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 consolidated 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 operate in two business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in thePermian Basin inWest Texas and (ii) through our publicly-traded subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of thePermian Basin . 2020 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 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. 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 sharp decline in commodity prices during the first quarter of 2020, we recorded a non-cash ceiling test impairment for the three months endedMarch 31, 2020 of$1.0 billion . The impairment charge adversely affected our results of operations but did not reduce our cash flows. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. Our production, proved reserves and cash flows will also be adversely impacted. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in thePermian Basin where we operate.
Our Response to the Commodity Price Volatility and Impact of COVID-19
• We have taken swift and decisive actions to protect the health and safety
of our employees and preserve the strength of our organization during the
COVID-19 pandemic and the depressed commodity price markets.
• We immediately responded to the sharp drop in commodity prices in early
March 2020 by ceasing all completion operations for a minimum of one month. • We have hedged approximately 100% of our remaining expected 2020 oil
production, including basis differentials and a majority of WTI contract
exposure and removed all three-way collar hedge exposure to maximize downside protection.
• We have hedged approximately 50% of our expected 2021 oil production in
the form of swaps and two-way collars. 41
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• We plan to voluntarily curtail 10% to 15% of our expected
production in areas where we can manage production economically and
without the addition of material operating expense, and will continue to
monitor whether additional strategic curtailments are warranted inJune 2020 and in future periods. • We immediately reduced our full year 2020 capital budget by over 40%,
while high-grading our operating plan to acreage with the highest returns
where we own mineral and royalty interests and have low required midstream
or infrastructure expenditures.
• We plan to average less than one completion crew in the second quarter of
2020 to meet our leasehold obligations and will assess bringing completion
crews back to work in the third quarter of 2020 depending on the commodity
price environment. • We expect to complete less than 10% of our estimated full year 2020 completed gross well count in the second quarter of 2020. • We currently are operating 14 drilling rigs and plan to enter the third
quarter of 2020 running eight drilling rigs and enter the fourth quarter
of 2020 running seven drilling rigs, with the ability to reduce the rig
count further should conditions warrant in the fourth quarter of 2020 and
into 2021.
• We have reduced our operating costs by increasing water infrastructure
efficiencies and reducing trucking costs.
• We have reduced flaring to less than 0.5% of net production at the end of
the first quarter 2020 from over 1.5% of net production in
First Quarter 2020 Highlights
• We recorded a net loss of
31, 2020.
• Our average production was 321.1 MBOE/d), with average oil production up
12% over the first quarter of 2019. • We turned 80 gross operated wells to production and had capital expenditures of$790 million during the first quarter of 2020.
• As of
borrowings under our revolving credit facility and approximately
billion of cash on hand.
• Our cash operating costs for the first quarter ended
$8.52 per BOE; including cash general and administrative expenses of$0.51 per BOE.
• On
first quarter of 2020 of$0.3750 per share of common stock, payable onMay 21, 2020 to our stockholders of record at the close of business ofMay 14, 2020 .
• During the three months ended
$98 million of common stock under our$2 billion repurchase program approved by our board of directors inMay 2019 and, as ofMarch 31, 2020 ,$1.3 billion remained available for future repurchases under this stock
repurchase program although we have suspended this program to preserve
liquidity. Upstream Segment In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in theMidland Basin and the Wolfcamp and Bone Spring formations in theDelaware Basin . We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Also, in our upstream segment, our publicly-traded subsidiary Viper is focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in thePermian Basin and theEagle Ford Shale and derives royalty income and lease bonus income from such interests. 42
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As ofMarch 31, 2020 , we had approximately 382,404 net acres, which primarily consisted of approximately 200,056 net acres in theMidland Basin and approximately 155,304 net acres in theDelaware Basin . As ofDecember 31, 2019 , we had an estimated 12,310 gross horizontal locations that we believe to be economic at$60 per Bbl West Texas Intermediate, or WTI.
