VIPER ENERGY, INC. The following discussion and analysis should be read in conjunction with our unaudited 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, 2019 . 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 onFebruary 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties inNorth America . We are currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in thePermian Basin and theEagle Ford Shale . We operate in one reportable segment. SinceMay 10, 2018 , we have been treated as a corporation forU.S. federal income tax purposes. As ofMarch 31, 2020 , our general partner had a 100% general partner interest in us, and Diamondback owned 731,500 common units and all of our 90,709,946 outstanding Class B units, representing approximately 58% of our total units outstanding. Diamondback also owns and controls our general partner.
Recent Developments
COVID-19 and Recent Collapse in Commodity Prices
OnMarch 11, 2020 , theWorld Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a "pandemic." To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Such actions have resulted in a swift and unprecedented reduction in international andU.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets. In earlyMarch 2020 , oil prices dropped sharply, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases byOPEC members and other exporting nations and the ongoing COVID-19 pandemic. The commodity prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize. 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, curtailed near term production and reduced their rig count, all of which may be subject to further reductions or curtailments if the commodity markets and macroeconomic conditions do not improve. These actions have had and are expected to continue to have an adverse effect on our business, financial results and cash flows. Although after performing the ceiling test for the quarter endedMarch 31, 2020 , we were not required to record an impairment on our proved oil and natural gas interests, if the commodity prices continue to fall, we will be required to record impairments in future periods and such impairments may be material. In addition, the administrative agent under theOperating Company's revolving credit facility has recommended that our borrowing base be decreased to$580.0 million , which is expected to be effective midMay 2020 . The decrease is subject to approval by the requisite lenders. Under the new expected borrowing base, theOperating Company would have had$406.5 million of availability for future borrowings under the revolving credit facility as ofMarch 31, 2020 . If commodity prices continue at current levels or decrease further, our production, proved reserves and cash flows will be adversely impacted. Our business may be further adversely impacted by any government rule, regulation or order that may impose production limits in thePermian Basin orEagle Ford Shale , as well as pipeline capacity and storage constraints. 20
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Table of Contents Acquisitions Update During the first quarter of 2020, we acquired mineral and royalty interests, from unrelated third-party sellers', representing 4,948 gross (410 net royalty) acres in thePermian Basin for an aggregate purchase price of approximately$63.4 million , subject to post-closing adjustments and, as ofMarch 31, 2020 , had mineral and royalty interests representing 24,714 net royalty acres. We funded these acquisitions with cash on hand and borrowings under theOperating Company's revolving credit facility.
Cash Distribution Policy Update
OnApril 30, 2020 , the board of directors of our general partner declared a cash distribution for the three months endedMarch 31, 2020 of$0.10 per common unit. The distribution is payable onMay 21, 2020 to eligible common unitholders of record at the close of business onMay 14, 2020 . This distribution represents 25% of total cash available for distribution with the remaining cash flow expected to be retained to strengthen our balance sheet. The board of directors of our general partner intends to review this distribution policy quarterly.
