Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 ended December 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 the Permian Basin in West 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 the Midland and Delaware Basins of the Permian Basin.

Guidon Acquisition and QEP Merger

On February 26, 2021, we completed the Guidon Acquisition, which included approximately 32,500 net acres in the Northern Midland Basin, in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash.

On March 17, 2021, we completed the acquisition of QEP pursuant to the Agreement and Plan of Merger, dated as of December 20, 2020, by and among Diamondback, certain of our subsidiaries and QEP. The addition of QEP’s assets increased our net acreage in the Midland 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 Developments

Recent and Pending Acquisitions and Divestitures

On October 19, 2021, we entered into a purchase and sale agreement with Rattler to sell certain water midstream assets with a carrying value of approximately $160 million to Rattler in exchange for cash proceeds of approximately $160 million. The drop down transaction is expected to close in the fourth quarter of 2021, subject to customary closing conditions.

On October 21, 2021 we completed the divestiture of our Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres acquired in the QEP Merger, for net cash proceeds of approximately $586 million after customary closing adjustments.

On November 1, 2021, we completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC for proceeds of approximately $54 million, after customary closing adjustments.

On October 1, 2021, Viper completed the Swallowtail Acquisition, which included certain mineral and royalty interests for 15.25 million of Viper’s common units and approximately $225 million in cash. The cash portion of the purchase price was funded through a combination of cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.

On October 5, 2021, Rattler contributed approximately $104 million in cash for a 25% membership interest in the Remuda joint venture, which then completed the acquisition of a majority interest in WTG Midstream.

On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos Delaware Gas, LLC for proceeds of approximately $83 million at closing, subject to customary closing adjustments, and an aggregate of $10 million in contingent payments.

Redemption of Notes

In August 2021, we redeemed the remaining $432 million in aggregate principal amount of our outstanding 5.375% 2025 Senior Notes with cash on hand and borrowings under our revolving credit facility.

On November 1, 2021, we redeemed the aggregate $650 million principal amount of our outstanding 2023 Senior Notes with the proceeds received from the divestiture of our Williston Basin assets and cash on hand.

See Note 14—Subsequent Events for additional discussion of transactions completed in the fourth quarter of 2021.

Stock Repurchase Program

In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock. This repurchase program is another component of our capital return program, which also includes our quarterly dividend. We anticipate the repurchase program will be funded primarily by free cash flow generated from operations and liquidity events such as the sale of assets. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require us to acquire any specific number of shares and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the three and nine months ended September 30, 2021, we repurchased approximately $22 million shares of our common stock, and as of September 30, 2021, $1.98 billion remained available for future purchases under our common stock repurchase program.

COVID-19 and Commodity Prices

In early March 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 by OPEC 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. Additionally, the Delta variant emerged in March 2021 and became highly transmissible in July 2021, which contributed to additional pricing and demand volatility during the third quarter of 2021. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in 2021 in response to the overall increase in demand.

During 2020 and 2021, the posted NYMEX WTI price for crude oil ranged from $(37.63) to $80.64 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $6.31 per MMBtu. On October 13, 2021, the NYMEX WTI price for crude oil was $80.44 per Bbl and the NYMEX Henry Hub price of natural gas was $5.59 per MMBtu. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices.

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 the Permian 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 remainder of 2021, focusing on cost control and using excess cash flow for debt payment and return of capital to our stockholders.

During the third quarter of 2021, we continued building on our execution track record, generating free cash flow while keeping capital costs under control, and our efficiency gains, particularly in the Midland Basin drilling and completion programs, were able to mitigate certain inflationary pressures on well costs and have led to our second decrease in capital guidance in 2021, now down 10% from our guidance presented in April of 2021. We expect to continue to exercise capital discipline and maintain flat oil production in 2022 and believe that this can be accomplished by spending similar capital to our fourth quarter 2021 guidance. This capital range accounts for the inflationary pressures seen this year and anticipated in 2022. We expect to be in a position to continue to deliver on the recently announced enhanced capital return program, where we expect to distribute 50% of our quarterly free cash flow to our stockholders, beginning with the fourth quarter 2021. Our capital return program is currently focused on our sustainable and growing dividend and a combination of stock repurchases and variable dividends, which are expected to be used interchangeably, depending on which option we believe presents the best return of capital to our stockholders at the relevant time.