The following table sets forth the total number of operated horizontal wells
drilled and completed during the three months ended
Three Months Ended March 31, 2020(1) Drilled Completed Area Gross Net Gross Net Midland Basin 55 50 34 30 Delaware Basin 38 35 46 42 Total 93 85 80 72
(1) The average lateral length for the wells completed during the first quarter
of 2020 was 9,751 feet. Operated completions during the first quarter of 2020
consisted of 47 Wolfcamp A wells, nine Wolfcamp B wells, seven Lower
Spraberry wells, six Middle Spraberry wells, two
As of
Vertical Wells Horizontal Wells Total Area Gross Net Gross Net Gross Net Midland Basin 1,548 1,454 1,041 952 2,589 2,406 Delaware Basin 32 23 544 509 576 532 Total 1,580 1,477 1,585 1,461 3,165 2,938
As of
Our development program is focused entirely within thePermian Basin , where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in theMidland Basin and the Wolfcamp andBone Springs formations in theDelaware Basin .
Midstream Operations
In our midstream operations segment, Rattler's crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler's facilities gather crude oil from horizontal and vertical wells in our ReWard,Spanish Trail ,Pecos andGlasscock areas within thePermian Basin . Rattler's natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from ourPecos area assets within thePermian Basin . Rattler's water sourcing and distribution assets consists of water wells, hydraulic fracturing pits, pipelines and water treatment facilities, which collectively gather and distribute water fromPermian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler's produced water gathering and disposal system spans approximately 482 miles and consists of gathering pipelines along with produced water disposal wells and facilities which collectively gather and dispose of produced water from operations throughout ourPermian Basin acreage. We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler's infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in theDelaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications. 43
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Sources of Our Revenues
In our exploration and production segment, our main sources of revenues are the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing, derived from our net revenue and royalty interests. In our midstream operations segment, our results are primarily driven by the volumes of crude oil that Rattler gathers, transports and delivers; natural gas that Rattler gathers, compresses, transports and delivers; fresh water that Rattler sources, transports and delivers; and produced water that Rattler gathers, transports and disposes of, and the fees Rattler charges per unit of throughput for our midstream services.
The following table presents the breakdown of our oil and natural gas revenues for the following periods:
Three Months Ended March 31, 2020 2019 Revenues: Oil sales 94 % 88 % Natural gas sales - % 3 % Natural gas liquid sales 6 % 9 % 100 % 100 % Commodity Prices In our upstream business, our production consists primarily of oil. As a result, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas or natural gas liquids prices. Oil, natural gas and natural gas liquids prices have historically been volatile. Oil prices dropped sharply in earlyMarch 2020 , 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 oil exporting nations and the ongoing COVID-19 pandemic. During the first quarter of 2020, the depressed commodity prices negatively impacted our revenue, production and results of operations, and we recorded an impairment on proved oil and natural gas properties. In addition, the administrative agent under Viper's credit agreements has recommended that the borrowing base under such credit agreement be decreased to$580 million effectivemid-May 2020 . Oil and natural gas prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize. If commodity prices continue at current levels or decrease further, our ability to produce oil and natural gas economically and, as a result, our business, results of operations and financial condition will be adversely affected. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits in thePermian Basin where we operate. In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler's other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler's other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler's commercial agreements do not contain minimum volume commitments. 44
