Executive Overview
  Outlook
  Operations
  Market Conditions
  Results of Operations
  Critical Accounting Estimates
  Accounting Standards Not Yet Adopted
  Cash Flows
  Liquidity and Capital Resources
  Environmental Matters and Other Contingencies
The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with the preceding consolidated
financial statements and notes in   Item 1  .
Executive Overview
We are an independent exploration and production company based in Houston,
Texas. Our strategy is to deliver competitive and improving corporate level
returns by focusing our capital investment in the lower cost, higher margin U.S.
resource plays (the Eagle Ford in Texas, the Bakken in North Dakota, STACK and
SCOOP in Oklahoma and Northern Delaware in New Mexico).
  Commodity prices experienced significant volatility and declined substantially
in the first half of 2020. While commodity prices improved during the third
quarter as compared to the second quarter of 2020, they are likely to remain
lower and volatile for the foreseeable future. We believe we can manage through
this lower commodity price macro environment as our portfolio affords us the
flexibility to respond to changing market conditions. Our primary focus remains
on protecting our balance sheet and maintaining a strong liquidity position. We
believe our financial strength, quality portfolio, and ongoing focus on reducing
our cost structure better position us to navigate during this unprecedented
time.
The risks associated with COVID-19 impacted our workforce and the way we meet
our business objectives. Due to concerns over health and safety, the vast
majority of our corporate workforce works remotely as we plan a process for a
phased return of employees to the office. Working remotely has not significantly
impacted our ability to maintain operations, has allowed our field offices to
operate without any disruption, and has not caused us to incur significant
additional expenses; however, we are unable to predict the duration or ultimate
impact of these measures.

Key highlights include the following:
Maintained focus on balance sheet and liquidity
•At the end of the third quarter 2020, we had approximately $4.1 billion of
liquidity, comprised of an undrawn $3.0 billion revolving credit facility and
$1.1 billion in cash. We remain investment grade at all three primary rating
agencies.
•In August, we closed on the remarketing of $400 million sub-series B bonds. On
October 1, 2020, we completed a cash tender for an aggregate principal amount of
$500 million of our outstanding $1 billion 2.8% 2022 Notes. The tender was
funded from cash on hand, resulting in a gross debt reduction of $100 million
from the second quarter of 2020.
•The September 30, 2020 cash balance reflects an increase of approximately $261
million from year-end, primarily due to the remarketing of $400 million of
sub-series B bonds, partially offset by repurchases of common stock and dividend
payments made during the first quarter. Our cash provided from operations was
commensurate with our capital expenditures for the nine months ended September
30, 2020.
•In early July 2020, we collected an $89 million cash refund related to
alternative minimum tax credits and associated interest.
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•On October 1, the Board of Directors approved and declared the reinstatement of
the base quarterly dividend of $0.03 per share, effective in the fourth quarter
of 2020. Our share repurchase program remains suspended as we continue to
maximize liquidity.
•Continued our capital discipline to be within our Capital Budget of $1.2
billion.
•Continued to opportunistically execute additional commodity derivatives to
minimize the risk of price fluctuations.

Financial and operational results
•U.S. net sales volumes decreased by 12% to 297 mboed, including a 21% reduction
in U.S. crude oil net sales volumes compared to the same quarter last year as a
result of overall lower wells to sales activity driven by the lower drilling and
completions activity.
•Our net loss per share was $0.40 in the third quarter of 2020 as compared to
net income per share of $0.21 in the same period last year. Included in our
financial results for the current quarter:
•Revenues from contracts with customers decreased $488 million compared to the
same quarter last year, largely due to lower price realizations and decreased
production volumes. Average crude oil price realizations decreased by 37% during
the third quarter of 2020 as compared to the third quarter of 2019.
•Net loss on commodity derivatives of $1 million for the third quarter of 2020,
a $48 million decrease from the same period in 2019, which was a net gain of $47
million.
•A non-cash impairment of an investment in one of our equity method investees of
$18 million.
•Net cash provided by operating activities in the first nine months of 2020
decreased to $1.1 billion or 49% primarily as a result of lower commodity price
realizations and decreased production volumes, compared to the first nine months
of 2019. As described in the preceding section, we reduced our Capital Budget
such that Capital Budget expenditures are closely aligned with cash generated by
operations over the duration of the year.
Outlook
Capital Budget
  Earlier this year, we announced an approved 2020 Capital Budget of $2.4
billion, including $200 million to fund resource play leasing and exploration
("REx"). In light of the substantial decline in commodity prices and oversupply
in the market, our Board of Directors approved a reduction to our Capital Budget
earlier in the year to a level of $1.3 billion. Due to strong execution and
capital efficiency improvement, in August we further reduced our full year 2020
capital spending budget to $1.2 billion. This revised Capital Budget represents
a 50% reduction of our original budget. The revised budget contemplates a full
suspension of our Oklahoma activity in 2020, a decrease in Northern Delaware
drilling activity, and a continued optimization of our development plans in the
Bakken and Eagle Ford. This also completes our REx drilling program for 2020.
Additional adjustments to capital spending plans may be necessary in the future
to respond to the shifts in the macro environment.

Commensurate with our budget of $1.2 billion for 2020, we believe our full year production volumes will be between 375 mboed to 390 mboed. Operations


  The following table presents a summary of our sales volumes for each of our
segments. Refer to the Results of Operations section for a price-volume analysis
for each of the segments.
                                                        Three Months Ended September 30,                                   Nine Months Ended September 30,
                                                                                         Increase                                                           Increase
Net Sales Volumes                               2020                 2019               (Decrease)                 2020                 2019               (Decrease)
United States (mboed)                                297                  339                   (12) %                  314                  322                    (2) %
International (mboed)(a)                              71                   88                   (19) %                   79                   94                   (16) %
Total (mboed)                                        368                  427                   (14) %                  393                  416                    (6) %


(a)We closed on the sale of our U.K. business in the third quarter of 2019. The
nine months ended September 30, 2019 includes net sales volumes related to the
U.K. of 7 mboed. See   Note 4   to the consolidated financial statements for
further information.
United States
  Net sales volumes in the segment were lower in the third quarter of 2020 and
the first nine months of 2020 as compared to their respective 2019 periods. In
the second quarter of 2020, we began the process of transitioning to a
significantly lower level
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of drilling and completion activity across our domestic portfolio. As a result
of the decreased drilling and completion activity, fewer wells were brought to
sales resulting in a significant decline in production in the third quarter of
2020.