Third Quarter 2021 Operating Highlights

We recorded net income of $649 million for the third quarter of 2021.
Our average production was 404.3 MBOE/d during the third quarter of 2021.
During the third quarter of 2021, we drilled 47 gross horizontal wells in the Midland Basin and 11 gross horizontal wells in the Delaware Basin.
We turned 73 gross operated horizontal wells (63 in the Midland Basin and 10 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $391 million during the third quarter of 2021.
The average lateral length for the wells completed during the third quarter of 2021 was 11,225 feet.
Our cash operating costs for the third quarter of 2021 were $9.97 per BOE, including lease operating expenses of $4.19 per BOE, cash general and administrative expenses of $0.65 per BOE and production and ad valorem taxes and gathering and transportation expenses of $5.13 per BOE.
On October 28, 2021, our board of directors declared a cash dividend for the third quarter of 2021 of $0.50 per share of common stock, payable on November 18, 2021 to our stockholders of record at the close of business on November 11, 2021.

Upstream Segment

In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin within the Permian 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 the Permian Basin and derives royalty income and lease bonus income from such interests.

As of September 30, 2021, we had approximately 540,915 net acres, which primarily consisted of approximately 263,208 net acres in the Midland Basin and 149,405 net acres in the Delaware Basin. Additionally, completed the divestiture of all of our Williston Basin assets totaling approximately 95,000 net acres in October 2021.

The following table sets forth the total number of operated horizontal wells drilled and completed during the three and nine months ended September 30, 2021:


	Three Months Ended September 30, 2021				Nine Months Ended September 30, 2021
	Drilled		Completed(1)		Drilled		Completed(2)
Area	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Midland Basin	47	44	63	59	135	127	152	140
Delaware Basin	11	10	10	9	28	26	49	46
Other	—	—	—	—	—	—	4	3
Total	58	54	73	68	163	153	205	189

(1)The average lateral length for the wells completed during the third quarter of 2021 was 11,225 feet. Operated completions during the third quarter of 2021 consisted of 23 Wolfcamp A wells, 21 Lower Spraberry wells, 10 Middle Spraberry wells, eight Jo Mill wells, four Wolfcamp B wells, four Dean wells, two Second Bone Springs wells and one Third Bone Springs wells.

(2)The average lateral length for the wells completed during the first nine months of 2021 was 10,906 feet. Operated completions during the first nine months of 2021 consisted of 61 Wolfcamp A wells, 50 Lower Spraberry wells, 25 Middle Spraberry wells, 21 Jo Mill wells, 17 Wolfcamp B wells, 10 Second Bone Springs wells, nine Third Bone Springs wells, seven Dean wells, two Bakken wells, two Three Forks wells and one Barnett well.

As of September 30, 2021, we operated the following wells:


	As of September 30, 2021
	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	2,298	2,142	1,689	1,565	3,987	3,707
Delaware Basin	28	25	656	613	684	638
Other	—	—	412	356	412	356
Total	2,326	2,167	2,757	2,534	5,083	4,701

As of September 30, 2021, we held interests in 11,214 gross (4,844 net) wells, including wells that we do not operate. During the first quarter of 2021, we acquired interests in 1,671 gross (1,240 net) wells as part of the QEP Merger.

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 and Glasscock areas within the Permian 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 from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler’s gathering and disposal system spans approximately 521 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 our Permian 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 the Delaware 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 nine months ended September 30, 2021 and 2020. See Note 15—Segment Information for further details regarding acquisitions.

Results of Operations

The following table sets forth selected operating data for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenues (In millions):
Oil sales	$	1,506	$	606	$	3,845	$	1,785
Natural gas sales	152		36		363		61
Natural gas liquid sales	239		65		528		156
Total oil, natural gas and natural gas liquid revenues	$	1,897	$	707	$	4,736	$	2,002

Production Data:
Oil (MBbls)	22,058		15,639		60,703		50,009
Natural gas (MMcf)	45,571		32,505		124,186		96,482
Natural gas liquids (MBbls)	7,540		5,377		19,992		16,326
Combined volumes (MBOE)(1)	37,193		26,433		101,393		82,415

Daily oil volumes (BO/d)	239,761		169,989		222,355		182,515
Daily combined volumes (BOE/d)	404,272		287,315		371,403		300,785

Average Prices:
Oil ($ per Bbl)	$	68.27	$	38.75	$	63.34	$	35.69
Natural gas ($ per Mcf)	$	3.34	$	1.11	$	2.92	$	0.63
Natural gas liquids ($ per Bbl)	$	31.70	$	12.09	$	26.41	$	9.56
Combined ($ per BOE)	$	51.00	$	26.75	$	46.71	$	24.29

