The following discussion is intended to assist you in understanding our business
and results of operations together with our present financial condition. This
section should be read in conjunction with our historical consolidated financial
statements and notes, as well as the selected historical consolidated financial
data included elsewhere in this report.
Certain statements in our discussion below are forward-looking statements. These
forward-looking statements involve risks and uncertainties. We caution that a
number of factors could cause actual results to differ materially from those
implied or expressed by the forward-looking statements. Please see "Cautionary
Statement Regarding Forward-Looking Statements" and "Item 1A. Risk Factors" for
further details about these statements.
Overview
We are an independent oil and natural gas company engaged in the acquisition,
development, exploration and production of oil and natural gas properties. We
are one of the largest operators in the Permian Basin of West Texas and
Southeast New Mexico. Concho's legacy in the Permian Basin provides us a deep
understanding of operating and geological trends, and we are actively developing
our resource base utilizing large-scale development projects, which include
long-lateral wells and multi-well pad locations, throughout our operating areas.
Oil comprised 62 percent of our 1,002 MMBoe of estimated proved reserves at
December 31, 2019 and 63 percent of our 121 MMBoe of production for 2019. We
seek to operate the wells in which we own an interest, and we operated wells
that accounted for 93 percent of our proved developed producing reserves and 75
percent of our 5,981 gross wells at December 31, 2019. By controlling
operations, we are able to more effectively manage the development strategy as
well as the cost and timing of exploration and development of our properties.

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Financial and Operating Performance
Our financial and operating performance for 2019 included the following
highlights:
•      Net loss was $705 million ($(3.55) per diluted share) as compared to net

income of $2,286 million ($13.25 per diluted share) in 2018. The decrease

was primarily due to:

$1,727 million change in (gain) loss on derivatives due to a loss on
             derivatives of $895 million during 2019, as compared to a gain of
             $832 million during 2018;

$890 million of impairments of long-lived assets during 2019;

$282 million of impairments of goodwill during 2019;

$630 million decrease in gain on disposition of assets due to a $170
             million net gain during 2019 primarily due to the contribution of
             certain infrastructure assets in exchange for a cash

distribution


             and an equity ownership interest in the entity in July 2019,
             partially offset by net losses from certain nonmonetary
             transactions, as compared to a net gain of $800 million primarily
             related to certain acquisitions and divestitures during 2018, as
             discussed in Note 5 of the Notes to Consolidated Financial
             Statements included in "Item 8. Financial Statements and
             Supplementary Data"; and


•            $486 million increase in depreciation, depletion and

amortization


             expense, primarily due to the increase in production and the
             increase in the depletion rate per Boe.


partially offset by:
•            $441 million increase in oil and natural gas revenues as a result of
             a 26 percent increase in production, partially offset by a 12
             percent decrease in commodity price realizations per Boe (excluding
             the effects of derivative activities);


•            $205 million increase in other income, primarily due to the gain of
             $289 million on the sale of our ownership interest in the subsidiary
             of our equity method investment, Oryx Southern Delaware Holdings,
             LLC ("Oryx"); and


•            $757 million change in income taxes due to a $154 million tax
             benefit during 2019, as compared to a $603 million tax expense
             during 2018.

• Average daily sales volumes increased by 26 percent from 262,937 Boe per

day during 2018 to 331,086 Boe per day during 2019.

• Net cash provided by operating activities increased by $278 million to

$2,836 million in 2019, as compared to $2,558 million in 2018, primarily

due to an increase in oil and natural gas revenues and changes related to


       cash settlements on derivatives, partially offset by an increase in
       operating costs on our oil and natural gas properties.



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Commodity Prices
Our results of operations are heavily influenced by commodity prices. See "Item
1A. Risk Factors" for a description of the factors that may impact future
commodity prices, including the price of oil, natural gas and natural gas
liquids.
Although we cannot predict the occurrence of events that may affect future
commodity prices, or the degree to which these prices will be affected, the
prices for any commodity that we produce will generally approximate current
market prices in the geographic region of the production. From time to time, we
expect that we may hedge a portion of our commodity price risk to mitigate the
impact of price volatility on our business. See Notes 9 and 19 of the Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding our commodity
derivative positions at December 31, 2019 and additional derivative contracts
entered into subsequent to December 31, 2019, respectively.
The following table sets forth the average NYMEX oil and natural gas prices for
the years ended December 31, 2019, 2018 and 2017, as well as the high and low
NYMEX prices for the same periods:
                                 Years Ended December 31,
                                2019          2018       2017
Average NYMEX prices:
Oil (Bbl)                  $   57.03        $ 64.81    $ 50.97
Natural gas (MMBtu)        $    2.53        $  3.07    $  3.02
High and Low NYMEX prices:
Oil (Bbl):
High                       $   66.30        $ 76.41    $ 60.42
Low                        $   45.41        $ 42.53    $ 42.53
Natural gas (MMBtu):
High                       $    3.59        $  4.84    $  3.72
Low                        $    2.07        $  2.55    $  2.56



Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows
of $63.27 and $49.57 per Bbl and $2.20 and $1.77 per MMBtu, respectively, during
the period from January 1, 2020 to February 14, 2020. At February 14, 2020, the
NYMEX oil price and NYMEX natural gas price were $52.05 per Bbl and $1.84 per
MMBtu, respectively.
Historically, and during the year ended December 31, 2019, we derived a
significant portion of our total natural gas revenues from the value of the
natural gas liquids contained in our natural gas, with the remaining portion
coming from the value of the dry natural gas residue. The average Mont Belvieu
price for a blended barrel of natural gas liquids was $20.19 per Bbl, $29.94 per
Bbl and $25.06 per Bbl during the years ended December 31, 2019, 2018 and 2017,
respectively.
Potential cost inflation. Oilfield service and supply costs are also subject to
supply and demand dynamics. As companies expand their drilling and development
activities, the demand for third-party oilfield services and suppliers may also
increase. As such, when commodity prices begin to trend upward, we expect demand
for oilfield services and supplies to grow, and the costs of drilling, equipping
and operating our wells and infrastructure could increase.

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Recent Events
The following are significant recent developments since our last quarterly
report on Form 10-Q was filed on October 30, 2019:
2020 capital budget. In February 2020, our board of directors approved our 2020
capital budget of up to $2.9 billion. We expect to spend between $2.6 billion
and $2.8 billion on drilling and completion activity.
Dividends. On February 18, 2020, our board of directors approved a cash dividend
of $0.20 per share for the first quarter of 2020 that is expected to be paid on
March 27, 2020 to stockholders of record as of February 28, 2020. The total cash
dividend paid to our stockholders during 2019 was $100 million.

New Mexico Shelf divestiture. In November 2019, we closed on our New Mexico
Shelf asset divestiture and received cash proceeds of $837 million, subject to
post-closing adjustments. Refer to Note 5 of the Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information regarding the New Mexico Shelf divestiture. We used the
proceeds from this divestiture to repay outstanding borrowings under our Credit
Facility and initiate the share repurchase program, as discussed below.

Share repurchase program. In September 2019, we announced that our board of
directors authorized the initiation of a share repurchase program for up to $1.5
billion of our common stock. A portion of the proceeds from the New Mexico Shelf
divestiture was used to initiate the share repurchase program. As of
December 31, 2019, we had repurchased and retired 3,300,370 shares under the
program at an aggregate cost of $250 million.
Derivative Financial Instruments
Derivative financial instrument exposure.  At December 31, 2019, the fair value
of our financial derivatives was a net liability of $102 million. Under the
terms of our financial derivative instruments, we do not have exposure to
potential "margin calls" on our financial derivative instruments. The terms of
our Credit Facility do not allow us to offset amounts we may owe a lender
against amounts we may be owed related to our financial instruments with such
party.
New commodity derivative contracts. After December 31, 2019, we entered into
derivative contracts to hedge additional amounts of estimated future production.
Refer to Note 19 of the Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional information
regarding these commodity derivative contracts.

