DIAMONDBACK 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 consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year endedDecember 31, 2020 . The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See " Part II. Item 1A. Risk Factors " and " Cautionary Statement Regarding Forward-Looking Statements ."
Overview
We operate in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in thePermian Basin inWest Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of midstream infrastructure assets in theMidland and Delaware Basins of thePermian Basin . Recent Developments
First Quarter 2021 Acquisitions
On
OnMarch 17, 2021 , we completed the acquisition of QEP pursuant to the Agreement and Plan of Merger, dated as ofDecember 20, 2020 (the "Merger Agreement"), by and among Diamondback,Bohemia Merger Sub, Inc. , aDelaware corporation and QEP. Pursuant to the Merger Agreement, at the effective time of the QEP Merger,Bohemia Merger Sub, Inc. merged with and into QEP, with QEP continuing as the surviving corporation and as a wholly owned subsidiary of Diamondback. The addition of QEP's assets increased our net acreage in theMidland Basin by approximately 49,000 net acres. Under the terms of the Merger Agreement, we issued approximately 12.12 million shares of our common stock (valued at a price of$81.41 per share on the closing date) to the former QEP stockholders, with the total value of approximately$987 million .
See Note 4- Acquisitions for additional discussion of the Guidon Acquisition and the QEP Merger.
Recent and Pending Divestitures
OnMay 3, 2021 , we signed a definitive agreement to divest all of ourWilliston Basin assets acquired in the QEP Merger, consisting of approximately 95,000 net acres, for a purchase price of approximately$745 million , subject to certain closing adjustments. This transaction is expected to close in the third quarter of 2021, subject to continued due diligence and closing conditions. We intend to use our net proceeds from this transaction toward debt reduction. OnApril 28, 2021 andApril 29, 2021 , we signed definitive agreements to divest certain non-core Permian assets, including 7,000 net acres of non-coreSouthern Midland Basin acreage inUpton county and approximately 1,300 net acres of non-core, non-operatedDelaware Basin assets inLea county ,New Mexico , for a combined gross purchase price of$87 million , subject to certain closing adjustments. These transactions are expected to close in the second quarter of 2021, subject to continued due diligence and closing conditions. We intend to use our net proceeds from these transactions toward debt reduction. OnApril 30, 2021 , each of Rattler and its joint venture partnerAmarillo Midstream, LLC sold its interest in Amarillo Rattler toEnLink Midstream Operating, LP for aggregate total gross potential consideration of$75 million , consisting of$50 million at closing,$10 million upon the first anniversary of closing and up to$15 million in contingent earn-out payments over a three-year span based upon the Company's development activity. Net of transaction expenses and working capital adjustments, Rattler received$24 million at closing, with an incremental$5 million due inApril 2022 and could receive up to$7.5 million in contingent payments from 2023 to 2025. 31 -------------------------------------------------------------------------------- Table of Contents First Quarter 2021 Debt Transactions OnMarch 24, 2021 , we completed a notes offering of ourMarch 2021 Notes resulting in aggregate net proceeds of$2.18 billion . The net proceeds were primarily used to fund the repurchase of$1.65 billion in fair value carrying amount of the QEP Notes that remained outstanding at the effective time of the QEP Merger for total cash consideration of$1.7 billion , and$368 million principal amount of 2025 Senior Notes, for total cash consideration of$381 million . These refinancing transactions are expected to result in an estimated annual interest cost savings of approximately$40 million in addition to an estimated$60 to$80 million of previously announced expected annual cost synergies from the QEP Merger.
See Note 9- Debt for additional discussion of our 2021 debt transactions.
COVID-19 and Commodity Prices
In earlyMarch 2020 , oil prices dropped sharply and continued to decline, briefly reaching negative levels as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken byOPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the ongoing COVID-19 pandemic. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in response to the increase in demand. During 2020 and 2021, the posted NYMEX WTI price for crude oil ranged from$(37.63) to$66.09 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from$1.48 to$3.35 per MMBtu. OnApril 12, 2021 , the NYMEX WTI price for crude oil was$59.70 per Bbl and the NYMEX Henry Hub price of natural gas was$2.56 per MMBtu. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices. As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance, however, we have restored curtailed production. 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.
