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, 2019. The following discussion contains "forward-looking
statements" that reflect our future plans, estimates, beliefs, and expected
performance. Actual results and the timing of events may differ materially from
those contained in these forward-looking statements due to a number of factors.
See "Part II. Item 1A. Risk Factors" and "Cautionary Statement Regarding
Forward-Looking Statements."

Overview



We operate in two business segments: (i) the upstream segment, which is engaged
in the acquisition, development, exploration and exploitation of unconventional,
onshore oil and natural gas reserves in the Permian Basin in West Texas and (ii)
through our publicly-traded subsidiary, Rattler, the midstream operations
segment, which is focused on ownership, operation, development and acquisition
of the midstream infrastructure assets in the Midland and Delaware Basins of the
Permian Basin.

2020 Recent Developments

COVID-19 and Recent Collapse in Commodity Prices



On March 11, 2020, the World Health Organization characterized the global
outbreak of the novel strain of coronavirus, COVID-19, as a "pandemic." To limit
the spread of COVID-19, governments have taken various actions including the
issuance of stay-at-home orders and social distancing guidelines, causing some
businesses to suspend operations and a reduction in demand for many products
from direct or ultimate customers. Such actions have resulted in a swift and
unprecedented reduction in international and U.S. economic activity which, in
turn, has adversely affected the demand for oil and natural gas and caused
significant volatility and disruption of the financial markets.

In early March 2020, oil prices dropped sharply, and then continued to decline
reaching levels below zero dollars per barrel. This was a result of multiple
factors affecting supply and demand in global oil and natural gas markets,
including the announcement of price reductions and production increases by OPEC
members and other exporting nations and the ongoing COVID-19 pandemic. Commodity
prices are expected to continue to be volatile as a result of changes in oil and
natural gas production, inventories and demand, as well as national and
international economic performance. We cannot predict when prices will improve
and stabilize.

As a result of the sharp decline in commodity prices during the first quarter of
2020, we recorded a non-cash ceiling test impairment for the three months ended
March 31, 2020 of $1.0 billion. The impairment charge adversely affected our
results of operations but did not reduce our cash flows. If the trailing
12-month commodity prices continue to fall as compared to the commodity prices
used in prior quarters, we will have material write downs in subsequent
quarters. Our production, proved reserves and cash flows will also be adversely
impacted. Our results of operations may be further adversely impacted by any
government rule, regulation or order that may impose production limits, as well
as pipeline capacity and storage constraints, in the Permian Basin where we
operate.

Our Response to the Commodity Price Volatility and Impact of COVID-19

• We have taken swift and decisive actions to protect the health and safety

of our employees and preserve the strength of our organization during the


       COVID-19 pandemic and the depressed commodity price markets.


• We immediately responded to the sharp drop in commodity prices in early

March 2020 by ceasing all completion operations for a minimum of one
       month.



•      We have hedged approximately 100% of our remaining expected 2020 oil

production, including basis differentials and a majority of WTI contract


       exposure and removed all three-way collar hedge exposure to maximize
       downside protection.


• We have hedged approximately 50% of our expected 2021 oil production in


       the form of swaps and two-way collars.




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• We plan to voluntarily curtail 10% to 15% of our expected May 2020 oil

production in areas where we can manage production economically and

without the addition of material operating expense, and will continue to


       monitor whether additional strategic curtailments are warranted in June
       2020 and in future periods.



•      We immediately reduced our full year 2020 capital budget by over 40%,

while high-grading our operating plan to acreage with the highest returns

where we own mineral and royalty interests and have low required midstream


       or infrastructure expenditures.


• We plan to average less than one completion crew in the second quarter of

2020 to meet our leasehold obligations and will assess bringing completion

crews back to work in the third quarter of 2020 depending on the commodity


       price environment.



•      We expect to complete less than 10% of our estimated full year 2020
       completed gross well count in the second quarter of 2020.



•      We currently are operating 14 drilling rigs and plan to enter the third

quarter of 2020 running eight drilling rigs and enter the fourth quarter

of 2020 running seven drilling rigs, with the ability to reduce the rig

count further should conditions warrant in the fourth quarter of 2020 and


       into 2021.


• We have reduced our operating costs by increasing water infrastructure


       efficiencies and reducing trucking costs.


• We have reduced flaring to less than 0.5% of net production at the end of

the first quarter 2020 from over 1.5% of net production in January 2020.

First Quarter 2020 Highlights

• We recorded a net loss of $272 million for the first quarter ended March


       31, 2020.


• Our average production was 321.1 MBOE/d), with average oil production up


       12% over the first quarter of 2019.



•      We turned 80 gross operated wells to production and had capital
       expenditures of $790 million during the first quarter of 2020.


• As of March 31, 2020, we had $1.8 billion of availability for future

borrowings under our revolving credit facility and approximately $0.1

billion of cash on hand.

• Our cash operating costs for the first quarter ended March 31, 2020 were

$8.52 per BOE; including cash general and administrative expenses of $0.51
       per BOE.


• On May 1, 2020, our board of directors declared a cash dividend for the


       first quarter of 2020 of $0.3750 per share of common stock, payable on
       May 21, 2020 to our stockholders of record at the close of business of
       May 14, 2020.


• During the three months ended March 31, 2020, we repurchased approximately

$98 million of common stock under our $2 billion repurchase program
       approved by our board of directors in May 2019 and, as of March 31, 2020,
       $1.3 billion remained available for future repurchases under this stock

repurchase program although we have suspended this program to preserve


       liquidity.



Upstream Segment

In our upstream segment, our activities are primarily directed at the horizontal
development of the Wolfcamp and Spraberry formations in the Midland Basin and
the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to
continue to develop our reserves and increase production through development
drilling and exploitation and exploration activities on our multi-year inventory
of identified potential drilling locations and through acquisitions that meet
our strategic and financial objectives, targeting oil-weighted reserves. Also,
in our upstream segment, our publicly-traded subsidiary Viper is focused on
owning and acquiring mineral interests and royalty interests in oil and natural
gas properties in the Permian Basin and the Eagle Ford Shale and derives royalty
income and lease bonus income from such interests.

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As of March 31, 2020, we had approximately 382,404 net acres, which primarily
consisted of approximately 200,056 net acres in the Midland Basin and
approximately 155,304 net acres in the Delaware Basin. As of December 31, 2019,
we had an estimated 12,310 gross horizontal locations that we believe to be
economic at $60 per Bbl West Texas Intermediate, or WTI.

