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 inHouston, Texas . Our strategy is to deliver competitive and improving corporate level returns by focusing our capital investment in the lower cost, higher marginU.S. resource plays (theEagle Ford inTexas , the Bakken inNorth Dakota , STACK and SCOOP inOklahoma andNorthern Delaware inNew 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. OnOctober 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. •TheSeptember 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 endedSeptember 30, 2020 . •In earlyJuly 2020 , we collected an$89 million cash refund related to alternative minimum tax credits and associated interest. 32 -------------------------------------------------------------------------------- •OnOctober 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 inU.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 ourOklahoma activity in 2020, a decrease inNorthern Delaware drilling activity, and a continued optimization of our development plans in the Bakken andEagle 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
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 ourU.K. business in the third quarter of 2019. The nine months endedSeptember 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 33 -------------------------------------------------------------------------------- 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
Wells drilled to total depth - 15 9 53 Wells brought to sales - 19 13 55Northern 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. 34 -------------------------------------------------------------------------------- •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 inOklahoma ; we do not plan to drill any additional wells inOklahoma 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
Note 4 to the consolidated financial statements for further information.
35 -------------------------------------------------------------------------------- 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 theOPEC decision to increase production. A revisedOPEC 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) % MagellanEast 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$0.70 per bbl for the first nine months of 2020 and 2019, respectively. (c)Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods presented. (d)Bloomberg Finance LLP : Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline. Crude oil and condensate - Price realizations may differ from benchmarks due to the quality and location of the product. Natural gas liquids - The majority of our sales volumes are sold at reference toMont Belvieu prices. Natural gas - A significant portion of our volumes are sold at bid-week prices, or first-of-month indices relative to our producing areas. International The following table presents our average price realizations and the related benchmark for crude oil for the third quarter and first nine months of 2020 and 2019. Three Months Ended September 30, Nine Months Ended September 30, Increase Increase 2020 2019 (Decrease) 2020 2019 (Decrease) Average Price Realizations Crude oil and condensate (per bbl)$ 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
36 --------------------------------------------------------------------------------
United Kingdom
Crude oil and condensate - Generally sold in relation to the Brent crude
benchmark. We closed on the sale of our
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 byAlba 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 toAlba 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 fromAlba Plant LLC being reflected in the income from equity method investments on the consolidated statements of income. Natural gas - Dry natural gas, processed byAlba 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 EndedSeptember 30, 2020 vs. Three Months EndedSeptember 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
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 37
-------------------------------------------------------------------------------- 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$34 million in the third quarter of 2020 versus the same period in 2019, primarily as a result of theU.S. segment's lower operational costs and continued cost management, specifically staffing and contract labor. International segment production expense slightly decreased due to timing of E.G. liftings.
The following table provides production expense and production expense rates (expense per boe) for each segment:
Three Months Ended September 30, ($ 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$68 million in the third quarter of 2020 as a result of lower sales volumes in ourU.S. and International segments. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense. The DD&A rate (expense per boe) is impacted by field-level changes in reserves, capitalized costs and sales volume mix between fields. The following table provides DD&A expense and DD&A expense rates for each segment: 38 -------------------------------------------------------------------------------- Three
Months Ended
Increase Increase ($ 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 theU.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 theU.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$43 million after-tax for the same period in 2019, primarily due to timing of E.G. liftings and lower price realizations resulting in lower income from equity method investments. Results of Operations Nine Months EndedSeptember 30, 2020 vs. Nine Months EndedSeptember 30, 2019 Revenues from contracts with customers are presented by segment in the table below: Nine Months Ended September 30, (In millions) 2020 2019 Revenues from contracts with customers United States$ 2,154 $ 3,434 International 121 396 Segment revenues from contracts with customers
39 --------------------------------------------------------------------------------
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 ) andU.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 2010-2011U.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 ourU.K. business, which closed during the third quarter of 2019. Production expense in ourU.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 ourUnited States segment due to the aforementioned reasons. Expense per boe for our International segment decreased due to the sale of theU.K. business, which closed during the third quarter of 2019. We expect our full year production expense rates forthe United States and International segments to be$4.25 -$4.75 per boe and$2.05 -$2.35 per boe, respectively. The following table provides production expense and production expense rates for each segment:
Nine Months Ended
Increase Increase ($ 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 theU.S during the first nine months of 2020 and 40 -------------------------------------------------------------------------------- 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$14 million in the first nine months of 2020 from the comparable 2019 period, primarily due to additional wells coming online in 2020 related to our resource exploration development coupled with field-level reserve adjustments increasing the United States DD&A expense. This was partially offset by the sale of ourU.K. business, which closed during the third quarter of 2019. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense. The DD&A rate (expense per boe) is impacted by field-level changes in reserves, capitalized costs and sales volume mix between fields. The DD&A rate for International decreased primarily as a result of dispositions. The following table provides DD&A expense and DD&A expense rates for each segment: Nine Months Ended September 30, ($ 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 theU.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 theU.S. segment. General and administrative expenses decreased$46 million in the first nine months of 2020 from the comparable 2019 period, which reflects costs savings realized from workforce reductions. Provision (benefit) for income taxes reflects an effective income tax rate of 1% in the first nine months of 2020, as compared to an effective income tax rate of (27)% for the comparable 2019 period. See Note 7 to the consolidated financial statements for a more detailed discussion concerning the components impacting the rate change. 41 -------------------------------------------------------------------------------- Segment Income Segment income represents income which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, impairments of proved property, goodwill and equity method investments, unrealized gains or losses on commodity and interest rate derivative instruments, effects of pension settlements and curtailments, or other items (as determined by the CODM) are not allocated to operating segments. The following table reconciles segment income (loss) to net income (loss): Nine Months Ended September 30, (In millions) 2020 2019 Increase (Decrease) United States$ (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 ourU.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 endedDecember 31, 2019 , except as discussed below. Impairment of Equity Method Investments During the nine months endedSeptember 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 andOPEC 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 endedDecember 31, 2019 for further discussion on commodity prices. 42 -------------------------------------------------------------------------------- •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 ourAlba Field . Our equity method investees currently process hydrocarbons from ourAlba Field , which consists of condensate, NGLs and natural gas reserves. Estimated quantities of hydrocarbons processed from ourAlba 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 endedDecember 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 ofMarch 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 actualSEC 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 lowerSEC 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. 43 --------------------------------------------------------------------------------
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)
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
The decline in our capital expenditures for theU.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. AtSeptember 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. OnOctober 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. 44 -------------------------------------------------------------------------------- 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 endedDecember 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. OnOctober 1, 2020 , our Board of Directors approved the reinstatement of and declared a base quarterly dividend of$0.03 per share payableDecember 10, 2020 to stockholders of record at the close of business onNovember 18, 2020 . Capital Resources Credit Arrangements and Borrowings AtSeptember 30, 2020 , we had no borrowings against our Credit Facility. AtSeptember 30, 2020 , we had$5.9 billion of total debt outstanding. OnOctober 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 inNovember 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. OnAugust 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 inDecember 2017 . Information about these bonds are available on the website of theMunicipal 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 inHouston, Texas . The lessor and other participants are providing financing for up to$340 million to fund the estimated project costs, which was reduced effectiveAugust 2020 from$380 million to align with our revised estimate of the project costs. As ofSeptember 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 theSEC under which we, as a "well-known seasoned issuer" for purposes ofSEC 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% atSeptember 30, 2020 and atDecember 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. 45 -------------------------------------------------------------------------------- Contractual Cash Obligations As ofSeptember 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 theSt. John the Baptist,State of Louisiana revenue refunding bonds. OnOctober 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 ofSeptember 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. 46 -------------------------------------------------------------------------------- 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 theU.S. and E.G., including changes in foreign currency exchange rates, interest rates, and inflation rates; •actions taken by the members ofOPEC andRussia 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 theSEC . 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. 47
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