Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
Exploration and Production
Second quarter 2022 vs. 2021
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $491.5 million in the second quarter of 2022 compared to income of $194.7 million in the second quarter of 2021. Results were $296.8 million favorable in the 2022 quarter compared to the 2021 period primarily due to higher revenues ($328.9 million), lower depreciation, depletion and amortization (DD&A, $26.3 million) and other operating expense ($37.6 million), partially offset by higher income tax expense ($76.4 million), and lease operating expense ($19.0 million). Higher revenues were primarily due to higher commodity prices, partially off-set by lower volumes. Lower DD&A is a result of lower production volumes and lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale. Lower other operating expense is primarily due to lower unfavorable mark to market revaluations on contingent consideration (as a result of commodity prices) related to prior Gulf of Mexico (GOM) acquisitions that occurred in the second quarter of 2021. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price. Higher lease operating expense is due to cost increases from inflationary pressures (mainly at our onshore businesses), higher severance taxes at Eagle Ford (due to higher commodity prices) and costs related to first production at the Khaleesi asset flowing to the King’s Quay facility.
Canadian E&P operations reported earnings of $47.2 million in the second quarter 2022 compared to income of $12.7 million in the second quarter of 2021. Results were favorable $34.5 million compared to the 2021 period primarily due to higher revenues from production ($36.2 million) and lower DD&A ($7.9 million), partially offset by higher tax expense ($12.9 million). Higher revenue is primarily attributable to higher oil and gas prices and higher natural gas volumes at Tupper Montney. Lower DD&A is due primarily to lower production volumes at Kaybob Duvernay due to normal well decline. Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price.
Other international E&P operations reported a loss from continuing operations of $3.5 million in the second quarter of 2022 compared to a loss of $10.4 million in the second quarter of 2021. The result was $6.9 million favorable in the 2022 period versus 2021 primarily due to higher revenue from Brunei.
Six months 2022 vs. 2021
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
United States E&P operations reported earnings of $744.4 million in the first six months of 2022 compared to earnings of $313.7 million in the first six months of 2021. Results were $430.7 million favorable in the 2022 period compared to the 2021 period, driven by higher revenues ($546.0 million) and lower DD&A ($49.4 million), partially offset by higher income tax expense ($106.1 million) and higher other operating expense ($43.7 million). Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2022 compared to 2021, offset by lower oil sales and production volumes driven primarily by a focused effort to reduce capital expenditures to prioritize corporate debt reduction. Lower DD&A is a result of lower production volumes and lower rates driven by positive reserve revisions. Higher income tax expense is a result of higher pre-tax income. Higher other operating expense is primarily due to a higher unfavorable mark to market revaluation on contingent consideration ($129.8 million; as a result of higher commodity prices) from prior GOM acquisitions.
Canadian E&P operations reported earnings of $69.9 million in the first six months of 2022 compared to a loss of $111.6 million in the first six months of 2021. Results were $181.5 million favorable compared to the 2021 period. Prior year results included an impairment charge ($171.3 million) recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and prior to the subsequent sanctioning of an asset life extension project in the third quarter of 2021. The current year results also include higher revenue from production ($61.5 million) and lower DD&A ($18.5 million) offset by higher income tax expense ($62.6 million), lease operating expenses ($7.2 million) and transportation, gathering and processing costs ($4.8 million). Higher revenue is primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs). Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay due to normal well decline. Higher income tax expense is a result of higher pre-tax income principally due to higher revenue and no repeat of the impairment charge. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation rates and capacity. Higher capacity is expected to be utilized by growth at Tupper Montney in the future.
Other international E&P operations reported a loss of $47.7 million in the first six months of 2022 compared to a loss of $17.3 million in the prior year. Results were $30.4 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were discovered.
