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)

11/04/2021 | 03:09pm


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 September 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. Additionally, the Delta variant emerged in March 2021 and became
highly transmissible in July 2021, which contributed to additional pricing and
demand volatility during the third quarter of 2021. 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 $80.64 Bbl, and the NYMEX
Henry Hub price of natural gas has ranged from $1.48 to $6.31 per MMBtu. On
October 13, 2021, the closing NYMEX WTI price for crude oil was $80.44 per Bbl
and the closing NYMEX Henry Hub price of natural gas was $5.59 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
nine months of 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
maintaining its fourth quarter 2021 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.

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 September 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 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.

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Acquisitions and Divestitures Update



Swallowtail Acquisition




On October 1, 2021, we completed the acquisition of certain mineral and royalty
interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC for
approximately 15.25 million of our common units and approximately $225.0 million
in cash. The mineral and royalty interests acquired in the Swallowtail
Acquisition represent approximately 2,313 net royalty acres primarily in the
Northern Midland Basin, of which approximately 62% are operated by Diamondback.
The Swallowtail Acquisition has an effective date of August 1, 2021. 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
the Operating Company's revolving credit facility.


As a result of the Swallowtail Acquisition, our footprint of mineral and royalty
interests increased to a total of 26,281 net royalty acres at October 1, 2021.



Cash Distributions on Common Units




On October 27, 2021, the board of directors of our general partner declared a
cash distribution for the three months ended September 30, 2021 of $0.38 per
common unit, maintaining our distribution from the second quarter of 2021 of 70%
of cash available for distribution. The distribution is payable on November 18,
2021
to eligible common unitholders of record at the close of business on
November 11, 2021. Net debt decreased 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. These were
primarily driven by Diamondback's anticipated development plan and benefits from
our 2021 hedging arrangements. 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. Third party operated net wells turned to production on
our acreage during the third quarter of 2021 are at their highest level since
the first quarter of 2020. There are currently 35 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 have a high level of visibility into
Diamondback's expected forward development plan that is expected to bolster oil
production for Viper not only for the next several quarters, but in the coming
years.

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The following table summarizes our gross well information as of the dates
indicated, inclusive of the Swallowtail Acquisition:




Third Party
Diamondback Operated Operated Total


Horizontal wells turned to production (third quarter
2021)(1):
Gross wells


44 179 223
Net 100% royalty interest wells 1.8 1.3 3.1
Average percent net royalty interest 4.0 % 0.7 % 1.4 %


Horizontal producing well count (as of October 11,
2021
):
Gross wells


1,295 4,282 5,577
Net 100% royalty interest wells 97.7 58.4 156.1
Average percent net royalty interest 7.5 % 1.4 % 2.8 %


Horizontal active development well count (as of October
11
, 2021)(2):
Gross wells


103 467 570
Net 100% royalty interest wells 5.8 3.7 9.5
Average percent net royalty interest 5.7 % 0.8 % 1.7 %

Line of sight wells (as of October 11, 2021)(3):
Gross wells 107 385 492
Net 100% royalty interest wells 5.7 3.6 9.3
Average percent net royalty interest 5.3 % 0.9 % 1.9 %


(1) Average lateral length of 10,163.
(2) The total 570 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 492 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 September
30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands)

Operating income:
Oil income $ 100,154 $ 53,595 $ 272,450 $ 153,412
Natural gas income 12,074 3,331 30,651 4,909
Natural gas liquids income 15,421 5,658 34,518 13,536
Royalty income 127,649 62,584 337,619 171,857
Lease bonus income 223 40 1,032 1,685

Other operating income 132 318 479 761
Total operating income 128,004 62,942 339,130 174,303
Costs and expenses:
Production and ad valorem taxes 8,625 5,049 23,426 14,306

Depletion 25,366 24,780 74,230 72,204

General and administrative expenses 1,735 1,811 6,118 6,160

Total costs and expenses 35,726 31,640 103,774 92,670
Income (loss) from operations 92,278 31,302 235,356 81,633
Other income (expense):
Interest expense, net (8,328) (8,238) (24,161) (24,870)

