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 , 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 a total value of approximately$987 million .
See Note 4- Acquisitions and Divestitures 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 sales price of approximately$745 million , subject to certain closing adjustments. This transaction is expected to close late 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. OnJune 3, 2021 andJune 7, 2021 , respectively, we closed transactions to divest certain non-core Permian assets, including over 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 sales price of$82 million , net of customary purchase price adjustments. We used our net proceeds from these transactions toward debt reduction.
OnMarch 24, 2021 , we completed an 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 million to$80 million of previously announced expected annual cost synergies from the QEP Merger. 32 -------------------------------------------------------------------------------- Table of Contents Redemption of the Energen 4.625% Senior Notes InJune 2021 , we redeemed the remaining$191 million principal amount of the outstanding Energen 4.625% senior notes due onSeptember 1, 2021 . We recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the repurchased notes.
Pending Full Redemption of the Outstanding 5.375% Senior Notes due 2025
OnJuly 23, 2021 , we elected to effect an optional redemption of all of our 2025 Notes outstanding as ofAugust 24, 2021 in the aggregate principal amount of$432 million , at a redemption price equal to 102.688% of the principal amount plus accrued interest. We intend to fund the redemption with cash on hand and borrowings under our revolving credit facility.
Amendment and Joinder to the Second Amended and Restated Credit Facility
OnJune 2, 2021 , we entered into an amendment to the credit agreement, which among other things (i) extended the maturity date toJune 2, 2026 , (ii) decreased the total revolving loan commitments from$2.0 billion to$1.6 billion , which amount may be increased in an amount up to$1.0 billion (for a total maximum commitment amount of$2.6 billion ), (iii) added the ability to incur up to$100 million of the loans under the credit agreement as swingline loans and (iv) changed the interest rate applicable to the loans and certain fees payable under the credit agreement. For additional discussion of our 2021 debt transactions and the amendment to the second amended and restated credit facility, see Note 7- Debt and Note 14- Subsequent Events-Pending Full Redemption of the Outstanding 5.375% Senior Notes due 2025 .
COVID-19 and Commodity Prices
In earlyMarch 2020 , oil prices dropped sharply and continued to decline, briefly reaching negative levels as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken byOPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the ongoing COVID-19 pandemic. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in response to the increase in demand. During 2020 and 2021, the posted NYMEX WTI price for crude oil ranged from$(37.63) to$75.25 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from$1.48 to$3.75 per MMBtu. OnJuly 16, 2021 , the NYMEX WTI price for crude oil was$71.81 per Bbl and the NYMEX Henry Hub price of natural gas was$3.67 per MMBtu. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices. In addition to the volatility in commodity prices and the impact of the COVID-19 pandemic on our business and industry, our results of operations may be 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. 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. We have since restored curtailed production in the second half of 2020 to stem production declines and respond to improved demand and increasing commodity prices, but have elected to keep production relatively flat during the first six months of 2021, focusing on cost control and using excess cash flow for debt payment and return of capital to our stockholders. We expect to continue to exercise capital discipline and maintain flat oil production for the foreseeable future. If this maintenance plan continues into 2022, we expect to be able to hold fourth quarter 2021 Permian oil production flat with 10% to 15% more capital than our current 2021 plan, demonstrating our improved capital efficiency that incorporates a full year of capital expenditures on the assets we acquired in the first quarter of 2021 in the QEP Merger and the Guidon Acquisition. We expect to be in a position to continue to increase our return of capital to stockholders and, beginning in 2022, plan to return 50% of our free cash flow to our stockholders. The form of such capital return will be decided by our board of directors at the appropriate time, based on its assessment of which opportunities present the best return to our stockholders at that time. 33 -------------------------------------------------------------------------------- Table of Contents Second Quarter 2021 Operating Highlights
•We recorded net income of
•Our average production was 401.5 MBOE/d during the second quarter of 2021 which includes a full quarter of production from our Guidon Acquisition and QEP Merger.
•During the second quarter of 2021, we drilled 47 gross horizontal wells in the
•We turned 65 gross operated horizontal wells (47 in the
•The average lateral length for the wells completed during the second quarter of 2021 was 11,137 feet.