Production and Operational Update
Our average daily production during the first quarter of 2020 was 27,575 BOE/d (63% oil), a 6% increase from the average daily oil production during the first quarter of 2019. Our operators received an average of$45.49 per Bbl of oil,$8.94 per Bbl of natural gas liquids and$0.13 per Mcf of natural gas, for an average realized price of$30.62 per BOE. The average realized price of$0.13 per Mcf of natural gas was primarily due to the pricing terms under our operators' natural gas delivery contracts, which are generally tied to NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the first quarter of 2020, natural gas sold at the WAHA Hub inPecos County, Texas averaged a differential of$(1.60) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are mostly impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within thePermian Basin . During the first quarter of 2020, we estimate that 192 gross (4.6 net 100% royalty interest) horizontal wells, in which we have an average royalty interest of 2.4% were turned to production on our existing acreage position with an average lateral length of 9,306 feet. Of these 192 gross wells, Diamondback is the operator of 78, in which we have an average royalty interest of 3.8%, and the remaining 114 gross wells, in which have an average royalty interest of 1.4%, are operated by third parties. Additionally, during the first quarter of 2020, we acquired 410 net royalty acres for an aggregate purchase price of approximately$63.4 million , which added a further 92 gross (0.6 net 100% royalty interest) producing horizontal wells with an average royalty interest of 0.6%. In total, as ofMarch 31, 2020 , we had 2,454 vertical wells and 4,309 horizontal wells producing on our acreage with a combined average net royalty interest of 3.7%. Despite the dramatic decline in oil prices, there continues to be active development across our asset base and we currently expect our full year 2020 acreage daily production to be between 22,500 to 27,000 Boe/d. Given the recent extreme weakness in commodity prices and forward pricing uncertainty, our current 2020 production guidance does not account for the potential effect of further production curtailments. Near-term activity is expected to be driven primarily by Diamondback's operations. To that end, there are 77 gross horizontal wells operated by Diamondback currently in the process of development on our royalty acreage, in which we expect to own an average 6.6% net royalty interest (5.1 net 100% royalty interest wells). These wells currently in the process of active development include various wells being drilled by the 12 active Diamondback rigs which were on our acreage as ofApril 22, 2020 , in addition to other wells currently waiting to be completed, actively in the process of being completed or waiting to be turned to production. Additionally, based on Diamondback's current completion schedule, we have line-of-sight to a further 50 gross (4.1 net 100% royalty interest) wells for which the process of active development has not yet begun, but for which we have visibility to the potential of future development in coming quarters. There is currently less visibility into third party operators' anticipated activity levels and well completion cadence given the current commodity price environment. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the current depressed oil prices and tight physical markets. Notwithstanding the foregoing, third parties continue to operate on our asset base. There are 492 gross horizontal wells operated by third parties in the process of active development, in which we expect to own an average 0.9% net royalty interest (4.4 net 100% royalty interest wells). Additionally, there are 379 gross (4.2 net 100% royalty interest) wells operated by third parties that have been permitted but not yet begun the process of active development. In total, as ofApril 22, 2020 , between Diamondback and third party operators, there were 569 (9.5 net 100% royalty interest) wells currently in the process of active development, including 37 active rigs, and a further 429 gross (8.2 net 100% royalty interest) line-of-sight wells which have not yet begun the process of active development. The acquisitions that we closed during the first quarter of 2020 contributed 39 gross (0.2 net 100% royalty interest) horizontal wells in the process of active development out of the total 569 21
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currently in our portfolio. Further, these recent acquisitions also contributed
18 gross (0.1 net 100% royalty interest) permits out of the total 429 total
gross line-of-sight wells for which the process of active development has not
yet begun.
Results of Operations
The following table summarizes our revenue and expenses and production data for
the periods indicated:
Three Months Ended March 31,
2020 2019
(in thousands)
Operating Results:
Operating income:
Royalty income $ 76,829 $ 60,428
Lease bonus income 1,622 1,160
Other operating income 241 2
Total operating income 78,692 61,590
Costs and expenses:
Production and ad valorem taxes 6,147 3,692
Depletion 24,642 16,199
General and administrative expenses 2,666 1,695 Total costs and expenses 33,455 21,586 Income from operations 45,237 40,004 Other income (expense): Interest expense, net (8,963 ) (4,549 ) Loss on derivative instruments, net (7,942 ) - (Loss) gain on revaluation of investment (10,120 ) 3,592 Other income, net 404 656 Total other expense, net (26,621 ) (301 ) Income before income taxes 18,616
39,703
Provision for (benefit from) income taxes 142,466 (34,608 ) Net (loss) income (123,850 ) 74,311 Net income attributable to non-controlling interest 18,319
40,532
Net (loss) income attributable to
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Three Months Ended March 31,
2020 2019
Production Data:
Oil (MBbls) 1,587 1,147
Natural gas (MMcf) 2,658 1,872
Natural gas liquids (MBbls) 479 254
Combined volumes (MBOE) 2,509 1,714
Average daily oil volumes (BO/d) 17,441 12,750
Average daily combined volumes (BOE/d) 27,575 19,042 Average sales prices: Oil ($/Bbl) $ 45.49 $ 45.31 Natural gas ($/Mcf)(1) $ 0.13 $ 2.05 Natural gas liquids ($/Bbl) $ 8.94 $ 18.09 Combined ($/BOE) $ 30.62 $ 35.26 Oil, hedged ($/Bbl)(2) $ 45.49 $ 45.31 Natural gas, hedged ($/MMbtu)(2) $ (0.04 ) $
2.05
Natural gas liquids ($/Bbl)(2) $ 8.94 $
18.09
Combined price, hedged ($/BOE)(2) $ 30.44 $
35.26
Average Costs ($/BOE): Production and ad valorem taxes $ 2.45 $
2.15
General and administrative - cash component 0.91
0.75
Total operating expense - cash $ 3.36 $
2.90
General and administrative - non-cash component $ 0.15 $
0.24 Interest expense, net $ 3.57 $ 2.65 Depletion $ 9.82 $ 9.45
(1) The average realized price of
to the pricing terms under our operators' natural gas delivery contracts,
which are generally tied to NYMEX price quoted at Henry Hub. Actual
volumetric prices realized from the sale of natural gas, however, differ from
the quoted NYMEX price as a result of quality and location differentials.