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Results of Operations
The following table sets forth summary production and operating data for the
years ended December 31, 2019, 2018 and 2017. The actual historical data in this
table excludes results from the RSP Acquisition for periods prior to July 19,
2018. Because of normal production declines, increased or decreased drilling
activities, fluctuations in commodity prices and the effects of acquisitions and
divestitures, the historical information presented below should not be
interpreted as being indicative of future results.
                                                 Years Ended December 31,
                                               2019          2018        

2017


Production and operating data:
Net production volumes:
Oil (MBbl)                                   76,369          61,251      43,472
Natural gas (MMcf)                          266,865         208,326     161,089
Total (MBoe)                                120,847          95,972      70,320

Average daily production volumes:
Oil (Bbl)                                   209,230         167,811     119,101
Natural gas (Mcf)                           731,137         570,756     441,340
Total (Boe)                                 331,086         262,937     192,658

Average prices per unit: (a)
Oil, without derivatives (Bbl)            $   54.03        $  56.22    $  

48.13


Oil, with derivatives (Bbl) (b)           $   52.35        $  52.73    $  

49.93


Natural gas, without derivatives (Mcf)    $    1.74        $   3.40    $   3.07
Natural gas, with derivatives (Mcf) (b)   $    1.86        $   3.37    $   3.06
Total, without derivatives (Boe)          $   38.00        $  43.25    $  36.78
Total, with derivatives (Boe) (b)         $   37.19        $  40.98    $  37.88

Operating costs and expenses per Boe: (a)
Oil and natural gas production            $    5.93        $   6.14    $   

5.80


Production and ad valorem taxes           $    2.89        $   3.19    $   

2.82

Gathering, processing and transportation $ 0.96 $ 0.58 $

-

Depreciation, depletion and amortization $ 16.25 $ 15.41 $ 16.29 General and administrative

$    2.69        $   3.25    $   3.46

(a) Per unit and per Boe amounts calculated using dollars and volumes rounded to thousands.



(b)  Includes the effect of net cash receipts from (payments on) derivatives:

                                                                    Years Ended December 31,
     (in millions)                                   2019                2018                       2017

Net cash receipts from (payments on)


     derivatives:
     Oil derivatives                             $     (129 )   $          (213 )             $            79
     Natural gas derivatives                             31                  (5 )                           -
     Total                                       $      (98 )   $          (218 )             $            79

The presentation of average prices with derivatives is a result of including the net cash receipts from

(payments on) commodity derivatives that are presented in our consolidated statements of cash flows. This

presentation of average prices with derivatives is a means by which to reflect the actual cash performance

of our commodity derivatives for the respective periods and presents oil and natural gas prices with

derivatives in a manner consistent with the presentation generally used by the investment community.









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The following table presents selected production data for the fields that
represent greater than 15 percent of our total proved reserves at December 31,
2019, 2018 and 2017:
                        Years Ended December 31,
                          2019            2018    2017
Production:
Delaware Basin:
Oil (MMBbl)            44                   34      25
Natural gas (Bcf)     170                  130     103
Total (MMBoe)          72                   56      42
Midland Basin:
Oil (MMBbl)            29                   21      11
Natural gas (Bcf)      76                   52      30
Total (MMBoe)          42                   30      16
Yeso:
Oil (MMBbl)           (a)                  (a)       7
Natural gas (Bcf)     (a)                  (a)      28
Total (MMBoe)         (a)                  (a)      12


(a) Represents less than 15% of our total proved reserves for the year indicated.










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The following tables and related discussion set forth key operating and
financial data as of and for the years ended December 31, 2019 and 2018. For
similar operating and financial data and discussion of our 2018 results compared
to our 2017 results, refer to "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" under Part II of our annual
report on Form 10-K for the year ended December 31, 2018, which was filed with
the SEC on February 20, 2019.
Oil and natural gas revenues. Revenue from oil and natural gas operations was
$4,592 million for the year ended December 31, 2019, an increase of $441 million
(11 percent) from $4,151 million for 2018. The increase was primarily due to the
increase in oil and natural gas production, in part due to the RSP Acquisition,
partially offset by the decrease in realized oil and natural gas prices
(excluding the effects of derivative activities).
Specific factors affecting oil and natural gas revenues for the years ended
December 31, 2019 and 2018 include the following:
                                                                Years Ended December 31,
                                                                 2019               2018
Net production volumes:
Oil (MBbl)                                                        76,369             61,251
Natural gas (MMcf)                                               266,865            208,326

Average prices per unit:
Average NYMEX oil price (Bbl)                               $      57.03       $      64.81
Realized oil price (Bbl)                                    $      54.03       $      56.22
Differential to NYMEX                                       $      (3.00 )     $      (8.59 )

Average NYMEX natural gas price (MMBtu)                     $       2.53       $       3.07
Realized natural gas price (Mcf)                            $       1.74       $       3.40
Average realized natural gas price as a percentage of NYMEX           69 %              111 %


• total oil production increased 15,118 MBbl (25 percent) for the year ended

December 31, 2019 as compared to 2018;


•      average realized oil price (excluding the effects of derivative
       activities) decreased 4 percent for the year ended December 31, 2019 as

compared to 2018. The decrease in average realized oil price was primarily

due to a decrease in the average NYMEX price, partially offset by the

narrowing of the basis differential. The basis differential (referred to

as the "Mid-Cush differential") between the location of Midland, Texas and

Cushing, Oklahoma (settlement location for NYMEX pricing) for our oil

directly impacts our realized oil price. For the years ended December 31,


       2019 and 2018, the average market Mid-Cush differentials were price
       reductions of $1.49 per Bbl and $6.51 per Bbl, respectively;

• total natural gas production increased 58,539 MMcf (28 percent) for the

year ended December 31, 2019 as compared to 2018; and

• average realized natural gas price (excluding the effects of derivative

activities) decreased 49 percent for the year ended December 31, 2019 as

compared to 2018. We derive a significant portion of our total natural gas

revenues from the value of the natural gas liquids contained in our

natural gas, with the remaining portion coming from the value of the dry

natural gas residue. The average Mont Belvieu price for a blended barrel

of natural gas liquids decreased from $29.94 per Bbl during the year ended

December 31, 2018 to $20.19 per Bbl during the year ended December 31,

2019. In addition, during the latter part of 2018 and into 2019, amid

concerns of rising natural gas production relative to the ability to

transport natural gas out of the Permian Basin, the price differential for

natural gas residue increased significantly. These widening natural gas

residue differentials negatively impacted our realized natural gas prices

during the year ended December 31, 2019. The combination of these factors

resulted in a realized natural gas price of 69 percent of the average

NYMEX natural gas price for the year ended December 31, 2019. Because of

our liquids-rich natural gas stream and the related value of the natural

gas liquids being included in our natural gas revenues and the Permian


       Basin local markets for residue gas settling more in parity with NYMEX
       price, our realized natural gas price (excluding the effects of
       derivatives) for the year ended December 31, 2018 reflected a price
       greater than the related NYMEX natural gas price.



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Oil and natural gas production expenses. The following table provides the
components of our oil and natural gas production expenses for the years ended
December 31, 2019 and 2018:
                                                               Years Ended December 31,
                                                            2019                        2018
(in millions, except per unit amounts)              Amount        Per Boe       Amount       Per Boe
Lease operating expenses                         $    681       $    5.64     $    553     $    5.76
Workover costs                                         35            0.29           37          0.38
Total oil and natural gas production expenses    $    716       $    5.93

$ 590 $ 6.14





Lease operating expenses were $681 million ($5.64 per Boe) for the year ended
December 31, 2019, an increase of $128 million (23 percent) from $553 million
($5.76 per Boe) for 2018. The increase in lease operating expenses during 2019
as compared to the prior year was primarily the result of an increase in well
count due to our acquisitions during 2018, and additional wells successfully
drilled and completed during 2018 and 2019, partially offset by the New Mexico
Shelf divestiture. The decrease in lease operating expenses per Boe was
primarily due to higher production from our drilling program during 2019 and the
New Mexico Shelf divestiture.
Workover costs were $35 million ($0.29 per Boe) for the year ended December 31,
2019, a decrease of $2 million from $37 million ($0.38 per Boe) for 2018. The
decrease in workover costs per Boe during 2019 was primarily due to increased
production and decreased workover activity.
Production and ad valorem taxes. The following table provides the components of
our production and ad valorem tax expenses for the years ended December 31, 2019
and 2018:
                                                   Years Ended December 31,
                                                 2019                      2018