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The following table sets forth information related to commodity prices for the following periods: Three Months Ended March 31, 2020 2019 High and Low Futures Contract Prices: Oil ($/Bbl, WTI Futures Contract 1) High$ 63.27 $ 60.14 Low$ 20.09 $ 46.54 Natural Gas ($/MMBtu, Futures Contract 1) High$ 2.20 $ 3.59 Low$ 1.60 $ 2.55 Average realized oil price ($/Bbl)$ 45.10 $ 46.12 Average WTI Futures Contract 1 ($/Bbl)$ 45.78 $ 54.90 Differential to WTI Futures Contract 1 (0.68 ) (8.78 ) Average realized oil price to WTI Futures Contract 1 99 % 84 % Average realized natural gas price ($/Mcf)$ 0.14 $ 1.32 Average Natural Gas Futures Contract 1 ($/Mcf)$ 1.87 $ 2.87 Differential to Natural Gas Futures Contract 1 (1.73 )
(1.55 ) Average realized natural gas price to Natural Gas Futures Contract 1
7 % 46 %
Average realized natural gas liquids price ($/Bbl)
$ 18.00 Average WTI Futures Contract 1 ($/Bbl)$ 45.78 $ 54.90 Average realized natural gas liquids price to WTI Futures Contract 1 21 % 33 %
On
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Results of Operations
The following table sets forth selected historical operating data for the three
months ended
Three Months Ended March 31, 2020 2019 (in thousands) Production Data: Oil (MBbls) 18,325 16,115 Natural gas (MMcf) 32,120 21,684 Natural gas liquids (MBbls) 5,538 3,908 Combined volumes (MBOE) 29,216 23,637 Daily combined volumes (BOE/d) 321,057 262,633 Daily oil volumes (BO/d) 201,369 179,056 Average Prices: Oil ($ per Bbl) $ 45.10$ 46.12 Natural gas ($ per Mcf) $ 0.14$ 1.32 Natural gas liquids ($ per Bbl) $ 9.45$ 18.00 Combined ($ per BOE) $ 30.23$ 35.63 Oil, hedged ($ per Bbl)(1) $ 49.32$ 46.92 Natural gas, hedged ($ per MMbtu)(1) $ 0.42$ 1.49 Natural gas liquids, hedged ($ per Bbl)(1) $ 9.45$ 18.19 Average price, hedged ($ per BOE)(1) $
33.19
(1) Hedged prices reflect the effect of our commodity derivative transactions on
our average sales prices. Our calculation of such effects include gains and
losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.
Production Data
Substantially all of our revenues are generated through the sale of oil, natural
gas liquids and natural gas production. The following tables set forth our
production data for the three months ended
Three Months Ended March 31, 2020 2019 Oil (MBbls) 63 % 68 % Natural gas (MMcf) 18 % 15 % Natural gas liquids (MBbls) 19 % 17 % 100 % 100 % 46
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Three Months EndedMarch 31, 2020
Three Months Ended
MidlandDelaware
Midland
Basin Basin Other(1) Total Basin
Basin Other(2) Total
(in thousands) Production Data: Oil (MBbls) 10,511 7,760 54 18,325 9,984 5,026 1,105 16,115 Natural gas (MMcf) 15,833 16,147 140 32,120 10,172 11,137 375 21,684 Natural gas liquids (MBbls) 3,048 2,463 27 5,538 2,176 1,671 61 3,908 Total (MBoe) 16,198 12,914 104 29,216 13,855 8,553 1,229 23,637
(1) Includes the Central Basin Platform, the
(2) Includes the
Comparison of the Three Months Ended
Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and natural gas liquids revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes. Our oil, natural gas and natural gas liquids revenues for the three months endedMarch 31, 2020 increased by$41 million , or 5%, to$883 million from$842 million during the three months endedMarch 31, 2019 , primarily due to an increase in oil, natural gas and natural gas liquids production volumes, partially offset by lower average sales prices. The increase in production volumes was due to a combination of increased drilling activity and growth through acquisitions. The net dollar effect of the change in prices (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and natural gas liquids) and the net dollar effect of the change in production (calculated as the increase in period-to-period volumes for oil, natural gas and natural gas liquids multiplied by the period average prices) are shown below: Three Months
Ended
Production Total net dollar Change in prices volumes(1) effect of change (in millions) Effect of changes in price: Oil$ (1.02 ) 18,325 $ (19 ) Natural gas$ (1.18 ) 32,120 (38 ) Natural gas liquids$ (8.55 ) 5,538 (47 ) Total revenues due to change in price $ (104 ) Change in production Prior period Average Total net dollar volumes(1) Prices effect of change (in millions) Effect of changes in production volumes: Oil 2,210 $ 46.12 $ 102 Natural gas 10,436 $ 1.32 14 Natural gas liquids 1,630 $ 18.00 29 Total revenues due to change in production volumes 145 Total change in revenues $ 41 (1) Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas. 47
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Midstream Services Revenue. The following table shows midstream services revenue
for the three months ended
Three Months Ended March 31, 2020 2019 (in millions) Midstream services revenue $ 14$ 19 Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.