•Our cash operating costs for the second quarter endedJune 30, 2021 were$9.33 per BOE, including lease operating expenses of$4.30 per BOE, cash general and administrative expenses of$0.63 per BOE and production and ad valorem taxes and gathering and transportation expenses of$4.40 per BOE. •OnJuly 29, 2021 , our board of directors declared a cash dividend for the second quarter of 2021 of$0.45 per share of common stock, payable onAugust 19, 2021 to our stockholders of record at the close of business ofAugust 12, 2021 .
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 within thePermian 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. Additionally, 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 ofJune 30, 2021 , we had approximately 542,242 net acres, which primarily consisted of approximately 264,777 net acres in theMidland Basin and 149,309 net acres in theDelaware Basin . As discussed above, during the second quarter of 2021, we closed transactions to divest over 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 an aggregate sales price of$82 million , net of customary purchase price adjustments. Additionally, we entered into a definitive agreement to divest all of ourWilliston Basin net acres for$745 million , subjected to certain closing adjustments. This transaction is expected to close late in the third quarter of 2021, subject to continued due diligence and closing conditions.
The following table sets forth the total number of operated horizontal wells
drilled and completed during the three and six months ended
Three Months Ended June 30, 2021 Six Months Ended June 30, 2021
Drilled Completed(1) Drilled Completed(2)
Area Gross Net Gross Net Gross Net Gross Net
Midland Basin 47 43 47 44 88 83 89 81
Delaware Basin 9 9 14 14 17 16 39 37
Other - - 4 3 - - 4 3
Total 56 52 65 61 105 99 132 121
(1)The average lateral length for the wells completed during the second quarter
of 2021 was 11,137 feet. Operated completions during the second quarter of 2021
consisted of 19 Lower Spraberry wells, ten Wolfcamp A wells, nine Middle
Spraberry wells, eight Jo Mill wells, six Wolfcamp B wells, five Third Bone
Springs wells, two Second Bone Springs wells, two Dean wells, two Bakken wells
and two Three Forks wells.
(2)The average lateral length for the wells completed during the first six
months of 2021 was 10,729 feet. Operated completions during the first six months
of 2021 consisted of 38 Wolfcamp A wells, 29 Lower Spraberry wells, 15 Middle
Spraberry wells, 13 Wolfcamp B wells, 13 Jo Mill wells, eight Second Bone
Springs wells, eight Third Bone Springs wells, three Dean wells, two Bakken
wells, two Three Forks wells and one Barnett well.
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As of
As of June 30, 2021
Vertical Wells Horizontal Wells Total
Area Gross Net Gross Net Gross Net
Midland Basin 2,313 2,126 1,721 1,588 4,034 3,714
Delaware Basin 27 24 626 588 653 612
Other - - 402 347 402 347
Total 2,340 2,150 2,749 2,523 5,089 4,673
As of
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 consist 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 519 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. The midstream operations segment's revenues and operating expenses were not significant to our condensed consolidated statements of operations for the three and six months endedJune 30, 2021 and 2020. See Note 15- Segment Information for further details regarding acquisitions 35 -------------------------------------------------------------------------------- Table of Contents Results of Operations
The following table sets forth selected operating data for the three and six
months ended
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
Revenues (In millions):
Oil sales $ 1,395 $ 352 $ 2,339 $ 1,179
Natural gas sales 107 21 211 25
Natural gas liquid sales 165 39 289 91
Total oil, natural gas and natural gas
liquid revenues $ 1,667 $ 412 $ 2,839 $ 1,295
Production Data:
Oil (MBbls) 22,067 16,045 38,645 34,370
Natural gas (MMcf) 44,506 31,857 78,615 63,977
Natural gas liquids (MBbls) 7,047 5,411 12,452 10,949
Combined volumes (MBOE)(1) 36,532 26,765 64,200 55,982
Daily oil volumes (BO/d)(2) 242,495 176,323 213,508 188,846
Daily combined volumes (BOE/d)(2) 401,451 294,126 354,696 307,592
Average Prices:
Oil ($ per Bbl) $ 63.22 $ 21.99 $ 60.53 $ 34.31
Natural gas ($ per Mcf) $ 2.40 $ 0.63 $ 2.68 $ 0.39
Natural gas liquids ($ per Bbl) $ 23.41 $ 7.17 $ 23.21 $ 8.33
Combined ($ per BOE) $ 45.63 $ 15.39 $ 44.22 $ 23.13
Oil, hedged ($ per Bbl)(3) $ 49.85 $ 35.21 $ 48.54 $ 42.73
Natural gas, hedged ($ per MMBtu)(3) $ 1.82 $ 0.33 $ 2.18 $ 0.38
Natural gas liquids, hedged ($ per
Bbl)(3) $ 23.27 $ 7.17 $ 23.05 $ 8.33
Average price, hedged ($ per BOE)(3) $ 36.82 $ 22.95 (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.
