VIPER ENERGY PARTNER

VNOM
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VIPER ENERGY PARTNERS LP : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

08/03/2021 | 04:26pm


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 ended
December 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 traded Delaware limited partnership formed by Diamondback to
own and acquire mineral and royalty interests in oil and natural gas properties
primarily in the Permian Basin. We operate in one reportable segment. Since May
10, 2018
, we have been treated as a corporation for U.S. federal income tax
purposes.

As of June 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 early March 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 by OPEC 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 for
West 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. On July 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
ended June 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 at June 30, 2021.

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Cash Distributions on Common Units




On July 28, 2021, the board of directors of our general partner declared a cash
distribution for the three months ended June 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 on August 19, 2021 to
eligible common unitholders of record at the close of business on August 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 the Permian 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 July 12, 2021):
Gross wells


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 July 12,
2021)(2):
Gross wells


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 of July 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.

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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)



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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 $ 43.44 $ 23.06




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 $ 36.01 $ 22.52




Average costs ($/BOE):
Production and ad valorem taxes $ 3.28 $


1.39 $ 3.06 $ 1.95




General and administrative - cash component(4) 0.73 0.63 0.77 0.78
Total operating expense - cash $ 4.01 $


2.02 $ 3.83 $ 2.73




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 June 30, 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.



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Royalty income increased $81.0 million and $100.7 million during the three and
six months ended June 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 the Permian Basin during the
first quarter of 2021. Production volumes were relatively flat for the six
months ended June 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 June 30, 2021 and 2020:




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 ended June 30, 2021 remained
consistent with the three and six months ended June 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 ended June
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 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.


Depletion expense and the depletion rate for the six months ended June 30, 2021
compared to 2020 were relatively flat.



Net Interest Expense



There were no significant changes in net interest expense for the three months
ended June 30, 2021 compared to 2020.



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Net interest expense for the six months ended June 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 the Operating 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 $ (29,546) $ (34,443) $ (61,050) $ (42,385)
Net cash receipts (payments) on derivatives $ (20,940) $ (2,101) $ (35,882) $ (2,554)






We recorded losses on our derivative instruments for the three and six months
ended June 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
ended June 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 ended June 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
June 30, 2021 and 2020 due to maintaining a valuation allowance against our
deferred tax assets.




We recorded an immaterial income tax expense for the six months ended June 30,
2021
and $142.5 million for the six months ended June 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 ended June
30, 2020
. The total income tax provision for the six months ended June 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 to Viper 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
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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 $ 65,374 $ 41,407




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 $ 57,916 $ 34,266




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 $ 0.58 $ 0.13



(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 $0.33 per common unit is
payable on August 19, 2021 to common unitholders of record at the close of
business on August 12, 2021. See Note 7- Unitholders' Equity and
Distributions for further discussion of our distributions.



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 the February 2021 winter storms in the Permian 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 ended June 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 June 30, 2021
and 2020, was primarily related to acquisitions of oil and natural gas
interests.



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Financing Activities




Net cash used in financing activities during the six months ended June 30, 2021,
was primarily related to the net repayment of $22.0 million of borrowings under
the Operating 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 ended June 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 the Operating Company's revolving credit facility of
$57.0 million during the second quarter of 2020.


Common Unit Repurchase Program




On November 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 ended June 30, 2021, we repurchased
approximately $19.8 million of common units under our repurchase program. As
of June 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 through December 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 of June 30, 2021, our indebtedness consists of $479.9 million in principal
amount of Notes outstanding and $62.0 million in borrowings under the Operating
Company's
revolving credit facility. We did not repurchase any Notes during the
three and six months ended June 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 of June 30,
2021
, based on the Operating Company's oil and natural gas reserves and other
factors, although the Operating 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 of June 30, 2021, there was $62.0 million of outstanding
borrowings and $438.0 million available for future borrowings under the
Operating Company's revolving credit facility. During the three and six months
ended June 30, 2021, the weighted average interest rate on the Operating
Company's
revolving credit facility was 1.93% and 1.90%, respectively. The
revolving credit facility will mature on June 2, 2025.


As of June 30, 2021, the Operating Company was in compliance with the financial
maintenance covenants under its credit agreement.



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 December 31, 2020.



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 December 31,
2020
.



Off-Balance Sheet Arrangements



We currently have no off-balance sheet arrangements.



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