Lease Operating Expenses. The following table shows lease operating expenses for
the three months ended
Three Months Ended March 31, 2020 2019 Amount Per BOE Amount Per BOE (in millions, except per BOE amounts) Lease operating expenses$ 127 $ 4.35 $ 109 $ 4.61 Lease operating expenses for the three months endedMarch 31, 2020 increased by$18 million as compared to the three months endedMarch 31, 2019 . This increase is primarily associated with our higher well count due to new drilling activity and, to a lesser extent, power generation costs as a result of reduced electrical availability. We are actively working to mitigate this power generation issue and expect these costs to decrease in the future. Lease operating expenses per BOE decreased by$0.26 for the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 , primarily due to higher production from our increased drilling activity during the period and growth through acquisitions.
Production and Ad Valorem Tax Expense. The following table shows production and
ad valorem tax expense for the three months ended
Three Months Ended March 31, 2020 2019 Amount Per BOE Amount Per BOE (in millions, except per BOE amounts) Production taxes$ 42 $ 1.42 $ 41 $ 1.73 Ad valorem taxes 29 1.01 14 0.60 Total production and ad valorem expense$ 71 $ 2.43 $
55
In general, production taxes and ad valorem taxes are directly related to commodity price changes; however,Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. Production taxes for the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 increased by$1 million due to increased overall production from acquisitions and well completions. Production taxes per BOE for the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 decreased by$0.31 primarily due to a higher percentage increase in production volumes as compared to production taxes. Ad valorem taxes for the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 increased by$15 million primarily due to an increase in production volumes from wells drilled and completed in 2019. 48
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Midstream Services Expense. The following table shows midstream services expense
for the three months ended
Three Months Ended March 31, 2020 2019 (in millions) Midstream services expense $ 23$ 17
Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.
Depreciation, Depletion and Amortization. The following table provides the
components of our depreciation, depletion and amortization expense for the three
months ended
Three Months Ended March 31, 2020 2019 (in millions, except BOE amounts) Depletion of proved oil and natural gas properties $ 392$ 311 Depreciation of midstream assets 11 8 Depreciation of other property and equipment 4 3 Depreciation, depletion and amortization expense $
407
$ 13.93$ 13.62
The increase in depletion of proved oil and natural gas properties of
Impairment ofOil and Natural Gas Properties . The following table shows impairment of oil and natural gas properties for the three months endedMarch 31, 2020 and 2019: Three Months Ended March 31, 2020 2019 (in millions) Impairment of oil and natural gas properties$ 1,009
$ -
As a result of the sharp decline in commodity prices during the first quarter of 2020, we recorded a non-cash ceiling test impairment for the three months endedMarch 31, 2020 of$1.0 billion which was included in accumulated depletion. The impairment charge affected our results of operations but did not reduce cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. No impairment on proved oil and natural gas properties was recorded for the three months endedMarch 31, 2019 . 49
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General and Administrative Expenses. The following table shows general and
administrative expenses for the three months ended
Three Months Ended March 31, 2020 2019 Amount Per BOE Amount Per BOE (in millions, except per BOE amounts) General and administrative expenses$ 15 $ 0.51 $ 13 $ 0.55 Non-cash stock-based compensation 9 0.31
14 0.59
Total general and administrative expenses
General and administrative expenses for the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 decreased by$3 million primarily due to a decrease in non-cash stock compensation partially offset by higher salary and benefit expenses, legal fees, community donations and software license expenses.
Net Interest Expense. The following table shows net interest expense for the
three months ended
Three Months Ended March 31, 2020 2019 (in millions) Net interest expense $ 48$ 46 Net interest expense for the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 , increased by$2 million . This increase was primarily due to increased average borrowings under our credit facility partially offset by a decrease in interest expense of$3 million related to our DrillCo Agreement during the three months endedMarch 31, 2020 as compared to the three months endedMarch 31, 2019 .