(in millions, except per unit amounts) Amount Per Boe Amount


   Per Boe
Production taxes                       $   282       $    2.33    $    272    $    2.84
Ad valorem taxes                            67            0.56          33         0.35

Total production and ad valorem taxes $ 349 $ 2.89 $ 305

$ 3.19





Production taxes per unit of production were $2.33 per Boe during the year ended
December 31, 2019, a decrease of 18 percent from $2.84 per Boe during 2018. Over
the same period, our revenue per Boe (excluding the effects of derivatives)
decreased 12 percent. The decrease in production taxes per unit of production
was due to lower realized revenue per Boe along with a higher percentage of our
total production originating in Texas, which has a lower tax rate than New
Mexico.
Production taxes fluctuate with the market value of our production sold, while
ad valorem taxes are generally based on the valuation of our oil and natural gas
properties at the beginning of the year, which vary across the different areas
in which we operate.
Ad valorem taxes increased $34 million during the year ended December 31, 2019
as compared to the year ended December 31, 2018, primarily due to additional
wells drilled and completed, new wells acquired and an increase in tax rates in
certain counties. The increase in ad valorem taxes per Boe during the year ended
December 31, 2019 as compared to the year ended December 31, 2018 was primarily
due to an increase in tax rates.
Gathering, processing and transportation costs. The following table shows the
gathering, processing and transportation costs for the years ended December 31,
2019 and 2018:
                                                                Years Ended December 31,
                                                            2019                         2018
(in millions, except per unit amounts)              Amount         Per Boe       Amount       Per Boe
Gathering, processing and transportation costs   $    115        $    0.96

$ 55 $ 0.58





Gathering, processing and transportation costs were $115 million ($0.96 per Boe)
for the year ended December 31, 2019, an increase of 109 percent from $55
million for 2018. The increase in gathering, processing and transportation costs
for 2019 was primarily due to a certain crude oil gathering and transportation
contract that, among other things, was modified to allow repurchase rights. As
such, costs related to this contract that were previously recorded as a
deduction to revenue during 2018 are now recorded in gathering, processing and
transportation costs. In addition, contributing to the increase in gathering,
processing and transportation costs was the RSP Acquisition and the increase in
production. The increase in gathering, processing and transportation costs per
Boe was primarily related to the aforementioned crude oil gathering and
transportation contract and fixed costs associated with

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certain contracts. Additionally, we entered into a marketing contract that
requires us to deliver 50,000 barrels of oil per day that began in October 2019.
As a result of this contract, we expect our realized oil prices, as well as our
gathering, processing and transportation costs, to increase for the related oil
production in future periods.
Exploration and abandonments expense. The following table provides the
components of our exploration and abandonments expense for the years ended
December 31, 2019 and 2018:
                                          Years Ended December 31,
(in millions)                                   2019                 2018
Geological and geophysical         $          17                    $  12
Leasehold abandonments                       147                       35
Other                                         37                       18
Total exploration and abandonments $         201                    $  65



Our geological and geophysical expense for the periods presented above primarily
consists of the costs of acquiring and processing geophysical data and core
analysis.
We recorded $147 million and $35 million of leasehold abandonments for the years
ended December 31, 2019 and 2018, respectively, primarily related to certain
expiring acreage where we had no plans to extend the lease and acreage where we
had no long-term plans to drill.
Our other expense for the periods presented above primarily consists of surface
and title costs on locations we no longer intend to drill, certain plugging
costs and delay rentals. The increase in other expense during 2019 was primarily
due to the abandonments of certain exploratory wells, in part due to mechanical
issues encountered during the completion of certain wells that made them unable
to produce hydrocarbons in economic quantities.
Depreciation, depletion and amortization expense. The following table provides
components of our depreciation, depletion and amortization expense for the years
ended December 31, 2019 and 2018:
                                                            Years Ended 

December 31,


                                                          2019              

2018


(in millions, except per unit amounts)            Amount      Per Boe      Amount      Per Boe
Depletion of proved oil and natural gas
properties                                       $ 1,932     $  15.98     $ 1,453     $  15.14
Depreciation of other property and equipment          30         0.25          22         0.23
Amortization of intangible assets                      2         0.02       

3 0.04 Total depletion, depreciation and amortization $ 1,964 $ 16.25 $ 1,478 $ 15.41



Oil price used to estimate proved oil reserves
at period end                                    $ 52.19                  $ 

62.04


Natural gas price used to estimate proved
natural gas reserves at period end               $  2.58                  $ 

3.10





Depletion of proved oil and natural gas properties was $1,932 million ($15.98
per Boe) for the year ended December 31, 2019, an increase of $479 million (33
percent) from $1,453 million ($15.14 per Boe) for 2018. The increase in
depletion expense was due to an increase in production and the depletion rate
per Boe. The increase in depletion expense per Boe was primarily due to the RSP
Acquisition and certain downward adjustments to our proved oil and natural gas
reserves, partially offset by lower depletion of the Yeso field due to the
impairment charge recognized during 2019, as discussed below, and the New Mexico
Shelf divestiture.
Impairments of long-lived assets. During the year ended December 31, 2019, we
recognized impairments of long-lived assets of $890 million. During the second
quarter of 2019, we recognized an impairment charge of $868 million that was
primarily attributable to certain downward adjustments to our economically
recoverable proved oil and natural gas reserves associated with properties in
our Yeso field due to the decline in commodity prices. During the third quarter
of 2019, we recognized an additional impairment charge of $20 million primarily
to reduce the carrying value of the remaining assets in the Yeso field to their
fair value. Our Yeso field was primarily composed of the New Mexico Shelf assets
that we sold in November 2019. We did not recognize an impairment during 2018.
See Note 8 of the Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information on
the fair value assumptions used for long-lived assets.
It is reasonably possible that the estimate of undiscounted future net cash
flows of our long-lived assets may change in the future resulting in the need to
further impair carrying values. The primary factors that may affect estimates of
future net cash flows are (i) commodity prices including differentials, (ii)
increases or decreases in production and capital costs, (iii) future reserve
volume adjustments, both positive and negative, to proved reserves and
appropriate risk-adjusted probable and possible reserves, (iv) results of future
drilling activities and (v) changes in income and expenses from integrated
assets.

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Impairments of goodwill. During the year ended December 31, 2019, we recognized
goodwill impairments of $282 million. The impairments were due to a decline in
our market capitalization along with declines in observed control premiums
during the second half of 2019 and the New Mexico Shelf divestiture. See Note 2
of the Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information on the impairment
of our goodwill.
General and administrative expenses. The following table provides components of
our general and administrative expenses for the years ended December 31, 2019
and 2018:
                                                   Years Ended December 31,
                                                  2019                   2018

(in millions, except per unit amounts) Amount Per Boe Amount

  Per Boe
General and administrative expenses       $  259     $  2.13     $  248     $  2.58
Less: Operating fee reimbursements           (18 )     (0.15 )      (19 )     (0.19 )
Non-cash stock-based compensation             85        0.71         82     

0.86

Total general and administrative expenses $ 326 $ 2.69 $ 311 $ 3.25





Total general and administrative expenses were $326 million ($2.69 per Boe) for
the year ended December 31, 2019, an increase of $15 million (5 percent) from
$311 million ($3.25 per Boe) for 2018. The increase in total general and
administrative expenses was primarily due to an increase in the average employee
headcount, in part due to the RSP Acquisition, partially offset by lower
variable compensation accruals during 2019. The decrease in total general and
administrative expenses per Boe was primarily the result of increased
production, partially offset by the increase in total general and administrative
expenses.
We receive fees for the operation of jointly-owned oil and natural gas
properties during the drilling and production phases and record such
reimbursements as reductions to general and administrative expenses in the
consolidated statements of operations. We earned reimbursements of approximately
$18 million and $19 million during the years ended December 31, 2019 and 2018,
respectively.
Gain (loss) on derivatives. The following table sets forth the gain (loss) on
derivatives for the years ended December 31, 2019 and 2018:
                                Years Ended December 31,
(in millions)                     2019              2018
Gain (loss) on derivatives:
Oil derivatives             $       (1,003 )     $     848
Natural gas derivatives                108             (16 )
Total                       $         (895 )     $     832

The following table represents our net cash receipts from (payments on) derivatives for the years ended December 31, 2019 and 2018:


                                                     Years Ended December 

31,


(in millions)                                          2019             

2018


Net cash receipts from (payments on) derivatives:
Oil derivatives                                   $      (129 )     $      (213 )
Natural gas derivatives                                    31                (5 )
Total                                             $       (98 )     $      (218 )



Our earnings are affected by the changes in value of our derivatives portfolio
between periods and the related cash settlements of those derivatives, which
could be significant. To the extent the future commodity price outlook declines
between measurement periods, we will have mark-to-market gains; while to the
extent future commodity price outlook increases between measurement periods, we
will have mark-to-market losses. See Note 8 of the Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding significant judgments made in
classifying financial instruments in the fair value hierarchy.
Gain on disposition of assets, net. During the year ended December 31, 2019, we
recorded a net gain on disposition of assets of $170 million, primarily due to a
gain of $297 million related to our contribution of certain water infrastructure
assets in exchange for a cash distribution and an equity ownership interest in
an entity, partially offset by losses related to certain nonmonetary
transactions and the New Mexico Shelf divestiture.