First Quarter 2021 Operating Highlights
•We recorded net income of
•Our average production was 307.4 MBOE/d during the first quarter of 2021 which includes the effect of approximately four to five days of lost total net production duringFebruary 2021 resulting from the recent winter storms in thePermian Basin . The Company expects to make up these production losses throughout the remainder of 2021.
•During the first quarter of 2021, we drilled 41 gross horizontal wells in the
•We turned 67 gross operated horizontal wells (42 in the
•The average lateral length for the wells completed during the first quarter of 2021 was 10,331 feet.
•As ofMarch 31, 2021 , we had$1.9 billion of availability for future borrowings under our revolving credit facility and approximately$121 million of cash on hand. •Our cash operating costs for the first quarter endedMarch 31, 2021 were$8.06 per BOE, including lease operating expenses of$3.69 per BOE, cash general and administrative expenses of$0.54 per BOE and production and ad valorem taxes and gathering and transportation expenses of$3.83 per BOE. •OnApril 29, 2021 , our board of directors declared a cash dividend for the first quarter of 2021 of$0.40 per share of common stock, payable onMay 20, 2021 to our stockholders of record at the close of business ofMay 13, 2021 . 32
-------------------------------------------------------------------------------- Table of Contents 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 primarily in thePermian Basin and derives royalty income and lease bonus income from such interests. As ofMarch 31, 2021 , we had approximately 554,594 net acres, which primarily consisted of approximately 275,113 net acres in theMidland Basin , 151,245 net acres in theDelaware Basin and 94,610 net acres in theWilliston Basin . As discussed above, we recently entered into definitive agreements to divest (i) all of ourWilliston Basin net acres, (ii) 7,000 net acres of non-coreSouthern Midland Basin acreage inUpton county and (iii) approximately 1,300 net acres of non-core, non-operatedDelaware Basin assets inLea county ,New Mexico for an aggregate purchase price of$832 million , subject to certain closing adjustments. These transactions are expected to close in the second and third quarters of 2021, subject to continued due diligence and closing conditions.
As of
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, 2021
Drilled Completed(1)
Area Gross Net Gross Net
Midland Basin 41 40 42 37
Delaware Basin 8 7 25 23
Total 49 47 67 60
(1)The average lateral length for the wells completed during the first quarter
of 2021 was 10,331 feet. Operated completions during the first quarter of 2021
consisted of 27 Wolfcamp A wells, eight Wolfcamp B wells, ten Lower Spraberry
wells, seven Middle Spraberry wells, six Second Bone Springs wells, four Jo Mill
wells, three Third Bone Springs wells, one Dean well and one Barnett well.
As of
As of March 31, 2021
Vertical Wells Horizontal Wells Total
Area Gross Net Gross Net Gross Net
Midland Basin 2,322 2,157 1,685 1,556 4,007 3,713
Delaware Basin 26 23 616 576 642 599
Other - - 397 345 397 345
Total 2,348 2,180 2,698 2,477 5,046 4,657
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 . 33 -------------------------------------------------------------------------------- Table of Contents 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 gathering and disposal system spans approximately 524 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.
Results of Operations
The following table sets forth selected operating data for the three months
ended
Three Months Ended March 31,
2021 2020
Revenues (In millions):
Oil sales $ 944 $ 827
Natural gas sales 104 4
Natural gas liquid sales 124 52
Total oil, natural gas and natural gas liquid revenues $ 1,172 $ 883
Production Data:
Oil (MBbls) 16,578 18,325
Natural gas (MMcf) 34,109 32,120
Natural gas liquids (MBbls) 5,405 5,538
Combined volumes (MBOE)(1) 27,668 29,216
Daily oil volumes (BO/d)(2) 184,200 201,369
Daily combined volumes (BOE/d)(2) 307,422 321,057
Average Prices:
Oil ($ per Bbl) $ 56.94 $ 45.10
Natural gas ($ per Mcf) $ 3.05 $ 0.14
Natural gas liquids ($ per Bbl) $ 22.94 $ 9.45
Combined ($ per BOE) $ 42.36 $ 30.23
Oil, hedged ($ per Bbl)(3) $ 46.81 $ 49.32
Natural gas, hedged ($ per MMBtu)(3) $ 2.64 $ 0.42
Natural gas liquids, hedged ($ per Bbl)(3) $ 22.76 $ 9.45
Average price, hedged ($ per BOE)(3) $
35.75
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one
Bbl.