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 the mix of our production data by product and basin for the three and six months endedJune 30, 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Oil (MBbls) 61 % 60 % 60 % 61 % Natural gas (MMcf) 20 % 20 % 21 % 19 % Natural gas liquids (MBbls) 19 % 20 % 19 % 20 % 100 % 100 % 100 % 100 % 36
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Three Months Ended June 30, 2021 Three Months Ended June 30, 2020
Midland Basin Delaware Basin Other(1) Total Midland Basin Delaware Basin
Other(2) Total
Production Data:
Oil (MBbls) 13,960 6,391 1,716 22,067 9,382 6,626 37 16,045
Natural gas (MMcf) 25,119 16,238 3,149 44,506 17,049 14,721 87 31,857
Natural gas liquids (MBbls) 4,363 2,068 616 7,047 3,146 2,244 21 5,411
Total (MBoe) 22,510 11,165 2,857 36,532 15,370 11,324 73 26,765
Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Midland Basin Delaware Basin Other(1) Total Midland Basin Delaware Basin Other(2) Total
Production Data:
Oil (MBbls) 23,800 12,827 2,018 38,645 19,893 14,386 91 34,370
Natural gas (MMcf) 43,576 31,293 3,746 78,615 32,882 30,868 227 63,977
Natural gas liquids (MBbls) 7,599 4,137 716 12,452 6,194 4,707 48 10,949
Total (MBoe) 38,662 22,180 3,358 64,200 31,567 24,238 177 55,982
(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 three months endedJune 30, 2021 increased by$1.3 billion , or 305%, to$1.7 billion from$412 million during the three months endedJune 30, 2020 . Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed to$1.1 billion of the total increase. The remainder of the overall change is due to a 36% increase in combined volumes sold Our oil, natural gas and natural gas liquids revenues for the six months endedJune 30, 2021 increased by$1.5 billion , or 119%, to$2.8 billion from$1.3 billion during the six months endedJune 30, 2020 . Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed to$1.4 billion of the total increase. The remainder of the overall change is due to a 15% increase in combined volumes sold. In both cases, higher commodity prices in the 2021 periods compared to the 2020 periods primarily reflect a recovery from historically low prices experienced in 2020 due to the COVID-19 pandemic as discussed in "- Recent Developments " above. The increase in production for the 2021 periods compared to the 2020 periods resulted primarily from the Guidon Acquisition and QEP Merger during the first quarter of 2021 and an overall recovery in our drilling and production activities after curtailments in the second quarter of 2020 in response to the COVID-19 pandemic.
Lease Operating Expenses. The following table shows lease operating expenses for
the three and six months ended
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
Amount Per BOE Amount Per BOE Amount Per BOE Amount Per BOE
(In millions, except per BOE amounts)
Lease operating expenses $ 157 $ 4.30 $ 103 $ 3.85 $ 259 $ 4.03 $ 230 $ 4.11
Lease operating expenses increased by $54 million , or $0.45 per BOE for the
second quarter of 2021 compared to the second quarter of 2020 and increased by
$29 million , or $0.08 per BOE for the first half of 2021 compared to the first
half of 2020, primarily due to an increase in production between periods driven
by the Guidon Acquisition and the QEP Merger in the first quarter of 2021. The
production acquired from QEP has higher lease operating costs per BOE on average
than our historical properties. Additionally, the increase in lease operating
costs for the first half of 2021 compared to the first half of
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2020 was partially offset by a decrease of approximately $12 million in power
generation costs related to enhancements in infrastructure which occurred
between periods.