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During the year ended December 31, 2018, we recognized a net gain on disposition
of assets of $800 million, which was primarily due to (i) a gain of $575 million
related to our February 2018 acquisition and divestiture primarily in the
Midland Basin, (ii) a gain of $134 million related to our Delaware Basin
divestiture in January 2018 and (iii) a gain of $79 million related to the
contribution of certain infrastructure assets in the southern portion of the
Delaware Basin. In addition, during 2018, we completed multiple nonmonetary
transactions that included the exchange of both proved and unproved oil and
natural gas properties that resulted in pre-tax gains of $15 million.
Refer to Notes 2 and 5 of the Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for further
discussion of certain of the 2019 and 2018 transactions mentioned above.
Interest expense. The following table sets forth interest expense, weighted
average interest rates and weighted average debt balances for the years ended
December 31, 2019 and 2018:
                                                               Years Ended December 31,
(in millions)                                                   2019               2018
Interest expense, as reported                              $        185       $        149
Capitalized interest                                                 19                  8

Interest expense, excluding impact of capitalized interest $ 204

$ 157



Weighted average interest rate - Credit Facility                    4.2 %              4.5 %
Weighted average interest rate - senior notes                       4.4 %              4.3 %
Total weighted average interest rate                                4.4 %              4.3 %

Weighted average Credit Facility balance                   $        439       $        172
Weighted average senior notes balance                             4,000     

3,195


Total weighted average debt balance                        $      4,439

$ 3,367





The increase in interest expense during the year ended December 31, 2019 as
compared to 2018 was primarily due to the increase in the weighted average debt
balance, partially offset by the increase in capitalized interest and lower
weighted average interest rate on our Credit Facility. The increase in the
weighted average senior notes balance was primarily due to the senior notes
issued in connection with the RSP Acquisition.
Other income, net. During the year ended December 31, 2019, we recorded other
income of $313 million, primarily related to $289 million of cash proceeds from
the sale of our ownership interest in Oryx I, a crude oil gathering and
transportation system in the Delaware Basin ("Oryx I"). See Note 2 of the Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional information regarding this sale.
During the year ended December 31, 2018, we recorded other income of $108
million primarily related to a cash distribution received from Oryx. See Note 2
of the Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding this
distribution.
Income tax provisions.  We recorded an income tax benefit of $154 million and an
income tax expense of $603 million for the years ended December 31, 2019 and
2018, respectively. The change to income tax benefit in 2019 from income tax
expense in 2018 was primarily due to the pre-tax loss during 2019 as compared to
pre-tax income during 2018.
For the year ended December 31, 2019, we recorded an income tax benefit of $21
million due to the decrease in our applicable state tax rate in New Mexico as a
result of the New Mexico Shelf divestiture. During the second quarter of 2019,
the state of New Mexico enacted a tax law which, among other changes, amended
the apportioned net operating loss carryforwards for corporations. As a result
of this law change, we recorded a deferred state tax benefit of $6 million for
the year ended December 31, 2019.
For the year ended December 31, 2018, the Company completed its accounting for
all of the enactment-date tax effects of the TCJA and recognized an adjustment
to the provisional amount recorded as of the enactment date of approximately $7
million primarily related to the deductibility of certain performance-based
compensation expenses.
Our effective income tax rates were 18 percent and 21 percent for the years
ended December 31, 2019 and 2018, respectively. Our effective income tax rate of
18 percent for the year ended December 31, 2019 differed from the federal
statutory tax rate of 21 percent primarily due to (i) nondeductible goodwill
impairment; (ii) deferred benefit recognized from the decrease in the applicable
state tax rate as a result of the New Mexico Shelf divestiture; (iii) state
income taxes, including the impact of the enacted New Mexico tax law change; and
(iv) research and development credits, net of unrecognized tax benefits.
Our effective tax rate of 21 percent for the year ended December 31, 2018
approximated the federal statutory tax rate of 21 percent primarily due to the
benefits from (i) research and development credits, net of unrecognized tax
benefits; (ii) the change in

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the applicable state tax rates due to the RSP Acquisition; and (iii) the adjustment to provisional TCJA tax effects; offset by (iv) other recurring permanent differences and state income taxes that affect our rates.


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Capital Commitments, Capital Resources and Liquidity
Capital commitments. Our primary needs for cash are for (i) development,
exploration and acquisition of oil and natural gas assets, (ii) midstream joint
ventures and other capital commitments, (iii) payment of contractual obligations
and (iv) working capital obligations. Funding for these cash needs may be
provided by any combination of internally-generated cash flow, financing under
our Credit Facility, proceeds from the disposition of assets or alternative
financing sources, as discussed in "- Capital resources" below.
Oil and natural gas properties. Our costs incurred on oil and natural gas
properties, excluding acquisitions, during the years ended December 31, 2019 and
2018 totaled $3.0 billion and $2.6 billion, respectively. The primary reason for
the differences in costs incurred and cash flow expenditures included in our
consolidated statements of cash flows was the timing of payments. Our 2019
capital expenditures were primarily funded from cash flows from operations and
borrowings under our Credit Facility.
2020 capital budget. In February 2020, our board of directors approved our 2020
capital budget of up to $2.9 billion. We expect to spend between $2.6 billion
and $2.8 billion on drilling and completion activity.
Dividends. On February 18, 2020, our board of directors declared a cash dividend
of $0.20 per share for the first quarter of 2020 that is expected to be paid on
March 27, 2020 to stockholders of record as of February 28, 2020. Total cash
dividends paid to our stockholders during the year ended December 31, 2019 were
$100 million. We intend to continue to pay a quarterly dividend of $0.20 in the
future, however, any payment of future dividends will be at the discretion of
our board of directors and will depend on, among other things, our earnings,
financial condition, capital requirements, level of indebtedness, statutory and
contractual restrictions applying to the payment of dividends and other
considerations that our board of directors deems relevant.
Share repurchase program. In September 2019, we announced that our board of
directors authorized the initiation of a share repurchase program for up to $1.5
billion of our common stock. The maximum aggregate dollar amount of repurchases
that may be made in any quarter requires advance approval of the board of
directors. The share repurchase program may be modified, suspended or terminated
at any time by our board of directors and we are not obligated to acquire any
specific number of shares.
We used a portion of the proceeds from the New Mexico Shelf divestiture, which
closed in November 2019, to initiate share repurchases in the fourth quarter of
2019, while maintaining sufficient liquidity to fund our capital commitments and
dividend payments. All additional future repurchases will require the approval
of the Company's board of directors. As of December 31, 2019, we repurchased and
retired 3,300,370 shares under the program at an aggregate cost of $250 million.
Other than the customary purchase of leasehold acreage, our capital budgets are
exclusive of acquisitions. We do not have a specific acquisition budget because
the timing and size of acquisitions are difficult to forecast. We evaluate
opportunities to purchase or sell oil and natural gas properties in the
marketplace and could participate as a buyer or seller of properties at various
times. We seek to acquire oil and natural gas properties that provide
opportunities for the addition of reserves and production through a combination
of development, high-potential exploration and control of operations that will
allow us to apply our operating expertise.
Acquisitions. The following table reflects our expenditures for acquisitions of
proved and unproved properties for the years ended December 31, 2019 and 2018:
                                          Years Ended December 31,
(in millions)                                  2019               2018
Property acquisition costs:
Proved                               $       8                  $ 4,136
Unproved                                    50                    3,617
Total property acquisition costs (a) $      58                  $ 7,753

(a) Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of $50 million and $51 million for the years ended December 31, 2019 and 2018, respectively. Our unbudgeted acquisitions during 2018 were primarily comprised of approximately $7.6 billion of property acquisition costs related to the RSP Acquisition.