(2)The volumes presented are based on actual results and are not calculated
using the rounded numbers in the table above.
(3)Hedged prices reflect the effect of our commodity derivative transactions on
our average sales prices and include gains and losses on cash settlements for
matured commodity derivatives, which we do not designate for hedge accounting.
Hedged prices exclude gains or losses resulting from the early settlement of
commodity derivative contracts.
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Production Data
Substantially all of our revenues are generated through the sale of oil, natural
gas and natural gas liquids production. The following tables set forth our
production data for the three months ended
Three Months Ended March 31,
2021 2020
Oil (MBbls) 60 % 63 %
Natural gas (MMcf) 21 % 18 %
Natural gas liquids (MBbls) 19 % 19 %
100 % 100 %
Three Months Ended March 31, 2021 Three Months Ended March 31, 2020
Midland Basin Delaware Basin Other(1) Total Midland Basin Delaware Basin Other(2) Total
Production Data:
Oil (MBbls) 9,840 6,436 302 16,578 10,511 7,760 54 18,325
Natural gas (MMcf) 18,457 15,055 597 34,109 15,833 16,147 140 32,120
Natural gas liquids (MBbls) 3,236 2,069 100 5,405 3,048 2,463 27 5,538
Total (MBoe) 16,152 11,014 502 27,668 16,198 12,914 104 29,216
(1)Includes the
Comparison of the Three Months Ended
Oil, Natural Gas and Natural Gas Liquids Revenues. Our 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 first quarter of 2021 increased by$289 million , or 33%, to$1,172 million from$883 million during the first quarter of 2020. The increase in average prices received during the three months endedMarch 31, 2021 as compared to the same period in 2020 contributed to$368 million of the total increase. The impact of higher pricing was partially offset by a 5.3% decrease in combined volumes sold primarily driven by the recent winter storms in thePermian Basin which caused the loss of approximately four to five days of total net production duringFebruary 2021 . The production declines were slightly offset by additional production contributed during the first quarter of 2021 from the QEP Merger and Guidon Acquisition. The Company expects to make up weather related production losses throughout the remainder of 2021. Average daily production sold decreased by 13,635 BOE/d to 307,422 BOE/d during the three months endedMarch 31, 2021 from 321,057 BOE/d during the three months endedMarch 31, 2020 .
Lease Operating Expenses. The following table shows lease operating expenses for
the three months ended
Three Months Ended March 31,
2021 2020
Amount Per BOE Amount Per BOE
(In millions, except per BOE amounts)
Lease operating expenses $ 102 $ 3.69 $ 127 $ 4.35
Lease operating expenses for the three months ended March 31, 2021 as compared
to the three months ended March 31, 2020 decreased by $25 million , or $0.66 per
BOE. The decrease in lease operating expenses was primarily due to declining
power generation costs which were partially offset by additional costs resulting
from production associated with the acquisitions discussed in Note
4- Acquisitions .
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Production and Ad Valorem Tax Expense. The following table shows production and
ad valorem tax expense for the three months ended March 31, 2021 and 2020:
Three Months Ended
2021 2020
Amount Per BOE Amount Per BOE
(In millions, except per BOE amounts)
Production taxes $ 60 $ 2.17 $ 42 $ 1.42
Ad valorem taxes 15 0.54 29 1.01
Total production and ad valorem expense $ 75 Production taxes as a % of oil, natural gas, and natural gas liquids revenue 5.1 % 4.8 % In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the three months endedMarch 31, 2021 compared to the same period in 2020. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the three months endedMarch 31, 2021 as compared to the three months endedMarch 31, 2020 decreased by$14 million primarily due to lower overall valuations resulting from a decrease in commodity prices between valuation periods.