See Note 4- Acquisitions for further details regarding acquisitions.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three and six months endedJune 30, 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Amount Per BOE Amount Per BOE Amount Per BOE Amount Per BOE (In millions, except per BOE amounts) Production taxes$ 87 $ 2.38 $ 19 $ 0.73 $ 147 $ 2.29 $ 61 $ 1.09 Ad valorem taxes 18 0.49 3 0.10 33 0.51 32 0.58 Total production and ad valorem expense$ 105 $ 2.87 $ 22 $ 0.83 $ 180 $ 2.80 $ 93 $ 1.67 Production taxes as a % of oil, natural gas, and natural gas liquids revenue 5.2 % 4.6 % 5.2 % 4.7 % 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 increased for the three and six months endedJune 30, 2021 compared to the same periods in 2020 due to the addition of production revenues from the newly acquiredWilliston Basin properties which have a higher production tax rate than our other properties. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the three months endedJune 30, 2021 as compared to the three months endedJune 30, 2020 increased by$15 million primarily due to valuation adjustments that were made in 2020 related to the COVID-19 pandemic. Ad valorem taxes for the six months endedJune 30, 2021 as compared to the six months endedJune 30, 2020 remained relatively flat. Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three and six months endedJune 30, 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Amount Per BOE Amount Per BOE Amount Per BOE Amount Per BOE (In millions, except per BOE amounts) Gathering and transportation expense$ 56 $ 1.53 $ 36 $ 1.35 $ 87 $ 1.36 $ 72 $ 1.29 The per BOE increases for gathering and transportation expenses for the three and six months endedJune 30, 2021 , compared to the same periods in 2020 are primarily attributable to the increase in production between periods, which was primarily driven by the Guidon Acquisition and the QEP Merger. The increase in gathering and transportation expense per BOE was also driven by QEP production, which on average has a higher gathering and transportation cost per BOE than our historical properties. 38
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Table of Contents Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three and six months endedJune 30, 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 (In millions, except BOE amounts) Depletion of proved oil and natural gas properties $ 318$ 330 $ 575 $ 722 Depreciation of midstream assets 15 10 26 20 Depreciation of other property and equipment 5 3 8 8 Asset retirement obligation accretion 3 1 5 3 Depreciation, depletion and amortization expense $ 341$ 344 $ 614 $ 753 Oil and natural gas properties depletion rate per BOE $ 8.70$ 12.33 $ 8.96 $ 12.90 The decrease in depletion of proved oil and natural gas properties of$12 million for the three months endedJune 30, 2021 as compared to the three months endedJune 30, 2020 and$147 million for the six months endedJune 30, 2021 as compared to the six months endedJune 30, 2020 resulted largely from a reduction in the average depletion rate for our oil and natural gas properties in 2021. The decline in rate resulted primarily from a decrease in the net book value of our properties due to the full cost ceiling impairments recorded in 2020. Impairment ofOil and Natural Gas Properties . No impairment expense was recorded for the three and six months endedJune 30, 2021 . In connection with the QEP Merger and the Guidon Acquisition, we recorded the oil and natural gas properties acquired at fair value. Pursuant toSEC guidance, we determined the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, we requested 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 related to the QEP Merger and the Guidon Acquisition was recorded for the three months endedMarch 31, 2021 . Had we not received the waiver from theSEC , an impairment charge of approximately$1.1 billion would have been recorded in the first quarter of 2021. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs atMarch 31, 2021 of$3.0 billion and$1.1 billion , respectively. As a result of the sharp decline in commodity prices during 2020, we recorded non-cash ceiling test impairments for the three and six months endedJune 30, 2020 of$2.5 billion and$3.5 billion , respectively, which are included in accumulated depletion, depreciation, amortization and impairment on our condensed consolidated balance sheet. Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. See Note 5- Property and Equipment for further details regarding factors that impact the impairment of oil and natural gas properties. General and Administrative Expenses. The following table shows general and administrative expenses for the three and six months endedJune 30, 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Amount Per BOE Amount Per BOE Amount Per BOE Amount Per BOE (In millions, except per BOE amounts) General and administrative expenses$ 23 $ 0.63 $ 11 $ 0.41 $ 38 $ 0.59 $ 26 $ 0.46 Non-cash stock-based compensation 13 0.36 9 0.33 23 0.36 18 0.33 Total general and administrative expenses$ 36 $ 0.99 $ 20 $ 0.74 $ 61 $ 0.95 $ 44 $ 0.79 39
-------------------------------------------------------------------------------- Table of Contents The increases in general and administrative expenses for the three and six months endedJune 30, 2021 compared to the three and six months endedJune 30, 2020 were due largely to additional payroll and other employee driven costs of$9 million and$11 million , respectively, related to the QEP Merger and the Guidon Acquisition. Additionally, equity compensation increased by$4 million for each of the 2021 periods compared to the 2020 periods. Merger and Integration Expense. The following tables shows merger and integration expense for the three and six months endedJune 30, 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 (In millions) Merger and integration expense $ 2 $ - $ 77 $ - Total merger and integration expense for the six months endedJune 30, 2021 includes$68 million in costs incurred for the QEP Merger and$9 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of$38 million in severance costs and$30 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consist primarily of advisory and legal fees. See Note 4- Acquisitions for further details regarding the QEP Merger and the Guidon Acquisition.