Derivative Instruments. The following table shows the gain (loss) on derivative
instruments, net for the three months ended
Three Months EndedMarch 31, 2020 2019 (in millions)
Change in fair value of open non-hedge derivative instruments
$ (285 ) Gain on settlement of non-hedge derivative instruments 87
17
Gain (loss) on derivative instruments, net$ 542
We are required to recognize all derivative instruments on the 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 "Gain (loss) on derivative instruments, net." Provision for (Benefit From) Income Taxes. The following table shows provision for (benefit from) income taxes for the three months endedMarch 31, 2020 and 2019: Three Months Ended March 31, 2020 2019 (in millions) Provision for (benefit from) income taxes $ 83$ (33 ) 50
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The change in our income tax provision was primarily due to the pre-tax loss for the three months endedMarch 31, 2020 offset by discrete tax expense resulting from application of a valuation allowance on Viper's deferred tax assets, compared to pre-tax income for the three months endedMarch 31, 2019 , offset by a discrete income tax benefit resulting from the revision of estimated deferred taxes recognized as a result of Viper's change in tax status.
Liquidity and Capital Resources
Historically, our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of our senior notes and cash flows from operations. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. 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.
Liquidity and Cash Flow
Our cash flows for the three months endedMarch 31, 2020 and 2019 are presented below: Three Months EndedMarch 31, 2020 2019 (in millions)
Net cash provided by operating activities $ 849 $ 377 Net cash used in investing activities
(923 ) (937 ) Net cash provided by financing activities 101 471 Net increase (decrease) in cash $ 27 $ (89 )
Operating Activities
Net cash provided by operating activities was$849 million for the three months endedMarch 31, 2020 as compared to$377 million for the three months endedMarch 31, 2019 . The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in production growth partially offset by a decrease in average prices during the three months endedMarch 31, 2020 . Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. 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. See "-Sources of our revenue" above.
Investing Activities
The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. Net cash used in investing activities was$923 million and$937 million during the three months endedMarch 31, 2020 and 2019, respectively. During the three months endedMarch 31, 2020 , we spent (a)$746 million on capital expenditures in conjunction with our development program, in which we drilled 93 gross (85 net) operated horizontal wells, of which 38 gross (35 net) wells were in theDelaware Basin and the remaining wells were in theMidland Basin , and turned 80 gross (72 net) operated horizontal wells into production, of which 46 gross (42 net) wells were in theDelaware Basin and the remaining wells were in theMidland Basin , (b)$44 million on additions to midstream assets, (c)$40 million on leasehold interest acquisitions, (d)$65 million for the acquisition of mineral interests, (e)$23 million on equity method investment contributions net of distributions received and (f)$5 million for the purchase of other property, equipment and land. 51
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During the three months endedMarch 31, 2019 , we spent (a)$569 million on capital expenditures in conjunction with our drilling program and related infrastructure projects, in which we drilled 83 gross (73 net) operated horizontal wells, of which 40 gross (36 net) wells were in theDelaware Basin and the remaining wells were in theMidland Basin , and turned 82 gross (74 net) operated horizontal wells into production, of which 28 gross (24 net) wells were in theDelaware Basin and the remaining wells were in theMidland Basin , (b)$58 million on additions to midstream assets, (c) $75 million on leasehold interest acquisitions, (d)$82 million for mineral interests acquisitions, (e)$4 million for the purchase of other property, equipment and land and (f)$149 million on equity method investments.
Our investing activities for the three months ended
Three Months EndedMarch 31, 2020 2019 (in millions)
Drilling, completions and non-operated $ (690 ) $ (533 ) Additions to infrastructure assets
(56 ) (36 ) Additions to midstream assets (44 ) (58 ) Purchase of other property, equipment and land (5 ) (4 ) Acquisitions of leasehold interests (40 ) (75 ) Acquisitions of mineral interests (65 ) (82 ) Contributions to equity method investments (33 ) (149 ) Distributions from equity method investments 10
-
Net cash used in investing activities $ (923 ) $ (937 )
Financing Activities Net cash provided by financing activities for the three months endedMarch 31, 2020 and 2019 was$101 million and$471 million , respectively. During the three months endedMarch 31, 2020 , the amount provided by financing activities was primarily attributable to$290 million of borrowings, net of repayments under our credit facility and$16 million in proceeds from joint ventures, partially offset by$5 million of share repurchases for tax withholdings,$98 million of share repurchases as part of our stock repurchase program,$59 million of dividends to stockholders and$43 million of distributions to non-controlling interest. The 2019 amount provided by financing activities was primarily attributable to$170 million of borrowings, net of repayments under our credit facility, an aggregate of$341 million of net proceeds from Viper's public offering, partially offset by$26 million of distributions to non-controlling interest,$21 million of dividends to stockholders,$23 million in proceeds from joint ventures and$13 million of share repurchases for tax withholdings.