Oil, hedged ($ per Bbl)(2)	$	53.81	$	38.17	$	50.46	$	41.31
Natural gas, hedged ($ per MMBtu)(2)	$	2.04	$	0.95	$	2.13	$	0.57
Natural gas liquids, hedged ($ per Bbl)(2)	$	31.30	$	12.09	$	26.16	$	9.56
Average price, hedged ($ per BOE)(2)	$	40.76	$	26.22	$	37.97	$	27.63

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)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 nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Oil (MBbls)	59	%	59	%	60	%	61	%
Natural gas (MMcf)	21	%	21	%	20	%	19	%
Natural gas liquids (MBbls)	20	%	20	%	20	%	20	%
	100	%	100	%	100	%	100	%


	Three Months Ended September 30, 2021				Three Months Ended September 30, 2020
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	14,265	6,247	1,546	22,058	8,971	6,627	41	15,639
Natural gas (MMcf)	26,246	16,210	3,115	45,571	17,403	15,003	99	32,505
Natural gas liquids (MBbls)	4,547	2,301	692	7,540	3,087	2,268	22	5,377
Total (MBoe)	23,186	11,250	2,757	37,193	14,958	11,395	80	26,433


	Nine Months Ended September 30, 2021				Nine Months Ended September 30, 2020
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	38,065	19,074	3,564	60,703	28,864	21,013	132	50,009
Natural gas (MMcf)	69,822	47,503	6,861	124,186	50,285	45,871	326	96,482
Natural gas liquids (MBbls)	12,146	6,438	1,408	19,992	9,281	6,975	70	16,326
Total (MBoe)	61,848	33,429	6,116	101,393	46,525	35,633	257	82,415

(1)Includes the Eagle Ford Shale, Rockies and High Plains.

(2)Includes the Central Basin Platform, Eagle Ford Shale and Rockies.

Comparison of the Three Months Ended September 30, 2021 and 2020 and Nine Months Ended September 30, 2021 and 2020

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 ended September 30, 2021 increased by $1.2 billion, or 168%, to $1.9 billion from $707 million during the three months ended September 30, 2020. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed $0.9 billion of the total increase. The remainder of the overall change is due to a 41% increase in combined volumes sold.

Our oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2021 increased by $2.7 billion, or 137%, to $4.7 billion from $2.0 billion during the nine months ended September 30, 2020. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed to $2.3 billion of the total increase. The remainder of the overall change is due to a 23% 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. We expect to hold our oil production levels flat for the foreseeable future.

Lease Operating Expenses. The following table shows lease operating expenses for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,								Nine Months Ended September 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	$	156	$	4.19	$	102	$	3.86	$	415	$	4.09	$	332	$	4.03

Lease operating expenses increased by $54 million, or $0.33 per BOE for the third quarter of 2021 compared to the third quarter of 2020 and increased by $83 million, or $0.06 per BOE for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. In both cases, this increase is 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 increase on a per BOE basis is primarily related to the Williston Basin assets acquired in the QEP Merger which have higher lease operating costs per BOE on average than our historical properties.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,										Nine Months Ended September 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	$	98		$	2.63	$	36		$	1.36	$	245		$	2.42	$	97		$	1.18
Ad valorem taxes	26			0.70		19			0.72		59			0.58		51			0.62
Total production and ad valorem expense	$	124		$	3.33	$	55		$	2.08	$	304		$	3.00	$	148		$	1.80

Production taxes as a % of oil, natural gas, and natural gas liquids revenue	5.2		%			5.1		%			5.2		%			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 increased slightly for the three and nine months ended September 30, 2021 compared to the same periods in 2020 due to the addition of production revenues from the acquired Williston Basin properties which have a higher production tax rate than our other properties. We completed the divestiture of the Williston Basin properties in October 2021.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the three and nine months ended September 30, 2021 as compared to the same periods in 2020 increased by $7 million and $8 million, respectively, primarily due to additional properties acquired in the Guidon acquisition and the QEP Merger.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,								Nine Months Ended September 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	$	67	$	1.80	$	33	$	1.25	$	154	$	1.52	$	105	$	1.27

The increases for gathering and transportation expenses for the three and nine months ended September 30, 2021, compared to the same periods in 2020 are primarily attributable to the increase in production between periods. Additionally, the production added from the QEP Merger has higher average gathering and transportation costs per BOE than our historical properties.