We continue to expect that our planned pace of drilling and completions activity
during the remainder of the year will enable us to meet our 2020 production
guidance as noted in the preceding Outlook section. The following tables provide
additional details regarding net sales volumes, sales mix and operational
drilling activity for our significant operations within this segment:
                                                    Three Months Ended September 30,                                   Nine Months Ended September 30,
                                                                                     Increase                                                           Increase
Net Sales Volumes                           2020                 2019               (Decrease)                 2020                 2019               (Decrease)
Equivalent Barrels (mboed)
Eagle Ford                                        91               107                      (15) %                  104               107                       (3) %
Bakken                                            98               109                      (10) %                  103               101                        2  %
Oklahoma                                          73                84                      (13) %                   69                77                      (10) %
Northern Delaware                                 27                30                      (10) %                   29                28                        4  %
Other United States                                8                 9                      (11) %                    9                 9                        -  %
Total United States                              297               339                      (12) %                  314               322                       (2) %


                                                                     Three Months Ended September 30, 2020
Sales Mix - U.S. Resource Plays      Eagle Ford             Bakken                Oklahoma            Northern Delaware           Total
Crude oil and condensate                    58  %                 71  %                   25  %                   55  %                54  %
Natural gas liquids                         21  %                 16  %                   34  %                   20  %                23  %
Natural gas                                 21  %                 13  %                   41  %                   25  %                23  %


                                                 Three Months Ended September 30,                         Nine Months Ended September 30,
Drilling Activity - U.S. Resource Plays         2020                            2019                    2020                            2019
Gross Operated
Eagle Ford:
Wells drilled to total depth                       17                                31                    58                                97
Wells brought to sales                              9                                35                    67                               117

Bakken:


Wells drilled to total depth                        6                                20                    41                                52
Wells brought to sales                              8                                30                    41                                89

Oklahoma:


Wells drilled to total depth                        -                                15                     9                                53
Wells brought to sales                              -                                19                    13                                55
Northern Delaware:
Wells drilled to total depth                        -                                10                    15                                37
Wells brought to sales                              1                                10                    13                                41


•Eagle Ford - Our net sales volumes were 91 mboed in the third quarter of 2020,
including oil sales of 53 mbbld and we brought 9 gross company-operated wells to
sales. Given the market conditions in the second quarter, we suspended frac
activities. In the third quarter of 2020, we restarted our drilling program with
2 rigs and 1 frac crew which we expect to continue for the remainder of the
year.
•Bakken - Our net sales volumes were 98 mboed, including 69 mbbld of oil sales
and we brought 8 gross company-operated wells to sales. We suspended frac
activity in the second quarter. In the third quarter of 2020, we resumed
completions activities. We plan to average 2 rigs and 1 frac crew for the
remainder of the year.
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•Oklahoma - Our net sales volumes were 73 mboed, including 18 mbbld of oil
sales. During the second quarter, we suspended all drilling and completions
operations in Oklahoma; we do not plan to drill any additional wells in Oklahoma
during 2020.
•Northern Delaware - Our net sales volumes were 27 mboed, including 15 mbbld of
oil sales and we brought 1 gross company-operated well to sales. We suspended
all drilling and completions operations during the second quarter and expect to
bring only a limited number of wells to sales during the remainder of the year.

International


  Net sales volumes were lower in the third quarter of 2020 compared to the
third quarter of 2019 primarily due to timing of E.G. liftings. The following
table provides details regarding net sales volumes for our operations within
this segment:
                                                    Three Months Ended September 30,                                     Nine Months Ended September 30,
                                                                                      Increase                                                             Increase
Net Sales Volumes                          2020                  2019                (Decrease)                 2020                  2019                (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea                                71                  88                      (19) %                   79                  86                       (8) %
United Kingdom(a)                                 -                   -                        -  %                    -                   7                     (100) %
Other International                               -                   -                        -  %                    -                   1                     (100) %
Total International                              71                  88                      (19) %                   79                  94                      (16) %
Equity Method Investees
LNG (mtd)                                     3,960               4,590                      (14) %                4,551               4,849                       (6) %
Methanol (mtd)                                1,065               1,036                        3  %                  996               1,058                       (6) %
Condensate and LPG (boed)                     9,340              11,586                      (19) %               10,288              10,858                       (5) %

(a)Includes natural gas acquired for injection and subsequent resale.

•Equatorial Guinea - Net sales volumes in the third quarter of 2020 were lower compared to the same period in 2019 primarily due to timing of liftings. •United Kingdom - In July 2019, we closed on the sale of our U.K. business. See

Note 4 to the consolidated financial statements for further information.


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Market Conditions
Commodity prices are the most significant factor impacting our revenues,
profitability, operating cash flows, the amount of capital we invest in our
business, payment of dividends and funding of share repurchases. Commodity
prices declined substantially in the first half of 2020 resulting from demand
contraction related to the global pandemic and increased supply following the
OPEC decision to increase production. A revised OPEC deal to reduce production
was agreed early in the second quarter of 2020 and oil prices partially
recovered in the latter part of the second quarter. Prices continued to increase
in the third quarter; however, pricing remains lower relative to 2019 and given
the scale of worldwide demand contraction, we expect commodity prices to remain
volatile. Refer to Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K
for further discussion on how further declines in commodity prices could impact
us.
United States

The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for the third quarter and first nine months of 2020 and 2019.