Gain (loss) on derivative instruments, net (9,599) (5,084) (70,649) (47,469)
Gain (loss) on revaluation of investment - (1,984) - (8,661)
Other income, net - 188 77 1,111
Total other expense, net (17,927) (15,118) (94,733) (79,889)
Income (loss) before income taxes 74,351 16,184 140,623 1,744
Provision for (benefit from) income taxes 906 - 941 142,466
Net income (loss) 73,445 16,184 139,682 (140,722)
Net income (loss) attributable to non-controlling
interest 56,613 16,948 121,208 23,963
Net income (loss) attributable to Viper Energy
Partners LP $ 16,832 $ (764) $ 18,474 $ (164,685)



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The following table summarizes our production data, average sales prices and
average costs for the periods indicated:




Three Months Ended


September



30,


Nine Months Ended September 30,



2021 2020 2021 2020
Production data:
Oil (MBbls) 1,480 1,456 4,378 4,359
Natural gas (MMcf) 3,347 3,111 9,828 8,454
Natural gas liquids (MBbls) 503 455 1,359 1,402
Combined volumes (MBOE)(1) 2,541 2,430 7,375 7,169

Average daily oil volumes (BO/d) 16,087 15,829 16,037 15,907
Average daily combined volumes (BOE/d) 27,620 26,409 27,015 26,165

Average sales prices:
Oil ($/Bbl) $ 67.67 $ 36.80 $ 62.23 $ 35.20
Natural gas ($/Mcf) $ 3.61 $ 1.07 $ 3.12 $ 0.58
Natural gas liquids ($/Bbl) $ 30.66 $ 12.44 $ 25.40 $ 9.66
Combined ($/BOE)(2) $ 50.24 $ 25.76 $ 45.78 $ 23.97

Oil, hedged ($/Bbl)(3) $ 50.57 $ 27.65 $ 48.26 $ 32.56
Natural gas, hedged ($/Mcf)(3) $ 3.61 $ 0.16 $ 3.12 $ (0.27)
Natural gas liquids ($/Bbl)(3) $ 30.66 $ 12.44 $ 25.40 $ 9.66
Combined price, hedged ($/BOE)(3) $ 40.28 $ 19.11


$ 37.48 $ 21.36




Average costs ($/BOE):
Production and ad valorem taxes $ 3.39 $ 2.08


$ 3.18 $ 2.00




General and administrative - cash component(4) 0.59 0.63 0.70 0.73
Total operating expense - cash $ 3.98 $ 2.71


$ 3.88 $ 2.73




General and administrative - non-cash unit
compensation expense $ 0.10 $ 0.11 $ 0.13 $ 0.13
Interest expense, net $ 3.28 $ 3.39 $ 3.28 $ 3.47
Depletion $ 9.98 $ 10.20 $ 10.07 $ 10.07


(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 of our matured commodity
derivative transactions on our average sales prices.
(4)Excludes non-cash unit-based compensation expense for the respective periods
presented.

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Comparison of the Three and Nine Months Ended September 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.




Royalty income increased $65.1 million and $165.8 million during the three and
nine months ended September 30, 2021, respectively, compared to the same periods
in 2020. Higher average prices contributed approximately $63.4 million and
$164.7 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 5% increase in production volumes during the third quarter of 2021 compared
to the same period in 2020 contributed approximately $1.7 million of the total
increase in royalty income. The 3% increase in production volumes during the
nine months ended September 30, 2021 compared to the same period in 2020
contributed approximately $1.1 million of the total increase in royalty income.
The increase in production for both the three and nine month periods is
primarily attributable to new well additions between periods.