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties	$	324	$	273	$	899	$	995
Depreciation of midstream assets	11		9		37		29
Depreciation of other property and equipment	4		4		12		12
Asset retirement obligation accretion	2		2		7		5
Depreciation, depletion and amortization expense	$	341	$	288	$	955	$	1,041
Oil and natural gas properties depletion rate per BOE	$	8.71	$	10.33	$	8.87	$	12.07

The increase in depletion of proved oil and natural gas properties of $51 million for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020 resulted largely from increased production partially offset by a lower average depletion rate. The decline in rate resulted primarily from higher SEC prices utilized in the reserve calculations in the 2021 period, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.

The decrease in depletion of proved oil and natural gas properties of $96 million for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 resulted largely from a reduction in the average depletion rate partially offset by increased production in 2021. The decline in rate resulted primarily from higher SEC oil prices utilized in the reserve calculations in the 2021 period, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.

Impairment of Oil and Natural Gas Properties. No impairment expense was recorded for the three and nine months ended September 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 to SEC 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 the SEC 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 ended March 31, 2021. Had we not received the waiver from the SEC, 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 at March 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 nine months ended September 30, 2020 of $1.5 billion and $5.0 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 nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,								Nine Months Ended September 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	$	24	$	0.65	$	11	$	0.42	$	62	$	0.61	$	37	$	0.45
Non-cash stock-based compensation	14		0.37		9		0.34		37		0.37		27		0.33
Total general and administrative expenses	$	38	$	1.02	$	20	$	0.76	$	99	$	0.98	$	64	$	0.78

The increases in general and administrative expenses for the three and nine months ended September 30, 2021 compared to the three and nine months ended September 30, 2020 were due largely to additional payroll and other employee driven costs of $11 million and $21 million, respectively, related to the QEP Merger and the Guidon Acquisition. Additionally, equity compensation increased by $5 million and $10 million for the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020.

Merger and Integration Expense. The following tables shows merger and integration expense for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Merger and integration expense	$	—	$	—	$	77	$	—

Total merger and integration expense for the nine months ended September 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 and Divestitures 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 nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Revolving credit agreements	$	2	$	4	$	7	$	17
Senior notes	66		57		197		155
Amortization of debt issuance costs and discounts	5		4		13		9
Other	1		2		5		7
Capitalized interest	(16)		(14)		(51)		(41)
Total	58		53		171		147
Less: interest income	1		—		1		—
Interest expense, net	$	57	$	53	$	170	$	147

Net interest expense increased by $4 million and $23 million for the three and nine months ended September 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, the newly issued March 2021 Notes, and to a lesser extent, interest expense incurred on the QEP Notes that remained outstanding following the QEP Merger completed in March 2021. These increases were partially offset by interest cost savings on the repurchases of our 2025 Senior Notes in March 2021 and August 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 nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Gain (loss) on derivative instruments, net	$	(234)	$	(99)	$	(895)	$	82
Net cash received (paid) on settlements(1)(2)(3)	$	(397)	$	(9)	$	(822)	$	288

(1)The three and nine months ended September 30, 2021 include cash paid on commodity contracts terminated prior to their contractual maturity of $16 million.

(2)The three and nine months ended September 30, 2020 include cash received on commodity contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.

(3)The nine months ended September 30, 2021 include cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

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 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 September 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 nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Provision for (benefit from) income taxes	$	193	$	(304)	$	352	$	(902)

The changes in our income tax provision for the three and nine months ended September 30, 2021 compared to the same periods in 2020 were primarily due to the increase in pre-tax income for the three and nine months ended September 30, 2021, partially offset by income tax expense resulting from recording a valuation allowance on Viper’s deferred tax assets for the nine months ended September 30, 2021.

Liquidity and Capital Resources

As of September 30, 2021, we had $1.6 billion of availability for future borrowings under the credit agreement and approximately $457 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 nine months ended September 30, 2021 and 2020 are presented below:


	Nine Months Ended September 30,
	2021		2020
	(In millions)
Net cash provided by (used in) operating activities	$	2,777	$	1,715
Net cash provided by (used in) investing activities	(1,323)		(1,855)
Net cash provided by (used in) financing activities	(1,021)		111
Net increase (decrease) in cash	$	433	$	(29)

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 increase in operating cash flows for the nine months ended September 30, 2021 compared to the same period in 2020 primarily resulted from (i) an increase of $2.7 billion in our total revenues, and (ii) receipt of $152 million in refunds of income taxes 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 $1.1 billion due to making net cash payments of $847 million on our derivative contracts in the nine months ended September 30, 2021 compared to receiving net cash of $288 million on our derivative contracts in the nine months ended September 30, 2020, (ii) an increase in our cash operating expenses of approximately $396 million primarily due to the QEP Merger and the Guidon Acquisition, (iii) an increase of $77 million in our cash paid for interest primarily due to interest payments on senior notes which were issued in 2020 and 2021 and (iv) other working capital changes, primarily due to recording activity for working capital assets and liabilities acquired in the QEP Merger during March 2021. See “— Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

Net cash used in investing activities was $1.3 billion compared to $1.9 billion during the nine months ended September 30, 2021 and 2020, respectively. The majority of our net cash used for investing activities during the nine months ended September 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 Divestitures.

