The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year endedDecember 31, 2020 . 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 " Part II. 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. SinceMay 10, 2018 , we have been treated as a corporation forU.S. federal income tax purposes. As ofJune 30, 2021 , our general partner held a 100% general partner interest in us, and Diamondback owned 731,500 of our common units and beneficially owned all of our 90,709,946 outstanding Class B units, representing approximately 59% of our total units outstanding. Diamondback also owns and controls our general partner. Recent Developments COVID-19 and 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. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in response to the increase in demand. During 2020 and 2021, the posted price forWest Texas intermediate light sweet crude oil, or NYMEX WTI, has ranged from$(37.63) to$75.25 Bbl, and the NYMEX Henry Hub price of natural gas has ranged from$1.48 to$3.75 per MMBtu. OnJuly 16, 2021 , the closing NYMEX WTI price for crude oil was$71.81 per Bbl and the closing NYMEX Henry Hub price of natural gas was$3.67 per MMBtu. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices. As a result of the reduction in crude oil demand caused by factors discussed above, Diamondback and other operators on properties in which we have mineral and royalty interests lowered their 2020 capital budgets and production guidance, however, Diamondback and certain of our other operators have since restored curtailed production. 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 the first six months of 2021, using excess cash flow for debt repayment and/or return to their stockholders rather than expanding their drilling programs. 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. Based on the results of the quarterly ceiling test, we were not required to record an impairment on our proved oil and natural gas interests for the quarter endedJune 30, 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 fail to stabilize or decrease further, our production, proved reserves and cash flows will be adversely impacted. Our business may be also further adversely impacted by any pipeline capacity and storage constraints.
Acquisitions and Divestitures Update
We had immaterial acquisitions and divestitures of mineral and royalty interests during the second quarter of 2021, bringing our footprint of mineral and royalty interests to a total of 24,341 net royalty acres atJune 30, 2021 . 17
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Cash Distributions on Common Units
OnJuly 28, 2021 , the board of directors of our general partner declared a cash distribution for the three months endedJune 30, 2021 of$0.33 per common unit, increasing our distribution for the second quarter of 2021 to 70% of cash available for distribution. The distribution is payable onAugust 19, 2021 to eligible common unitholders of record at the close of business onAugust 12, 2021 . With net debt decreasing in the third quarter of 2020 from peak levels due to strong free cash flow generation, as well as an improved forward outlook for production, realized pricing and free cash flow yield, driven primarily by Diamondback's anticipated development plan and benefiting from our hedging arrangements rolling off in 2021, we expect to continue to increase our return on capital to unitholders in future quarters.
Production and Operational Update
Our business has rebounded strongly from the unprecedented volatility experienced throughout 2020 as commodity prices increased and activity has returned to our acreage. There are currently 36 rigs operating on our mineral and royalty acreage, five of which are operated by Diamondback. 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 have increased our production outlook for 2021 and continue to maintain visibility into Diamondback's expected forward development plan that includes several large pads where Viper will own a significant royalty interest. The following table summarizes our gross well information as of the dates indicated: Third Party Diamondback Operated Operated Total
Horizontal wells turned to production (second quarter 2021)(1): Gross wells
24 160 184 Net 100% royalty interest wells 2.6 0.7 3.3 Average percent net royalty interest 10.9 % 0.4 % 1.8 %
Horizontal producing well count (as of
1,189 3,671 4,860 Net 100% royalty interest wells 92.8 54.0 146.8 Average percent net royalty interest 7.8 % 1.5 % 3.0 %
Horizontal active development well count (as of