Corporate
Second quarter 2022 vs. 2021
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 $124.8 million in the second quarter of 2022 compared to a loss of $223.9 million in the second quarter of 2021. The $99.1 million favorable variance is principally due to lower losses on derivative instruments in 2022 ($123.2 million) compared to the 2021 period (2022: $103.1 million loss; 2021: $226.2 million loss), partially offset by higher tax expense ($27.3 million). Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) 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 June 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $100.49 (versus swap contract fixed hedge price of $44.88). The swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. Higher income tax benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments.
Six months 2022 vs. 2021
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 the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $421.1 million in the first six months of 2022 compared to a loss of $478.8 million in the first six months of 2021. The $57.7 million favorable variance is primarily due to lower interest expense ($60.1 million) and lower losses on derivative instruments in 2022 ($16.8 million) compared to 2021 (2022: $423.8 million loss; 2021: $440.6 million loss), partially offset by lower tax benefits ($19.5 million). Interest charges are lower in the first six months of 2022 primarily due to lower debt redemption premiums ($3.4 million in 2022; $34.2 million in 2021) incurred by the Company and lower overall debt. In the first six months of 2022 the Company redeemed $200.0 million of notes compared to the 2021 redemption of $576.4 million. Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) 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 June 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $100.49 (versus swap contract fixed hedge price of $44.88). Lower income tax benefit is a result of lower pre-tax losses.
Production Volumes and Prices
Second quarter 2022 vs. 2021
Total hydrocarbon production from continuing operations averaged 173,173 barrels of oil equivalent per day in the second quarter of 2022, which was 5% lower than the 182,050 barrels per day produced in second quarter 2021. The decrease in production is principally due to an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction and return funds to shareholders; partially offset by first oil from the Khaleesi, Mormont, Samurai field development project in the second quarter.
Average crude oil and condensate production from continuing operations was 98,661 barrels per day in the second quarter of 2022 compared to 109,327 barrels per day in the second quarter of 2021. The decrease of 10,666 barrels per day was associated with lower volumes in the Gulf of Mexico (5,041 barrels per day) principally due to the focused effort to reduce capital expenditures and several planned downtime events at St. Malo and Chinook, partially offset by first production from the first four wells at the Khaleesi, Mormont, Samurai development. Canada production is lower (1,700 barrels per day) primarily attributable to Kaybob Duvernay well decline and temporary operational issues at Hibernia. Eagle Ford Shale production is lower (4,949 barrels per day) due to normal well decline. On a worldwide basis, the Company’s crude oil and condensate prices averaged $109.25 per barrel in the second quarter 2022 compared to $65.57 per barrel in the 2021 period, an increase of 67% quarter over quarter.
Total production of natural gas liquids (NGL) from continuing operations was 10,950 barrels per day in the second quarter 2022 compared to 11,252 barrels per day in the 2021 period. The average sales price for U.S. NGL was $39.37 per barrel in the 2022 quarter compared to $22.18 per barrel in 2021. The average sales price for NGL in Canada was $63.99 per barrel in the 2022
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
quarter compared to $30.63 per barrel in 2021. 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 381.4 million cubic feet per day (MMCFD) in the second quarter 2022 compared to 368.8 MMCFD in 2021. The increase of 12.5 MMCFD was a result of higher volumes in Canada (20.8 MMCFD), partially offset by lower volumes in the Gulf of Mexico (8.3 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 15 new wells at Tupper Montney in the second quarter of 2022.
Natural gas prices for the total Company averaged $3.90 per thousand cubic feet (MCF) in the 2022 quarter, versus $2.34 per MCF average in the same quarter of 2021. Average natural gas prices in the U.S. and Canada in the quarter were $7.37 and $2.78 per MCF, respectively.
Six months 2022 vs. 2021
Total hydrocarbon production from Exploration and Production averaged 161,579 barrels of oil equivalent per day in the first six months of 2022, which represented a 7.0% decrease from the 173,762 barrels per day produced in the first six months of 2021. The decrease in production is principally due to an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction and return funds to shareholders.