                                                 Three Months Ended September 30,                             Nine Months Ended September 30,
                                                                               Increase                                                     Increase
                                          2020              2019              (Decrease)               2020              2019              (Decrease)
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b) $   37.78          $ 55.09                      (31) %       $   34.82          $ 56.14                      (38) %
Natural gas liquids (per bbl)             11.80            11.37                        4  %            9.77            13.81                      (29) %
Natural gas (per mcf)(c)                   1.78             1.92                       (7) %            1.61             2.20                      (27) %
Benchmarks
WTI crude oil average of daily prices
(per bbl)                             $   40.92          $ 56.44                      (27) %       $   38.21          $ 57.10                      (33) %
Magellan East Houston ("MEH") crude
oil average of daily prices (per bbl)     41.59            61.06                      (32) %           38.93            62.60                      (38) %
Mont Belvieu NGLs (per bbl)(d)            15.87            15.16                        5  %           13.77            18.14                      (24) %
Henry Hub natural gas settlement date
average (per mmbtu)                        1.98             2.23                      (11) %            1.88             2.67                      (30) %


(a)Excludes gains or losses on commodity derivative instruments.
(b)Inclusion of realized gains (losses) on crude oil derivative instruments
would have increased average price realizations by $2.24 per bbl and $0.72 per
bbl for the third quarter 2020 and 2019, respectively, and $1.74 per bbl and
$0.70 per bbl for the first nine months of 2020 and 2019, respectively.
(c)Inclusion of realized gains (losses) on natural gas derivative instruments
would have a minimal impact on average price realizations for the periods
presented.
(d)Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane,
8% isobutane and 7% natural gasoline.
Crude oil and condensate - Price realizations may differ from benchmarks due to
the quality and location of the product.
Natural gas liquids - The majority of our sales volumes are sold at reference to
Mont Belvieu prices.
Natural gas - A significant portion of our volumes are sold at bid-week prices,
or first-of-month indices relative to our producing areas.
International
The following table presents our average price realizations and the related
benchmark for crude oil for the third quarter and first nine months of 2020 and
2019.
                                             Three Months Ended September 30,                             Nine Months Ended September 30,
                                                                           Increase                                                     Increase
                                      2020              2019              (Decrease)               2020              2019              (Decrease)
Average Price Realizations
Crude oil and condensate (per
bbl)                              $   30.28          $ 46.04                      (34) %       $   26.05          $ 53.98                      (52) %
Natural gas liquids (per bbl)          1.00             1.00                        -  %            1.00             1.53                      (35) %
Natural gas (per mcf)                  0.24             0.24                        -  %            0.24             0.35                      (31) %
Benchmark
Brent (Europe) crude oil (per
bbl)(a)                           $   42.96          $ 61.93                      (31) %       $   40.92          $ 64.67                      (37) %

(a)Average of monthly prices obtained from the United States Energy Information Agency website.


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United Kingdom Crude oil and condensate - Generally sold in relation to the Brent crude benchmark. We closed on the sale of our U.K. business on July 1, 2019.

Equatorial Guinea
Crude oil and condensate - Alba field liquids production is primarily condensate
and generally sold in relation to the Brent crude benchmark. Alba Plant LLC
processes the rich hydrocarbon gas which is supplied by the Alba field under a
fixed price long term contract. Alba Plant LLC extracts NGLs and secondary
condensate which is then sold by Alba Plant LLC at market prices, with our share
of the revenue reflected in income from equity method investments on the
consolidated statements of income. Alba Plant LLC delivers the processed dry
natural gas to the Alba field for distribution and sale to AMPCO and EG LNG.
Natural gas liquids - Wet gas is sold to Alba Plant LLC at a fixed-price term
contract resulting in realized prices not tracking market price. Alba Plant LLC
extracts and keeps NGLs, which are sold at market price, with our share of
income from Alba Plant LLC being reflected in the income from equity method
investments on the consolidated statements of income.
Natural gas - Dry natural gas, processed by Alba Plant LLC on behalf of the Alba
field is sold by the Alba field to EG LNG and AMPCO at fixed-price long term
contracts resulting in realized prices not tracking market price. We derive
additional value from the equity investment in our downstream gas processing
units EG LNG and AMPCO. EG LNG sells LNG on a market-based long-term contract
and AMPCO markets methanol at market prices.
Results of Operations
Three Months Ended September 30, 2020 vs. Three Months Ended September 30, 2019
Revenues from contracts with customers are presented by segment in the table
below:
                                                                      Three Months Ended September 30,
(In millions)                                                            2020                   2019
Revenues from contracts with customers
United States                                                      $          722          $     1,172
International                                                                  39                   77
Segment revenues from contracts with customers                     $        

761 $ 1,249

Below is a price/volume analysis for each segment. Refer to the preceding

Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

Increase (Decrease) Related to


                                              Three Months Ended                                      Net Sales          Three Months Ended
(In millions)                                 September 30, 2019         Price Realizations            Volumes           September 30, 2020
United States Price/Volume Analysis
Crude oil and condensate                    $             1,017          $           (253)         $       (212)         $           552
Natural gas liquids                                          64                         2                     7                       73
Natural gas                                                  81                        (5)                   (7)                      69
Other sales                                                  10                                                                       28
Total                                       $             1,172                                                          $           722
International Price/Volume Analysis
Crude oil and condensate                    $                67          $            (16)         $        (20)         $            31
Natural gas liquids                                           1                         -                     -                        1
Natural gas                                                   8                         -                    (1)                       7
Other sales                                                   1                                                                        -
Total                                       $                77                                                          $            39


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Net gain (loss) on commodity derivatives in the third quarter of 2020, was a
loss of $1 million, compared to a net gain of $47 million for the same period in
2019. We have multiple crude oil, natural gas and NGL derivative contracts that
settle against various indices. We record commodity derivative gains/losses as
the index pricing and forward curves change each period. See   Note 15   to the
consolidated financial statements for further information.
Income from equity method investments decreased $31 million for the third
quarter of 2020 from the comparable 2019 period primarily due to an impairment
of $18 million to an investment in an equity method investee. Lower Alba plant
condensate sales volumes and lower methanol prices at AMPCO methanol facility
also contributed to the decline. See   Note 11   to the consolidated financial
statements for further information on the equity method investee impairment.
Net gain on disposal of assets decreased $21 million in the third quarter of
2020 versus the same period in 2019, primarily as a result of the sale of our
U.K. business during third quarter of 2019. See   Note 4   to the consolidated
financial statements for more detail.
Production expenses decreased $34 million in the third quarter of 2020 versus
the same period in 2019, primarily as a result of the U.S. segment's lower
operational costs and continued cost management, specifically staffing and
contract labor. International segment production expense slightly decreased due
to timing of E.G. liftings.

