MURPHY OIL CORP 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) Exploration and Production Third quarter 2021 vs. 2020 All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted. United States E&P operations reported earnings of $168.1 million in the third quarter of 2021 compared to a loss of $172.6 million in the third quarter of 2020. Results were $340.7 million favorable in the 2021 quarter compared to the 2020 period primarily due to higher revenues ($234.4 million), lower impairment charge ($205.1 million) and depreciation, depletion and amortization (DD&A: $19.2 million), partially offset by higher income tax expense ($78.4 million), other operating expense ($16.6 million) and exploration expense ($15.5 million). Higher revenues were primarily due to higher commodity prices. The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in the third quarter of 2020. Lower impairment charges were due to impairment charges recognized in the prior period related to Gulf of Mexico Cascade & Chinook field and no such charges in current period. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price. Higher other operating expense is primarily due to unfavorable mark to market revaluation on contingent consideration (as a result of higher commodity prices) related to prior Gulf of Mexico (GOM) acquisitions. Higher exploration expense is primarily due to dry hole costs related to Silverback in the current period. Canadian E&P operations reported earnings of $73.9 million in the third quarter 2021 compared to a loss of $8.6 million in the third quarter of 2020. Results were favorable $82.5 million compared to the 2020 period primarily due to a credit of $71.8 million reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. Results were also favorably impacted by higher revenue ($28.3 million) and lower DD&A ($19.9 million), partially offset by higher tax expense ($28.3 million) and higher transportation, gathering and processing ($4.2 million). Higher revenue is primarily attributable to higher natural gas prices and higher natural gas volumes at Tupper Montney. Lower DD&A is due to lower production volumes at Kaybob Duvernay due to normal well decline. Higher transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future. Other international E&P operations reported a loss from continuing operations of $5.2 million in the third quarter of 2021 compared to a loss of $11.7 million in the third quarter of 2020. The result was $6.5 million favorable in the 2021 period versus 2020 primarily due lower exploration expenses in Brazil and Mexico. Nine months 2021 vs. 2020 All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted. United States E&P operations reported earnings of $481.8 million in the first nine months of 2021 compared to a loss of $1,011.7 million in the first nine months of 2020. Results were $1,493.5 million favorable in 2021 period compared to the 2020 period primarily due to no impairment charges in the current period (2020: $1,152.5 million). Further, the change year over year is driven by higher revenues ($633.8 million), lower DD&A ($112.9 million), lower lease operating expenses (LOE: $83.2 million), partially offset by higher income tax expense ($357.6 million) and higher other operating expense ($132.5 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of lower oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment. Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2021 compared to 2020. The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in 2020. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower lease operating expenses were primarily due to higher GOM workover costs in the prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million). Higher income tax expense is a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE. Higher other operating expense is primarily due to an unfavorable mark to market revaluation on contingent consideration ($105.1 million; as a result of higher commodity prices) from prior GOM acquisitions. Canadian E&P operations reported a loss of $37.7 million in the first nine months of 2021 compared to a loss of $35.0 million in the first nine months of 2020. Results were comparable year over year. 2021 results include an impairment charge ($171.3 million) recorded in the first quarter following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenue ($104.0 million) and lower DD&A ($33.3 million) offset by higher transportation, gathering and processing expenses ($15.3 million) and lease operating expenses ($9.4 million). Higher revenue is primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital 27 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) expenditures throughout 2020. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future. Other international E&P operations reported a loss of $22.5 million in the first nine months of 2021 compared to a loss of $73.0 million in the prior year. Results were $50.5 million favorable compared to the 2020 period primarily due to no repeat of an impairment charge of $39.7 million in the prior year. Corporate Third quarter 2021 vs. 2020 Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $98.8 million in the third quarter of 2021 compared to net loss of $72.9 million in the third quarter of 2020. The $25.9 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021: $59.2 million loss; 2020: $5.3 million loss), partially offset by lower impairment charges ($14.1 million), higher tax benefits ($5.7 million), lower restructuring charges ($5.0 million), and lower DD&A ($2.3 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. Lower impairment and restructuring charges are due to the 2020 cost reduction efforts which included closing the Company’s previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. Higher income tax benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments. Nine months 2021 vs. 2020 Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $577.6 million in the first nine months of 2021 compared to earnings of $26.9 million in the first nine months of 2020. The $604.5 million unfavorable variance is primarily due to realized and unrealized losses on derivative instruments in 2021 compared to gains in 2020 (2021: $499.8 million loss; 2020: $319.5 million gain), and higher interest expense ($54.1 million), partially offset by higher tax benefits ($177.6 million), lower restructuring charges ($46.4 million), lower G&A ($15.0 million), lower impairment charges ($14.1 million) and lower DD&A ($7.2 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2021, the average forward NYMEX WTI price for the remainder of 2021 was $74.87 and for 2022 was $70.87 (versus swap contract fixed hedge prices of $42.77 and $44.88, respectively). Interest charges are higher in 2021 primarily due an early redemption premium incurred by the Company upon the early retirement of the notes originally due June and December 2022. Higher income tax benefit is a result of pre-tax losses driven by the higher realized and unrealized losses on derivative instruments. Lower restructuring charges, G&A expenditures and impairment charges are due to the 2020 cost reduction efforts which included closing its previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. Production Volumes and Prices Third quarter 2021 vs. 2020 Total hydrocarbon production from continuing operations averaged 163,224 barrels of oil equivalent per day in the third quarter of 2021, which was in line with the 162,824 barrels per day produced in third quarter 2020. U.S. Gulf of Mexico production in the current year was impacted by Hurricane Ida and the prior year was impacted by multiple storms. The estimated storm impact in the third quarter of 2021 was 14,542 barrels of oil equivalent per day (including NCI) and 14,230 barrels of oil equivalent per day (including NCI) in the third quarter of 2020. Average crude oil and condensate production from continuing operations was 88,245 barrels per day in the third quarter of 2021 compared to 95,391 barrels per day in the third quarter of 2020. The decrease of 7,146 barrels per day was associated with lower volumes in Canada (5,281 barrels per day lower primarily attributable to Kaybob Duvernay well decline), lower volumes in the Gulf of Mexico (3,506 barrels per day principally due to facility shut-ins as a result of Hurricane Ida), offset by higher Eagle Ford Shale production (1,342 barrels per day higher at Karnes due to 2021 capital expenditures in this area). On a 28 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) worldwide basis, the Company’s crude oil and condensate prices averaged $68.88 per barrel in the third quarter 2021 compared to $39.79 per barrel in the 2020 period, an increase of 73% quarter over quarter. Total production of natural gas liquids (NGL) from continuing operations was 10,391 barrels per day in the third quarter 2021 compared to 10,523 barrels per day in the 2020 period. The average sales price for U.S. NGL was $32.01 per barrel in the 2021 quarter compared to $13.91 per barrel in 2020. The average sales price for NGL in Canada was $45.12 per barrel in the 2021 quarter compared to $19.97 per barrel in 2020. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets. Natural gas production volumes from continuing operations averaged 387.5 million cubic feet per day (MMCFD) in the third quarter 2021 compared to 341.5 MMCFD in 2020. The increase of 46 MMCFD was a result of higher volumes in Canada (49 MMCFD), offset by lower volumes in the Gulf of Mexico (7 MMCFD) and in the Eagle Ford Shale (4 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 10 new wells at Tupper Montney in the second quarter of 2021. Lower volumes in the Gulf of Mexico are principally due to facility shut-ins as a result of Hurricane Ida. Natural gas prices for the total Company averaged $2.78 per thousand cubic feet (MCF) in the 2021 quarter, versus $1.78 per MCF average in the same quarter of 2020. Average natural gas prices in the U.S. and Canada in the quarter were $3.99 and $2.47 per MCF, respectively. Nine months 2021 vs. 2020 Total hydrocarbon production from all E&P continuing operations averaged 170,209 barrels of oil equivalent per day in the first nine months of 2021, which represented a 6% decrease from the 180,443 barrels per day produced in the first nine months of 2020. The decrease in production is principally due to lower capital expenditures throughout 2020 to support generating positive free cashflow. Average crude oil and condensate production from continuing operations was 98,314 barrels per day in the first nine months of 2021 compared to 108,678 barrels per day in the first nine months of 2020. The decrease of 10,364 barrels per day was principally due to lower Gulf of Mexico production (5,472 barrels per day) due to temporary operational issues at the Cascade & Chinook and Kodiak fields in the first quarter of 2021 and facility shut-ins as a result of Hurricane Ida in the third quarter of 2021. Lower Canada production (3,628 barrels per day) is due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia and lower Eagle Ford Shale production (1,393 barrels per day) is due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. On a worldwide basis, the Company’s crude oil and condensate prices averaged $64.19 per barrel in the first nine months of 2021 compared to $36.88 per barrel in the 2020 period, an increase of 74% year over year. Total production of natural gas liquids (NGL) from continuing operations was 10,498 barrels per day in the first nine months of 2021 compared to 11,901 barrels per day in the 2020 period. The average sales price for U.S. NGL was $25.63 per barrel in 2021 compared to $10.13 per barrel in 2020. The average sales price for NGL in Canada was $37.05 per barrel in 2021 compared to $16.95 per barrel in 2020. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets. Natural gas sales volumes from continuing operations averaged 368.4 million cubic feet per day (MMCFD) in the first nine months of 2021 compared to 359.2 MMCFD in 2020. The increase of 9.2 MMCFD was primarily the result of higher volumes at Tupper (18.8 MMCFD) driven by the 10 new wells at Tupper Montney in the second quarter of 2021, partially offset by lower volumes in the Gulf of Mexico (4.3 MMCFD), other Canada assets (4.0 MMCFD), and in the Eagle Ford (1.3 MMCFD). Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields. Lower volumes at Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021. Natural gas prices for the total Company averaged $2.56 per thousand cubic feet (MCF) in the first nine months of 2021, versus $1.68 per MCF average in the same period of 2020. Average natural gas prices in the U.S. and Canada in the quarter were $3.26 and $2.33, respectively. Additional details about results of oil and natural gas operations are presented in the tables on pages 25 and 26. 29 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2021 and 2020. Three Months Ended September 30, Nine Months Ended September 30, Barrels per day unless otherwise noted 2021 2020 2021 2020 Continuing operations Net crude oil and condensate United States Onshore 26,193 24,851 26,552 27,945 Gulf of Mexico 1 53,011 56,517 61,905 67,377 Canada Onshore 4,963 9,595 5,598 8,106 Offshore 3,779 4,428 4,016 5,136 Other 299 — 243 114 Total net crude oil and condensate - continuing operations 88,245 95,391 98,314 108,678 Net natural gas liquids United States Onshore 5,847 5,489 5,043 5,459 Gulf of Mexico 1 3,459 3,521 4,296 5,131 Canada Onshore 1,085 1,513 1,159 1,311 Total net natural gas liquids - continuing operations 10,391 10,523 10,498 11,901 Net natural gas – thousands of cubic feet per day United States Onshore 31,478 27,520 27,750 29,054 Gulf of Mexico 1 46,339 53,046 63,557 67,850 Canada Onshore 309,709 260,895 277,077 262,279 Total net natural gas - continuing operations 387,526 341,461 368,384 359,183 Total net hydrocarbons - continuing operations including NCI 2,3 163,224 162,824 170,209 180,443 Noncontrolling interest Net crude oil and condensate – barrels per day (7,546) (9,298) (8,834) (10,674) Net natural gas liquids – barrels per day (243) (327) (322) (443) Net natural gas – thousands of cubic feet per day 2 (2,331) (3,269) (3,498) (4,137) Total noncontrolling interest (8,178) (10,170) (9,739) (11,807) Total net hydrocarbons - continuing operations excluding NCI 2,3 155,046 152,654 160,470 168,636 1 Includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM). 2 Natural gas converted on an energy equivalent basis of 6:1 3 NCI – noncontrolling interest in MP GOM. 30 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and nine-month periods ended September 30, 2021 and 2020. Comparative periods are conformed to current presentation. Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Weighted average Exploration and Production sales prices Continuing operations Crude oil and condensate – dollars per barrel United States Onshore 69.30 37.83 64.16 35.56 Gulf of Mexico 1 68.93 40.82 64.44 38.08 Canada 2 Onshore 63.76 36.65 58.70 30.29 Offshore 72.64 43.81 68.93 37.85 Other — — — 63.51 Natural gas liquids – dollars per barrel United States Onshore 30.37 13.39 24.29 10.78 Gulf of Mexico 1 34.71 14.71 27.17 9.43 Canada 2 Onshore 45.12 19.97 37.05 16.95 Natural gas – dollars per thousand cubic feet United States Onshore 3.85 1.78 3.23 1.76 Gulf of Mexico 1 4.09 2.01 3.28 1.91 Canada 2 Onshore 2.47 1.74 2.33 1.62 1 Prices include the effect of noncontrolling interest share for MP GOM. 2 U.S. dollar equivalent. Financial Condition Cash Provided by Operating Activities Net cash provided by continuing operating activities was $1,091.3 million for the first nine months of 2021 compared to $578.0 million during the same period in 2020. The increased cash from operating activities is primarily attributable to higher revenue from sales to customers ($727.3 million), lower working capital ($143.6 million), lower lease operating expense ($74.6 million), and lower general and administrative and cash restructuring expense ($47.4 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $271.3 million; 2020: realized gain of $215.0 million). Cash Required by Investing Activities Net cash required by investing activities was $311.9 million for the first nine months of 2021 compared to $723.7 million during the same period in 2020. Property additions and dry hole costs, which includes amounts expensed, were $582.0 million and $723.7 million in the first nine months of 2021 and 2020, respectively. These amounts include $17.7 million and $74.9 million used to fund the development of the King’s Quay FPS in the first nine months of 2021 and 2020, respectively. In the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimbursed the Company for previously incurred capital expenditures. Lower property additions in 2021 are principally due to lower capital spending at Eagle Ford Shale and lower spend on King’s Quay. 31 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.) Financial Condition (contd.) Total accrual basis capital expenditures were as follows: Nine Months Ended September 30, (Millions of dollars) 2021 2020 Capital Expenditures Exploration and production $ 556.0 671.0 Corporate 12.7 9.3 Total capital expenditures $ 568.7 680.3 A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows. Nine Months Ended September 30, (Millions of dollars) 2021 2020 Property additions and dry hole costs per cash flow statements $ 564.2 