The majority of our net cash used in investing activities during the nine months ended September 30, 2020 was incurred for drilling and completion costs in conjunction with our development program. Our capital expenditures for each period are discussed further below.

Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:


	Nine Months Ended September 30,
	2021		2020
	(In millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)	$	987	$	1,404
Infrastructure additions to oil and natural gas properties	43		96
Additions to midstream assets	23		133
Total	$	1,053	$	1,633

(1)During the nine months ended September 30, 2021, in conjunction with our development program, we drilled 163 gross (153 net) operated horizontal wells, of which 135 gross (127 net) wells were in the Midland Basin and 28 gross (26 net) wells were in the Delaware Basin, and turned 205 gross (189 net) operated horizontal wells to production, of which 152 gross (140 net) wells were in the Midland Basin and 49 gross (46 net) wells were in the Delaware Basin.

(2)During the nine months ended September 30, 2020, in conjunction with our development program, we drilled 183 gross (173 net) operated horizontal wells, of which 114 gross (108 net) wells were in the Midland Basin and 69 gross (65 net) wells were in the Delaware Basin, and turned 136 gross (124 net) operated horizontal wells to production, of which 69 gross (61 net) wells were in the Midland Basin and 67 gross (63 net) wells were in the Delaware Basin .

Financing Activities

Net cash used in financing activities for the nine months ended September 30, 2021 was $1.0 billion compared to net cash provided by financing activities for the nine months ended September 30, 2020 of $111 million. During the nine months ended September 30, 2021, the amount used in financing activities was primarily attributable to (i) $2.5 billion paid for the repurchase of principal outstanding on certain senior notes as discussed in “— Repurchases of Notes” below, as well as $178 million of additional premiums paid in connection with the repurchases, (ii) $221 million of dividends paid to stockholders, (iii) $94 million of repayments under our credit facilities, net of borrowings, (iv) $72 million in distributions to non-controlling interest, and (v) $85 million of repurchases as part of the share and unit repurchase programs. These cash outflows were partially offset by $2.2 billion in proceeds from the March 2021 Notes and $25 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.

Net cash provided by financing activities for the nine months ended September 30, 2020 was primarily attributable to $758 million in proceeds, net of repayments, from senior notes and $47 million in proceeds from joint ventures. These cash inflows were partially offset by (i) $321 million of repayments, net of borrowings, under our credit facilities (i) $177 million of dividends to stockholders, (ii) $98 million of share repurchases as part of our previous stock repurchase program, and (iii) $77 million of distributions to non-controlling interest.

Indebtedness

At September 30, 2021, our debt, including the debt of Viper and Rattler, consists of approximately $6.9 billion in aggregate outstanding principal amount of senior notes, $92 million in aggregate outstanding borrowings under revolving credit facilities and $65 million in outstanding amounts due under our DrillCo Agreement. Our revolving credit facilities and

significant changes in our outstanding indebtedness during the nine months ended September 30, 2021 are discussed further below. See Note 7—Debt for additional discussion of our outstanding debt at September 30, 2021.

Second Amended and Restated Credit Facility

As discussed in “— Recent Developments” on June 2, 2021, we entered into an amendment to the credit agreement. As of September 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 of September 30, 2021, there was an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under the credit agreement on a dollar for dollar basis. During the nine months ended September 30, 2021, the weighted average interest rate on the credit facility was 1.67%.

As of September 30, 2021, we were in compliance with all financial maintenance covenants under the credit agreement.

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 in March and September, beginning in September 2021.

Repurchases of Notes

Subsequent to the QEP Merger, in March 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 ended March 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.

In March 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. This resulted in a loss on extinguishment of debt during the nine months ended September 30, 2021 of $14 million.

We funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above.

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, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.

In June 2021, we redeemed the remaining $191 million principal amount of the outstanding Energen 4.625% senior notes due on September 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. We funded the redemption with internally generated cash flow from operations as well as proceeds from the divestitures of certain non-core assets as discussed in Note 4—Acquisitions and Divestitures.