Gathering and Transportation Expense. The following table shows gathering and
transportation expense for the three months ended
Three Months Ended March 31,
2021 2020
Amount Per BOE Amount Per BOE
(In millions, except per BOE amounts)
Gathering and transportation expense $ 31 $ 1.12 $
36
For the three months ended
Depreciation, Depletion, Amortization and Accretion. The following table
provides the components of our depreciation, depletion, amortization and
accretion expense for the three months ended
Three Months Ended March 31,
2021 2020
(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties $ 257 $ 392
Depreciation of midstream assets 11 11
Depreciation of other property and equipment 3 4
Asset retirement obligation accretion 2 2
Depreciation, depletion and amortization expense $ 273 $ 409
Oil and natural gas properties depletion rate per BOE $
9.29
The decrease in depletion of proved oil and natural gas properties of$135 million for the three months endedMarch 31, 2021 as compared to the three months endedMarch 31, 2020 resulted largely from a reduction in the average depletion rate for our oil and natural gas properties in 2021, which stemmed from a decrease in the net book value of our properties due primarily to the full cost ceiling impairments recorded in 2020. 36 -------------------------------------------------------------------------------- Table of Contents Impairment ofOil and Natural Gas Properties . Pursuant toSEC guidance, we determined the fair value of the properties acquired in the QEP Merger and Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt and received a waiver from theSEC to exclude the acquired properties from the first quarter 2021 ceiling test calculation. As a result, no impairment expense was recorded for the three months endedMarch 31, 2021 . The properties acquired in the QEP Merger and Guidon Acquisition had an unamortized cost atMarch 31, 2021 of$3.0 billion and$1.1 billion , respectively. Had we not received the waiver from theSEC , the impairment charge recorded would have been an additional$1.1 billion for the three months endedMarch 31, 2021 . As a result of the sharp decline in commodity prices during 2020, we recorded a non-cash ceiling test impairment for the three months endedMarch 31, 2020 of$1.0 billion , which is included in accumulated depletion, depreciation, amortization and impairment on our condensed consolidated balance sheet. Impairment charges affect our results of operations but do not reduce our 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 fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. See Note 6- Property and Equipment for further details regarding factors that impact the impairment of oil and natural gas properties.
General and Administrative Expenses. The following table shows general and
administrative expenses for the three months ended
Three Months Ended March 31,
2021 2020
Amount Per BOE Amount Per BOE
(In millions, except per BOE amounts)
General and administrative expenses $ 15 $ 0.54 $ 15 $ 0.51
Non-cash stock-based compensation 10 0.36 9 0.31
Total general and administrative expenses $ 25 $ 0.90
Merger and Integration Expense. The following tables shows merger and
integration expense for the three months ended
Three Months Ended March 31,
2021 2020
(In millions)
Merger and integration expense $ 75 $ -
Total merger and integration expense for the three months endedMarch 31, 2021 includes$67 million in costs incurred for the QEP Merger and$8 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of$38 million in severance costs and$23 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consist primarily of advisory fees. See Note 4- Acquisitions for further details regarding the QEP Merger and Guidon Acquisition. 37 -------------------------------------------------------------------------------- Table of Contents Net Interest Expense. The following table shows the components of net interest expense for the three months endedMarch 31, 2021 and 2020: Three
Months Ended
2021 2020
(In millions)
Revolving credit agreements $ 3 $ 7
Senior notes 61 48
Amortization of debt issuance costs and discounts 4 2
Other 4 4
Capitalized interest (14) (13)
Total 58 48
Less: interest income 2 -
Interest expense, net $ 56 $ 48
Net interest expense increased by $8 million for the three months ended
March 31, 2021 compared to the same period in 2020. The increase was primarily
due to interest expense related to our May 2020 Notes, Rattler's 5.625% Senior
Notes due 2025, and to a lesser extent, interest expense incurred on the QEP
Notes that remained outstanding following the QEP Merger completed in March 2021
and the newly issued March 2021 Notes, which increase was partially offset by
interest cost savings on the repurchase of $368 million in outstanding principal
of our 2025 Notes in March 2021 , and a decrease in borrowings under our
revolving credit agreements. See Note 9- Deb t for further details
regarding outstanding borrowings and interest expense.