Average crude oil and condensate production was 91,154 barrels per day in the first six months of 2022 compared to 103,434 barrels per day in the first six months of 2021. The decrease of 12,280 barrels per day was principally due to lower Gulf of Mexico production (7,064 barrels per day) due to the focused effort to reduce capital expenditures and several planned downtime events including a facility upgrade which lowered current production at Neidermeyer and Marmalard as well as maintenance operations at St. Malo, Front Runner, Habanero and Chinook. Canada production is lower (2,434 barrels per day) due to normal field decline at Kaybob and temporary operational issues at Hibernia. Eagle Ford Shale production is lower (3,400 barrels per day) due to normal well decline. On a worldwide basis, the Company’s crude oil and condensate prices averaged $102.86 per barrel in the first six months of 2022 compared to $62.14 per barrel in the 2021 period, an increase of 65.5% year over year.
Total production of natural gas liquids (NGL) was 10,150 barrels per day in the first six months of 2022 compared to 10,552 barrels per day in the 2021 period. The average sales price for U.S. NGL was $40.00 per barrel in 2022 compared to $22.41 per barrel in 2021. The average sales price for NGL in Canada was $59.23 per barrel in 2022 compared to $33.34 per barrel in 2021. 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 averaged 361.7 million cubic feet per day (MMCFD) in the first six months of 2022 compared to 358.7 MMCFD in 2021. The increase of 3.0 MMCFD was primarily the result of higher volumes in Canada 12.7 MMCFD) and Eagle Ford Shale (2.7 MMCFD), partially offset by the Gulf of Mexico (12.4 MMCFD). The higher natural gas volumes in Canada was the result of new wells on production in the first half of the year. Natural gas prices for the total Company averaged $3.54 per thousand cubic feet (MCF) in the first six months of 2022, versus $2.44 per MCF average in the same period of 2021. Average realized natural gas prices in the U.S. and Canada in the quarter were $6.26 per MCF and $2.66 per MCF, respectively. Average realized gas prices in Canada are lower as a result of certain fixed price sales volume contracts.
Additional details about results of oil and natural gas operations are presented in the tables on pages 25 and 26.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table reports hydrocarbons produced during the three-month and six-month periods ended June 30, 2022 and 2021.
Three Months Ended
June 30, Six Months Ended
June 30,
Barrels per day unless otherwise noted 2022 2021 2022 2021
Net crude oil and condensate
United States Onshore 26,304 31,253 23,334 26,734
Gulf of Mexico 1
63,427 68,468 59,363 66,427
Canada Onshore 4,419 5,558 4,400 5,921
Offshore 3,128 3,689 3,224 4,137
Other 1,383 359 833 215
Total net crude oil and condensate - continuing operations 98,661 109,327 91,154 103,434
Net natural gas liquids
United States Onshore 5,178 5,327 5,006 4,634
Gulf of Mexico 1
4,913 4,763 4,223 4,721
Canada Onshore 859 1,162 921 1,197
Total net natural gas liquids - continuing operations 10,950 11,252 10,150 10,552
Net natural gas – thousands of cubic feet per day
United States Onshore 29,651 29,653 28,512 25,855
Gulf of Mexico 1
63,703 71,962 59,902 72,308
Canada Onshore 288,019 267,210 273,237 260,491
Total net natural gas - continuing operations 381,373 368,825 361,651 358,654
Total net hydrocarbons - continuing operations including NCI 2,3
173,173 182,050 161,579 173,762
Noncontrolling interest
Net crude oil and condensate – barrels per day (7,962) (9,800) (8,044) (9,489)
Net natural gas liquids – barrels per day (319) (370) (303) (362)
Net natural gas – thousands of cubic feet per day 2
(3,097) (4,024) (2,845) (4,091)
Total noncontrolling interest (8,797) (10,841) (8,821) (10,533)
Total net hydrocarbons - continuing operations excluding NCI 2,3
164,376 171,209 152,758 163,229
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.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (contd.)