The following table sets forth the total number of operated horizontal wells drilled and completed during the three months ended March 31, 2020:


                           Three Months Ended March 31, 2020(1)
                                Drilled                       Completed
Area                          Gross                 Net       Gross    Net
Midland Basin        55                              50       34        30
Delaware Basin       38                              35       46        42
Total                93                              85       80        72

(1) The average lateral length for the wells completed during the first quarter

of 2020 was 9,751 feet. Operated completions during the first quarter of 2020

consisted of 47 Wolfcamp A wells, nine Wolfcamp B wells, seven Lower

Spraberry wells, six Middle Spraberry wells, two Jo Mill wells, five Second

Bone Springs wells, and four Third Bone Springs wells.

As of March 31, 2020, we operated the following wells:


                 Vertical Wells         Horizontal Wells          Total
Area              Gross      Net          Gross       Net     Gross   Net
Midland Basin    1,548      1,454       1,041          952    2,589  2,406
Delaware Basin      32         23         544          509      576    532
Total            1,580      1,477       1,585        1,461    3,165  2,938


As of March 31, 2020, we held interests in 3,642 gross (3,035 net) wells, including wells that we do not operate.



Our development program is focused entirely within the Permian Basin, where we
continue to focus on long-lateral multi-well pad development. Our horizontal
development consists of multiple targeted intervals, primarily within the
Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone
Springs formations in the Delaware Basin.

Midstream Operations



In our midstream operations segment, Rattler's crude oil infrastructure assets
consist of gathering pipelines and metering facilities, which collectively
gather crude oil for its customers. Rattler's facilities gather crude oil from
horizontal and vertical wells in our ReWard, Spanish Trail, Pecos and Glasscock
areas within the Permian Basin. Rattler's natural gas gathering and compression
system consists of gathering pipelines, compression and metering facilities,
which collectively service the production from our Pecos area assets within the
Permian Basin. Rattler's water sourcing and distribution assets consists of
water wells, hydraulic fracturing pits, pipelines and water treatment
facilities, which collectively gather and distribute water from Permian Basin
aquifers to the drilling and completion sites through buried pipelines and
temporary surface pipelines. Rattler's produced water gathering and disposal
system spans approximately 482 miles and consists of gathering pipelines along
with produced water disposal wells and facilities which collectively gather and
dispose of produced water from operations throughout 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.


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Sources of Our Revenues



In our exploration and production segment, our main sources of revenues are the
sale of oil and natural gas production, as well as the sale of natural gas
liquids that are extracted from our natural gas during processing, derived from
our net revenue and royalty interests.
In our midstream operations segment, our results are primarily driven by the
volumes of crude oil that Rattler gathers, transports and delivers; natural gas
that Rattler gathers, compresses, transports and delivers; fresh water that
Rattler sources, transports and delivers; and produced water that Rattler
gathers, transports and disposes of, and the fees Rattler charges per unit of
throughput for our midstream services.

The following table presents the breakdown of our oil and natural gas revenues for the following periods:


                           Three Months Ended March 31,
                               2020             2019
Revenues:
Oil sales                         94 %             88 %
Natural gas sales                  - %              3 %
Natural gas liquid sales           6 %              9 %
                                 100 %            100 %



Commodity Prices

In our upstream business, our production consists primarily of oil. As a result,
our revenues are more sensitive to fluctuations in oil prices than they are to
fluctuations in natural gas or natural gas liquids prices. Oil, natural gas and
natural gas liquids prices have historically been volatile. Oil prices dropped
sharply in early March 2020, and then continued to decline reaching levels below
zero dollars per barrel. This was a result of multiple factors affecting the
supply and demand in global oil and natural gas markets, including the
announcement of price reductions and production increases by OPEC members and
other oil exporting nations and the ongoing COVID-19 pandemic. During the first
quarter of 2020, the depressed commodity prices negatively impacted our revenue,
production and results of operations, and we recorded an impairment on proved
oil and natural gas properties. In addition, the administrative agent under
Viper's credit agreements has recommended that the borrowing base under such
credit agreement be decreased to $580 million effective mid-May 2020. Oil and
natural gas prices are expected to continue to be volatile as a result of
changes in oil and natural gas production, inventories and demand, as well as
national and international economic performance. We cannot predict when prices
will improve and stabilize. If commodity prices continue at current levels or
decrease further, our ability to produce oil and natural gas economically and,
as a result, our business, results of operations and financial condition will be
adversely affected. Our results of operations may be further adversely impacted
by any government rule, regulation or order that may impose production limits in
the Permian Basin where we operate.

In our midstream operations business, we have indirect exposure to commodity
price risk in that persistent low commodity prices may cause us or Rattler's
other customers to delay drilling or shut in production, which would reduce the
volumes available for gathering and processing by our infrastructure assets. If
we or Rattler's other customers delay drilling or temporarily shut in production
due to persistently low commodity prices or for any other reason, our revenue in
the midstream operations segment could decrease, as Rattler's commercial
agreements do not contain minimum volume commitments.


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The following table sets forth information related to commodity prices for the
following periods:

                                                              Three Months Ended March 31,
                                                                  2020             2019
High and Low Futures Contract Prices:
Oil ($/Bbl, WTI Futures Contract 1)
High                                                        $       63.27    $       60.14
Low                                                         $       20.09    $       46.54
Natural Gas ($/MMBtu, Futures Contract 1)
High                                                        $        2.20    $        3.59
Low                                                         $        1.60    $        2.55

Average realized oil price ($/Bbl)                          $       45.10    $       46.12
Average WTI Futures Contract 1 ($/Bbl)                      $       45.78    $       54.90
Differential to WTI Futures Contract 1                              (0.68 )          (8.78 )
Average realized oil price to WTI Futures Contract 1                   99 %             84 %

Average realized natural gas price ($/Mcf)                  $        0.14    $        1.32
Average Natural Gas Futures Contract 1 ($/Mcf)              $        1.87    $        2.87
Differential to Natural Gas Futures Contract 1                      (1.73 ) 

(1.55 ) Average realized natural gas price to Natural Gas Futures Contract 1

                                                              7 %             46 %

Average realized natural gas liquids price ($/Bbl) $ 9.45

  $       18.00
Average WTI Futures Contract 1 ($/Bbl)                      $       45.78    $       54.90
Average realized natural gas liquids price to WTI Futures
Contract 1                                                             21 %             33 %


On March 31, 2020, the WTI Futures Contract 1 price for crude oil was $20.48 per Bbl and the Natural Gas Futures Contract 1 price was $1.64 per MMBtu.


