production is delivered. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded based upon the Partnership's interest. Where available, historical actual data is used to calculate volume estimates for wells operated by third parties. If historical actual data is not available for these wells, engineering estimates are used to calculate expected volumes. As such, estimated volumes utilized in period end royalty income accruals are subject to revision as additional actual data becomes available and such revisions may have a material impact on our results of operations and our royalty income receivables. 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. We record the differences between our estimates and the actual amounts received for royalties from third parties in the month that payment is received from the producer. We have existing internal controls for our royalty income estimation process and related accruals, but actual third party royalty income in future periods could differ materially from estimated amounts. AtDecember 31, 2021 , our accrual for third party royalty was approximately$49.4 million . Actual revenues received from third parties differed by approximately$1.9 million or 7% compared to the accrual atDecember 31, 2020 .
Oil and Natural Gas Accounting and Reserves
We account for oil and natural gas producing activities using the full cost
method of accounting, which is dependent on the estimation of proved reserves to
determine the rate at which we record depletion on our oil and natural gas
properties and whether the value of our evaluated oil and natural gas properties
is permanently impaired based on the quarterly full cost ceiling impairment
test. Further, we utilize estimated proved reserves to assign fair value to
acquired mineral and royalty interests. As such, we consider the estimation of
proved reserves to be a critical accounting estimate.
Oil and natural gas reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be precisely
measured and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Our independent engineers and technical staff prepare our estimates of oil and
natural gas reserves and their associated future net cash flows. The process of
estimating oil and natural gas reserves is complex, requiring significant
decisions in the evaluation of available geological, geophysical, engineering
and economic data. Significant inputs included in the calculation of future net
cash flows include our estimate of operating and development costs, anticipated
production of proved reserves and other relevant data. The data for a given
property may also change substantially over time as a result of numerous
factors, including additional development activity, evolving production history
and a continual reassessment of the viability of production under changing
economic conditions. As a result, material revisions to existing reserve
estimates occur from time to time, and reserve estimates are often different
from the quantities of oil and natural gas that are ultimately recovered.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various
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properties increase the likelihood of significant changes in these estimates. If
such changes are material, they could significantly affect future depletion of
capitalized costs and result in impairment of assets that may be material.
Revisions of previous quantity estimates accounted for approximately 4% of the
change in the total standardized measure of our reserves from December 31, 2020
to December 31, 2021 , and were primarily related to negative revisions due to
PUD downgrades during 2021.
Our unevaluated property costs are tracked by lease and prospect. We assess all
items classified as unevaluated property (on an individual basis or as a group
if properties are individually insignificant) on an annual basis for possible
impairment. This assessment is subjective and includes consideration of the
calculated value for each lease based on the total costs incurred for the lease
divided by the number of acres available to develop compared to current market
prices for acreage in the related basins. We also monitor information available
from third party operators of our acreage for future drilling plans as part of
our impairment assessment. At December 31, 2021 , our unevaluated properties
totaled $1.6 billion . No impairments were recorded on our proved oil and natural
gas properties during the years ended December 31, 2021 and 2019; however,
impairment expense of $69.2 million was recorded for the year ended December 31,
2020 as discussed further in Note 5- Oil and Natural Gas Interests of the
notes to the consolidated financial statements included elsewhere in this Annual
Report. Due to an increase in the historical 12-month average trailing SEC
prices for oil and natural throughout 2021 and into 2022, we are not currently
projecting a full cost ceiling impairment in the first quarter of 2022. Any
future impairment could be material to our consolidated financial statements.
Derivative Instruments
In order to reduce uncertainty around commodity prices received for our oil and natural gas operators' production, we enter into commodity price derivative contracts from time to time. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties' creditworthiness. We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.
See Item 7A. Quantitative and Qualitative Disclosures About Market
Risk - Commodity Price Risk for additional sensitivity analysis of
our open derivative positions at
Income Taxes
We have elected to be treated as a corporation forU.S. federal income tax purposes. The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when 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 the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized after considering all positive and negative evidence available concerning the realizability of our deferred tax assets. During the year endedDecember 31, 2020 , we established a valuation allowance for the full amount of our deferred tax assets. The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters. 41
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Table of Content
Recent Accounting Pronouncements
See Note 2- Summary of Significant Accoun ting Policies to in the notes of our consolidated financial statements included elsewhere in this Annual Report for a full listing of our significant accounting policies.
Off-Balance Sheet Arrangements
We currently have no off-balance sheet arrangements.
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