The following table provides production expense and production expense rates (expense per boe) for each segment:


                                                                      Three Months Ended September 30,
($ in millions; rate in $ per boe)            2020       2019    Increase 

(Decrease) 2020 2019 Increase (Decrease) Production Expense and Rate

                                 Expense                                         Rate
United States                              $    118    $  147                 (20) %       $ 4.32    $ 4.75                  (9) %
International                              $     11    $   16                 (31) %       $ 1.76    $ 1.98                 (11) %


Shipping, handling and other operating expenses increased $45 million in the
third quarter of 2020 primarily due to increased purchased volumes from third
parties of commodities for resale in order to satisfy transportation commitments
and other expenses.
Exploration expenses include unproved property impairments, dry well costs,
geological and geophysical, and other costs, which remained relatively flat in
comparison to the third quarter of 2019.
The following table summarizes the components of exploration expenses:
                                                                          Three Months Ended September 30,
(In millions)                                                    2020                  2019           Increase (Decrease)
Exploration Expenses
Unproved property impairments                             $            23          $      15                         53  %
Dry well costs                                                          -                  1                       (100) %
Geological and geophysical                                              2                  1                        100  %
Other                                                                   2                  5                        (60) %
Total exploration expenses                                $            27          $      22                         23  %


Depreciation, depletion and amortization decreased $68 million in the third
quarter of 2020 as a result of lower sales volumes in our U.S. and International
segments. Our segments apply the units-of-production method to the majority of
their assets, including capitalized asset retirement costs; therefore volumes
have an impact on DD&A expense.
The DD&A rate (expense per boe) is impacted by field-level changes in reserves,
capitalized costs and sales volume mix between fields. The following table
provides DD&A expense and DD&A expense rates for each segment:
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                                                                      Three 

Months Ended September 30,


                                                                         Increase                                       Increase
($ in millions; rate in $ per boe)            2020          2019        (Decrease)              2020       2019        (Decrease)
DD&A Expense and Rate                                      Expense                                             Rate
United States                           $    530         $   589                (10) %       $ 19.39    $ 18.90                  3  %
International                           $     19         $    25                (24) %       $  2.89    $  3.15                 (8) %


Taxes other than income include production, severance and ad valorem taxes,
primarily in the U.S., which tend to increase or decrease in relation to revenue
and sales volumes. Taxes other than income decreased $32 million primarily due
to lower price realizations and lower sales volumes in the U.S. segment in the
third quarter of 2020.
General and administrative expenses decreased $29 million in the third quarter
of 2020 primarily as a result of cost savings realized from workforce
reductions.
Segment Income
Segment income represents income which excludes certain items not allocated to
our operating segments, net of income taxes. A portion of our corporate and
operations general and administrative support costs are not allocated to the
operating segments. These unallocated costs primarily consist of employment
costs (including pension effects), professional services, facilities and other
costs associated with corporate and operations support activities. Additionally,
items which affect comparability such as: gains or losses on dispositions,
impairments of proved property, goodwill and equity method investments,
unrealized gains or losses on commodity and interest rate derivative
instruments, effects of pension settlements and curtailments, or other items (as
determined by the CODM) are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
                                                                          Three Months Ended September 30,
(In millions)                                                     2020               2019           Increase (Decrease)
United States                                                 $     (135)         $    180                      (175) %
International                                                          8                43                       (81) %
Segment income (loss)                                               (127)              223                      (157) %
Items not allocated to segments, net of income taxes                (190)              (58)                     (228) %
Net income (loss)                                             $     (317)         $    165                      (292) %


United States segment income (loss) in the third quarter of 2020, was $135
million loss after-tax versus $180 million income after-tax for the same period
in 2019, primarily due to lower price realizations and sales volumes in the
current quarter, which was partially offset by lower DD&A and production taxes
(due to the lower sales volumes), coupled with cost management efforts to lower
production and G&A expenses.
International segment income in the third quarter of 2020, was $8 million
after-tax versus $43 million after-tax for the same period in 2019, primarily
due to timing of E.G. liftings and lower price realizations resulting in lower
income from equity method investments.
Results of Operations
 Nine Months Ended September 30, 2020 vs. Nine Months Ended September 30, 2019
Revenues from contracts with customers are presented by segment in the table
below:
                                                                          Nine Months Ended
                                                                            September 30,
(In millions)                                                                        2020                 2019
Revenues from contracts with customers
United States                                                                   $     2,154          $     3,434
International                                                                           121                  396
Segment revenues from contracts with customers                              

$ 2,275 $ 3,830


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Below is a price/volume analysis for each segment. Refer to the preceding

Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

Increase (Decrease) Related to


                                             Nine Months Ended                                                                  Nine Months Ended
(In millions)                                September 30, 2019         Price Realizations           Net Sales Volumes          September 30, 2020
United States Price/Volume Analysis
Crude oil and condensate                    $           2,897          $           (1,066)         $              (90)         $           1,741
Natural gas liquids                                       225                         (67)                          3                        161
Natural gas                                               263                         (70)                         (3)                       190
Other sales                                                49                                                                                 62
Total                                       $           3,434                                                                  $           2,154
International Price/Volume Analysis
Crude oil and condensate                    $             341          $             (102)         $             (143)         $              96
Natural gas liquids                                         4                          (1)                          -                          3
Natural gas                                                36                         (10)                         (4)                        22
Other sales                                                15                                                                                  -
Total                                       $             396                                                                  $             121