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Contractual obligations. We had the following contractual obligations at
December 31, 2019:
                                                          Payments Due by Period
                                                    Less than      1 - 3     3 - 5     More than
(in millions)                            Total        1 year       years     years      5 years
Long-term debt (a)                      $ 4,000    $         -    $    -    $    -    $     4,000
Cash interest expense on debt (b)         2,769            235       350       350          1,834
Derivative liabilities (c)                  119            112         7         -              -
Asset retirement obligations (d)            139              9        11         5            114
Employment agreements with officers (e)      10             10         -         -              -
Purchase obligations (f)                    333             51       109        70            103
Lease obligations (g)                        43             21        19         1              2

Total contractual obligations (h) $ 7,413 $ 438 $ 496 $ 426 $ 6,053

(a) See Note 10 of the Notes to Consolidated Financial Statements included in

"Item 8. Financial Statements and Supplementary Data" for information

regarding future interest payment obligations on our long-term debt. The

amounts included in the table above represent principal maturities only.

(b) Cash interest expense on our senior notes is estimated assuming no principal

repayment until their maturity dates. Also included in the "Less than 1 year"

column is accrued interest at December 31, 2019 of approximately $60 million.

At December 31, 2019, we had no variable-rate debt outstanding under our

Credit Facility.

(c) Derivative obligations represent commodity derivatives that were valued at

December 31, 2019. The ultimate settlement amounts of our derivative

obligations are unknown because they are subject to continuing market risk.

See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and

Note 9 of the Notes to Consolidated Financial Statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information

regarding our derivative obligations.

(d) Amounts represent costs related to expected oil and natural gas property

abandonments, net of any future accretion.

(e) Represents amounts of cash compensation we are obligated to pay to our

officers under employment agreements assuming such employees continue to

serve the entire term of their employment agreement and their cash

compensation is not adjusted.

(f) Relates to purchase agreements we have entered into including water

commitment agreements, throughput volume delivery commitments, fixed and

variable power commitments, sand commitment agreements and other commitments.

(g) Relates to our operating and financing leases, including office space, office

equipment, drilling rigs, field equipment and vehicles. See Note 11 of the

Notes to Consolidated Financial Statements included in "Item 8. Financial

Statements and Supplementary Data" for information regarding our lease

obligations. Included in the "Less than 1 year" column are the Company's

drilling rigs. Drilling rigs are short-term leases and are not capitalized

under the lease standard. A portion of these costs will be reimbursed to the

Company by other working interest owners.

(h) The amounts above do not include the liability for unrecognized tax benefits.


    See Note 12 of the Notes to Consolidated Financial Statements included in
    "Item 8. Financial Statements and Supplementary Data" for additional
    information.





Off-balance sheet arrangements. Currently, we do not have any material
off-balance sheet arrangements.
Capital resources. Our primary sources of liquidity have been cash flows
generated from (i) operating activities, (ii) borrowings under our Credit
Facility, (iii) asset dispositions and (iv) proceeds from bond and equity
offerings. In February 2020, our board of directors approved our 2020 capital
budget of up to $2.9 billion. We expect to spend between $2.6 billion and $2.8
billion on drilling and completion activity. We expect to fund our 2020 capital
budget primarily with operating cash flows. We believe that our current cash and
cash equivalents, together with cash flows generated from operating activities
and available borrowings under our Credit Facility, will be sufficient to meet
our anticipated cash requirements for at least the next 12 months.

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The following table summarizes our changes in cash and cash equivalents for the
years ended December 31, 2019 and 2018. The discussion of changes in cash and
cash equivalents for the year ended December 31, 2017 is included in Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under Part II of our Annual Report on Form 10-K for the year ended
December 31, 2018, which was filed with the SEC on February 20, 2019.
                                             Years Ended December 31,
(in millions)                                  2019             2018

Net cash provided by operating activities $ 2,836 $ 2,558 Net cash used in investing activities (1,993 ) (2,216 ) Net cash used in financing activities

            (773 )            (342 )

Net change in cash and cash equivalents $ 70 $ -





Cash flow from operating activities. The increase in operating cash flows during
the year ended December 31, 2019 as compared to 2018 was primarily due to an
increase in our total operating revenues of $441 million and an increase of $120
million due to $98 million of settlements paid on derivatives during the year
ended December 31, 2019, as compared to $218 million during 2018. The increase
was partially offset by an increase in operating expenses on our oil and natural
gas properties.
Our net cash provided by operating activities included a reduction of $40
million and a benefit of $4 million for the years ended December 31, 2019 and
2018, respectively, associated with changes in working capital items. Changes in
working capital items adjust for the timing of receipts and payments of actual
cash.
Cash flow from investing activities. Our investing activities consist primarily
of drilling and completion activity, acquisitions and divestitures. The primary
reason for the differences in costs incurred on oil and natural gas properties,
including acquisitions, and cash flow expenditures is the timing of payments and
the issuances of shares of common stock to fund certain acquisitions.
For the year ended December 31, 2019, our net cash used in investing activities
was approximately $2.0 billion, which consisted primarily of our investment of
approximately $3.1 billion for additions to oil and natural gas properties. This
was partially offset by approximately $1.3 billion of cash proceeds from asset
dispositions primarily due to the New Mexico Shelf divestiture, the sale of Oryx
I and the contribution of certain water infrastructure assets to an entity. We
used the proceeds from these and other divestitures to repay our outstanding
balance under our Credit Facility. Our capital expenditures during the year
ended December 31, 2019 were funded with cash flows from operations and
borrowings under our Credit Facility.
For the year ended December 31, 2018, our net cash used in investing activities
was approximately $2.2 billion, which consisted primarily of our investment of
approximately $2.5 billion for additions to oil and natural gas properties and
$136 million of oil and natural gas property acquisitions, partially offset by
(i) $361 million of proceeds received from the disposition of certain assets and
(ii) a $148 million distribution received from Oryx, one of our equity method
investments. The total distribution from Oryx was $157 million, of which $9
million represented cumulative Oryx earnings and was classified as cash flow
from operating activities, while the remaining amount of $148 million was
classified as cash flow from investing activities. The 2018 expenditures were
primarily funded with cash flows from operations.
Cash flow from financing activities.  For the year ended December 31, 2019, our
net cash used in financing activities was $773 million primarily due to $250
million of common stock repurchases under our share repurchase program, $242
million of net payments under our Credit Facility and $100 million of dividends
paid on our common stock. During the year ended December 31, 2019, we decreased
our book overdrafts by $159 million.
For the year ended December 31, 2018, our net cash used in financing activities
was $342 million. In July 2018, we issued $1.6 billion in aggregate principal
amount of senior unsecured notes and used the net proceeds to redeem and cancel
certain senior unsecured notes assumed in the RSP Acquisition ("RSP Notes"). We
made aggregate payments of approximately $1.2 billion to redeem and cancel the
RSP Notes, including make-whole call premiums of $68 million. We also paid
accrued interest of $14 million on the RSP Notes. The remaining proceeds, along
with borrowings under our Credit Facility, were used to repay the $540 million
of outstanding principal under RSP's revolving credit facility, including $1
million in accrued interest. We also made net payments of $80 million on our
Credit Facility during 2018.
In September 2017, we elected to enter into an Investment Grade Period under our
Credit Facility, which had the effect of releasing all collateral formerly
securing our Credit Facility. If the Investment Grade Period under our Credit
Facility terminates (whether automatically or by our election), our Credit
Facility will once again be secured by a first lien on substantially all of our
oil and natural gas properties and by a pledge of the equity interests in our
subsidiaries. At December 31, 2019, we had unused commitments under our Credit
Facility of $2.0 billion.
Advances on our Credit Facility bear interest, at our option, based on:
(i) an alternative base rate, which is equal to the highest of



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(a) the prime rate of JPMorgan Chase Bank (4.8 percent at December 31, 2019),

(b) the federal funds effective rate plus 0.5 percent, and

(c) the LIBOR plus 1.0 percent; or

(ii) LIBOR.