67 400 467 Net 100% royalty interest wells 5.0 3.2 8.3 Average percent net royalty interest 7.5 % 0.8 % 1.8 % Line of sight wells (as ofJuly 12 , 2021)(3): Gross wells 113 383 496 Net 100% royalty interest wells 4.5 2.7 7.2 Average percent net royalty interest 3.9 % 0.7 % 1.4 % (1) Average lateral length of 8,638. (2) The total 467 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. (3) The total 496 gross line-of-sight wells are those that are not currently in the process of active development, but for which we have 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 royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices. 18
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Results of Operations
The following table summarizes our income and expenses for the periods indicated: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 (In thousands) Operating income: Oil income$ 93,952 $ 27,617 $ 172,296 $ 99,817 Natural gas income 9,533 1,234 18,577 1,578 Natural gas liquids income 9,973 3,593 19,097 7,878 Royalty income 113,458 32,444 209,970 109,273 Lease bonus income 484 23 809 1,645 Other operating income 208 202 347 443 Total operating income 114,150 32,669 211,126 111,361 Costs and expenses: Production and ad valorem taxes 8,152 3,110 14,801 9,257 Depletion 23,978 22,782 48,864 47,424 General and administrative expenses 2,162 1,683 4,383 4,349 Total costs and expenses 34,292 27,575 68,048 61,030 Income (loss) from operations 79,858 5,094 143,078 50,331 Other income (expense): Interest expense, net (7,973) (7,669) (15,833) (16,632) Gain (loss) on derivative instruments, net (29,546) (34,443) (61,050) (42,385) Gain (loss) on revaluation of investment - 3,443 - (6,677) Other income, net 39 519 77 923 Total other expense, net (37,480) (38,150) (76,806) (64,771) Income (loss) before income taxes 42,378 (33,056) 66,272 (14,440) Provision for (benefit from) income taxes - - 35 142,466 Net income (loss) 42,378 (33,056) 66,237 (156,906) Net income (loss) attributable to non-controlling interest 37,716 (11,304) 64,595 7,015 Net income (loss) attributable to Viper Energy Partners LP$ 4,662 $ (21,752) $ 1,642 $ (163,921) 19
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The following table summarizes our production data, average sales prices and average costs for the periods indicated:
Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Production Data: Oil (MBbls) 1,503 1,315 2,898 2,902 Natural gas (MMcf) 3,219 2,685 6,481 5,344 Natural gas liquids (MBbls) 449 467 856 947 Combined volumes (MBOE)(1) 2,489 2,230 4,834 4,740 Average daily oil volumes (BO/d)(2) 16,516 14,453 16,011 15,947 Average daily combined volumes (BOE/d)(2) 27,352 24,508 26,707 26,041 Average sales prices(2): Oil ($/Bbl)$ 62.51 $ 21.00 $ 59.45 $ 34.39 Natural gas ($/Mcf) $ 2.96$ 0.46 $ 2.87 $ 0.30 Natural gas liquids ($/Bbl)$ 22.21 $ 7.69 $ 22.31 $ 8.32 Combined ($/BOE)$ 45.58 $
14.55
Oil, hedged ($/Bbl)(3)$ 48.58 $ 22.39 $ 47.07 $ 35.03 Natural gas, hedged ($/Mcf)(3) $ 2.96$ (1.01) $ 2.87 $ (0.53) Natural gas liquids ($/Bbl)(3)$ 22.21 $ 7.69 $ 22.31 $ 8.32 Combined price, hedged ($/BOE)(3)$ 37.18 $
13.60
Average costs ($/BOE): Production and ad valorem taxes $ 3.28 $
1.39
General and administrative - cash component(4) 0.73 0.63 0.77 0.78 Total operating expense - cash $ 4.01 $
2.02
General and administrative - non-cash unit compensation expense $ 0.14$ 0.13 $ 0.14 $ 0.14 Interest expense, net $ 3.20$ 3.44 $ 3.28 $ 3.51 Depletion $ 9.63$ 10.21 $ 10.11 $ 10.01 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. (2)Average daily volumes and average sales prices presented are based on actual production volumes and not calculated utilizing the rounded production volumes presented in the table above. (3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices. (4)Excludes non-cash unit-based compensation expense for the respective periods presented.
Comparison of the Three and Six Months Ended
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.
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Royalty income increased$81.0 million and$100.7 million during the three and six months endedJune 30, 2021 , respectively, compared to the same periods in 2020. Higher average prices contributed approximately$77.0 million and$101.3 million of the total increases, respectively, 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 periods as discussed in "- Overview
."
The 12% increase in production volumes during the second quarter of 2021 compared to the same period in 2020 contributed approximately$4.0 million of the total increase in royalty income and is primarily attributable to the make-up of lost production due to winter storms in thePermian Basin during the first quarter of 2021. Production volumes were relatively flat for the six months endedJune 30, 2021 compared to the same period in 2020.