During the first quarter of 2020, natural gas sold at the WAHA Hub in
County,
quoted at Henry Hub. Our operators may have varying terms under which they
sell their natural gas, but we are mostly impacted by location differences
resulting from supply and demand imbalances and limited takeaway capacity
within the
(2) Hedged prices reflect the effect of our commodity derivative transactions on
our average sales prices. Our calculation of such effects includes gains and
losses on cash settlements for commodity derivatives, which we do not
designate for hedge accounting. We did not have any derivative contracts
prior to February of 2020.
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Comparison of the Three Months Ended
Royalty Income
Our royalty income for the three months endedMarch 31, 2020 and 2019 was$76.8 million and$60.4 million , respectively. Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes. The decrease in average prices received during the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 was partially offset by a 46% increase in combined volumes sold by our operators as compared to the three months endedMarch 31, 2019 . Production Total net dollar Change in prices volumes(1) effect of change (in thousands) Effect of changes in price: Oil $ 0.19 1,587 $ 294 Natural gas $ (1.92 ) 2,658 (5,109 ) Natural gas liquids $ (9.15 ) 479 (4,383 ) Total income due to change in price$ (9,198 ) Change in production Prior period Total net dollar volumes(1) average prices effect of change (in thousands) Effect of changes in production volumes: Oil 440 $ 45.31$ 19,919 Natural gas 787 $ 2.05 1,614 Natural gas liquids 225 $ 18.09 4,066 Total income due to change in production volumes 25,599 Total change in income$ 16,401
(1) Production volumes are presented in MBbls for oil and natural gas liquids and
MMcf for natural gas.
Lease Bonus Income
Lease bonus income increased by $0.5 million for the three months ended
March 31, 2020 as compared to the three months ended March 31, 2019 . During the
three months ended March 31, 2020 , we received $0.3 million in lease bonus
payments to extend the term of one lease and $1.3 million for two new leases.
During the three months ended March 31, 2019 , we received $44,688 in lease bonus
payments to extend the term of five leases and $1.1 million for six new leases.
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Production and Ad Valorem Taxes
Production taxes per unit of production for the three months endedMarch 31, 2020 and 2019 were$1.43 and$1.75 , respectively. The decrease in production taxes per unit of production during the three months endedMarch 31, 2020 was primarily due to a higher percentage increase in production volumes as compared to production taxes. Ad valorem taxes per unit of production for the three months endedMarch 31, 2020 and 2019 were$1.02 and$0.40 , respectively. The increase in ad valorem taxes per unit of production during the three months endedMarch 31, 2020 was primarily due to an increase in production volumes from wells drilled and acquired in 2019, along with an increase in the valuation of oil and natural gas interests year over year. Three Months Ended March 31, 2020 2019 Amount Amount (in thousands) Per BOE (in thousands) Per BOE Production taxes$ 3,575 $ 1.43 $ 3,008$ 1.75 Ad valorem taxes 2,572 1.02 684 0.40
Total production and ad valorem taxes
3,692 $ 2.15
Depletion
Depletion expense increased by
General and Administrative Expenses
The general and administrative expenses primarily reflect costs associated with us being a publicly traded limited partnership, unit-based compensation and the amounts reimbursed to our general partner under our partnership agreement. For the three months endedMarch 31, 2020 and 2019, we incurred general and administrative expenses of$2.7 million and$1.7 million , respectively. The increase of$1.0 million during the three months endedMarch 31, 2020 was due to an increase in expenses allocated from the General Partner under the Partnership Agreement, an increase in software expenses, bad debt expense and additional professional service fees attributable to acquisitions.