Our Credit Facility's interest rates and commitment fees on the unused portion
of the available commitment vary depending on our credit ratings from Moody's
and S&P. At our current credit ratings, LIBOR Rate Loans and Alternate Base Rate
Loans bear interest margins of 150 basis points and 50 basis points per annum,
respectively, and commitment fees on the unused portion of the available
commitment are 25 basis points per annum.
In conducting our business, we may utilize various financing sources, including
the issuance of (i) fixed and floating rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock and (v) other securities. Historically,
we have demonstrated our use of the capital markets by issuing common stock and
senior unsecured debt. There are no assurances that we can access the capital
markets to obtain additional funding, if needed, and at cost and terms that are
favorable to us. We may also sell assets and issue securities in exchange for
oil and natural gas assets or interests in energy companies. Additional
securities may be of a class senior to common stock with respect to such matters
as dividends and liquidation rights and may also have other rights and
preferences as determined from time to time. Utilization of some of these
financing sources may require approval from the lenders under our Credit
Facility.
Liquidity. Our principal source of liquidity is the available borrowing capacity
under our Credit Facility. At December 31, 2019, our commitments from our bank
group totaled $2.0 billion, all of which was unused.
Debt ratings.  We receive debt credit ratings from S&P, Moody's and Fitch and
are designated as investment grade with all three agencies. In determining our
ratings, the agencies perform regular reviews and consider a number of
qualitative and quantitative factors including, but not limited to, the industry
in which we operate, production growth opportunities, liquidity, debt levels and
asset and reserve mix.
A downgrade in our credit ratings could (i) negatively impact our costs of
capital and our ability to effectively execute aspects of our strategy, (ii)
affect our ability to raise debt in the public debt markets, and the cost of any
new debt could be much higher than our outstanding debt and (iii) negatively
affect our ability to obtain additional financing or the interest rate, fees and
other terms associated with such additional financing. Further, if we are unable
to maintain credit ratings of "Ba2" or better from Moody's and "BB" or better
from S&P, the Investment Grade Period under our Credit Facility will
automatically terminate and cause our Credit Facility to once again be secured
by a first lien on substantially all of our oil and natural gas properties and
by a pledge of the equity interests in our subsidiaries. These and other impacts
of a downgrade in our credit ratings could have a material adverse effect on our
business, financial condition and results of operations.
As of the filing date of this Annual Report on Form 10-K, there have been no
changes to our credit ratings; however, we cannot be assured that our credit
ratings will not be downgraded in the future.
Book capitalization and current ratio.  Our net book capitalization at
December 31, 2019 was $21.8 billion, consisting of cash and cash equivalents of
$70 million, debt of $4.0 billion and stockholders' equity of $17.8 billion. Our
net book capitalization at December 31, 2018 was $23.0 billion, consisting of
debt of $4.2 billion and stockholders' equity of $18.8 billion. Our ratio of net
debt to net book capitalization was 18 percent and 18 percent at December 31,
2019 and 2018, respectively. Our ratio of current assets to current liabilities
was 0.89 to 1.0 at December 31, 2019 as compared to 1.04 to 1.0 at December 31,
2018.
Inflation and changes in prices. Our revenues, the value of our assets and our
ability to obtain bank financing or additional capital on attractive terms have
been and will continue to be affected by changes in commodity prices and the
costs to produce our reserves. Commodity prices are subject to significant
fluctuations that we are unable to control or predict. During the year ended
December 31, 2019, we received an average of $54.03 per barrel of oil and $1.74
per Mcf of natural gas before consideration of commodity derivative contracts
compared to $56.22 and $48.13 per barrel of oil and $3.40 and $3.07 per Mcf of
natural gas in the years ended December 31, 2018 and 2017, respectively.
Although certain of our costs are affected by general inflation, inflation does
not normally have a significant effect on our business.

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Critical Accounting Policies, Practices and Estimates
Our historical consolidated financial statements and related notes to
consolidated financial statements contain information that is pertinent to our
management's discussion and analysis of financial condition and results of
operations. Preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires that our management
make estimates, judgments and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses, and the disclosure of contingent
assets and liabilities. However, the accounting principles used by us generally
do not change our reported cash flows or liquidity. Interpretation of the
existing rules must be done and judgments made on how the specifics of a given
rule apply to us.
In management's opinion, the more significant reporting areas impacted by
management's judgments and estimates are the choice of accounting method for oil
and natural gas activities, oil and natural gas reserve estimation, asset
retirement obligations, impairments of long-lived assets, valuation of
stock-based compensation, valuation of business combinations, accounting and
valuation of nonmonetary transactions, impairments of goodwill, litigation and
environmental contingencies, valuation of financial derivative instruments,
uncertain tax positions and income taxes. Management's judgments and estimates
in these areas are based on information available from both internal and
external sources, including engineers, geologists and historical experience in
similar matters. Actual results could differ from the estimates as additional
information becomes known.
Successful Efforts Method of Accounting
We utilize the successful efforts method of accounting for our oil and natural
gas exploration and development activities. Under this method, exploration
expenses, including geological and geophysical costs, lease rentals and
exploratory dry holes, are charged against income as incurred. Costs of
successful wells and related production equipment, undeveloped leases and
developmental dry holes are capitalized. Exploratory drilling costs are
initially capitalized, but are charged to expense if and when a well is
determined not to have found proved reserves. Generally, a gain or loss is
recognized when producing fields are sold. This accounting method may yield
significantly different results than the full cost method of accounting.
The application of the successful efforts method of accounting requires
management's judgment to determine the proper designation of wells as either
developmental or exploratory, which will ultimately determine the proper
accounting treatment of costs of dry holes. Once a well is drilled, the
determination that proved reserves have been discovered may take considerable
time, and requires both judgment and application of industry experience. The
evaluation of oil and natural gas leasehold acquisition costs included in
unproved properties requires management's judgment to estimate the fair value of
such properties. Drilling activities in an area by other companies may also
effectively impair our leasehold positions.
Depletion of capitalized drilling and development costs of oil and natural gas
properties is computed using the unit-of-production method on total estimated
proved developed oil and natural gas reserves. Depletion of producing leaseholds
is based on the unit-of-production method using our total estimated proved
reserves. In arriving at rates under the unit-of-production method, the
quantities of recoverable oil and natural gas are established based on estimates
made by our geologists and engineers and independent engineers. Service
properties, equipment and other assets are depreciated using the straight-line
method over estimated useful lives of two to 39 years.
Oil and Natural Gas Reserves and Standardized Measure of Discounted Net Future
Cash Flows
This report presents estimates of our proved reserves as of December 31, 2019,
which have been prepared and presented in accordance with SEC guidelines. The
pricing that was used for estimates of our reserves as of December 31, 2019 was
based on the 12-month unweighted average of the first-day-of-the-month WTI
posted price of $52.19 per Bbl for oil and Henry Hub spot natural gas price of
$2.58 per MMBtu for natural gas.
Our independent engineers and technical staff prepare the estimates of our oil
and natural gas reserves and associated future net cash flows. Even though our
independent engineers and technical staff are knowledgeable and follow
authoritative guidelines for estimating reserves, they must make a number of
subjective assumptions based on professional judgments in developing the reserve
estimates. Reserve estimates are updated at least annually and consider recent
production levels and other technical information about each field. Periodic
revisions to the estimated reserves and future net cash flows may be necessary
as a result of a number of factors, including reservoir performance, new
drilling, oil and natural gas prices, cost changes, technological advances, new
geological or geophysical data, or other economic factors. We cannot predict the
amounts or timing of future reserve revisions. If such revisions are
significant, they could significantly alter future depletion and result in
impairment of long-lived assets that may be material.
It should not be assumed that the Standardized Measure included in this report
as of December 31, 2019 is the current market value of our estimated proved
reserves. In accordance with SEC requirements, we based the 2019 Standardized
Measure on the 12-month unweighted average of the first-day-of-the-month pricing
for oil and natural gas and prevailing costs on the date of the estimate. Actual
future prices and costs may be materially higher or lower than the prices and
costs utilized in the estimate. See "Item 1A. Risk Factors" and "Item 2.
Properties" for additional information regarding estimates of proved reserves.
Our estimates of proved reserves materially impact depletion expense. If the
estimates of proved reserves decline, the rate at which we record depletion
expense will increase, reducing future earnings. Such a decline may result from
lower commodity prices,