2025 Senior Notes
OnDecember 20, 2016 , we issued$500 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the existing 2025 notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, which we refer to as the 2025 indenture. OnJanuary 29, 2018 , we issued$300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture, which we refer to as the new 2025 notes and, together with the existing 2025 notes, as the 2025 senior notes. The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears onMay 31 andNovember 30 of each year and will mature onMay 31, 2025 . All of our existing and future restricted subsidiaries that guarantee our revolving credit facility guarantee the 2025 senior notes. Currently, the 2025 senior notes are not guaranteed by any of our subsidiaries other thanDiamondback O&G LLC and will not be guaranteed by any of our future unrestricted subsidiaries. The 2025 indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our 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, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries 52
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as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.
For additional information regarding the 2025 senior notes, see Note 10-Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q. We may use cash on hand to repurchase a portion of the 2025 senior notes in privately-negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.
OnDecember 5, 2019 , we issued$1.0 billion in aggregate principal amount of 2.875% senior notes due 2024, which we refer to as the 2024 notes,$800 million in aggregate principal amount of 3.250% senior notes due 2026, which we refer to as the 2026 notes, and$1.2 billion aggregate principal amount of 3.500% senior notes due 2029, which we refer to as the 2029 notes. We refer to the 2024 notes, the 2026 notes and the 2029 notes, collectively, as theDecember 2019 notes. The 2024 notes will mature onDecember 1, 2024 , the 2026 notes will mature onDecember 1, 2026 and the 2029 notes will mature onDecember 1, 2029 . Interest will accrue and be payable semi-annually, in arrears onJune 1 andDecember 1 of each year, commencing onJune 1, 2020 . TheDecember 2019 notes are guaranteed byDiamondback O&G LLC and are not guaranteed by any of our other subsidiaries. TheDecember 2019 notes were issued under an indenture, dated as ofDecember 5, 2019 , among us and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as ofDecember 5, 2019 , which we collectively refer to as theDecember 2019 Notes Indenture. TheDecember 2019 Notes Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of certain of our subsidiaries to incur liens securing funded indebtedness and on our ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets. For additional information regarding theDecember 2019 Notes, see Note 10-Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q. We may use cash on hand to repurchase a portion of theDecember 2019 Notes in privately-negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.
Second Amended and Restated Credit Facility
We, as parent guarantor, andDiamondback O&G LLC , as borrower, entered into the second amended and restated credit agreement, datedNovember 1, 2013 , as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliateWells Fargo Securities, LLC , as sole book runner and lead arranger. OnJune 28, 2019 , the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied which changes became effectiveNovember 20, 2019 . As ofMarch 31, 2020 , the maximum credit amount available under the credit agreement is$2.0 billion . As ofMarch 31, 2020 , we had approximately$199 million of outstanding borrowings under our revolving credit facility and$1.8 billion available for future borrowings under our revolving credit facility. 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 0.125% to 1.0% per annum in the case of the alternative base rate and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies' ratings of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies' ratings of our unsecured debt. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date ofNovember 1, 2022 . The credit agreement contains a financial covenant that requires us to maintain a total net debt to capitalization ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined 53
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in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets. As ofMarch 31, 2020 , we were in compliance with all financial maintenance covenants under our revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under our 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. Energen Notes At the effective time of the merger, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of$530 million in notes, which we refer to as the Energen Notes, issued under an indenture datedSeptember 1, 1996 withThe Bank of New York as Trustee, which we refer to as the Energen Indenture. As ofMarch 31, 2020 , the Energen Notes consist of: (a)$400 million aggregate principal amount of 4.625% senior notes due onSeptember 1, 2021 , (2)$100 million of 7.125% notes due onFebruary 15, 2028 , (3)$20 million of 7.32% notes due onJuly 28, 2022 , and (4)$10 million of 7.35% notes due onJuly 28, 2027 . The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as our wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen's senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes. For additional information regarding the Energen Notes, See Note 10-Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q. We may use cash on hand to repurchase a portion of the Energen Notes in privately-negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.