Production and Ad Valorem Taxes



The following table presents production and ad valorem taxes for the three and
nine months ended September 30, 2021 and 2020:




Three Months Ended September 30,
2021 2020
Amount Percentage of Amount Percentage of
(In thousands) Per BOE Royalty Income (In thousands) Per BOE Royalty Income
Production taxes $ 6,750 $ 2.65 5.3 % $ 3,106 $ 1.28 5.0 %
Ad valorem taxes 1,875 0.74 1.5 1,943 0.80 3.1
Total production and ad
valorem taxes $ 8,625 $ 3.39 6.8 % $ 5,049 $ 2.08 8.1 %



Nine Months Ended September 30,
2021 2020
Amount Percentage of Amount Percentage of
(In thousands) Per BOE Royalty Income (In thousands) Per BOE Royalty Income
Production taxes $ 17,264 $ 2.34 5.1 % $ 8,373 $ 1.17 4.9 %
Ad valorem taxes 6,162 0.84 1.8 5,933 0.83 3.4
Total production and ad
valorem taxes $ 23,426 $ 3.18 6.9 % $ 14,306 $ 2.00 8.3 %



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 nine months ended September 30, 2021 remained
consistent with the three and nine months ended September 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 interests
remained relatively flat.

Depletion

Depletion expense and the depletion rate for the three and nine months ended
September 30, 2021 compared to the same periods in 2020 were relatively flat as
the increases in production during the 2021 periods were partially offset by a
slight decrease in average depletion rates.

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Net Interest Expense



Net interest expense remained relatively flat for the three and nine months
ended September 30, 2021 compared to the same periods in 2020. Net interest
expense may increase in future periods as approximately $190.0 million of the
Swallowtail Acquisition was funded with additional borrowings under the
Operating Company's revolving credit facility in October 2021 as discussed in "-



Liqui dity and Capital Resources - Indebted ne s s "
above.

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 September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands)
Gain (loss) on derivative instruments $ (9,599) $ (5,084) $ (70,649) $ (47,469)
Net cash receipts (payments) on derivatives $ (25,306) $ (16,164) $ (61,188) $ (18,718)



We recorded losses on our derivative instruments for the three and nine months
ended September 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 three and
nine months ended September 30, 2021, as we fully divested our equity interest
in a limited partnership during 2020. We recorded losses on revaluation of
investment of $2.0 million and $8.7 million for the three and nine months ended
September 30, 2020 primarily due to recording the remaining investment at its
fair value at September 30, 2020.


Provision for (Benefit from) Income Taxes



Income tax expense remained low at $0.9 million for the three months ended
September 30, 2021, due to maintaining a valuation allowance against our
deferred tax assets. We did not record an income tax benefit or expense for the
three months ended September 30, 2020.




Income tax expense for the nine months ended September 30, 2021 was $0.9 million
compared to $142.5 million for the nine months ended September 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 first quarter of
2020. The total income tax provision for the nine months ended September 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.

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We define Adjusted EBITDA as net income (loss) attributable to Viper Energy
Partners LP
plus net income (loss) attributable to non-controlling interest
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 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.

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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


September



30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands)
Net income (loss) attributable to Viper Energy $ 16,832 $ (764) $ 18,474 $ (164,685)
Partners LP
Net income (loss) attributable to 56,613 16,948 121,208 23,963
non-controlling interest
Net income (loss) 73,445 16,184 139,682 (140,722)
Interest expense, net 8,328 8,238 24,161 24,870

Non-cash unit-based compensation expense 243 275 896 945
Depletion 25,366 24,780 74,230 72,204

(Gain) loss on revaluation of investment - 1,984 - 8,661


Non-cash (gain) loss on derivative instruments (15,707) (11,080)


9,461 28,751
(Gain) loss on extinguishment of debt - 20 - 6
Provision for (benefit from) income taxes 906 - 941 142,466
Consolidated Adjusted EBITDA 92,581 40,401 249,371 137,181
Less: Adjusted EBITDA attributable to
non-controlling interest(1) 54,269 23,113 145,685 78,492
Adjusted EBITDA attributable to Viper Energy
Partners LP $ 38,312 $ 17,288


