VIPER ENERGY, INC. 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 of
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. Additionally, the Delta variant emerged inMarch 2021 and became highly transmissible inJuly 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 forWest Texas intermediate light sweet crude oil, or NYMEX WTI, has ranged from$(37.63) to$80.64 Bbl, and the NYMEXHenry Hub price of natural gas has ranged from$1.48 to$6.31 per MMBtu. OnOctober 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 endedSeptember 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. 18
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Acquisitions and Divestitures Update
Swallowtail Acquisition
OnOctober 1, 2021 , we completed the acquisition of certain mineral and royalty interests fromSwallowtail Royalties LLC andSwallowtail 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 theNorthern Midland Basin , of which approximately 62% are operated by Diamondback. The Swallowtail Acquisition has an effective date ofAugust 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 theOperating 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
Cash Distributions on Common Units
OnOctober 27, 2021 , the board of directors of our general partner declared a cash distribution for the three months endedSeptember 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 onNovember 18, 2021 to eligible common unitholders of record at the close of business onNovember 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 thePermian 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. 19
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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
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
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
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 Average costs ($/BOE): Production and ad valorem taxes$ 3.39 $ 2.08
General and administrative - cash component(4) 0.59 0.63 0.70 0.73 Total operating expense - cash$ 3.98 $ 2.71
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. 22
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Comparison of the Three and Nine 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.
Royalty income increased$65.1 million and$165.8 million during the three and nine months endedSeptember 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 endedSeptember 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
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
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 endedSeptember 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 endedSeptember 30, 2020 primarily due to recording the remaining investment at its fair value atSeptember 30, 2020 .
Provision for (Benefit from) Income Taxes
Income tax expense remained low at
Income tax expense for the nine months endedSeptember 30, 2021 was$0.9 million compared to$142.5 million for the nine months endedSeptember 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 endedSeptember 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. 24
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We define Adjusted EBITDA as net income (loss) attributable toViper 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. 25
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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 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
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
(1) Does not take into account special income allocation consideration.
Cash Distributions
The distribution for the third quarter of 2021 of
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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 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:
Nine
Months Ended
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
Financing Activities
Net cash used in financing activities during the nine months endedSeptember 30, 2021 , was primarily related to the net borrowings of$8.0 million under theOperating 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. 27
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Net cash used in financing activities during the nine months endedSeptember 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 theOperating Company's revolving credit facility of$30.0 million .
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, of which approximately$57.6 million has been expended throughSeptember 30, 2021 . During the nine months endedSeptember 30, 2021 , we repurchased approximately$33.6 million of common units under our repurchase program, which is authorized to extend throughDecember 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 ofSeptember 30, 2021 , our indebtedness consists of$479.9 million in principal amount of Notes outstanding and$92.0 million in borrowings under theOperating Company's revolving credit facility. We did not repurchase any Notes during the three and nine months endedSeptember 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 ofSeptember 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 of$580.0 million is expected to be reaffirmed by the lenders during the regularly scheduled (semi-annual) fall 2021 redetermination inNovember 2021 . The next semi-annual redetermination is scheduled to occur inMay 2022 . As ofSeptember 30, 2021 , there was$408.0 million available for future borrowings under theOperating Company's revolving credit facility. During the three and nine months endedSeptember 30, 2021 , the weighted average interest rate on theOperating Company's revolving credit facility was 1.98% and 2.14%, respectively. The revolving credit facility will mature onJune 2, 2025 . OnOctober 1, 2021 , the Partnership and theOperating 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 theOperating Company's revolving credit facility, reducing the amount that remained available for future borrowings under this facility to$218.0 million as ofOctober 1, 2021 .
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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