Net gain (loss) on commodity derivatives in the first nine months of 2020, was a
gain of $131 million, compared to a net loss of $28 million for the same period
in 2019. We have multiple crude oil, natural gas and NGL derivative contracts
that settle against various indices. We record commodity derivative gains/losses
as the index pricing and forward curves change each period. See   Note 15   to
the consolidated financial statements for further information.
Income (loss) from equity method investments decreased $237 million for the
first nine months of 2020 primarily due to impairments of $170 million to an
investment in an equity method investee in the first nine months of 2020 as well
as lower price realizations and lower net sales volumes from equity method
investments in E.G. primarily due to the planned triennial turnaround in the
first quarter of 2020.
Net gain on disposal of assets decreased $48 million for the first nine months
of 2020 primarily as a result of the sale of our working interest in the Droshky
field (Gulf of Mexico) and U.K. business during the first nine months of 2019.
Other income decreased $38 million in the first nine months of 2020 primarily
due to income recognized in 2019 arising from indemnification payments received
from Marathon Petroleum Corporation ("MPC"). Pursuant to the Tax Sharing
Agreement we entered into with MPC, in connection with the 2011 spin-off
transaction, MPC agreed to indemnify us for certain liabilities. The indemnity
relates to tax and interest allocable to MPC as a result of the closure of the
2010-2011 U.S. Federal Tax Audit in the first quarter of 2019.
Production expenses for the first nine months of 2020 decreased by $125 million
compared to the same period in 2019. Production expense in our International
segment decreased $69 million primarily as a result of the sale of our U.K.
business, which closed during the third quarter of 2019. Production expense in
our U.S. segment decreased $58 million primarily due to lower operational
activity and continued cost management, specifically staffing and contract
labor.
The first nine months of 2020 production expense rate (expense per boe) was
lower for our United States segment due to the aforementioned reasons. Expense
per boe for our International segment decreased due to the sale of the U.K.
business, which closed during the third quarter of 2019. We expect our full year
production expense rates for the United States and International segments to be
$4.25 - $4.75 per boe and $2.05 - $2.35 per boe, respectively.
The following table provides production expense and production expense rates for
each segment:
                                                                        

Nine Months Ended September 30,


                                                                        Increase                                     Increase
($ in millions; rate in $ per boe)              2020       2019        (Decrease)             2020      2019        (Decrease)
Production Expense and Rate                                  Expense                                         Rate
United States                                $    375    $  433                (13) %       $ 4.36    $ 4.94                (12) %
International                                $     43    $  112                (62) %       $ 2.00    $ 4.33                (54) %


Shipping, handling and other operating expenses decreased $30 million in the
first nine months of 2020 from the comparable 2019 period, primarily as a result
of lower net sales volumes in the U.S during the first nine months of 2020 and
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lower NGL shipping and handling rates realized in Bakken in the second quarter
of 2020. This was partially offset by higher marketing costs due to higher
volumes purchased for resale during the third quarter of 2020.
Exploration expenses include unproved property impairments, dry well costs,
geological and geophysical, and other, which decreased $26 million in the first
nine months of 2020. Decreases in unproved property impairments were primarily
driven by our decision not to drill certain leases related to resource
exploration in the first quarter of 2019.
The following table summarizes the components of exploration expenses:
                                                                          Nine Months Ended September 30,
(In millions)                                                    2020                 2019           Increase (Decrease)
Exploration Expenses
Unproved property impairments                              $           62          $     79                        (22) %
Dry well costs                                                          1                 6                        (83) %
Geological and geophysical                                              6                10                        (40) %
Other                                                                  12                12                          -  %
Total exploration expenses                                 $           81          $    107                        (24) %


Depreciation, depletion and amortization increased $14 million in the first nine
months of 2020 from the comparable 2019 period, primarily due to additional
wells coming online in 2020 related to our resource exploration development
coupled with field-level reserve adjustments increasing the United States DD&A
expense. This was partially offset by the sale of our U.K. business, which
closed during the third quarter of 2019. Our segments apply the
units-of-production method to the majority of their assets, including
capitalized asset retirement costs; therefore volumes have an impact on DD&A
expense.
The DD&A rate (expense per boe) is impacted by field-level changes in reserves,
capitalized costs and sales volume mix between fields. The DD&A rate for
International decreased primarily as a result of dispositions. The following
table provides DD&A expense and DD&A expense rates for each segment:
                                                                     Nine Months Ended September 30,
($ in millions; rate in $ per boe)         2020        2019    Increase (Decrease)          2020       2019    Increase (Decrease)
DD&A Expense and Rate                                    Expense                                           Rate
United States                           $  1,716    $ 1,664                   3  %       $ 19.91    $ 18.95                   5  %
International                           $     62    $    97                 (36) %       $  2.87    $  3.77                 (24) %


Impairments increased $74 million in the first nine months of 2020, primarily as
a result of the impairment to goodwill for $95 million related to our
International reporting unit in the first quarter of 2020. See   Note 11   for
discussion of the impairments in further detail.
Taxes other than income include production, severance and ad valorem taxes,
primarily in the U.S., which tend to increase or decrease in relation to revenue
and sales volumes. Taxes other than income decreased $87 million in the first
nine months of 2020 from the comparable 2019 period primarily due to lower price
realizations and lower sales volumes in the U.S. segment.
General and administrative expenses decreased $46 million in the first nine
months of 2020 from the comparable 2019 period, which reflects costs savings
realized from workforce reductions.
Provision (benefit) for income taxes reflects an effective income tax rate of 1%
in the first nine months of 2020, as compared to an effective income tax rate of
(27)% for the comparable 2019 period. See   Note 7   to the consolidated
financial statements for a more detailed discussion concerning the components
impacting the rate change.
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Segment Income
Segment income represents income which excludes certain items not allocated to
our operating segments, net of income taxes. A portion of our corporate and
operations general and administrative support costs are not allocated to the
operating segments. These unallocated costs primarily consist of employment
costs (including pension effects), professional services, facilities and other
costs associated with corporate and operations support activities. Additionally,
items which affect comparability such as: gains or losses on dispositions,
impairments of proved property, goodwill and equity method investments,
unrealized gains or losses on commodity and interest rate derivative
instruments, effects of pension settlements and curtailments, or other items (as
determined by the CODM) are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
                                                                        Nine Months Ended September 30,
(In millions)                                                 2020                 2019            Increase (Decrease)
United States                                            $       (520)         $      527                       (199) %
International                                                       1                 200                       (100) %
Segment income (loss)                                            (519)                727                       (171) %
Items not allocated to segments, net of income taxes             (594)               (227)                      (162) %
Net income (loss)                                        $     (1,113)         $      500                       (323) %