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Results of Operations

The following table sets forth selected historical operating data for the three months ended March 31, 2020 and 2019:


                                                              Three Months Ended March 31,
                                                                   2020            2019
                                                                     (in thousands)
Production Data:
Oil (MBbls)                                                           18,325        16,115
Natural gas (MMcf)                                                    32,120        21,684
Natural gas liquids (MBbls)                                            5,538         3,908
Combined volumes (MBOE)                                               29,216        23,637

Daily combined volumes (BOE/d)                                       321,057       262,633
Daily oil volumes (BO/d)                                             201,369       179,056

Average Prices:
Oil ($ per Bbl)                                             $          45.10   $     46.12
Natural gas ($ per Mcf)                                     $           0.14   $      1.32
Natural gas liquids ($ per Bbl)                             $           9.45   $     18.00
Combined ($ per BOE)                                        $          30.23   $     35.63

Oil, hedged ($ per Bbl)(1)                                  $          49.32   $     46.92
Natural gas, hedged ($ per MMbtu)(1)                        $           0.42   $      1.49
Natural gas liquids, hedged ($ per Bbl)(1)                  $           9.45   $     18.19
Average price, hedged ($ per BOE)(1)                        $          

33.19 $ 36.38

(1) Hedged prices reflect the effect of our commodity derivative transactions on

our average sales prices. Our calculation of such effects include gains and


    losses on cash settlements for commodity derivatives, which we do not
    designate for hedge accounting.


Production Data

Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. The following tables set forth our production data for the three months ended March 31, 2020 and 2019:


                              Three Months Ended March 31,
                                  2020             2019
Oil (MBbls)                          63 %             68 %
Natural gas (MMcf)                   18 %             15 %
Natural gas liquids (MBbls)          19 %             17 %
                                    100 %            100 %



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                          Three Months Ended March 31, 2020

Three Months Ended March 31, 2019


                       Midland     Delaware

Midland Delaware


                        Basin       Basin     Other(1)   Total        Basin 

Basin Other(2) Total


                                                          (in thousands)
Production Data:
Oil (MBbls)              10,511      7,760         54   18,325         9,984      5,026      1,105   16,115
Natural gas (MMcf)       15,833     16,147        140   32,120        10,172     11,137        375   21,684
Natural gas liquids
(MBbls)                   3,048      2,463         27    5,538         2,176      1,671         61    3,908
Total (MBoe)             16,198     12,914        104   29,216        13,855      8,553      1,229   23,637

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

(2) Includes the Eagle Ford Shale.

Comparison of the Three Months Ended March 31, 2020 and 2019



Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and
natural gas liquids revenues are a function of oil, natural gas and natural gas
liquids production volumes sold and average sales prices received for those
volumes. Our oil, natural gas and natural gas liquids revenues for the three
months ended March 31, 2020 increased by $41 million, or 5%, to $883 million
from $842 million during the three months ended March 31, 2019, primarily due to
an increase in oil, natural gas and natural gas liquids production volumes,
partially offset by lower average sales prices. The increase in production
volumes was due to a combination of increased drilling activity and growth
through acquisitions.

The net dollar effect of the change in prices (calculated as the change in
period-to-period average prices multiplied by current period production volumes
of oil, natural gas and natural gas liquids) and the net dollar effect of the
change in production (calculated as the increase in period-to-period volumes for
oil, natural gas and natural gas liquids multiplied by the period average
prices) are shown below:
                                                          Three Months 

Ended March 31, 2020 Compared to 2019


                                                                             Production         Total net dollar
                                                     Change in prices        volumes(1)         effect of change
                                                                                                 (in millions)
Effect of changes in price:
Oil                                                $        (1.02 )                 18,325   $           (19 )
Natural gas                                        $        (1.18 )                 32,120               (38 )
Natural gas liquids                                $        (8.55 )                  5,538               (47 )
Total revenues due to change in price                                                        $          (104 )

                                                   Change in production Prior period Average    Total net dollar
                                                        volumes(1)             Prices           effect of change
                                                                                                 (in millions)
Effect of changes in production volumes:
Oil                                                         2,210       $            46.12   $           102
Natural gas                                                10,436       $             1.32                14
Natural gas liquids                                         1,630       $            18.00                29
Total revenues due to change in production volumes                                                       145
Total change in revenues                                                                     $            41


(1) Production volumes are presented in MBbls for oil and natural gas liquids and
    MMcf for natural gas.




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Midstream Services Revenue. The following table shows midstream services revenue for the three months ended March 31, 2020 and 2019:


                                   Three Months Ended March 31,
                                          2020                    2019
                                          (in millions)
Midstream services revenue $          14                         $  19



Our midstream services revenue represents fees charged to our joint interest
owners and third parties for the transportation of oil and natural gas along
with water gathering and related disposal facilities. These assets complement
our operations in areas where we have significant production.

Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2020 and 2019:


                                     Three Months Ended March 31,
                                     2020                        2019
                               Amount        Per BOE      Amount    Per BOE
                                (in millions, except per BOE amounts)
Lease operating expenses $    127           $    4.35    $    109  $    4.61



Lease operating expenses for the three months ended March 31, 2020 increased by
$18 million as compared to the three months ended March 31, 2019. This increase
is primarily associated with our higher well count due to new drilling activity
and, to a lesser extent, power generation costs as a result of reduced
electrical availability. We are actively working to mitigate this power
generation issue and expect these costs to decrease in the future. Lease
operating expenses per BOE decreased by $0.26 for the three months ended March
31, 2020 as compared to the three months ended March 31, 2019, primarily due to
higher production from our increased drilling activity during the period and
growth through acquisitions.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2020 and 2019:


                                                    Three Months Ended March 31,
                                                     2020                       2019
                                              Amount         Per BOE      Amount   Per BOE
                                               (in millions, except per BOE amounts)
Production taxes                        $    42             $    1.42    $    41  $    1.73
Ad valorem taxes                             29                  1.01         14       0.60
Total production and ad valorem expense $    71             $    2.43    $  

55 $ 2.33





In general, production taxes and ad valorem taxes are directly related to
commodity price changes; however, Texas ad valorem taxes are based upon prior
year commodity prices, among other factors, whereas production taxes are based
upon current year commodity prices. Production taxes for the three months ended
March 31, 2020 as compared to the three months ended March 31, 2019 increased by
$1 million due to increased overall production from acquisitions and well
completions. Production taxes per BOE for the three months ended March 31, 2020
as compared to the three months ended March 31, 2019 decreased by $0.31
primarily due to a higher percentage increase in production volumes as compared
to production taxes. Ad valorem taxes for the three months ended March 31, 2020
as compared to the three months ended March 31, 2019 increased by $15 million
primarily due to an increase in production volumes from wells drilled and
completed in 2019.