Net Interest Expense
Net interest expense for the three months endedMarch 31, 2020 and 2019 was$9.0 million and$4.5 million , respectively. The increase of$4.4 million in net interest expense for three months endedMarch 31, 2020 as compared to 2019 was due to increased borrowings and our senior notes issued inOctober 2019 .
Derivatives
We recorded a loss on derivatives for the three months endedMarch 31, 2020 of$7.9 million . We had no derivatives during the three months endedMarch 31, 2019 . 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 consolidated statements of operations under the line item captioned "Loss on derivative instruments, net."
Provision for (Benefit from) Income Taxes
We recorded income tax expense of$142.5 million and income tax benefit of$34.6 million for the three months endedMarch 31, 2020 and 2019, respectively. The change in our income tax provision was primarily due to the application of a valuation allowance on the our deferred tax assets during the three months endedMarch 31, 2020 , and the revision during the three months endedMarch 31, 2019 of estimated deferred taxes recognized as a result of our change in federal income tax status. Total income tax provision for the three months endedMarch 31, 2020 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to impact of recording a valuation allowance on our deferred tax assets and net income attributable to the non-controlling interest. 25
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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) plus interest expense, net,
non-cash unit-based compensation expense, depletion expense, (loss) gain on
revaluation of investment, non-cash loss (gain) on derivative instruments and
provision for (benefit from) income taxes. Adjusted EBITDA is not a measure of
net (loss) income as determined by GAAP. We exclude the items listed above from
net (loss) income 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.
Adjusted EBITDA should not be considered an alternative to, or more meaningful
than, net income, royalty income, cash flow from operating activities or any
other measure of financial performance or liquidity presented in accordance with
GAAP. Our computations of Adjusted EBITDA may not be comparable to other
similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDA to net income
(loss), our most directly comparable GAAP financial measure for the periods
indicated:
Three Months Ended March 31,
2020 2019
(In thousands)
Net (loss) income $ (123,850 ) $ 74,311
Interest expense, net 8,963 4,549
Non-cash unit-based compensation expense 387 405
Depletion 24,642 16,199
(Loss) gain on revaluation of investment 10,120 (3,592 ) Non-cash loss on derivative instruments, net 7,489 - Provision for (benefit from) income taxes 142,466 (34,608 ) Consolidated Adjusted EBITDA 70,217
57,264
EBITDA attributable to non-controlling interest (40,175 ) (30,708 ) Adjusted EBITDA attributable to Viper Energy Partners LP $ 30,042$ 26,556 Non-GAAP Financial Measures
Gross oil, natural gas, and natural gas liquids sales and net sales prices
Revenues and gathering and transportation expenses related to production are
reported net in our financial statements under GAAP. This impacts the
comparability of certain operating metrics, such as per-unit sales prices, as
those metrics are prepared in accordance with GAAP using the net presentation
for some revenues and the gross presentation for other metrics. In order to
provide metrics consistent with management's assessment of our operating
results, we have presented both net (GAAP) and gross (non-GAAP) oil, natural
gas, and natural gas liquid sales and the gross sales price. The gross sales
price (non-GAAP), is calculated by using the net oil, natural gas, and natural
liquid gas net revenues plus gathering and transportation expenses divided by
the sales volumes. We believe presenting our gross revenues and sales prices
allows for a useful comparison of net and gross sales prices for prior periods.