Derivative Instruments. The following table shows the net gain (loss) on
derivative instruments and the net cash receipts (payments) on settlements of
derivative instruments for the three months ended
Three Months Ended March 31,
2021 2020
(In millions)
Gain (loss) on derivative instruments, net $ (164) $ 542
Net cash received (paid) on settlements(1) $
(102)
(1)The three months ended
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 condensed consolidated statements of operations under the line item captioned "Gain (loss) on derivative instruments, net." As part of the QEP Merger, we received by novation from QEP certain derivative instruments which were included on our balance sheet as ofMarch 31, 2021 . Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months endedMarch 31, 2021 and 2020: Three Months EndedMarch 31, 2021 2020 (In millions) Provision for (benefit from) income taxes $
65
The change in our income tax provision for the first quarter of 2021 compared to the same period in 2020 was primarily due to income tax expense resulting from recording a valuation allowance on Viper's deferred tax assets for the three months endedMarch 31, 2020 . 38
-------------------------------------------------------------------------------- Table of Contents Liquidity and Capital Resources
Historically, our primary sources of liquidity have been cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility and proceeds from the issuance of our senior notes. 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, 2021 and 2020 are presented below: Three Months Ended March 31, 2021 2020 (In millions) Net cash provided by (used in) operating activities $ 624$ 849 Net cash provided by (used in) investing activities (587) (923) Net cash provided by (used in) financing activities 29 101 Net increase (decrease) in cash $ 66$ 27 Operating Activities 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. The decrease in operating cash flows for the three months endedMarch 31, 2021 compared to the same period in 2020 primarily resulted from (i) working capital changes, primarily due to the timing of collections of our oil and natural gas sales receivables and recording working capital assets and liabilities acquired in the QEP Merger duringMarch 2021 , (ii) a reduction of$265 million due to making net cash payments of$178 million on our derivative contracts in the first quarter of 2021 compared to receiving net cash of$87 million on our derivative contracts in the first quarter of 2020, and (iii) acquisition costs of$75 million incurred during the first quarter of 2021 for the QEP Merger and Guidon Acquisition. These net cash outflows were partially offset by an increase of$285 million in our total revenues and receipt of a$100 million refund of an income tax receivable related to the carryback of federal net operating losses and the accelerated refund of minimum tax credits allowed under the CARES Act in 2020. Investing Activities Net cash used in investing activities was$587 million compared to$923 million during the three months endedMarch 31, 2021 and 2020, respectively. The majority of our cash used for investing activities during 2021 was for the purchase and development of oil and natural gas properties and related assets including the acquisition of certain leasehold interests as part of the Guidon Acquisition. The majority of our net cash used in investing activities during the three months endedMarch 31, 2020 was incurred for drilling and completion costs in conjunction with our development program. Our capital expenditures for each period are discussed further below. 39 -------------------------------------------------------------------------------- Table of Contents Capital Expenditure Activities
Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:
Three Months Ended March 31,
2021 2020
(In millions) Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)
$ 281 $ 690
Infrastructure additions to oil and natural gas properties 8 56
Additions to midstream assets 7 44
Total $ 296 $ 790
(1)During the three months ended March 31, 2021 , in conjunction with our
development program, we drilled 49 gross (47 net) operated horizontal wells, of
which 41 gross (40 net) wells were in the Midland Basin and eight gross (seven
net) wells were in the Delaware Basin , and turned 67 gross (60 net) operated
horizontal wells to production, of which 42 gross (37 net) wells were in the
Midland Basin and 25 gross (23 net) wells were in the Delaware Basin .
(2)During the three months ended March 31, 2020 , in conjunction with our
development program, we drilled 93 gross (85 net) operated horizontal wells, of
which 55 gross (50 net) wells were in the Midland Basin and 38 gross (35 net)
wells were in the Delaware Basin , and turned 80 gross (72 net) operated
horizontal wells to production, of which 46 gross (42 net) wells were in the
Delaware Basin and 34 gross (30 net) wells were in the Midland Basin .