648.7 Property additions King's Quay per cash flow statements 17.7 74.9 Geophysical and other exploration expenses 13.3 26.8 Capital expenditure accrual changes and other (26.6) (70.2) Total capital expenditures $ 568.7 680.3 Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as a result of capital expenditure reductions to support generating positive free cash flow. Cash Used in/ Provided by Financing Activities Net cash required by financing activities was $585.6 million for the first nine months of 2021 compared to net cash provided by financing activities of $59.1 million during the same period in 2020. In 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million). As of September 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF. In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($450.0 million), offset by repayments on the revolving credit facility ($250.0 million), cash dividends to shareholders ($76.8 million), and distributions to our noncontrolling interest ($43.7 million). Working Capital Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, 2021 was a deficit of $344.9 million, $315.5 million lower than December 31, 2020, with the decrease primarily attributable to higher accounts payable ($208.3 million), higher other accrued liabilities ($165.6 million), higher operating lease liabilities ($53.5 million), partly offset by a higher cash balance ($194.5 million) and lower accounts receivable ($75.3 million). Higher accounts payable is primarily due to the increase in unrealized losses on derivative instruments (swaps and collars) maturing in the next 12 months. Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 Gulf of Mexico acquisitions). Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS. Lower accounts receivable are principally due to the timing of cash received from our joint venture partners to fund joint operations. 32 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.) Financial Condition (contd.) Capital Employed At September 30, 2021, long-term debt of $2,613.7 million had decreased by $374.4 million compared to December 31, 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due 2022 and 2024 ($726.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021. The total of the fixed-rate notes in issue had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent. A summary of capital employed at September 30, 2021 and December 31, 2020 follows. September 30, 2021 December 31, 2020 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 2,613.7 39.8 % $ 2,988.1 41.5 % Murphy shareholders' equity 3,949.5 60.2 % 4,214.3 58.5 % Total capital employed $ 6,563.2 100.0 % $ 7,202.4 100.0 % Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2021, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $119.4 million in Canada and $6.2 million in Brunei. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S. Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements Outlook As discussed in the Summary section on page 23, average crude oil prices continued to recover during the second half of 2021 versus 2020 (Q3 2021 WTI: $70.56; Q3 2020 WTI: $40.93). As of close on November 2, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $83.91 and $76.27 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic and OPEC+ decisions) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash-flows. For the fourth quarter, production is expected to average between 145.5 and 153.5 MBOEPD, excluding noncontrolling interest (NCI). The Company’s capital expenditure spend for 2021 is expected to be between $675.0 million and $685.0 million. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its remaining capital program in 2021 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects. The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) to repay outstanding debt. The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). The Company continues to monitor the effects of the COVID-19 pandemic and is encouraged by the progress of the vaccination roll-outs globally. As of November 2, 2021, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows: Commodity Type Volumes (Bbl/d) Price (USD/Bbl) Remaining Period Area Start Date End Date United States WTI ¹ Fixed price derivative swap 45,000 $42.77 10/1/2021 12/31/2021 United States WTI ¹ Fixed price derivative swap 20,000 $44.88 1/1/2022 12/31/2022 Volumes (Bbl/d) Average Put (USD/Bbl) Average Call (USD/Bbl) Remaining Period Area Commodity Type Start Date End Date United States WTI ¹ Derivative collars 23,000 $62.652 $74.774 1/1/2022 12/31/2022 1 West Texas Intermediate 33 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Volumes (MMcf/d) Price/Mcf Remaining Period Area Commodity Type Start Date End Date Montney Natural Gas Fixed price forward sales 196 C$2.55 10/1/2021 12/31/2021 Montney Natural Gas Fixed price forward sales 186 C$2.36 1/1/2022 1/31/2022 Montney Natural Gas Fixed price forward sales 176 C$2.34 2/1/2022 4/30/2022 Montney Natural Gas Fixed price forward sales 205 C$2.34 5/1/2022 5/31/2022 Montney Natural Gas Fixed price forward sales 247 C$2.34 6/1/2022 10/31/2022 Montney Natural Gas Fixed price forward sales 266 C$2.36 11/1/2022 12/31/2022 Montney Natural Gas Fixed price forward sales 269 C$2.35 1/1/2023 3/31/2023 Montney Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023 Montney Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024 Montney Natural Gas Fixed price forward sales 45 US$2.05 10/1/2021 12/31/2022 Montney Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024 Montney Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024 Forward-Looking Statements This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2020 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 37 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements. 34 Table of Contents