United States segment income (loss) for the first nine months of 2020, was a
$520 million loss after-tax versus $527 million income after-tax for the same
period in 2019, primarily as a result of lower crude price realizations and
lower net sales volumes, which was partially offset by lower production taxes
and production expenses.
International segment income for the first nine months of 2020, was $1 million
after-tax versus $200 million after-tax for the same period in 2019, primarily
due to lower price realizations and sales volumes partially offset by lower
costs due to the sale of our U.K. business in third quarter of 2019.
Critical Accounting Estimates
There have been no material changes or developments in the evaluation of the
accounting estimates and the underlying assumptions or methodologies pertaining
to our Critical Accounting Estimates disclosed in our Form 10-K for the year
ended December 31, 2019, except as discussed below.
Impairment of Equity Method Investments
During the nine months ended September 30, 2020, we recorded an impairment of
$170 million to an investment in an equity method investee, which was reflected
in income (loss) from equity method investments in our consolidated statements
of income. Equity method investments are assessed for impairment whenever
changes in the facts and circumstances indicate a loss in value may have
occurred. When a loss is deemed to have occurred that is other than temporary,
the carrying value of the equity method investment is written down to fair
value.
Fair value calculated for the purpose of testing our equity method investees for
impairment is estimated using the present value of expected future cash flows
method. Significant judgment is involved in performing these fair value
estimates since the results are based on forecasted assumptions and the
performance of entities that we do not control. Significant assumptions include:
•Future condensate, NGL, LNG, natural gas & methanol prices. Our estimates of
future prices are based on our analysis of market supply and demand and
consideration of market price indicators. Although these commodity prices may
experience extreme volatility in any given year, we believe long-term industry
prices are driven by global market supply and demand. To estimate supply, we
consider numerous factors, including the worldwide resource base, depletion
rates and OPEC production policies. We believe demand is largely driven by
global economic factors, such as population and income growth, and governmental
policies. The prices we use in our fair value estimates are consistent with
those used in our planning and capital investment reviews. There has been
significant volatility in commodity prices and estimates of such future prices
are inherently imprecise. See Item 1A. Risk Factors in our Form 10-K for the
year ended December 31, 2019 for further discussion on commodity prices.



                                       42
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•Estimated quantities of feedstock condensate, NGLs and natural gas processed by
our investees. There are two primary sets of inputs used to estimate feedstock
volumes processed by our investees. The first input involves hydrocarbons
produced from our Alba Field. Our equity method investees currently process
hydrocarbons from our Alba Field, which consists of condensate, NGLs and natural
gas reserves. Estimated quantities of hydrocarbons processed from our Alba Field
are based on a combination of proved reserves and risk-weighted probable
reserves and resources such that the combined volumes represent the most likely
expectation of recovery. See Item 1A. Risk Factors in our Form 10-K for the year
ended December 31, 2019 for further discussion on reserves.

The second input involves our estimate of future third-party gas to be processed
by our investees. Our investees have capacity to process hydrocarbons from
sources other than our Alba field. During 2019, we executed agreements for
processing natural gas produced from the third party-owned Alen Unit through the
existing Alba Plant LLC LPG processing plant and the EGHoldings LNG production
facility beginning in 2021. Estimated natural gas volumes processed from the
Alen Unit were based on forecasts received from the operator of the Alen Unit.

•Expected timing of production. Production forecasts are the outcome of
engineering studies which estimate reserves, as well as expected capital
programs. The actual timing of the production could be different than the
projection. Cash flows realized later in the projection period are less valuable
than those realized earlier due to the time value of money. The expected timing
of production from the Alba Field that we use in our fair value estimates is
consistent with that used in our planning and capital investment reviews. The
expected timing of production from the Alen Unit is consistent with forecasts
received from the operator of that field.
•Discount rate commensurate with the risks involved. We apply a discount rate to
our expected cash flows based on a variety of factors, including market and
economic conditions, operational risk, regulatory risk and political risk. A
higher discount rate decreases the net present value of cash flows
We base our fair value estimates on projected financial information which we
believe to be reasonably likely to occur. This includes the estimated dividends
and/or return of capital we expect to be paid by our equity method investees,
which are directly affected by the significant assumptions described in the
preceding paragraphs. An estimate of the sensitivity to changes in assumptions
in our cash flow calculations is not practicable, given the numerous other
assumptions (e.g. reserves, commodity prices, operating costs, inflation and
discount rates) that can materially affect our estimates. Unfavorable
adjustments to some of the above listed assumptions would likely be offset by
favorable adjustments in other assumptions.
See   Note 11   to the consolidated financial statements for further information
regarding the impairment recognized during the second and third quarter of 2020.
Fair Value Estimates - Goodwill
  In the first quarter of 2020, a triggering event (significant decline in
market capitalization caused by worldwide declines in hydrocarbon demand and
corresponding prices) required us to assess our goodwill in the International
reporting unit for impairment as of March 31, 2020. We estimated the fair value
of our International reporting unit using a combination of market and income
approaches and concluded that a full impairment of $95 million was required. See
  Note 14   to the consolidated financial statements for further information.
Estimated Quantity of Net Reserves
Continued lower commodity prices could have a material effect on the quantity
and present value of our proved reserves. When we apply actual SEC pricing as of
year-end, a portion of our proved reserves could be deemed uneconomic and no
longer classified as proved. This could impact both proved developed producing
reserves as well as proved undeveloped reserves. Future reserve revisions could
also result from changes to our Capital Budget and drilling plans among other
things. However, any impact of lower SEC pricing will likely be partially offset
by continued cost reduction efforts. Also, any volumes reclassified to unproved
reserves could return to proved reserves as commodity prices improve. Any
reduction in proved reserves, especially as a result of continued lower
commodity prices, could result in an acceleration of future DD&A expense and
impairments to long-lived assets.
Accounting Standards Not Yet Adopted
See   Note 2   to the consolidated financial statements.
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Cash Flows