In August 2021, we redeemed the remaining $432 million principal amount of our outstanding 5.375% Senior Notes due 2025 for total cash consideration of $449 million, including redemption and early premium fees of $12 million, which resulted in a loss on extinguishment of debt during the three and nine months ended September 30, 2021 of $12 million. We funded the redemption with cash on hand and borrowings under its revolving credit facility.

On November 1, 2021, we redeemed the aggregate $650 million principal amount of our outstanding 2023 Senior Notes at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. We funded the redemption with proceeds received from the divestiture of our Williston Basin assets and cash on hand.

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 of September 30, 2021, although Viper LLC had elected a commitment amount of $500 million, based on Viper LLC’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November, and is expected to be reaffirmed at $580 million by the lenders during the redetermination in November 2021. As of September 30, 2021, there were $92 million of outstanding borrowings and $408 million available for future borrowings under the Viper credit agreement. In the fourth quarter of 2021, approximately $190.0 million of the cash portion of the Swallowtail Acquisition was funded through borrowings under Viper’s credit agreement, reducing the amount that remained available for future borrowings under this facility to $218.0 million as of October 1, 2021. During the three and nine months ended September 30, 2021, the weighted average interest rate on borrowings under the Viper credit agreement was 1.98% and 2.14%, respectively. The Viper credit agreement will mature on June 2, 2025.

As of September 30, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

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 of September 30, 2021, there were no outstanding borrowings and $600 million available for future borrowings under the Rattler credit agreement. During the three and nine months ended September 30, 2021, the weighted average interest rate on borrowings under the Rattler credit agreement was 1.34% and 1.38%, respectively. The Rattler credit agreement matures on May 28, 2024.

As of September 30, 2021, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

Capital Requirements and Sources of Liquidity

Our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of contractual obligations, including debt maturities, (iii) dividends and share repurchases, and (iv) working capital obligations.

During the fourth quarter of 2021, we updated our 2021 capital budget to approximately $1.49 billion to $1.53 billion, which represented a decrease at the midpoint of 4% over our previously announced capital budget. This decrease is due to cost control and volume outperformance of our 2021 development plan. We intend to maintain current production levels with less capital and fewer completed wells than were originally expected in our 2021 development plan. We estimate that, of these expenditures, approximately:

$1.39 billion to $1.42 billion will be spent primarily on drilling and completing and 265 to 275 gross (246 to 256 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,500 feet;
$40 million will be spent on midstream infrastructure, excluding joint venture investments; and
$60 million to $70 million will be spent on infrastructure and environmental expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

During the nine months ended September 30, 2021, we spent $948 million on drilling and completion, $23 million on midstream, $39 million on non-operated properties and $43 million on infrastructure, for total capital expenditures, excluding acquisitions, of $1,053 million.

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 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.

In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock. We repurchased approximately $22 million of our common stock during the nine months ended September 30, 2021, with approximately $1.98 billion remaining available for future repurchases under this program. We intend to continue to purchase shares under this repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs.

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 in an internal subsidiary restructuring on June 30, 2021, 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 the December 2019 Notes, the May 2020 Notes, the 2025 Senior Notes and the March 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 event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback 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. The 2025 Indenture was terminated in connection with the early redemption of the remaining $432 million principal amount of our 2025 Senior Notes in the third quarter of 2021.

Diamondback E&P’s guarantees of the December 2019 Notes, the May 2020 Notes, and the March 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 against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback 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 of Diamondback 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.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback 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 the SEC’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.


	September 30, 2021		December 31, 2020
Summarized Balance Sheets:	(In millions)
Assets:
Current assets	$	979	$	308

Property and equipment, net	$	14,558	$	6,934
Other noncurrent assets	$	44	$	6
Liabilities:
Current liabilities	$	1,675	$	355
Intercompany accounts payable, non-guarantor subsidiary	$	468	$	335
Long-term debt	$	5,748	$	4,293
Other noncurrent liabilities	$	1,270	$	886


	Nine Months Ended September 30, 2021
Summarized Statement of Operations:	(In millions)
Revenues	$	3,516
Income (loss) from operations	$	1,964
Net income (loss)	$	658

Contractual Obligations

In addition to the changes in debt discussed in “—Indebtedness” above and in Note 7—Debt included in the notes to the condensed consolidated financial statements included elsewhere in this report, we acquired certain contractual obligations during the nine months ended September 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 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 December 31, 2020.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of September 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.

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