Viper's Credit Agreement
OnJuly 20, 2018 ,Viper LLC , as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended, which we refer to as the Viper credit agreement, provides for a revolving credit facility in the maximum credit amount of$2 billion and a borrowing base based onViper LLC's oil and natural gas reserves and other factors (the "borrowing base") of$775 million , subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates ofMay 1st andNovember 1st . In addition,Viper LLC 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$775 million , andViper LLC had$174 million of outstanding borrowings and$601 million available for future borrowings under the Viper credit agreement. In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent under the Viper credit agreement has recommended that the borrowing base be decreased under the Viper credit agreement to$580 million effectivemid-May 2020 . The decrease is subject to approval by the requisite lenders under the Viper credit agreement. Under the new expected borrowing base,Viper LLC would have had$407 million of availability for future borrowings under the Viper credit agreement as ofMarch 31, 2020 . The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected byViper LLC that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% 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.Viper LLC is 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 prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) 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), (ii) 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 (iii) at the maturity date ofNovember 1, 2022 . The loan is secured by substantially all of the assets ofViper and Viper LLC . 54
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The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, 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 Covenant Required
Ratio
Ratio of total net debt to EBITDAX, as defined in the Viper Not greater than credit agreement
4.0 to 1.0
Ratio of current assets to liabilities, as defined in the Not less than 1.0 Viper 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. The covenant limiting dividends and distributions includes an exception allowingViper LLC to make distributions if no default, event of default or borrowing base deficiency exists. As ofMarch 31, 2020 ,Viper and Viper LLC were in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.
Viper's Notes
OnOctober 16, 2019 , Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of$500 million , which we refer to as the Viper Notes. Viper received gross proceeds of$500 million from the such offering, which it loaned toViper LLC .Viper LLC paid the expenses of the offering, resulting in net proceeds of the offering of$490 million , whichViper LLC used to pay down borrowings under the Viper credit agreement. The Viper Notes were issued under an indenture, dated as ofOctober 16, 2019 , among Viper, as issuer,Viper LLC , as guarantor and Wells Fargo, as trustee, which we refer to as the Viper Indenture. Pursuant to the Viper Indenture and the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, payable semi-annually onMay 1 andNovember 1 of each year, commencing onMay 1, 2020 . The Viper Notes will mature onNovember 1, 2027 .
The Viper Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Viper's 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, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events. Viper may use cash on hand to repurchase a portion of the Viper Notes in privately-negotiated transactions, open market purchases or otherwise, but is under no obligation to do so.
Rattler's Credit Agreement
In connection with the Rattler Offering, Rattler, as parent, andRattler LLC , as borrower, entered into a credit agreement, datedMay 28, 2019 , with Wells Fargo, as administrative agent, and a syndicate of banks, including Wells Fargo, as lenders party thereto, which we refer to as the Rattler credit agreement. The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of$600 million which is expandable to$1 billion upon Rattler's election, subject to obtaining lender commitments and satisfaction of customary conditions. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid at the maturity date ofMay 28, 2024 . 55
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The Rattler credit agreement is guaranteed byRattler, Tall City, Rattler OMOG LLC andRattler AJAX Processing LLC and is secured by substantially all of the assets ofRattler LLC, Rattler, Tall City, Rattler OMOG LLC andRattler AJAX Processing LLC . As ofMarch 31, 2020 ,Rattler LLC had$451 million of outstanding borrowings and$149 million available for future borrowings under the Rattler credit agreement. The outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected byRattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement).Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio. The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler,Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowingRattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default or event of default exists.
The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below: Financial
Required Ratio
Covenant
Consolidated Total Leverage Ratio Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Rattler credit agreement) is applicable, then not greater than 5.25 to 1.00) Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Rattler credit agreement) is made Not greater than 3.50 to 1.00 Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) Not less than 2.50 to
1.00
For purposes of calculating the financial maintenance covenants prior to the fiscal quarter endingJune 30, 2020 , EBITDA (as defined in the Rattler credit agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter endingSeptember 30, 2019 . As ofMarch 31, 2020 ,Rattler and Rattler LLC were in compliance with all financial maintenance covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control.