Net Interest Expense. The following table shows the components of net interest
expense for the three and six months ended
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(In millions)
Revolving credit agreements $ 2 $ 6 $ 5 $ 13
Senior notes 70 49 131 98
Amortization of debt issuance costs and
discounts 4 2 8 5
Other 2 2 4 5
Capitalized interest (21) (13) (35) (27)
Interest expense, net $ 57 $ 46 $ 113 $ 94
Net interest expense increased by $11 million and $19 million for the three and
six months ended June 30, 2021 compared to the same periods in 2020. In both
cases, 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.
These increases were partially offset by interest cost savings on the repurchase
of $368 million in outstanding principal of our 2025 Notes in March 2021 , and
the reduction in borrowings under our revolving credit agreements during 2021.
See Note 7- Debt 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 and six months ended June 30, 2021 and
2020:
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(In millions)
Gain (loss) on derivative instruments, net $ (497) $ (361) $ (661) $ 181
Net cash received (paid) on settlements(1) $ (323) $ 210 $ (425) $ 297 (1)The six 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
commodity 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
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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 of
June 30, 2021 .
We have designated certain of our interest rate swaps as fair value hedges for
accounting purposes. As a result, gains and losses due to changes in the fair
value of the interest rate swaps completely offset changes in the fair value of
the hedged portion of the underlying debt and no gain or loss is recognized due
to hedge ineffectiveness. Changes in fair value are recorded as an adjustment to
the carrying value of the 2029 Notes in the condensed consolidated balance
sheet. Beginning on December 1, 2021 , semi-annual cash settlements of these
interest rate swaps will be recorded in interest expense in the condensed
consolidated statements of operations.
Provision for (Benefit from) Income Taxes. The following table shows the
provision for (benefit from) income taxes for the three and six months ended
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(Inmillions)
Provision for (benefit from) income taxes $ 94$ (681) $ 159$ (598) The changes in our income tax provision for the three and six months endedJune 30, 2021 compared to the same periods in 2020 were primarily due to the increase in pre-tax income for the three and six months endedJune 30, 2021 , partially offset by income tax expense resulting from recording a valuation allowance on Viper's deferred tax assets for the three and six months endedJune 30, 2020 .
Liquidity and Capital Resources
As ofJune 30, 2021 , we had$1.6 billion of availability for future borrowings under the credit agreement and approximately$344 million of cash on hand. Historically, our primary sources of liquidity have been cash flows from operations, proceeds from our public equity offerings, borrowings under the credit agreement and proceeds from the issuance of our senior notes. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties and return of capital to our stockholders. As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the commodity pricing environment and uncertain macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Liquidity and Cash Flow Our cash flows for the six months endedJune 30, 2021 and 2020 are presented below: Six Months Ended June 30, 2021 2020 (In millions) Net cash provided by (used in) operating activities$ 1,578 $ 1,173 Net cash provided by (used in) investing activities (898) (1,535) Net cash provided by (used in) financing activities (392) 293 Net increase (decrease) in cash $ 288$ (69) 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. 41 -------------------------------------------------------------------------------- Table of Contents The increase in operating cash flows for the six months endedJune 30, 2021 compared to the same period in 2020 primarily resulted from (i) an increase of$1.5 billion in our total revenues, and (ii) receipt of a$99 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. These net cash inflows were partially offset by (i) a reduction of$781 million due to making net cash payments of$484 million on our derivative contracts in the six months endedJune 30, 2021 compared to receiving net cash of$297 million on our derivative contracts in the six months endedJune 30, 2020 , (ii) an increase in our cash operating expenses of approximately$228 million primarily due to the QEP Merger and the Guidon Acquisition, and (iii) working capital changes, primarily due to recording working capital assets and liabilities acquired in the QEP Merger duringMarch 2021 . See "- Results of Operations" for discussion of significant changes in our revenues and expenses.