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Midstream Services Expense. The following table shows midstream services expense for the three months ended March 31, 2020 and 2019:


                                   Three Months Ended March 31,
                                          2020                    2019
                                          (in millions)
Midstream services expense $          23                         $  17

Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, Depletion and Amortization. The following table provides the components of our depreciation, depletion and amortization expense for the three months ended March 31, 2020 and 2019:


                                                                 Three Months Ended March 31,
                                                                      2020             2019

                                                                   (in millions, except BOE
                                                                           amounts)
Depletion of proved oil and natural gas properties              $           392     $    311
Depreciation of midstream assets                                             11            8
Depreciation of other property and equipment                                  4            3
Depreciation, depletion and amortization expense                $           

407 $ 322 Oil and natural gas properties depreciation, depletion and amortization per BOE

                                            $         13.93     $  13.62

The increase in depletion of proved oil and natural gas properties of $81 million for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 resulted primarily from higher production levels and an increase in net book value on new reserves added.



Impairment of Oil and Natural Gas Properties. The following table shows
impairment of oil and natural gas properties for the three months ended March
31, 2020 and 2019:
                                                                 Three Months Ended March
                                                                            31,
                                                                    2020           2019
                                                                       (in millions)
Impairment of oil and natural gas properties                    $     1,009

$ -





As a result of the sharp decline in commodity prices during the first quarter of
2020, we recorded a non-cash ceiling test impairment for the three months ended
March 31, 2020 of $1.0 billion which was included in accumulated depletion. The
impairment charge affected our results of operations but did not reduce cash
flow. In addition to commodity prices, our production rates, levels of proved
reserves, future development costs, transfers of unevaluated properties and
other factors will determine our actual ceiling test calculation and impairment
analysis in future periods. If the trailing 12-month commodity prices continue
to fall as compared to the commodity prices used in prior quarters, we will have
material write downs in subsequent quarters. No impairment on proved oil and
natural gas properties was recorded for the three months ended March 31, 2019.


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General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2020 and 2019:



                                                            Three Months Ended March 31,
                                                            2020                     2019
                                                     Amount     Per BOE       Amount     Per BOE
                                                        (in millions, except per BOE amounts)
General and administrative expenses                $     15   $    0.51     $     13   $    0.55
Non-cash stock-based compensation                         9        0.31     

14 0.59 Total general and administrative expenses $ 24 $ 0.82 $ 27 $ 1.14





General and administrative expenses for the three months ended March 31, 2020 as
compared to the three months ended March 31, 2019 decreased by $3 million
primarily due to a decrease in non-cash stock compensation partially offset by
higher salary and benefit expenses, legal fees, community donations and software
license expenses.

Net Interest Expense. The following table shows net interest expense for the three months ended March 31, 2020 and 2019:


                             Three Months Ended March 31,
                                    2020                    2019
                                    (in millions)
Net interest expense $          48                         $  46



Net interest expense for the three months ended March 31, 2020 as compared to
the three months ended March 31, 2019, increased by $2 million. This increase
was primarily due to increased average borrowings under our credit facility
partially offset by a decrease in interest expense of $3 million related to our
DrillCo Agreement during the three months ended March 31, 2020 as compared to
the three months ended March 31, 2019.

Derivative Instruments. The following table shows the gain (loss) on derivative instruments, net for the three months ended March 31, 2020 and 2019:


                                                              Three Months Ended March 31,
                                                                   2020           2019
                                                                     (in millions)

Change in fair value of open non-hedge derivative instruments $ 455

    $    (285 )
Gain on settlement of non-hedge derivative instruments                  87  

17


Gain (loss) on derivative instruments, net                    $        542

$ (268 )





We are required to recognize all derivative instruments on the balance sheet as
either assets or liabilities measured at fair value. We have not designated our
derivative instruments as hedges for accounting purposes. As a result, we mark
our derivative instruments to fair value and recognize the cash and non-cash
changes in fair value on derivative instruments in our consolidated statements
of operations under the line item captioned "Gain (loss) on derivative
instruments, net."

Provision for (Benefit From) Income Taxes. The following table shows provision
for (benefit from) income taxes for the three months ended March 31, 2020 and
2019:
                                                 Three Months Ended March 31,
                                                        2020                  2019
                                                        (in millions)
Provision for (benefit from) income taxes $         83                       $ (33 )



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The change in our income tax provision was primarily due to the pre-tax loss for
the three months ended March 31, 2020 offset by discrete tax expense resulting
from application of a valuation allowance on Viper's deferred tax assets,
compared to pre-tax income for the three months ended March 31, 2019, offset by
a discrete income tax benefit resulting from the revision of estimated deferred
taxes recognized as a result of Viper's change in tax status.

Liquidity and Capital Resources



Historically, our primary sources of liquidity have been proceeds from our
public equity offerings, borrowings under our revolving credit facility,
proceeds from the issuance of our senior notes and cash flows from operations.
Our primary uses of capital have been for the acquisition, development and
exploration of oil and natural gas properties. As we pursue our business and
financial strategy, we regularly consider which capital resources, including
cash flow and equity and debt financings, are available to meet our future
financial obligations, planned capital expenditure activities and liquidity
requirements. Our future ability to grow proved reserves and production will be
highly dependent on the capital resources available to us. Continued prolonged
volatility in the capital, financial and/or credit markets due to the COVID-19
pandemic, the depressed commodity markets and/or adverse macroeconomic
conditions may limit our access to, or increase our cost of, capital or make
capital unavailable on terms acceptable to us or at all.

Liquidity and Cash Flow



Our cash flows for the three months ended March 31, 2020 and 2019 are presented
below:
                                            Three Months Ended March 31,
                                                2020             2019
                                                    (in millions)

Net cash provided by operating activities $ 849 $ 377 Net cash used in investing activities

              (923 )            (937 )
Net cash provided by financing activities           101               471
Net increase (decrease) in cash           $          27     $         (89 )



Operating Activities



Net cash provided by operating activities was $849 million for the three months
ended March 31, 2020 as compared to $377 million for the three months ended
March 31, 2019. The increase in operating cash flows is primarily the result of
an increase in our oil and natural gas revenues due to an increase in production
growth partially offset by a decrease in average prices during the three months
ended March 31, 2020.

Our operating cash flow is sensitive to many variables, the most significant of
which is the volatility of prices for the oil and natural gas we produce. Prices
for these commodities are determined primarily by prevailing market conditions.
Regional and worldwide economic activity, weather and other substantially
variable factors influence market conditions for these products. These factors
are beyond our control and are difficult to predict. See "-Sources of our
revenue" above.

Investing Activities



The purchase and development of oil and natural gas properties accounted for the
majority of our cash outlays for investing activities. Net cash used in
investing activities was $923 million and $937 million during the three months
ended March 31, 2020 and 2019, respectively.

