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.

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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.


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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.



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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.


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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.

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Production Data

Substantially all of our revenues are generated through the sale of oil, natural
gas and natural gas liquids production. The following tables set forth 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
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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.

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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.

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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.

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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         Nine Months Ended September
                                                              30,                                  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         Nine Months Ended September
                                                                    30,                                 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.

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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         Nine Months Ended September
                                                            30,                                 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.
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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
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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.
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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
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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.

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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-  Deb  t 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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