Investing Activities
Net cash used in investing activities was$898 million compared to$1.5 billion during the six months endedJune 30, 2021 and 2020, respectively. The majority of our net cash used for investing activities during the six months endedJune 30, 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. These expenditures were partially offset by proceeds from the sale of leasehold acreage discussed in Note 4- Acquisitions and D ivestitures .
The majority of our net cash used in investing activities during the six months
ended
Capital Expenditure Activities
Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:
Six Months Ended June 30,
2021 2020
(In millions) Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)
$ 623 $ 1,178 Infrastructure additions to oil and natural gas properties 22 80 Additions to midstream assets 17 94 Total$ 662 $ 1,352 (1)During the six months endedJune 30, 2021 , in conjunction with our development program, we drilled 105 gross (99 net) operated horizontal wells, of which 88 gross (83 net) wells were in theMidland Basin and 17 gross (16 net) wells were in theDelaware Basin , and turned 132 gross (121 net) operated horizontal wells to production, of which 89 gross (81 net) wells were in theMidland Basin and 39 gross (37 net) wells were in theDelaware Basin . (2)During the six months endedJune 30, 2020 , in conjunction with our development program, we drilled 151 gross (141 net) operated horizontal wells, of which 92 gross (86 net) wells were in theMidland Basin and 59 gross (55 net) wells were in theDelaware Basin , and turned 95 gross (83 net) operated horizontal wells to production, of which 51 gross (47 net) wells were in theDelaware Basin and 44 gross (36 net) wells were in theMidland Basin .
Financing Activities
Net cash used in financing activities for the six months endedJune 30, 2021 was$392 million compared to net cash provided by financing activities for the six months endedJune 30, 2020 of$293 million . During the six months endedJune 30, 2021 , the amount used in financing activities was primarily attributable to (i)$2.1 billion paid for the repurchase of a portion of the QEP Notes and the 2025 Senior Notes and the Energen Notes and the redemption of the Energen 4.62% Senior Notes due 2021, as well as$166 million of additional premiums paid in connection with the repurchases, (ii)$140 million of dividends paid to stockholders, (iii)$119 million of repayments under our credit facilities, net of borrowings, (iv)$41 million in distributions to non-controlling interest, and (v)$36 million of unit repurchases as part of the Viper and Rattler unit repurchase programs. These cash outflows were partially offset by$2.2 billion in proceeds from theMarch 2021 Notes and$59 million in net cash receipts from the early settlement of interest rate swaps and commodity derivative contracts that contained an other-than-insignificant financing element. 42 -------------------------------------------------------------------------------- Table of Contents Net cash provided by financing activities for the six months endedJune 30, 2020 was primarily attributable to (i)$275 million in proceeds, net of repayments, from senior notes, (ii)$262 million of borrowings, net of repayments, under our credit facilities and (iii)$43 million in proceeds from joint ventures. These cash inflows were partially offset by (i)$118 million of dividends to stockholders, (ii)$98 million of share repurchases as part of our previous stock repurchase program, and (iii)$62 million of distributions to non-controlling interest.
Indebtedness
AtJune 30, 2021 , our debt, including the debt of Viper and Rattler, consists of approximately$7.3 billion in aggregate outstanding principal amount of senior notes,$67 million in aggregate outstanding borrowings under revolving credit facilities and$68 million in outstanding amounts due under our DrillCo Agreement. Our revolving credit facilities and significant changes in our outstanding indebtedness during the six months endedJune 30, 2021 are discussed further below. See Note 7- Debt for additional discussion of our outstanding debt atJune 30, 2021 .
Second Amended and Restated Credit Facility
As discussed in "- Recent Developments " onJune 2, 2021 , we entered into an amendment to the credit agreement. As ofJune 30, 2021 , the maximum credit amount available under the credit agreement was$1.6 billion , with no outstanding borrowings and$1.6 billion available for future borrowings. As ofJune 30, 2021 , there was an aggregate of$3 million in outstanding letters of credit, which reduces available borrowings under the credit agreement on a dollar for dollar basis. The borrowing base is scheduled to be redetermined semi-annually in May and November. During the three and six months endedJune 30, 2021 , the weighted average interest rate on the credit facility was 1.68% and 1.67%, respectively.