During the three months ended March 31, 2020, we spent (a) $746 million on
capital expenditures in conjunction with our development program, in which we
drilled 93 gross (85 net) operated horizontal wells, of which 38 gross (35 net)
wells were in the Delaware Basin and the remaining wells were in the Midland
Basin, and turned 80 gross (72 net) operated horizontal wells into production,
of which 46 gross (42 net) wells were in the Delaware Basin and the remaining
wells were in the Midland Basin, (b) $44 million on additions to midstream
assets, (c) $40 million on leasehold interest acquisitions, (d) $65 million for
the acquisition of mineral interests, (e) $23 million on equity method
investment contributions net of distributions received and (f) $5 million for
the purchase of other property, equipment and land.


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During the three months ended March 31, 2019, we spent (a) $569 million on
capital expenditures in conjunction with our drilling program and related
infrastructure projects, in which we drilled 83 gross (73 net) operated
horizontal wells, of which 40 gross (36 net) wells were in the Delaware Basin
and the remaining wells were in the Midland Basin, and turned 82 gross (74 net)
operated horizontal wells into production, of which 28 gross (24 net) wells were
in the Delaware Basin and the remaining wells were in the Midland Basin, (b) $58
million on additions to midstream assets, (c) $75 million on leasehold interest
acquisitions, (d) $82 million for mineral interests acquisitions, (e) $4 million
for the purchase of other property, equipment and land and (f) $149 million on
equity method investments.

Our investing activities for the three months ended March 31, 2020 and 2019 are summarized in the following table:


                                                  Three Months Ended March 31,
                                                      2020              2019
                                                          (in millions)

Drilling, completions and non-operated $ (690 ) $ (533 ) Additions to infrastructure assets

                        (56 )              (36 )
Additions to midstream assets                             (44 )              (58 )
Purchase of other property, equipment and land             (5 )               (4 )
Acquisitions of leasehold interests                       (40 )              (75 )
Acquisitions of mineral interests                         (65 )              (82 )
Contributions to equity method investments                (33 )             (149 )
Distributions from equity method investments               10               

-

Net cash used in investing activities $ (923 ) $ (937 )





Financing Activities

Net cash provided by financing activities for the three months ended March 31,
2020 and 2019 was $101 million and $471 million, respectively. During the three
months ended March 31, 2020, the amount provided by financing activities was
primarily attributable to $290 million of borrowings, net of repayments under
our credit facility and $16 million in proceeds from joint ventures, partially
offset by $5 million of share repurchases for tax withholdings, $98 million of
share repurchases as part of our stock repurchase program, $59 million of
dividends to stockholders and $43 million of distributions to non-controlling
interest. The 2019 amount provided by financing activities was primarily
attributable to $170 million of borrowings, net of repayments under our credit
facility, an aggregate of $341 million of net proceeds from Viper's public
offering, partially offset by $26 million of distributions to non-controlling
interest, $21 million of dividends to stockholders, $23 million in proceeds from
joint ventures and $13 million of share repurchases for tax withholdings.

2025 Senior Notes



On December 20, 2016, we issued $500 million in aggregate principal amount of
5.375% senior notes due 2025, which we refer to as the existing 2025 notes,
under an indenture among us, the subsidiary guarantors party thereto and Wells
Fargo, as the trustee, which we refer to as the 2025 indenture. On January 29,
2018, we issued $300 million aggregate principal amount of new 5.375% senior
notes due 2025 as additional notes under the 2025 indenture, which we refer to
as the new 2025 notes and, together with the existing 2025 notes, as the 2025
senior notes.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payable
semi-annually, in arrears on May 31 and November 30 of each year and will mature
on May 31, 2025. All of our existing and future restricted subsidiaries that
guarantee our revolving credit facility guarantee the 2025 senior notes.
Currently, the 2025 senior notes are not guaranteed by any of our subsidiaries
other than Diamondback O&G LLC and will not be guaranteed by any of our future
unrestricted subsidiaries.
The 2025 indenture contains certain covenants that, subject to certain
exceptions and qualifications, among other things, limit our ability and the
ability of our restricted subsidiaries to incur or guarantee additional
indebtedness or issue certain redeemable or preferred equity, make certain
investments, declare or pay dividends or make distributions on equity interests
or redeem, repurchase or retire equity interests or subordinated indebtedness,
transfer or sell assets, agree to payment restrictions affecting its restricted
subsidiaries, consolidate, merge, sell or otherwise dispose of all or
substantially all of its assets, enter into transactions with affiliates, incur
liens and designate certain of its subsidiaries

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as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.



For additional information regarding the 2025 senior notes, see Note 10-Debt
included in Notes to the Consolidated Financial Statements included elsewhere in
this Form 10-Q. We may use cash on hand to repurchase a portion of the 2025
senior notes in privately-negotiated transactions, open market purchases or
otherwise, but we are under no obligation to do so.

December 2019 Notes Offering



On December 5, 2019, we issued $1.0 billion in aggregate principal amount of
2.875% senior notes due 2024, which we refer to as the 2024 notes, $800 million
in aggregate principal amount of 3.250% senior notes due 2026, which we refer to
as the 2026 notes, and $1.2 billion aggregate principal amount of 3.500% senior
notes due 2029, which we refer to as the 2029 notes. We refer to the 2024 notes,
the 2026 notes and the 2029 notes, collectively, as the December 2019 notes. The
2024 notes will mature on December 1, 2024, the 2026 notes will mature on
December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest
will accrue and be payable semi-annually, in arrears on June 1 and December 1 of
each year, commencing on June 1, 2020. The December 2019 notes are guaranteed by
Diamondback O&G LLC and are not guaranteed by any of our other subsidiaries.

The December 2019 notes were issued under an indenture, dated as of December 5,
2019, among us and Wells Fargo, as the trustee, as supplemented by the first
supplemental indenture dated as of December 5, 2019, which we collectively refer
to as the December 2019 Notes Indenture. The December 2019 Notes Indenture
contains certain covenants that, subject to certain exceptions and
qualifications, among other things, limit our ability and the ability of certain
of our subsidiaries to incur liens securing funded indebtedness and on our
ability to consolidate, merge or sell, convey, transfer or lease all or
substantially all of its assets.
For additional information regarding the December 2019 Notes, see Note 10-Debt
included in Notes to the Consolidated Financial Statements included elsewhere in
this Form 10-Q. We may use cash on hand to repurchase a portion of the December
2019 Notes in privately-negotiated transactions, open market purchases or
otherwise, but we are under no obligation to do so.