The following table reports the weighted average sales prices excluding transportation cost deduction and sales of purchased natural gas for the three-month and six-month periods ended June 30, 2022 and 2021.
Three Months Ended
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United States Onshore $ 110.66 64.55 $ 103.39 61.60
Gulf of Mexico 1
109.55 65.95 102.76 62.56
Canada 2
Onshore 100.51 60.69 96.84 56.55
Offshore 115.65 73.20 113.46 67.51
Other 86.51 — 86.51 —
Natural gas liquids – dollars per barrel
United States Onshore 38.29 19.75 38.30 20.38
Gulf of Mexico 1
40.46 24.84 41.95 24.36
Canada 2
Onshore 63.99 30.63 59.23 33.34
Natural gas – dollars per thousand cubic feet
United States Onshore 7.06 2.54 5.89 2.84
Gulf of Mexico 1
7.52 2.64 6.43 3.01
Canada 2
Onshore 2.78 2.23 2.66 2.25
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 $959.2 million for the first six months of 2022 compared to $686.3 million during the same period in 2021. The increased cash from operating activities of $273.0 million is primarily attributable to higher revenue from production ($629.5 million), offset by the timing of working capital settlements ($148.2 million; primarily higher revenue received in cash following the end of the quarter), and higher realized losses on derivative instruments ($167.2 million).
Cash Required by Investing Activities
Net cash required by investing activities was $599.3 million for the first six months of 2022 compared to net cash provided by investing activities of $193.7 million during the same period in 2021. In the second quarter of 2022, the Company acquired an 11.0% additional working interest in Kodiak for $46.5 million (also see Note D). Property additions and dry hole costs (excluding King’s Quay), which includes amounts expensed, were $552.8 million and $422.8 million in the first six months of 2022 and 2021, respectively. The first quarter of 2021 included sales proceeds for the King’s Quay FPS of $267.7 million, which was sold to ArcLight Capital Partners, LLC (ArcLight).
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)
Total accrual basis capital expenditures were as follows:
Six Months Ended
June 30,
(Millions of dollars) 2022 2021
Capital Expenditures
Exploration and production $ 611.4 449.4
Corporate 10.5 8.8
Total capital expenditures $ 621.9 458.2
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Six Months Ended
June 30,
(Millions of dollars) 2022 2021
Property additions and dry hole costs per cash flow statements 1
$ 552.8 422.8
Property additions King's Quay per cash flow statements — 17.7
Acquisition of oil and gas properties 1
46.5 22.5
Geophysical and other exploration expenses 16.3 12.4
Capital expenditure accrual changes and other 6.3 (17.2)
Total capital expenditures $ 621.9 458.2
1 Certain prior-period amounts have been reclassified to conform to the current period presentation
The increase in capital expenditures in the exploration and production business in 2022 compared to 2021 is primarily attributable to expenditures related to the Kodiak acquisition in Gulf of Mexi co ($46.5 million), Cutthroat-1 exploration well in Brazil ($24.3 million), capital invested at the Khaleesi, Mormont, Samurai field development project and higher development drilling activities in Tupper Montney and Kaybob Duvernay assets.
Cash Required by Financing Activities
Net cash required by financing activities was $447.5 million for the first six months of 2022 compared to $386.7 million during the same period in 2021. In 2022, the cash used in financing activities was principally for the early redemption of the notes due 2024 ($200.0 million), payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($94.9 million), and cash dividends to shareholders of $0.325 per share ($50.5 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.25 per share, or $1.00 per share on an annualized basis. This amount represents a 43% increase from the first quarter of 2022 and a 100% increase from fourth quarter 2021. Additionally, the Company announced a capital allocation framework, approved by the Board of Directors, that allows for further capital to be returned to the shareholders beyond the current dividend, while still advancing the Company’s long-term debt reduction goals. Details of the framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.