Financing Activities
Net cash provided by financing activities for the three months endedMarch 31, 2021 and 2020 was$29 million and$101 million , respectively. During the three months endedMarch 31, 2021 , the amount provided by financing activities was primarily attributable to$2.2 billion in proceeds from theMarch 2021 Notes and$76 million in proceeds that relate primarily to the early settlement of interest rate swaps that contained an other-than-insignificant financing element. These net increases in cash flows from financing activities were partially offset by$1.9 billion paid for the repurchase of a portion of the QEP Notes and 2025 Senior Notes, as well as$166 million of additional premiums paid in connection with the repurchases,$68 million of dividends paid to stockholders,$24 million of unit repurchases as part of the Viper and Rattler unit repurchase programs and$23 million of repayments under our credit facilities, net of borrowings. The 2020 amount provided by financing activities was primarily attributable to$290 million of borrowings, net of repayments under our credit facilities and$16 million in proceeds from joint ventures, partially offset by$98 million of share repurchases as part of our previous stock repurchase program,$59 million of dividends to stockholders,$43 million of distributions to non-controlling interest and$5 million of cash paid for tax withholding on vested equity awards.
Indebtedness
AtMarch 31, 2021 , our debt, including the debt of Viper and Rattler, consists of approximately$7.5 billion in aggregate outstanding principal amount of senior notes (including$191 million due in 2021),$163 million in aggregate outstanding borrowings under revolving credit facilities and$75 million in outstanding amounts due under our DrillCo Agreement. Our revolving credit facilities and significant changes in our outstanding indebtedness during the three months endedMarch 31, 2021 are discussed further below. See Note 9- Debt for additional discussion of our outstanding debt atMarch 31, 2021 .
Second Amended and Restated Credit Facility
As ofMarch 31, 2021 , the maximum credit amount available under our credit agreement was$2 billion , with$52 million in outstanding borrowings and$1.9 billion available for future borrowings. As ofMarch 31, 2021 , there was an aggregate of$3 million in letters of credit outstanding under our credit agreement. The weighted average interest rate on borrowings under the credit facility was 1.65% for the three months endedMarch 31, 2021 .
As of
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March 2021 Notes Offering
On March 24, 2021 , we issued $650 million of our 2023 Notes, $900 million of our
2031 Notes and $650 million of our 2051 Notes and received proceeds of $2.18
billion , net of $24 million in debt issuance costs and discounts. The net
proceeds were primarily used to fund the repurchase of other senior notes
outstanding as discussed further below. Interest on the March 2021 Notes is
payable semi-annually on March 24 and September 24 , beginning on September 24,
2021 .
QEP Notes and Repurchases of Notes
On
Subsequent to the QEP Merger, inMarch 2021 , we repurchased pursuant to tender offers commenced by us approximately$1.65 billion in fair value carrying amount of the QEP Notes for total cash consideration of$1.7 billion , including redemption and early premium fees, which resulted in a loss on extinguishment of debt during the three months endedMarch 31, 2021 of approximately$47 million . The aggregate fair value of the QEP Notes repurchased consisted of (i)$453 million , or 94.65%, of the outstanding fair value carrying amount of the QEP 2022 Notes, (ii)$663 million , or 98.43%, of the outstanding fair value carrying amount of the QEP 2023 Notes, and (iii)$538 million , or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes. InMarch 2021 , we also repurchased an aggregate of$368 million principal amount of our 5.375% 2025 Senior Notes, representing approximately 45.97% of the outstanding 2025 Senior Notes, for total cash consideration of$381 million , including redemption and early premium fees, which resulted in a loss on extinguishment of debt during the three months endedMarch 31, 2021 of$14 million .
We funded the repurchases of the QEP Notes and 2025 Senior Notes with the
proceeds from the
In connection with the tender offers to repurchase the QEP Notes discussed above, we also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the QEP indenture under which the QEP Notes were issued. We received the requisite number of consents and, onMarch 23, 2021 , entered into a supplemental indenture relating to the QEP Notes adopting these amendments.