Second Amended and Restated Credit Facility



We, as parent guarantor, and Diamondback O&G LLC, as borrower, entered into the
second amended and restated credit agreement, dated November 1, 2013, as
amended, with a syndicate of banks, including Wells Fargo, as administrative
agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and
lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an
eleventh amendment, which implemented certain changes to the credit facility for
the period on and after the date on which our unsecured debt achieves an
investment grade rating from two rating agencies and certain other conditions in
the credit agreement are satisfied which changes became effective November 20,
2019. As of March 31, 2020, the maximum credit amount available under the credit
agreement is $2.0 billion. As of March 31, 2020, we had approximately $199
million of outstanding borrowings under our revolving credit facility and $1.8
billion available for future borrowings under our revolving credit facility.
The outstanding borrowings under the credit agreement bear interest at a per
annum rate elected by us that is equal to an alternate base rate (which is equal
to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%
and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin.
The applicable margin ranges from 0.125% to 1.0% per annum in the case of the
alternative base rate and from 1.125% to 2.0% per annum in the case of LIBOR, in
each case, depending on the pricing level, which in turn depends on the rating
agencies' ratings of our unsecured debt. We are obligated to pay a quarterly
commitment fee ranging from 0.125% to 0.350% per year on the unused portion of
the commitment, based on the pricing level, which in turn depends on the rating
agencies' ratings of our unsecured debt.
Loan principal may be optionally prepaid from time to time without premium or
penalty (other than customary LIBOR breakage). Loan principal is required to be
repaid (a) to the extent the loan amount exceeds the commitment due to any
termination or reduction of the aggregate maximum credit amount and (b) at the
maturity date of November 1, 2022.
The credit agreement contains a financial covenant that requires us to maintain
a total net debt to capitalization ratio (as defined in the credit agreement) of
no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for
borrowed money in an aggregate principal amount up to 15% of consolidated net
tangible assets (as defined

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in the credit agreement) and we and our restricted subsidiaries may incur liens
if the aggregate amount of debt secured by such liens does not exceed 15% of
consolidated net tangible assets.

As of March 31, 2020, we were in compliance with all financial maintenance
covenants under our revolving credit facility, as then in effect. The lenders
may accelerate all of the indebtedness under our revolving credit facility upon
the occurrence and during the continuance of any event of default. The credit
agreement contains customary events of default, including non-payment, breach of
covenants, materially incorrect representations, cross-default, bankruptcy and
change of control.

Energen Notes

At the effective time of the merger, Energen became our wholly owned subsidiary
and remained the issuer of an aggregate principal amount of $530 million in
notes, which we refer to as the Energen Notes, issued under an indenture dated
September 1, 1996 with The Bank of New York as Trustee, which we refer to as the
Energen Indenture. As of March 31, 2020, the Energen Notes consist of: (a) $400
million aggregate principal amount of 4.625% senior notes due on September 1,
2021, (2) $100 million of 7.125% notes due on February 15, 2028, (3) $20 million
of 7.32% notes due on July 28, 2022, and (4) $10 million of 7.35% notes due on
July 28, 2027.

The Energen Notes are the senior unsecured obligations of Energen and,
post-merger, Energen, as our wholly owned subsidiary, continues to be the sole
issuer and obligor under the Energen Notes. The Energen Notes rank equally in
right of payment with all other senior unsecured indebtedness of Energen if any,
and are effectively subordinated to Energen's senior secured indebtedness, if
any, to the extent of the value of the collateral securing such indebtedness.
Neither we nor any of our subsidiaries guarantee the Energen Notes.

For additional information regarding the Energen Notes, See Note 10-Debt
included in Notes to the Consolidated Financial Statements included elsewhere in
this Form 10-Q. We may use cash on hand to repurchase a portion of the Energen
Notes in privately-negotiated transactions, open market purchases or otherwise,
but we are under no obligation to do so.

Viper's Credit Agreement



On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated
credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent,
and the other lenders. The credit agreement, as amended, which we refer to as
the Viper credit agreement, provides for a revolving credit facility in the
maximum credit amount of $2 billion and a borrowing base based on Viper LLC's
oil and natural gas reserves and other factors (the "borrowing base") of $775
million, subject to scheduled semi-annual and other elective borrowing base
redeterminations. The borrowing base is scheduled to be re-determined
semi-annually with effective dates of May 1st and November 1st. In addition,
Viper LLC and Wells Fargo each may request up to three interim redeterminations
of the borrowing base during any 12-month period. As of March 31, 2020, the
borrowing base was $775 million, and Viper LLC had $174 million of outstanding
borrowings and $601 million available for future borrowings under the Viper
credit agreement. In connection with the regularly scheduled (semi-annual)
spring 2020 redetermination, the administrative agent under the Viper credit
agreement has recommended that the borrowing base be decreased under the Viper
credit agreement to $580 million effective mid-May 2020. The decrease is subject
to approval by the requisite lenders under the Viper credit agreement. Under the
new expected borrowing base, Viper LLC would have had $407 million of
availability for future borrowings under the Viper credit agreement as of
March 31, 2020.

The outstanding borrowings under the Viper credit agreement bear interest at a
per annum rate elected by Viper LLC that is equal to an alternate base rate
(which is equal to the greatest of the prime rate, the Federal Funds effective
rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the
applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in
the case of the alternate base rate and from 1.75% to 2.75% per annum in the
case of LIBOR, in each case depending on the amount of loans and letters of
credit outstanding in relation to the commitment, which is defined as the lesser
of the maximum credit amount and the borrowing base. Viper LLC is obligated to
pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the
unused portion of the commitment, which fee is also dependent on the amount of
loans and letters of credit outstanding in relation to the commitment. Loan
principal may be optionally prepaid from time to time without premium or penalty
(other than customary LIBOR breakage), and is required to be repaid (i) to the
extent the loan amount exceeds the commitment or the borrowing base, whether due
to a borrowing base redetermination or otherwise (in some cases subject to a
cure period), (ii) in an amount equal to the net cash proceeds from the sale of
property when a borrowing base deficiency or event of default exists under the
credit agreement and (iii) at the maturity date of November 1, 2022. The loan is
secured by substantially all of the assets of Viper and Viper LLC.