$ 103,686 $ 58,689




Adjustments to reconcile Adjusted EBITDA to
cash available for distribution:
Income taxes payable $ (906) $ - $ (941) $ -
Debt service, contractual obligations, fixed
charges and reserves (2,996) (3,297) (10,230) (9,941)
Cash paid for tax withholding on vested common
units - (1) (20) (384)
Distribution equivalent rights payments (62) (2) (141) (26)
Preferred distributions (45) (45) (135) (135)

Cash available for distribution to Viper Energy
Partners LP unitholders $ 34,303 $ 13,943


$ 92,219 $ 48,203




Common limited partner units outstanding 63,831 67,851 63,831 67,851

Cash available for distribution per limited
partner unit $ 0.54 $ 0.21 $ 1.44 $ 0.71
Cash per unit approved for distribution $ 0.38 $ 0.10


$ 0.96 $ 0.23



(1) Does not take into account special income allocation consideration.



Cash Distributions



The distribution for the third quarter of 2021 of $0.38 per common unit is
payable on November 18, 2021 to common unitholders of record at the close of
business on November 11, 2021. See Note 7- Unitholders' Equity and
Distributions for further discussion of our distributions.



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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:




Nine


Months Ended September 30,



2021 2020
(In thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities $ 199,672 $ 143,206
Net cash provided by (used in) investing activities (6,728) (57,148)
Net cash provided by (used in) financing activities (140,525) (82,286)
Net increase (decrease) in cash and cash equivalents $ 52,419 $ 3,772



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 nine months ended September 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 nine months ended September 30,
2021
and 2020, was primarily related to acquisitions of oil and natural gas
interests.



Financing Activities




Net cash used in financing activities during the nine months ended September 30,
2021
, was primarily related to the net borrowings of $8.0 million under the
Operating Company's revolving credit facility, distributions of $112.0 million
to our unitholders and $33.6 million of repurchases of our common units during
the third quarter of 2021 as discussed below.

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Net cash used in financing activities during the nine months ended September 30,
2020
, was primarily related to distributions of $92.1 million to our unitholders
and by repurchases of the Notes totaling $19.7 million, net of discounts during
the second quarter of 2020. These reductions were partially offset by net
proceeds from borrowing activity under the Operating Company's revolving credit
facility of $30.0 million.


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, of which approximately $57.6 million has been expended through
September 30, 2021. During the nine months ended September 30, 2021, we
repurchased approximately $33.6 million of common units under our repurchase
program, which is authorized to extend through December 31, 2021. 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. Any common units
under the repurchase program will be purchased opportunistically with funds from
cash on hand, free cash flow from operations and potential liquidity events,
such as the sale of assets. Any such repurchases may be made from time to time
in open market or privately negotiated transactions in compliance with Rule
10b-18 under the Securities Exchange Act of 1934, as amended, and are subject to
market conditions, applicable legal requirements, contractual obligations and
other factors.

Indebtedness

As of September 30, 2021, our indebtedness consists of $479.9 million in
principal amount of Notes outstanding and $92.0 million in borrowings under the
Operating Company's revolving credit facility. We did not repurchase any Notes
during the three and nine months ended September 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 September 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 of $580.0
million
is expected to be reaffirmed by the lenders during the regularly
scheduled (semi-annual) fall 2021 redetermination in November 2021. The next
semi-annual redetermination is scheduled to occur in May 2022. As of
September 30, 2021, there was $408.0 million available for future borrowings
under the Operating Company's revolving credit facility. During the three and
nine months ended September 30, 2021, the weighted average interest rate on the
Operating Company's revolving credit facility was 1.98% and 2.14%, respectively.
The revolving credit facility will mature on June 2, 2025.

On October 1, 2021, the Partnership and the Operating Company completed the
Swallowtail Acquisition as discussed in Note 13- Subsequent
Events - Swallow tail Acquisition . Approximately $190.0 million
of the cash portion of this transaction was funded through borrowings under the
Operating Company's revolving credit facility, reducing the amount that remained
available for future borrowings under this facility to $218.0 million as of
October 1, 2021.


As of September 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.



28



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