As of June 30, 2022 and in the eve nt it is required to fund investing activities from borrowings, the Company has $1,572.4 million available on its committed RCF.
In first six months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 ($576.4 million ), early redemption cost (make whole payment) of the notes due 2022 ($34.2 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 ($75.2 million), and cash dividends to shareholders ($38.6 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million).
Working Capital
Working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) as of June 30, 2022 was a deficit of $566.9 million, $268.0 million lower than December 31, 2021, with the decrease p rimarily attributable to higher accounts payable ($286.9 million), higher other accrued liabilities ($122.6 million), a lower cash balance ($89.2 million) and higher operating lease liabilities ($28.5 million), partially offset by higher accounts receivable ($263.9 million). Higher accounts
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)
Financial Condition (contd.)
payable is primarily due to the increase in unrealized losses on derivative instruments (commodity price swaps and collars) maturing (payable) over the remainder of 2022 as well as higher trade payables principally r elated to the Khaleesi, Mormont and Samurai field development project. Higher other accrued liabilities are associated with higher contingent consideration obligations (from prior Gulf of Mexico acquisitions), due to higher commodity prices. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project. Higher accounts receivable are principally due to higher crude oil pricing.
Capital Employed
At June 30, 2022, long-term debt of $2,267.9 million had decreased by $197.5 million compared to December 31, 2021, primarily as a result of the partial redemption of notes due 2024 ($200.0 million). The total of the fixed-rate notes had a weighted average maturity of 7.4 years and a weighted average coupon of 6.2%.
A summary of capital employed at June 30, 2022 and December 31, 2021 follows.
June 30, 2022 December 31, 2021
(Millions of dollars) Amount % Amount %
Capital employed
Long-term debt $ 2,267.9 34.5 % $ 2,465.4 37.2 %
Murphy shareholders' equity 4,312.8 65.5 % 4,157.3 62.8 %
Total capital employed $ 6,580.7 100.0 % $ 6,622.7 100.0 %
Cash and invested cash are maintained in several operating locations outside the United States. As of June 30, 2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $82.7 million in Canada. In addition, approximately $21.8 million of cash was held in Brunei, $17.7 million of cash was held in Mexico and $13.6 million of cash was held in Brazil. 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 22, several factors have continued to contribute to the higher average crude oil price during the second quarter, which directly impacts the Company’s product revenue from sales (Q2 2022; $108.41 Q1 2022; $94.29; Q2 2021: $66.07). Currently, recessionary concerns have placed some downward pressure on average crude oil prices. As of close on August 2, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were lower at $92.82 and $86.14 per barrel, respectively; however, we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and production sector investment, inflation and the Russia/Ukraine conflict) may have on future commodity prices. Lower prices, should they occur, will result in lower profits and operating cash-flows. For the third quarter, production is expected to average between 180.0 and 188.0 MBOEPD, excluding noncontrolling interest (NCI).
The Company’s capital expenditure spend for 2022 is expected to be between $900.0 million and $950.0 million, excluding acquisitions and noncontrolling interest. Capital expenditures 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 plans to fund its remaining capital program in 2022 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).
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
As of August 2, 2022, 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 WTI² Fixed price derivative swap 20,000 $44.88 7/1/2022 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 WTI² Derivative collars 25,000 $63.24 $75.20 7/1/2022 12/31/2022
1 West Texas Intermediate
Volumes
(MMcf/d) Price/Mcf Remaining Period
Area Commodity Type Start Date End Date
Canada Natural Gas Fixed price forward sales 247 C$2.34 7/1/2022 10/31/2022
Canada Natural Gas Fixed price forward sales 266 C$2.36 11/1/2022 12/31/2022
Canada Natural Gas Fixed price forward sales 269 C$2.36 1/1/2023 3/31/2023
Canada Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023
Canada Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024
Canada Natural Gas Fixed price forward sales 45 US$2.05 7/1/2022 12/31/2022
Canada Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024
Canada 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 2021 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 36 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.