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The Viper credit agreement contains various affirmative, negative and financial
maintenance covenants. These covenants, among other things, limit additional
indebtedness, purchases of margin stock, additional liens, sales of assets,
mergers and consolidations, dividends and distributions, transactions with
affiliates and entering into certain swap agreements and require the maintenance
of the financial ratios described below.
Financial Covenant                                             Required 

Ratio

Ratio of total net debt to EBITDAX, as defined in the Viper Not greater than credit agreement

                                                 4.0 to 1.0

Ratio of current assets to liabilities, as defined in the Not less than 1.0 Viper credit agreement

                                             to 1.0



The covenant prohibiting additional indebtedness allows for the issuance of
unsecured debt of up to $1.0 billion in the form of senior unsecured notes and,
in connection with any such issuance, the reduction of the borrowing base by 25%
of the stated principal amount of each such issuance. The covenant limiting
dividends and distributions includes an exception allowing Viper LLC to make
distributions if no default, event of default or borrowing base deficiency
exists.

As of March 31, 2020, Viper and Viper LLC were in compliance with all financial
maintenance covenants under the Viper credit agreement, as then in effect. The
lenders may accelerate all of the indebtedness under the Viper credit agreement
upon the occurrence and during the continuance of any event of default. The
Viper credit agreement contains customary events of default, including
non-payment, breach of covenants, materially incorrect representations,
cross-default, bankruptcy and change of control.

Viper's Notes



On October 16, 2019, Viper completed an offering in which it issued its 5.375%
Senior Notes due 2027 in aggregate principal amount of $500 million, which we
refer to as the Viper Notes. Viper received gross proceeds of $500 million from
the such offering, which it loaned to Viper LLC. Viper LLC paid the expenses of
the offering, resulting in net proceeds of the offering of $490 million, which
Viper LLC used to pay down borrowings under the Viper credit agreement.

The Viper Notes were issued under an indenture, dated as of October 16, 2019,
among Viper, as issuer, Viper LLC, as guarantor and Wells Fargo, as trustee,
which we refer to as the Viper Indenture. Pursuant to the Viper Indenture and
the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per
annum on the outstanding principal amount thereof, payable semi-annually on May
1 and November 1 of each year, commencing on May 1, 2020. The Viper Notes will
mature on November 1, 2027.

Viper LLC guarantees the Viper Notes pursuant to the Viper Indenture. Neither we nor any of our other subsidiaries guarantee the Viper Notes.



The Viper Indenture contains certain covenants that, subject to certain
exceptions and qualifications, among other things, limit Viper's ability and the
ability of its restricted subsidiaries to incur or guarantee additional
indebtedness or issue certain redeemable or preferred equity, make certain
investments, declare or pay dividends or make distributions on equity interests
or redeem, repurchase or retire equity interests or subordinated indebtedness,
transfer or sell assets, agree to payment restrictions affecting its restricted
subsidiaries, consolidate, merge, sell or otherwise dispose of all or
substantially all of its assets, enter into transactions with affiliates, incur
liens and designate certain of its subsidiaries as unrestricted subsidiaries.
These covenants are subject to numerous exceptions, some of which are material.
Certain of these covenants are subject to termination upon the occurrence of
certain events. Viper may use cash on hand to repurchase a portion of the Viper
Notes in privately-negotiated transactions, open market purchases or otherwise,
but is under no obligation to do so.

Rattler's Credit Agreement



In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as
borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo,
as administrative agent, and a syndicate of banks, including Wells Fargo, as
lenders party thereto, which we refer to as the Rattler credit agreement.

The Rattler credit agreement provides for a revolving credit facility in the
maximum credit amount of $600 million which is expandable to $1 billion upon
Rattler's election, subject to obtaining lender commitments and satisfaction of
customary conditions. Loan principal may be optionally prepaid from time to time
without premium or penalty (other than customary LIBOR breakage), and is
required to be repaid at the maturity date of May 28, 2024.

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The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG
LLC and Rattler AJAX Processing LLC and is secured by substantially all of the
assets of Rattler LLC, Rattler, Tall City, Rattler OMOG LLC and Rattler AJAX
Processing LLC. As of March 31, 2020, Rattler LLC had $451 million of
outstanding borrowings and $149 million available for future borrowings under
the Rattler credit agreement.

The outstanding borrowings under the Rattler credit agreement bear interest at a
per annum rate elected by Rattler LLC that is based on the prime rate or LIBOR,
in each case plus an applicable margin. The applicable margin ranges from 0.250%
to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for
LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as
defined in the Rattler credit agreement). Rattler LLC is obligated to pay a
quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused
portion of the commitment, which fee is also dependent on the Consolidated Total
Leverage Ratio.

The Rattler credit agreement contains various affirmative and negative
covenants. These covenants, among other things, limit additional indebtedness,
additional liens, sales of assets, mergers and consolidations, distributions and
other restricted payments, transactions with affiliates, and entering into
certain swap agreements, in each case of Rattler, Rattler LLC and their
restricted subsidiaries. The covenants are subject to exceptions set forth in
the Rattler credit agreement, including an exception allowing Rattler LLC or
Rattler to issue unsecured debt securities and an exception allowing payment of
distributions if no default or event of default exists.

The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below: Financial

                                                  Required Ratio

Covenant


Consolidated Total Leverage Ratio                  Not greater than 5.00 to 1.00
                                                    (or not greater than 5.50 to
                                                     1.00 for 3 fiscal quarters
                                                         following certain
                                                     acquisitions), but if the
                                                    Consolidated Senior Secured
                                                   Leverage Ratio (as defined in
                                                   the Rattler credit agreement)
                                                      is applicable, then not
                                                     greater than 5.25 to 1.00)
Consolidated Senior Secured Leverage Ratio
commencing with the last day of any fiscal quarter
in which the Financial Covenant Election (as
defined in the Rattler credit agreement) is made   Not greater than 3.50 to 1.00
Consolidated Interest Coverage Ratio (as defined
in the Rattler credit agreement)                     Not less than 2.50 to 

1.00





For purposes of calculating the financial maintenance covenants prior to the
fiscal quarter ending June 30, 2020, EBITDA (as defined in the Rattler credit
agreement) will be annualized based on the actual EBITDA for the preceding
fiscal quarters starting with the fiscal quarter ending September 30, 2019.

As of March 31, 2020, Rattler and Rattler LLC were in compliance with all
financial maintenance covenants under the Rattler credit agreement. The lenders
may accelerate all of the indebtedness under the Rattler credit agreement upon
the occurrence and during the continuance of any event of default. The Rattler
credit agreement contains customary events of default,
including non-payment, breach of covenants, materially incorrect
representations, cross-default, bankruptcy and change in control.