Capital Requirements and Sources of Liquidity
Our board of directors approved a 2020 capital budget for drilling and completion, midstream and infrastructure of approximately$2.8 billion to$3.0 billion . In response to the current commodity price environment, we have updated our 2020 capital budget to narrow our anticipated capital expenditures for 2020 to approximately$1.5 billion to$1.9 billion , representing a decrease of 41% over our 2019 capital budget. We estimate that, of these expenditures, approximately:
•
170 to 200 gross (153 to 180 net) horizontal wells across our operated
leasehold acreage in the Northern Midland and Southern Delaware Basins,
with an average lateral length of approximately 9,700 feet;
•
excluding joint venture investments; and 56
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•
expenditures, excluding the cost of any leasehold and mineral interest
acquisitions. During the three months endedMarch 31, 2020 , our aggregate capital expenditures for our development program were$746 million . Additionally during the three months endedMarch 31, 2020 , we spent approximately$105 million in cash on acquisitions of leasehold interests and mineral acres. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. InMay 2019 , our board of directors approved a stock repurchase program to acquire up to$2 billion of our outstanding common stock throughDecember 31, 2020 . We repurchased approximately$98 million of our common stock under this program during the three months endedMarch 31, 2020 . Although we have approximately$1.3 billion remaining available for future repurchases under this program, we have suspended this program to preserve liquidity. The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating 14 drilling rigs and no completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions. Based upon current oil and natural gas prices and production expectations for 2020, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2020. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2020 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions. We monitor and adjust our projected capital expenditures in response to the results of our drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected. 57 --------------------------------------------------------------------------------
Guarantor Financial Information
As ofMarch 31, 2020 ,Diamondback O&G LLC is the sole guarantor under theDecember 2019 Notes Indenture governing the 2019 senior notes and the 2025 Indenture governing the 2025 senior notes. In connection with the satisfaction and discharge of the indenture, dated as ofOctober 28, 2016 , as subsequently supplemented, amongDiamondback Energy, Inc. , the guarantor subsidiaries party thereto and Wells Fargo, as trustee, governingDiamondback Energy, Inc.'s then outstanding 4.750% Senior Notes due 2024, or the 4.750% senior notes,Diamondback E&P LLC andEnergen Corporation and its subsidiaries were released as guarantors under the 4.750% senior notes, the 2025 senior notes andDiamondback O&G LLC's revolving credit facility.Rattler LLC was released as a guarantor underDiamondback O&G LLC's credit agreement onMay 28, 2019 . Viper, Viper'sGeneral Partner ,Viper LLC , Rattler, Rattler'sGeneral Partner and Rattler's subsidiaries remain non-guarantor subsidiaries.Diamondback O&G LLC's guarantees of the 2019 senior notes and the 2025 senior notes are "full and unconditional," as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the indentures governing the 2019 senior notes and the 2025 senior notes, such as, with certain exceptions, (1) in the eventDiamondback O&G LLC (or all or substantially all of its assets) is sold or disposed of, (2) in the eventDiamondback O&G LLC ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.Diamondback O&G LLC's guarantees of the 2019 senior notes and the 2025 senior notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness. The rights of holders of the senior notes againstDiamondback O&G LLC may be limited under theU.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limitDiamondback O&G LLC's liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability ofDiamondback O&G LLC . Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished. The following tables present summarized financial information forDiamondback Energy, Inc. , as the parent, andDiamondback O&G LLC , as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under theSEC's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity. March 31, 2020 December 31, 2019 Summarized Balance Sheet (in millions) Assets Current assets $ 952 $ 396 Property and equipment, net 10,556 10,109 Other noncurrent assets 43 17 Liabilities Current liabilities $ 182 $ 167 Intercompany accounts payable, non-guarantor subsidiary 794 600 Long-term debt 3,969 3,782 Other noncurrent liabilities 570 504 58
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