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which may make it uneconomical to drill for and produce higher cost fields. In
addition, a decline in proved reserve estimates may impact the outcome of our
assessment of our proved properties for impairment.
Asset Retirement Obligations
There are legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and the normal
operation of a long-lived asset. The primary impact of this relates to oil and
natural gas wells on which we have a legal obligation to plug and abandon. We
record the fair value of a liability for an asset retirement obligation in the
period in which it is incurred and, generally, a corresponding increase in the
carrying amount of the related long-lived asset. The determination of the fair
value of the liability requires us to make numerous judgments and estimates,
including judgments and estimates related to future costs to plug and abandon
wells, future inflation rates and estimated lives of the related assets. When
the judgments used to estimate the initial fair value of the asset retirement
obligation change, an adjustment is recorded to both the obligation and the
carrying amount of the related long-lived asset. Historically, there have been
no significant revisions to our initial estimates once future results became
known. See Note 6 of the Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional information
regarding our asset retirement obligations.
Impairment of Long-Lived Assets
All of our long-lived assets are monitored for potential impairment when
circumstances indicate that the carrying value of an asset may be greater than
management's estimates of its future net cash flows, including cash flows from
proved reserves, risk-adjusted probable and possible reserves, and integrated
assets. If the carrying value of the long-lived assets exceeds the sum of
estimated undiscounted future net cash flows, an impairment loss is recognized
for the difference between the estimated fair value and the carrying value of
the assets. The evaluations involve a significant amount of judgment since the
results are based on estimated future events, such as future sales prices for
oil and natural gas, future costs to produce these products, estimates of future
oil and natural gas reserves to be recovered and the timing thereof, the
economic and regulatory climates, cash flows from integrated assets and other
factors. The need to test an asset for impairment may result from significant
declines in sales prices or downward revisions in estimated quantities of oil
and natural gas reserves. Any assets held for sale are reviewed for impairment
when we approve the plan to sell. Estimates of anticipated sales prices are
highly judgmental and subject to material revision in future periods. At
December 31, 2019, our estimates of commodity prices for purposes of determining
undiscounted future cash flows, which are based on the NYMEX strip, ranged from
a 2020 price of $58.83 per barrel of oil decreasing to a 2023 price of $51.31
per barrel of oil then rising to a 2026 price of $52.57 per barrel of oil.
Natural gas prices ranged from a 2020 price of $2.29 per Mcf of natural gas
increasing to a 2026 price of $2.55 per Mcf of natural gas. Both oil and natural
gas commodity prices for this purpose were held flat after 2026.
Unproved oil and natural gas properties are periodically assessed for impairment
by considering future drilling and exploration plans, results of exploration
activities, commodity price outlooks, planned future sales and expiration of all
or a portion of the projects. During the years ended December 31, 2019, 2018 and
2017, we recognized expense of approximately $147 million, $35 million and $27
million, respectively, related to abandoned and expiring acreage, which is
included in exploration and abandonments expense in the accompanying
consolidated statements of operations.
Valuation of Stock-Based Compensation
In accordance with GAAP, we calculate the fair value of stock-based compensation
using various valuation methods. The valuation methods require the use of
estimates to derive the inputs necessary to determine fair value. We utilize
(i) the average of the high and low stock price on the date of grant for the
fair value of restricted stock awards and (ii) the Monte Carlo simulation method
for the fair value of performance unit awards. The significant assumptions used
in these models include expected volatility, expected term, risk-free interest
rate, forfeiture rate, dividends, and the probability of meeting performance
targets. Each of these valuation methods were chosen as management believes they
give the best estimate of fair value for the respective stock-based awards. See
Note 7 of the Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for more information regarding our
stock-based compensation.
Valuation of Business Combinations
In connection with a purchase business combination, the acquiring company must
record assets acquired and liabilities assumed based on fair values as of the
acquisition date. Deferred taxes must be recorded for any differences between
the assigned values and tax bases of assets and liabilities. Any excess of
purchase price over amounts assigned to assets and liabilities is recorded as
goodwill. The amount of goodwill recorded in any particular business combination
can vary significantly depending upon the value attributed to assets acquired
and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed, we
make various assumptions. The most significant assumptions related to the
estimated fair values assigned to proved and unproved oil and natural gas
properties and integrated assets. To estimate the fair values of these
properties, we utilize estimates of oil and natural gas reserves. We make future
price assumptions to apply to the estimated reserves quantities acquired and
estimate future operating and development costs to arrive at estimates of future
net cash flows. For estimated proved reserves, the future net cash flows are
discounted using a market-based weighted average cost of capital rate determined
appropriate at the time of the acquisition. The market-based weighted average
cost of capital rate is subject to additional project-specific risking factors.
To estimate the fair value of unproved properties, we apply

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risk-weighting factors of the future net cash flows of unproved reserves, or we
may evaluate acreage values through recent market transactions in the area.
Estimated fair values assigned to assets acquired can have a significant effect
on results of operations in the future. A higher fair value assigned to a
property results in a higher depletion expense, which results in lower net
earnings. Fair values are based on estimates of future commodity prices,
reserves quantities, operating expenses and development costs. This increases
the likelihood of impairment if future commodity prices or reserves quantities
are lower than those originally used to determine fair value or if future
operating expenses or development costs are higher than those originally used to
determine fair value. Impairment would have no effect on cash flows but would
result in a decrease in net income for the period in which the impairment is
recorded. Historically, we have had no material revisions to valuations of
business combinations once the valuation estimate was finalized.
Accounting and Valuation of Nonmonetary Transactions
In connection with nonmonetary transactions, which include exchanges of
producing and non-producing assets, we must evaluate the transaction to
determine appropriate accounting treatment. In general, the basic principle of
accounting for nonmonetary transactions is based on the fair values involved,
which is the same basis used in monetary transactions and results in the
recognition of gains and losses. However, certain nonmonetary transactions meet
criteria that require modification of the basic principle that necessitate
recording values based on historical book value. We determine the treatment of
nonmonetary transactions based on the individual facts and circumstances of each
transaction. In cases where nonmonetary transactions are recorded at fair value,
we make various assumptions. The most significant assumptions are related to the
estimated fair values assigned to proved and unproved oil and natural gas
properties, similar to our valuation of the fair value of oil and natural gas
assets acquired during a business combination described above. Any resulting
difference between the fair value of the assets involved and their carrying
value is recorded as a gain or loss in the consolidated statement of operations.
Estimated fair values assigned to assets exchanged can have a significant effect
on our results of operations in the future. If future commodity prices or
reserves quantities are lower than those originally used to determine fair value
or if future operating expenses or development costs are higher than those
originally used to determine fair value, we would record an impairment loss for
the amount by which the carrying amount of the asset exceeds the estimated fair
value. Impairment would have no effect on cash flows but would result in a
decrease in net income for the period in which the impairment is recorded.
Impairments of Goodwill
Goodwill is assessed for impairment on an annual basis, or more frequently if
indicators of impairment exist. Impairment tests, which involve the use of
estimates related to the fair market value of the business operations with which
goodwill is associated, is performed as of July 1 of each year. As we operate as
a single operating segment and a single reporting unit, we evaluate goodwill for
impairment based on an evaluation of the fair value of the company as a whole.
The fair value of the reporting unit is our enterprise value (combined market
capitalization of our equity plus a control premium, and the fair value of our
long-term debt). There are multiple valuation methodologies available to us in
determining the fair values; however, given that we are one reporting unit, we
use quoted market prices in active markets as the basis for our measurement as
we believe they are the best evidence of fair value. There is considerable
judgment involved in estimating fair values, particularly in determining the
control premium. To establish a reasonable control premium, we consider the
premiums paid in recent market acquisitions and analyze current industry, market
and economic conditions along with other factors or available information
specific to our business. Deteriorating industry, market and economic conditions
could negatively impact our control premium and our enterprise value, which
could lead to an impairment of our goodwill balance.
As discussed in Note 5 of the Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data," in August
2019, we entered into a definitive agreement to sell our assets in the New
Mexico Shelf. We classified these assets as held for sale at August 29, 2019. We
allocated $81 million of goodwill to this disposal group, all of which we
impaired. In addition, we performed an impairment test at September 30, 2019 due
to declines in our market capitalization and at December 31, 2019 due to
declines in observed control premiums. The fair value of the reporting unit at
September 30, 2019 exceeded the carrying value of our net assets. However,
during the fourth quarter of 2019, our fair value declined further resulting in
a $201 million goodwill impairment charge at December 31, 2019.
It is reasonably possible that the estimates of our enterprise value may change
in the future and result in the need to impair goodwill. Currently, the primary
factors that may negatively affect our enterprise value are the continued
depressed level of our stock price and estimated control premium we use in the
fair value of our reporting unit. We use an average stock price over a
determined period to estimate the fair value of our reporting unit, which we
believe removes the impact of short-term market fluctuations. We used an average
stock price of $72.23 in determining our market capitalization at December 31,
2019. In addition, our control premium is based on the estimated median control
premium of transactions involving companies in our industry. Further declines in
our average stock price and/or in our estimated control premium could result in
additional impairments of goodwill. Many factors affecting our stock price are
beyond our control and we cannot predict their potential effects on the price of
our common stock. In addition, stock markets in general can experience
considerable price and volume fluctuations. Other assumptions such as the
control premium and the value of our long-term debt will likely change in the
future, and these and other assumptions may worsen or partially mitigate some of
the effects of a reduction in our average stock price. As a result, we are
unable to predict with certainty whether or not a decline in our stock price
alone will or will not cause us to recognize an impairment charge or the
magnitude of such impairment charge.