As of
OnMarch 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 theMarch 2021 Notes is payable semi-annually onMarch 24 andSeptember 24 , beginning onSeptember 24, 2021 . 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 six months endedJune 30, 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 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. 43 -------------------------------------------------------------------------------- Table of Contents InJune 2021 , we redeemed the remaining$191 million principal amount of the outstanding Energen 4.625% senior notes due onSeptember 1, 2021 . We recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the redeemed notes.
Pending Full Redemption of the Outstanding 5.375% Senior Notes due 2025
As discussed in "- Recent Developments " on
Viper's Credit Agreement
The Viper credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of$2.0 billion , with a borrowing base of$580 million as ofJune 30, 2021 , althoughViper LLC had elected a commitment amount of$500 million , based onViper LLC's oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. As ofJune 30, 2021 , there were$62 million of outstanding borrowings and$438 million available for future borrowings under the Viper credit agreement. During the three and six months endedJune 30, 2021 , the weighted average interest rate on borrowings under the Viper credit agreement was 1.93% and 1.90%, respectively. The Viper credit agreement will mature onJune 2, 2025 .
As of
Rattler's Credit Agreement
The Rattler credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of$600 million , which is expandable to$1.0 billion upon Rattler's election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As ofJune 30, 2021 , there were$5 million of outstanding borrowings and$595 million available for future borrowings under the Rattler credit agreement. During the three and six months endedJune 30, 2021 , the weighted average interest rate on borrowings under the Rattler credit agreement was 1.36% and 1.39%. The Rattler credit agreement matures onMay 28, 2024 .
As of
Capital Requirements and Sources of Liquidity
Our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (iii) payments of contractual obligations, including debt maturities, (iv) dividends and share repurchases, and (v) working capital obligations. 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$1.5 billion to$1.6 billion to give effect to the QEP Merger, representing an increase at the midpoint of 9% over our original 2021 capital budget. We estimate that, of these expenditures, approximately: •$1.38 billion to$1.45 billion will be spent on drilling and completing 265 to 275 gross (246 to 256 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;
•$50 million to
•$100 million to
We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
During the six months endedJune 30, 2021 , we spent$603 million on drilling and completion,$17 million on midstream,$20 million on non-operated properties and$22 million on infrastructure, for total capital expenditures, excluding acquisitions, of$662 million . 44 -------------------------------------------------------------------------------- Table of Contents 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 nine 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 currently intend to reduce our estimated 2021 capital budget by 6% at the midpoint of the previously disclosed guidance due to cost control and outperformance of our 2021 development plan, intending to maintain current production levels with less capital and fewer completed wells than was originally expected in our 2021 development plan. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget 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 and thereafter. 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. We cannot assure you that the needed capital will be available on acceptable terms or at all. Further, our 2021 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.
Guarantor Financial Information
In connection with the merger of certain of the Company's wholly owned subsidiaries as ofJune 30, 2021 completed as part of the internal subsidiary restructuring,Diamondback E&P became the successor borrower to O&G under the credit agreement, the successor issuer of the Energen Medium-Term Notes and 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 the 2019 Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the eventDiamondback E&P (or all or substantially all of its assets) is sold or disposed of, (2) in the eventDiamondback E&P 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 E&P'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 E&P may be limited under theU.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limitDiamondback E&P'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 E&P . 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. 45 -------------------------------------------------------------------------------- Table of Contents The following tables present summarized financial information forDiamondback Energy, Inc. , as the parent, andDiamondback E&P , 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. June 30, 2021 December 31, 2020 Summarized Balance Sheets: (In millions) Assets: Current assets $ 774 $ 308 Property and equipment, net$ 14,314 $ 6,934 Other noncurrent assets $ 47 $ 6 Liabilities: Current liabilities$ 1,659 $ 355 Intercompany accounts payable, non-guarantor subsidiary $ 84 $ 335 Long-term debt$ 6,204 $ 4,293 Other noncurrent liabilities$ 1,088 $ 886 Six Months Ended June 30, 2021 Summarized Statement of Operations: (In millions) Revenues $
2,196
Income (loss) from operations $ 1,160
Net income (loss) $ 314
Contractual Obligations
In addition to the changes in debt discussed in " -Indebtedness " above and in
Note 7- Deb t included in the notes to the condensed consolidated financial
statements included elsewhere in this report, we acquired certain contractual
obligations during the six months ended June 30, 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
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 ofJune 30, 2021 . Please read Note 13- Commitments 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. 46
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