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The following table presents a reconciliation of net oil, natural gas and natural gas liquids sales (GAAP) to gross oil, natural gas and natural gas liquids sales (non-GAAP) for the periods indicated:
Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Oil Natural gas Natural gas Total Oil Natural gas Natural gas Total
(in thousands) liquids liquids
Net oil, natural gas
and natural gas
liquids sales (GAAP) $ 72,200 $ 344 $ 4,285 $ 76,829 $ 51,987 $ 3,839 $ 4,602 $ 60,428
Plus: Gathering and
transportation
expenses 287 414 380 1,081 234 305 249 788
Gross oil, natural
gas and natural gas
liquids sales
(non-GAAP) $ 72,487 $ 758 $ 4,665
2,658 479 2,509 1,147 1,872 254 1,714
Gross sales price
(non-GAAP) $ 45.67 $ 0.29 $ 9.74 $ 31.05 $ 45.51 $ 2.21 $ 19.07 $ 35.72 Liquidity and Capital Resources
Overview
Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings and borrowings under our credit agreement, and our primary uses of cash have been, and are expected to continue to be, distributions to our unitholders and replacement and growth capital expenditures, including the acquisition of mineral interests and royalty interests in oil and natural gas properties. We intend to finance potential future acquisitions through a combination of cash on hand, borrowings under our credit agreement, issuance of common units to the sellers 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 weather. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions, may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Our partnership agreement does not require us to distribute any of the cash we generate from operations. However, the board of directors of our general partner has adopted a policy pursuant to which theOperating Company will distribute all of the available cash it generates each quarter to its unitholders (including us), and we, in turn, will distribute all of the available cash we receive from theOperating Company to our common unitholders. Cash distributions are made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for us and theOperating Company for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for theOperating Company for each quarter will generally equal its Adjusted EBITDA reduced for cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any, and our available cash will generally equal our Adjusted EBITDA (which will be our proportionate share of the available cash distributed to us by theOperating Company ), less, as a result of the our election to be treated as a corporation forU.S. federal income tax purposes effective,May 10, 2018 , cash needed for the payment of income taxes payable by us, if any. OnApril 30, 2020 , the board of directors of our general partner approved a cash distribution for the first quarter of 2020 of$0.10 per common unit, payable onMay 21, 2020 , to eligible unitholders of record at the close of business onMay 14, 2020 . 27
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Table of Contents 2019 Equity Offering InMarch 2019 , we completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 54% of our total units then outstanding. We received net proceeds from this offering of approximately$340.6 million , after deducting underwriting discounts and commissions and estimated offering expenses. We used the net proceeds to purchase units of theOperating Company .The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under theOperating Company's revolving credit facility and finance acquisitions during the period.
Cash Flows
The following table presents our cash flows for the period indicated:
Three Months Ended March 31,
2020 2019
(in thousands)
Cash Flow Data:
Net cash provided by operating activities
(64,626 ) (81,923 )
Net cash provided by financing activities 5,184 22,929
Net increase (decrease) in cash $ 36,669 $ (12,543 )
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. Prices for these commodities are
determined primarily by prevailing market conditions. Regional and worldwide
economic activity, weather and other substantially variable factors influence
market conditions for these products. These factors are beyond our control and
are difficult to predict.
Investing Activities
Net cash used in investing activities was $64.6 million and $81.9 million during
the three months ended March 31, 2020 and 2019, respectively, and related to
acquisitions of oil and natural gas interests and land.
Financing Activities
Net cash provided by financing activities was$5.2 million during the three months endedMarch 31, 2020 , primarily related to net borrowing activity under theOperating Company's revolving credit facility of$77.0 million and partially offset by distributions of$71.4 million to our unitholders during the period. Net cash provided by financing activities was$22.9 million during the three months endedMarch 31, 2019 , primarily related to net proceeds from our public offering of common units of$340.6 million , partially offset by net repayments on borrowings of$254.0 million under the revolving credit facility and distributions of$63.3 million to our unitholders during that period.