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See Notes 2 and 4 of the Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for more information
regarding goodwill.
Litigation and Environmental Contingencies
We make judgments and estimates in recording liabilities for ongoing litigation
and environmental remediation. Actual costs can vary from such estimates for a
variety of reasons. The costs to settle litigation can vary from estimates based
on differing interpretations of laws and opinions and assessments on the amount
of damages. Similarly, environmental remediation liabilities are subject to
change because of changes in laws and regulations, developing information
relating to the extent and nature of site contamination and improvements in
technology. A liability is recorded for these types of contingencies if we
determine the loss to be both probable and reasonably estimable. If we are
unable to reasonably estimate an amount but we are able to estimate a range of
reasonably possible amounts, then the low end of the range is recorded. See
Notes 2 and 11 of the Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for more information
regarding our commitments and contingencies.
Valuation of Financial Derivatives
In order to reduce commodity price uncertainty and increase cash flow
predictability relating to the marketing of our oil and natural gas, we enter
into commodity price hedging arrangements with respect to a portion of our
expected production. In addition, we have used derivative instruments in
connection with acquisitions and certain price-sensitive projects. Management
exercises significant judgment in determining the types of instruments to be
used, production volumes to be hedged, prices at which to hedge and the
counterparties' creditworthiness. All derivative instruments are reflected at
fair value in our consolidated balance sheets.
Our open commodity derivative instruments were in a net liability position with
a fair value of $102 million at December 31, 2019. In order to determine the
fair value at the end of each reporting period, we compute discounted cash flows
for the duration of each commodity derivative instrument using the terms of the
related contract. Inputs consist of published forward commodity price curves as
of the date of the estimate. We compare these prices to the price parameters
contained in our hedge contracts to determine estimated future cash inflows or
outflows. We then discount the cash inflows or outflows using a combination of
published LIBOR rates and Eurodollar futures rates. The fair values of our
commodity derivative assets and liabilities include a measure of credit risk
based on average published yields by credit rating.
Changes in the fair values of our commodity derivative instruments have a
significant impact on our net income because we follow mark-to-market accounting
and recognize all gains and losses on such instruments in earnings in the period
in which they occur. For the year ended December 31, 2019, we reported a $895
million loss on commodity derivative instruments.
We compare our estimates of the fair values of our commodity derivative
instruments with those provided by our counterparties. There have been no
significant differences.
Income Taxes
On December 22, 2017, the President of the United States signed the TCJA into
law, which enacted significant changes to the federal income tax laws. According
to ASC 740, "Income Taxes," a company is required to record the effects of an
enacted tax law or rate change in the period of enactment. Based on the
comprehensiveness of TCJA and the challenges faced by calendar year-end
registrants to complete the accounting for the income tax effects of the TCJA in
the period of enactment, the SEC issued SAB 118 "Income Tax Accounting
Implications of the Tax Cuts and Jobs Act," which allowed companies to report
provisional amounts when based on reasonable estimates and to adjust these
amounts during a measurement period of up to one year.
We elected to apply SAB 118 and recorded provisional amounts of our income tax
balances in our consolidated financial statements at December 31, 2017. We
calculated our best estimate of the impact of the TCJA, including the federal
statutory tax rate change noted below, in our 2017 income tax provision in
accordance with our understanding of the TCJA and recorded a $398 million
decrease to our income tax provision at December 31, 2017. The provisional
amount related to the re-measurement of certain deferred tax assets and
liabilities based on the rates at which they are expected to reverse in the
future. At December 31, 2018, the Company completed its accounting for all of
the enactment-date tax effects of the TCJA and recognized an adjustment of $7
million to the provisional amount recorded at December 31, 2017. This adjustment
was primarily related to the deductibility of certain performance-based
compensation based on additional available regulatory and interpretive guidance.
On July 19, 2018, we completed the RSP Acquisition. For federal income tax
purposes, the transaction qualified as a tax-free merger whereby we acquired
carryover tax basis in RSP's assets and liabilities. As of December 31, 2018, we
recorded an opening balance sheet deferred tax liability of $515 million based
on our assessment of the carryover tax basis, which includes a deferred tax
asset related to tax attributes acquired from RSP. The acquired income tax
attributes primarily consist of NOLs and research and development credits that
are subject to an annual limitation under Internal Revenue Code Section 382. The
Company expects that these tax attributes will be fully utilized prior to
expiration.
Our provision for income taxes includes both federal and state taxes of the
jurisdictions in which we operate. We estimate our overall tax rate using a
combination of the enacted federal statutory tax rate, which decreased from 35
percent to 21 percent effective

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January 1, 2018 as a result of the TCJA, and a blend of enacted state tax rates.
Acquisitions or dispositions of assets and changes in our drilling plan by tax
jurisdiction could change the apportionment of our state taxes, which would
impact our overall tax rate.
We recognize the tax benefit from an uncertain tax position only if it is more
likely than not that the tax position will be sustained upon examination by the
taxing authorities, based upon the technical merits of the position. If all or a
portion of the unrecognized tax benefit is sustained upon examination by the
taxing authorities, the tax benefit will be recognized as a reduction to our
deferred tax liability and will affect our effective tax rate in the period it
is recognized. The assessment of potential uncertain tax positions requires a
significant amount of judgment and are reviewed and adjusted on a periodic
basis.
Our federal and state income tax returns are not prepared or filed before the
consolidated financial statements are prepared; therefore, we estimate the tax
basis of our assets and liabilities and tax attributes, which are based on
numerous judgments and assumptions inherent in the determination of taxable
income, at the end of each period. Adjustments related to these estimates are
recorded in our tax provision in the period in which we finalize our income tax
returns. Historically, we have had no significant changes as a result of filing
our tax returns. Material changes to our tax accruals and uncertain tax
positions may occur in the future based on audits, changes in legislation or
resolution of pending matters.
See Note 12 of the Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional information
regarding our current year income tax benefit, deferred tax balances and
uncertain tax positions.
New accounting pronouncements issued but not yet adopted. See Note 2 of the
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for information regarding new accounting
pronouncements issued but not yet adopted.

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