  Commodity prices are the most significant factor impacting our revenues,
profitability, operating cash flows, the amount of capital we invest in our
business, payment of dividends, and funding of share repurchases. While we
generated cash flows from operations during the first nine months of 2020, the
lower price environment reduced our cash flow generation compared to the prior
year. Should lower prices continue, our ability to generate cash from operations
could be negatively affected. The following table presents sources and uses of
cash and cash equivalents:
                                                                Nine Months Ended September 30,
(In millions)                                                     2020                    2019
Sources of cash and cash equivalents
Operating activities                                       $          1,055          $      2,049
Borrowings                                                              400                     -
Disposal of assets, net of cash transferred to the buyer                  9                   (84)
Other                                                                     7                    53
Total sources of cash and cash equivalents                 $          1,471          $      2,018
Uses of cash and cash equivalents
Additions to property, plant and equipment                 $         (1,090)         $     (1,934)
Additions to other assets                                                15                    41

Purchases of common stock                                               (92)                 (296)
Dividends paid                                                          (40)                 (122)
Other                                                                    (3)                   (4)
Total uses of cash and cash equivalents                    $         

(1,210) $ (2,315)




Cash flows generated from operating activities in the first nine months of 2020
were 49% lower compared to the same period in 2019, primarily as a result of
lower commodity price realizations.
The following table shows capital expenditures by segment and reconciles to
additions to property, plant and equipment as presented in the consolidated
statements of cash flows:
                                                                  Nine Months Ended September 30,
(In millions)                                                        2020                    2019
United States                                                $             874          $     1,959
International                                                                -                   16
Corporate                                                                   10                   15
Total capital expenditures                                                 884                1,990
Change in capital expenditure accrual                                      206                  (56)

Total use of cash and cash equivalents for property, plant and equipment

                                                $           

1,090 $ 1,934




The decline in our capital expenditures for the U.S. segment in the first nine
months of 2020 compared to the same period in 2019, was caused by lower drilling
and completions activities across all four of our shale basins.
In the first quarter of 2020, we acquired approximately 9 million common shares
at a cost of $85 million, which were held as treasury stock. See   Note 18  

to


the consolidated financial statements for further information.
Liquidity and Capital Resources
Available Liquidity
Our main sources of liquidity are cash and cash equivalents, internally
generated cash flow from operations, sales of non-core assets, capital market
transactions, and our revolving Credit Facility. At September 30, 2020, we had
approximately $4.1 billion of liquidity consisting of $1.1 billion in cash and
cash equivalents and $3.0 billion available under our revolving Credit Facility.
On October 1, 2020, we completed a cash tender offer for an aggregate principal
amount of $500 million of our $1 billion 2.8% 2022 Notes funded by cash on hand.
See Item 1A. Risk Factors for a more detailed discussion of recent developments
affecting the energy industry.
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Our working capital requirements are supported by our cash and cash equivalents
and our Credit Facility. We may draw on our revolving Credit Facility to meet
short-term cash requirements, or issue debt or equity securities through the
shelf registration statement discussed below as part of our longer-term
liquidity and capital management program. Because of the alternatives available
to us as discussed above, we believe that our short-term and long-term liquidity
are adequate to fund not only our current operations, but also our near-term and
long-term funding requirements including our capital spending programs, defined
benefit plan contributions, repayment of debt maturities, and other amounts that
may ultimately be paid in connection with contingencies. General economic
conditions, commodity prices, and financial, business and other factors,
including the global pandemic, could affect our operations and our ability to
access the capital markets.
During the first half of 2020, commodity prices significantly declined due to
the combined impacts of global crude oil oversupply and lower demand for
hydrocarbons due to the global pandemic. As a result, credit rating agencies
reviewed many companies in the industry, including us. We continue to be rated
investment grade at all three primary credit rating agencies. A downgrade in our
credit ratings could increase our future cost of financing or limit our ability
to access capital, and could result in additional credit support requirements.
See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended
December 31, 2019 for a discussion of how a downgrade in our credit ratings
could affect us.
During the second quarter of this year, our Board of Directors temporarily
suspended our quarterly dividend payment as we prioritize our liquidity and
balance sheet. On October 1, 2020, our Board of Directors approved the
reinstatement of and declared a base quarterly dividend of $0.03 per share
payable December 10, 2020 to stockholders of record at the close of business on
November 18, 2020.
Capital Resources
Credit Arrangements and Borrowings
At September 30, 2020, we had no borrowings against our Credit Facility. At
September 30, 2020, we had $5.9 billion of total debt outstanding. On October 1,
2020, we completed a cash tender offer for an aggregate principal amount of $500
million of our $1 billion 2.8% 2022 Notes funded by cash on hand. After giving
consideration to the cash tender, our next significant debt maturity is $500
million due in November 2022. We do not have any triggers on any of our
corporate debt that would cause an event of default in the case of a downgrade
of our credit ratings.
On August 18, 2020, we closed a $400 million remarketing to investors of
sub-series B bonds which are part of the $1.0 billion St. John the Baptist,
State of Louisiana revenue refunding bonds originally issued and purchased in
December 2017. Information about these bonds are available on the website of the
Municipal Securities Rulemaking Board via its Electronic Municipal Market Access
system at www.msrb.org. Information on that website is not incorporated by
reference into this filing.
In 2018, we signed an agreement with an owner/lessor to construct and lease a
new build-to-suit office building in Houston, Texas. The lessor and other
participants are providing financing for up to $340 million to fund the
estimated project costs, which was reduced effective August 2020 from $380
million to align with our revised estimate of the project costs. As of
September 30, 2020, project costs incurred totaled approximately $117 million,
including land acquisition and construction costs.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which
we, as a "well-known seasoned issuer" for purposes of SEC rules, have the
ability to issue and sell an indeterminate amount of various types of debt and
equity securities.
Debt-To-Capital Ratio
The Credit Facility includes a covenant requiring that our total debt to total
capitalization ratio not exceed 65% as of the last day of the fiscal quarter.
Our ratio was 35% and 31% at September 30, 2020 and at December 31, 2019,
respectively.
Capital Requirements
Share Repurchase Program
In the first quarter of 2020, we acquired approximately 9 million common shares
at a cost of $85 million under our share repurchase program. While the share
repurchase program has $1.3 billion of remaining authorization, we elected to
suspend additional share repurchases to preserve liquidity.