Viper's Credit Agreement
The Viper credit agreement, as amended to date, or the Viper credit agreement, provides for a revolving credit facility in the maximum credit amount of$2 billion , with a borrowing base of$580 million as ofMarch 31, 2021 based onViper LLC's oil and natural gas reserves and other factors (the "borrowing base"). The borrowing base is scheduled to be redetermined semi-annually in May and November. As ofMarch 31, 2021 ,Viper LLC had$57 million of outstanding borrowings and$523 million available for future borrowings under the Viper credit agreement. The weighted average interest rate on borrowings under the Viper credit agreement was 1.88% for the three months endedMarch 31, 2021 . The Viper credit agreement matures onNovember 1, 2022 .
As of
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Rattler's Credit Agreement
The Rattler credit agreement, as amended to date, or 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 additional lender commitments and satisfaction of customary
conditions. As of March 31, 2021 , Rattler LLC had $54 million of outstanding
borrowings and $546 million available for future borrowings under the Rattler
credit agreement. The weighted average interest rate on borrowings under the
Rattler credit agreement was 1.40% for the three months ended March 31, 2021 .
The Rattler credit agreement matures on May 28, 2024 .
As of
Capital Requirements and Sources of Liquidity
Our board of directors initially approved a 2021 capital budget for drilling and completion, midstream and infrastructure of approximately$1.4 billion to$1.6 billion . We have updated our 2021 capital budget to approximately$1.6 billion to$1.75 billion to give effect to the QEP Merger, representing an increase of 16% over our original 2021 capital budget. We estimate that, of these expenditures, approximately: •$1.5 billion to$1.6 billion will be spent on drilling and completing 275 to 285 gross (250 to 259 net) horizontal wells across our operated leasehold acreage in theNorthern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,300 feet;
•$60 million to
•$80 million to
We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
During the first quarter of 2021, we spent
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 11 drilling
rigs and three completion crews. We currently continue to execute on our
strategy to hold oil production flat while using cash flow from operations to
reduce debt, strengthen our balance sheet and return capital to our
stockholders. 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
2021, 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 the 12-month period following the filing of this report. 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
2021 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
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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.
Guarantor Financial Information
As ofMarch 31, 2021 ,Diamondback O&G LLC is the sole guarantor under the indentures governing theDecember 2019 Notes, theMay 2020 Notes, the 2025 Senior Notes and theMarch 2021 Notes. Guarantees 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 theDecember 2019 Notes Indenture and the 2025 Indenture, 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 theDecember 2019 Notes, theMay 2020 Notes, the 2025 Senior Notes and theMarch 2021 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, 2021 December 31, 2020 Summarized Balance Sheets: (In millions) Assets: Current assets $ 302 $ 308 Property and equipment, net$ 8,108 $ 6,934 Other noncurrent assets $ 10 $ 6 Liabilities: Current liabilities $ 769 $ 355
Intercompany accounts payable, non-guarantor subsidiary $ 408
$ 335
Long-term debt $ 6,132 $ 4,293
Other noncurrent liabilities $ 916 $ 886
Three Months Ended March 31, 2021
Summarized Statement of Operations: (In millions)
Revenues $ 650
Income (loss) from operations $
328
Net income (loss) $ 85
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-------------------------------------------------------------------------------- Table of Contents Contractual Obligations In addition to the changes in debt discussed in " - Indebtedness " above and in Note 9- Deb t included in the notes to the condensed consolidated financial statements included elsewhere in this report, we acquired certain contractual obligations during the three months endedMarch 31, 2021 in conjunction with the QEP Merger including an aggregate of approximately$68 million in various transportation, gathering and purchase commitments. There were no other significant changes in our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.
Critical Accounting Policies and Estimates
There have been no changes in our critical accounting policies from those
disclosed in our Annual Report on Form 10- K for the year ended
Off-Balance Sheet Arrangements
We had no material off-balance sheet arrangements as ofMarch 31, 2021 . Please read Note 15- Com mitments and Contingencies included in the notes to the condensed consolidated financial statements included elsewhere in this report, for a discussion of our commitments and contingencies, which are not recognized in the balance sheets under GAAP.
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