Capital Requirements and Sources of Liquidity



Our board of directors approved a 2020 capital budget for drilling and
completion, midstream and infrastructure of approximately $2.8 billion to $3.0
billion. In response to the current commodity price environment, we have updated
our 2020 capital budget to narrow our anticipated capital expenditures for 2020
to approximately $1.5 billion to $1.9 billion, representing a decrease of 41%
over our 2019 capital budget. We estimate that, of these expenditures,
approximately:

$1.31 billion to $1.63 billion will be spent on drilling and completing

170 to 200 gross (153 to 180 net) horizontal wells across our operated

leasehold acreage in the Northern Midland and Southern Delaware Basins,


       with an average lateral length of approximately 9,700 feet;


$100 million to $150 million will be spent on midstream infrastructure,


       excluding joint venture investments; and




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$90 million to $120 million will be spent on infrastructure and other

expenditures, excluding the cost of any leasehold and mineral interest


       acquisitions.



During the three months ended March 31, 2020, our aggregate capital expenditures
for our development program were $746 million. Additionally during the three
months ended March 31, 2020, we spent approximately $105 million in cash on
acquisitions of leasehold interests and mineral acres. We do not have a specific
acquisition budget since the timing and size of acquisitions cannot be
accurately forecasted.

In May 2019, our board of directors approved a stock repurchase program to
acquire up to $2 billion of our outstanding common stock through December 31,
2020. We repurchased approximately $98 million of our common stock under this
program during the three months ended March 31, 2020. Although we have
approximately $1.3 billion remaining available for future repurchases under this
program, we have suspended this program to preserve liquidity.

The amount and timing of our capital expenditures are largely discretionary and
within our control. We could choose to defer a portion of these planned capital
expenditures depending on a variety of factors, including but not limited to the
success of our drilling activities, prevailing and anticipated prices for oil
and natural gas, the availability of necessary equipment, infrastructure and
capital, the receipt and timing of required regulatory permits and approvals,
seasonal conditions, drilling and acquisition costs and the level of
participation by other interest owners. We are currently operating 14 drilling
rigs and no completion crews. We will continue monitoring commodity prices and
overall market conditions and can adjust our rig cadence up or down in response
to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for
2020, we believe that our cash flow from operations, cash on hand and borrowings
under our revolving credit facility will be sufficient to fund our operations
through year-end 2020. However, future cash flows are subject to a number of
variables, including the level of oil and natural gas production and prices, and
significant additional capital expenditures will be required to more fully
develop our properties. Further, our 2020 capital expenditure budget does not
allocate any funds for leasehold interest and property acquisitions.

We monitor and adjust our projected capital expenditures in response to the
results of our drilling activities, changes in prices, availability of
financing, drilling and acquisition costs, industry conditions, the timing of
regulatory approvals, the availability of rigs, contractual obligations,
internally generated cash flow and other factors both within and outside our
control. If we require additional capital, we may seek such capital through
traditional reserve base borrowings, joint venture partnerships, production
payment financing, asset sales, offerings of debt and or equity securities or
other means. We cannot assure you that the needed capital will be available on
acceptable terms or at all. If we are unable to obtain funds when needed or on
acceptable terms, we may be required to curtail our drilling programs, which
could result in a loss of acreage through lease expirations. In addition, we may
not be able to complete acquisitions that may be favorable to us or finance the
capital expenditures necessary to replace our reserves. If there is a decline in
commodity prices, our revenues, cash flows, results of operations, liquidity and
reserves may be materially and adversely affected.


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Guarantor Financial Information



As of March 31, 2020, Diamondback O&G LLC is the sole guarantor under the
December 2019 Notes Indenture governing the 2019 senior notes and the 2025
Indenture governing the 2025 senior notes. In connection with the satisfaction
and discharge of the indenture, dated as of October 28, 2016, as subsequently
supplemented, among Diamondback Energy, Inc., the guarantor subsidiaries party
thereto and Wells Fargo, as trustee, governing Diamondback Energy, Inc.'s then
outstanding 4.750% Senior Notes due 2024, or the 4.750% senior notes,
Diamondback E&P LLC and Energen Corporation and its subsidiaries were released
as guarantors under the 4.750% senior notes, the 2025 senior notes and
Diamondback O&G LLC's revolving credit facility. Rattler LLC was released as a
guarantor under Diamondback O&G LLC's credit agreement on May 28, 2019. Viper,
Viper's General Partner, Viper LLC, Rattler, Rattler's General Partner and
Rattler's subsidiaries remain non-guarantor subsidiaries.
Diamondback O&G LLC's guarantees of the 2019 senior notes and the 2025 senior
notes are "full and unconditional," as that term is used in Regulation S-X, Rule
3-10(b)(3), except that such guarantees will be released or terminated in
certain circumstances set forth in the indentures governing the 2019 senior
notes and the 2025 senior notes, such as, with certain exceptions, (1) in the
event Diamondback O&G LLC (or all or substantially all of its assets) is sold or
disposed of, (2) in the event Diamondback O&G LLC ceases to be a guarantor of or
otherwise be an obligor under certain other indebtedness, and (3) in connection
with any covenant defeasance, legal defeasance or satisfaction and discharge of
the relevant indenture.
Diamondback O&G LLC's guarantees of the 2019 senior notes and the 2025 senior
notes are senior unsecured obligations and rank senior in right of payment to
any of its future subordinated indebtedness, equal in right of payment with all
of its existing and future senior indebtedness, including its obligations under
its revolving credit facility, and effectively subordinated to any of its
existing and future secured indebtedness, to the extent of the value of the
collateral securing such indebtedness.
The rights of holders of the senior notes against Diamondback O&G LLC 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 O&G LLC's liability to the maximum amount that it could incur
without causing the incurrence of obligations under its guarantee to be a
fraudulent conveyance. However, there can be no assurance as to what standard a
court will apply in making a determination of the maximum liability of
Diamondback O&G LLC. Moreover, this provision may not be effective to protect
the guarantee from being voided under fraudulent conveyance laws. There is a
possibility that the entire guarantee may be set aside, in which case the entire
liability may be extinguished.
The following tables present summarized financial information for Diamondback
Energy, Inc., as the parent, and Diamondback O&G LLC, as the guarantor
subsidiary, on a combined basis after elimination of (i) intercompany
transactions and balances between the parent and the guarantor subsidiary and
(ii) equity in earnings from and investments in any subsidiary that is a
non-guarantor. The information is presented in accordance with the requirements
of Rule 13-01 under 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.
                                                    March 31, 2020        December 31, 2019
Summarized Balance Sheet                                        (in millions)
Assets
Current assets                                   $              952     $               396
Property and equipment, net                                  10,556                  10,109
Other noncurrent assets                                          43                      17
Liabilities
Current liabilities                              $              182     $               167
Intercompany accounts payable, non-guarantor
subsidiary                                                      794                     600
Long-term debt                                                3,969                   3,782
Other noncurrent liabilities                                    570                     504




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