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Contractual Cash Obligations
As of September 30, 2020, our contractual obligations as it relates to our short
and long-term debt increased by $400 million ($200 million in 2024 and $200
million thereafter) due to the remarketing of the St. John the Baptist, State of
Louisiana revenue refunding bonds. On October 1, 2020, we completed a cash
tender for an aggregate principal amount of $500 million of our outstanding $1
billion 2.8% 2022 Notes. The tender was funded from cash on hand, resulting in a
gross debt reduction of $100 million from the second quarter of 2020.
As of September 30, 2020, our contractual cash obligations as it relates to our
transportation and processing commitments decreased approximately $79 million
($8 million in 2021, $11 million in 2022, $11 million in 2023, $11 million in
2024 and $38 million thereafter) related to the cancellation of a transportation
service agreement in the Bakken resource play.
Environmental Matters and Other Contingencies
We have incurred and will continue to incur capital, operating and maintenance,
and remediation expenditures as a result of environmental laws and regulations.
If these expenditures, as with all costs, are not ultimately offset by the
prices we receive for our products and services, our operating results will be
adversely affected. We believe that substantially all of our competitors must
comply with similar environmental laws and regulations. However, the specific
impact on each competitor may vary depending on a number of factors, including
the age and location of its operating facilities, marketing areas and production
processes. These laws generally provide for control of pollutants released into
the environment and require responsible parties to undertake remediation of
hazardous waste disposal sites. Penalties may be imposed for noncompliance.
Other than the items set forth in Item 1. Legal Proceedings, there have been no
significant changes to the environmental, health and safety matters under Item
1. Business or Item 3. Legal Proceedings in our 2019 Annual Report on Form 10-K.
See   Note 24   to the consolidated financial statements for a description of
other contingencies.

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Forward-Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934 (the "Exchange Act"). All statements, other than
statements of historical fact, including without limitation statements regarding
our operational and financial strategies, including drilling plans and projects,
planned wells, rig count, inventory, seismic, exploration plans, maintenance
activities, drilling and completion improvements, cost reductions, and financial
flexibility; our ability to successfully effect those strategies and the
expected timing and results thereof; our 2020 Capital Budget and the planned
allocation thereof; planned capital expenditures and the impact thereof;
expectations regarding future economic and market conditions and their effects
on us; our financial and operational outlook, and ability to fulfill that
outlook; our financial position, balance sheet, liquidity and capital resources,
and the benefits thereof; resource and asset potential; reserve estimates;
growth expectations; and future production and sales expectations, and the
drivers thereof, are forward-looking statements. Words such as "anticipate,"
"believe," "could," "estimate," "expect," "forecast," "future," "guidance,"
"intend," "may," "outlook," "plan," "positioned," "project," "seek," "should,"
"target," "will," "would" or similar words may be used to identify
forward-looking statements; however, the absence of these words does not mean
that the statements are not forward-looking. While we believe our assumptions
concerning future events are reasonable, a number of factors could cause results
to differ materially from those projected, including, but not limited to:
•conditions in the oil and gas industry, including supply and demand levels for
crude oil and condensate, NGLs and natural gas and the resulting impact on
price;
•changes in expected reserve or production levels;
•changes in political and economic conditions in the U.S. and E.G., including
changes in foreign currency exchange rates, interest rates, and inflation rates;
•actions taken by the members of OPEC and Russia affecting the production and
pricing of crude oil; and other global and domestic political, economic or
diplomatic developments;
•risks related to our hedging activities;
•voluntary and involuntary volume curtailments;
•delays or cancellations of certain drilling activities;
•liability resulting from litigation;
•capital available for exploration and development;
•the inability of any party to satisfy closing conditions or delays in execution
with respect to our asset acquisitions and dispositions;
•drilling and operating risks;
•lack of, or disruption in, access to storage capacity, pipelines or other
transportation methods;
•well production timing;
•availability of drilling rigs, materials and labor, including the costs
associated therewith;
•difficulty in obtaining necessary approvals and permits;
•non-performance by third parties of their contractual obligations, including
due to bankruptcy;
•hazards such as weather conditions, a health pandemic (including COVID-19),
acts of war or terrorist acts and the governmental or military response thereto;
•shortages of key personnel, including employees, contractors and
subcontractors;
•cyber-attacks;
•changes in safety, health, environmental, tax and other regulations or
requirements or initiatives including those addressing the impact of global
climate change, air emissions or water management;
•other geological, operating and economic considerations; and
•the risk factors, forward-looking statements and challenges and uncertainties
described in our 2019 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q
and other filings with the SEC.
All forward-looking statements included in this report are based on information
available to us on the date of this report. Except as required by law, we
undertake no obligation to revise or update any forward-looking statements as a
result of new information, future events or otherwise.
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