Production and Ad Valorem Taxes
The following table presents the production and ad valorem taxes for the three
and six months ended
Three Months Ended June 30, 2021 2020 Amount Percentage of Amount Percentage of (In thousands) Per BOE Royalty Income (In thousands) Per BOE Royalty Income Production taxes$ 5,691 $ 2.29 5.0 %$ 1,692 $ 0.76 5.2 % Ad valorem taxes 2,461 0.99 2.2 1,418 0.63 4.4 Total production and ad valorem taxes$ 8,152 $ 3.28 7.2 %$ 3,110 $ 1.39 9.6 % Six Months Ended June 30, 2021 2020 Amount Percentage of Amount Percentage of (In thousands) Per BOE Royalty Income (In thousands) Per BOE Royalty Income Production taxes$ 10,514 $ 2.17 5.0 %$ 5,267 $ 1.11 4.8 % Ad valorem taxes 4,287 0.89 2.0 3,990 0.84 3.7 Total production and ad valorem taxes$ 14,801 $ 3.06 7.0 %$ 9,257 $ 1.95 8.5 % 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 the three and six months endedJune 30, 2021 remained consistent with the three and six months endedJune 30, 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 these same periods in 2021 compared to 2020 decreased primarily due to improved average sales prices, while the tax valuation of oil and natural gas interest remained fairly flat. Depletion Depletion expense increased$1.2 million , or 5%, for the three months endedJune 30, 2021 compared to the same period in 2020, primarily due to the 12% increase in production, which was partially offset by a decrease in the average depletion rate to$9.63 per BOE for the second quarter of 2021 compared to$10.21 per BOE for the second quarter of 2020. The rate decrease largely resulted from higherSEC 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.
Depletion expense and the depletion rate for the six months ended
Net Interest Expense
There were no significant changes in net interest expense for the three months
ended
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Net interest expense for the six months endedJune 30, 2021 and 2020 was$15.8 million and$16.6 million , respectively. The decrease of$0.8 million was due primarily to our repayment of borrowings under theOperating Company's revolving credit facility and our repurchase of$20.1 million of the Notes during the second and third quarters of 2020.
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:
Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020
(In thousands)
Gain (loss) on derivative instruments
We recorded losses on our derivative instruments for the three and six months endedJune 30, 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 six months endedJune 30, 2021 , as we divested our equity interest in a limited partnership during the third and fourth quarters of 2020. We recorded a loss on revaluation of investment of$6.7 million for the six months endedJune 30, 2020 to record the investment at its fair value during that period.
Provision for (Benefit from) Income Taxes
We did not record an income tax benefit or expense for the three months ended
We recorded an immaterial income tax expense for the six months endedJune 30, 2021 and$142.5 million for the six months endedJune 30, 2020 . 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 six months endedJune 30, 2020 . The total income tax provision for the six months endedJune 30, 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. Non-GAAP Financial Measures Adjusted EBITDA Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our common unitholders. We define Adjusted EBITDA as net income (loss) attributable toViper Energy Partners LP plus net income (loss) attributable to non-controlling interest ("net income (loss)") before interest expense, net, non-cash unit-based compensation expense, depletion expense, impairment expense, (gain) loss on revaluation of investment, non-cash (gain) loss on derivative instruments, (gain) loss on extinguishment of debt and provision for (benefit from) income taxes, if any. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in 22
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understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.
The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss). However, Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP and should not be considered an alternative to, or more meaningful than, net income (loss), royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented as determined in accordance with GAAP. Our computation of Adjusted EBITDA excludes some, but not all, items that affect net income (loss), and these measures may vary from those of other companies. As a result, Adjusted EBITDA as presented below may not be comparable to other similarly titled measures of other companies. The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution for the periods indicated: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 (In thousands) Net income (loss) attributable to Viper Energy$ 4,662 $ (21,752) $ 1,642 $ (163,921) Partners LP Net income (loss) attributable to 37,716 (11,304) 64,595 7,015 non-controlling interest Net income (loss) 42,378 (33,056) 66,237 (156,906) Interest expense, net 7,973 7,669 15,833 16,632 Non-cash unit-based compensation expense 338 283 653 670 Depletion 23,978 22,782 48,864 47,424 (Gain) loss on revaluation of investment - (3,443) - 6,677 Non-cash (gain) loss on derivative instruments 8,606 32,342 25,168 39,831 (Gain) loss on extinguishment of debt - (14) - (14) Provision for (benefit from) income taxes - - 35 142,466 Consolidated Adjusted EBITDA 83,273 26,563 156,790 96,780 Less: Adjusted EBITDA attributable to non-controlling interest(1) 48,637 15,198 91,416 55,373 Adjusted EBITDA attributable to Viper Energy Partners LP$ 34,636 $
11,365
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: Income taxes payable $ - $ -$ (35) $ - Debt service, contractual obligations, fixed charges and reserves (4,187) (3,261) (7,234) (6,644) Cash paid for tax withholding on vested common units - - (20) (383) Distribution equivalent rights payments (55) (4) (79) (24) Preferred distributions (45) (45) (90) (90) Cash available for distribution to Viper Energy Partners LP unitholders$ 30,349 $
8,055
Common limited partner units outstanding 64,546 67,831 64,546 67,831 Cash available for distribution per limited partner unit $ 0.47$ 0.12 $ 0.90 $ 0.51 Cash per unit approved for distribution $ 0.33 $
0.03
(1) Does not take into account special income allocation consideration.