OnJuly 20, 2018 , we, as guarantor, entered into an amended and restated credit agreement with theOperating Company , as borrower, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended to the date hereof, provides for a revolving credit facility in the maximum credit amount of$2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors of$725.0 million , subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates ofMay 1st andNovember 1st . In addition, theOperating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As ofMarch 31, 2020 , the borrowing base was set at$775.0 million and theOperating Company had$173.5 million of outstanding borrowings and$601.5 million available for future borrowings under theOperating Company's revolving credit facility. In connection with our regularly scheduled (semi-annual) spring 2020 redetermination, our administrative agent has recommended that our borrowing base be decreased to$580.0 million , which is expected to be effective 28
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midMay 2020 . The decrease is subject to approval by the requisite lenders under theOperating Company's revolving credit facility. Under the new expected borrowing base, theOperating Company would have had$406.5 million of availability for future borrowings under the revolving credit facility as ofMarch 31, 2020 . The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date ofNovember 1, 2022 . The loan is secured by substantially all of our and our subsidiary's assets. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described below: Financial Required Ratio Covenant
Ratio of total net debt to EBITDAX, as defined in the credit Not greater than agreement
4.0 to 1.0
Ratio of current assets to liabilities, as defined in the Not less than 1.0 credit agreement
to 1.0
The covenant prohibiting additional indebtedness allows for the issuance of
unsecured debt of up to $1.0 billion in the form of senior unsecured notes and,
in connection with any such issuance, the reduction of the borrowing base by 25%
of the stated principal amount of each such issuance. A borrowing base reduction
in connection with such issuance may require a portion of the outstanding
principal of the loan to be repaid.
As of March 31, 2020 , the Operating Company was in compliance with the financial
maintenance covenants under its credit agreement. The lenders may accelerate all
of the indebtedness under the Operating Company's revolving credit facility upon
the occurrence and during the continuance of any event of default. The credit
agreement contains customary events of default, including non-payment, breach of
covenants, materially incorrect representations, cross-default, bankruptcy and
change of control. With certain specified exceptions, the terms and provisions
of our credit agreement generally may be amended with the consent of the lenders
holding a majority of the outstanding loans or commitments to lend.
Notes Offering
OnOctober 16, 2019 , we issued our 5.375% Senior Notes due 2027 in the aggregate principal amount of$500.0 million (which we refer to as the Notes) in a notes offering (which we refer to as the Notes Offering) under an indenture, dated as ofOctober 16, 2019 , among the Partnership, as issuer, theOperating Company , as guarantor andWells Fargo Bank, National Association , as trustee, which we refer to as the Indenture. We received net proceeds of approximately$490.0 million from the Notes Offering. We loaned the gross proceeds of the Notes Offering to theOperating Company .The Operating Company used the proceeds from the Notes Offering to repay then outstanding borrowings under its revolving credit facility. Interest on the Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof fromOctober 16, 2019 , payable semi-annually onMay 1 andNovember 1 of each year, commencing onMay 1, 2020 . The Notes will mature onNovember 1, 2027 . 29
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The Operating Company guaranteed the Notes pursuant to the Indenture. Neither Diamondback nor the General Partner guarantees the Notes. The Indenture contains restrictive certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets including equity of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens and designate certain of our subsidiaries as unrestricted subsidiaries. Certain of these covenants are subject to termination upon the occurrence of certain events. We may use cash on hand to repurchase a portion of the Notes in privately negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.
Intercompany Promissory Note
In connection with and upon closing of the Notes Offering, we loaned the gross proceeds from the Notes Offering to theOperating Company under the terms of that certain subordinated promissory note, dated as ofOctober 16, 2019 , by theOperating Company in favor of us, which we refer to as the Intercompany Promissory Note. The Intercompany Promissory Note requires theOperating Company to repay the underlying loan to us on the same terms and in the same amounts as the Notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. Our right to receive payment under the Intercompany Promissory Note is contractually subordinated to theOperating Company's guarantee of the notes and is structurally subordinated to all of theOperating Company's secured indebtedness (including all borrowings and other obligations under theOperating Company's revolving credit facility) to the extent of the value of the collateral securing such indebtedness.
Contractual Obligations
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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