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Cash Distributions
The distribution for the second quarter of 2021 of
Liquidity and Capital Resources
Overview
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 our credit agreement. Our primary uses of cash have been distributions to our unitholders, repayment of debt and capital expenditures for the acquisition of our mineral interests and royalty interests in oil and natural gas properties, and repurchases of our common units. We intend to finance future expenditures through a combination of cash on hand, borrowings under our credit agreement, issuance of common units and, subject to market conditions and other factors, proceeds from one or more capital market transactions, which may include debt or equity offerings. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, competitive, legislative, regulatory and other factors, including extreme weather conditions, such as theFebruary 2021 winter storms in thePermian Basin that impacted production volumes on our mineral and royalty acreage. Continued prolonged volatility in the capital, financial and/or credit markets, commodity pricing environment and uncertain 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.
Cash Flows
The following table presents our cash flows for the periods indicated:
Six Months Ended June 30, 2021 2020 (In thousands) Cash Flow Data: Net cash provided by (used in) operating activities$ 129,680 $ 115,863 Net cash provided by (used in) investing activities (819) (65,272) Net cash provided by (used in) financing activities (105,560) (44,530) Net increase (decrease) in cash$ 23,301 $ 6,061 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 "- Result s 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 six months endedJune 30, 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 a reduction in cash collections on our accounts receivable in 2021 compared to 2020 due to 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 six months ended
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Financing Activities
Net cash used in financing activities during the six months endedJune 30, 2021 , was primarily related to the net repayment of$22.0 million of borrowings under theOperating Company's revolving credit facility, distributions of$60.8 million to our unitholders and$19.8 million of repurchases of our common units during the second quarter of 2021 as discussed below. Net cash used in financing activities during the six months endedJune 30, 2020 , was primarily related to distributions of$87.3 million to our unitholders and repurchases of the Notes totaling$13.8 million , net of discounts during the second quarter of 2020. These amounts were partially offset by net proceeds from borrowing activity under theOperating Company's revolving credit facility of$57.0 million during the second quarter of 2020.
Common Unit Repurchase Program
OnNovember 6, 2020 , the board of directors of our general partner approved an expansion of our return of capital program with the implementation of a common unit repurchase program to acquire up to$100.0 million of our outstanding common units. During the six months endedJune 30, 2021 , we repurchased approximately$19.8 million of common units under our repurchase program. As ofJune 30, 2021 ,$56.2 million remains available for us to repurchase units under our common unit repurchase program. The common unit repurchase program is authorized to extend throughDecember 31, 2021 , and we intend to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. The repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of our general partner at any time.
Indebtedness
As ofJune 30, 2021 , our indebtedness consists of$479.9 million in principal amount of Notes outstanding and$62.0 million in borrowings under theOperating Company's revolving credit facility. We did not repurchase any Notes during the three and six months endedJune 30, 2021 , but may do so opportunistically from time to time in future periods.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 ofJune 30, 2021 , based on theOperating Company's oil and natural gas reserves and other factors, although theOperating Company had elected a commitment amount of$500.0 million . The borrowing base is scheduled to be redetermined semi-annually in May and November. As ofJune 30, 2021 , there was$62.0 million of outstanding borrowings and$438.0 million available for future borrowings under theOperating Company's revolving credit facility. During the three and six months endedJune 30, 2021 , the weighted average interest rate on theOperating Company's revolving credit facility was 1.93% and 1.90%, respectively. The revolving credit facility will mature onJune 2, 2025 .
As of
See additional discussion of our indebtedness in Note 6- Debt .
Contractual Obligations
Other than the changes in our outstanding debt discussed in Note 6- Debt ,
there were no material changes in our contractual obligations and other
commitments as disclosed in our Annual Report on Form 10-K for the year
ended
Critical Accounting Policies
There have been no changes to our critical accounting policies from those
disclosed in our Annual Report on Form 10-K for the year ended
Off-Balance Sheet Arrangements
We currently have no off-balance sheet arrangements.
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