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Item 7. Management’s Discussion and Analysis

2022-02-25 compared with 2021-02-26 · 235 added, 394 removed, 369 unchanged (63% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Murphy Oil Corporation is a worldwide oil and natural gas exploration and production company.

A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.

In 2020 the continued spread of coronavirus disease 2019 (COVID-19) has led to significant disruption in the global economy and an associated weakness in demand for crude oil which has resulted in lower commodity prices in 2020 versus 2019.

Commodity prices at the end of the first quarter and all of the second quarter were exceptionally impacted.

In the first quarter of 2020, certain major global suppliers of crude oil announced supply increases which resulted in a contribution to the lower global commodity prices in the first quarter, shortly followed by exceptional demand reduction from the COVID-19 pandemic.

In the second quarter of 2020, the OPEC+ group of oil producing countries agreed to supply restrictions which helped support the oil price in the latter part of the second quarter and through the year end.

Nevertheless, oil prices during 2020 remained below average 2019 prices.

In response to the COVID-19 pandemic and reduced commodity prices, the Company reduced 2020 capital expenditures significantly from the original plan of $1.4 billion to $1.5 billion to $712 million (adjusted for comparability to exclude NCI and Kings Quay expenditures).

The Company also executed a cost reduction plan for both future direct operational expenditures and general and administrative costs, including closing its 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 (see Note W – Restructuring Charges).

The Company is closely monitoring the impact of lower commodity prices on its current and future financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note H – Financing Arrangements and Debt).

Also see the Company’s response to COVID-19 as discussed in more detail in the Risk Factors starting on page 14.

Significant Company operating and financial highlights during 2020 were as follows:

• Preserved liquidity of $1.7 billion, including $310.6 million of cash as of December 31, 2020 and $1.4 billion available on an unsecured revolving credit facility

• Realized $272.0 million as a result of commodity price risk management (forward sale fixed swaps) activities

• Maintained capital discipline with full year accrued capital expenditures of $712.1 million, excluding noncontrolling interest ($21.7 million) and King’s Quay Floating Production System (FPS) of $92.8 million (which is held for sale at the end of 2020)

• Decreased full year Selling, general and administrative costs by 40% from 2019, as a result of a Company wide restructuring

• Produced 174,636 barrels of oil equivalent (BOE) per day (163,617 excluding noncontrolling interest, NCI)

Throughout this section, the term, ‘excluding noncontrolling interest’ or ‘excluding NCI’ refers to amounts attributable to Murphy.

Unless noted, amounts include noncontrolling interest.

Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids (NGL) and natural gas in the United States, Gulf of Mexico and Canada and then selling these products to customers.

The Company’s revenue is affected by the prices of crude oil, natural gas and NGL.

In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, depreciation of capital expenditures, and expenses related to exploration, administration, and for capital borrowed from lending institutions and note holders.

Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company.

In 2020, liquids from continuing operations represented 64% of total hydrocarbons produced on an energy equivalent basis.

In 2021, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 59%.

If the prices for crude oil and natural gas are lower in 2021 or beyond, this will have an unfavorable impact on the Company’s operating profits.

The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.

Oil prices weakened in 2020 compared to the 2019 period.

The sales price of a barrel of West Texas Intermediate (WTI) crude oil averaged $39.40 in 2020, $57.03 in 2019, and $64.77 in 2018.

The WTI index decreased approximately 31% over the prior year as a result of decreased demand during the global downturn triggered by the COVID-19 pandemic (see Risk Factors).

The most common crude oil indices used to price the Company’s crude include WTI Houston (MEH), Heavy Louisiana Sweet (HLS), Mars and Brent.

The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $1.99 in 2020, $2.52 in 2019 and 3.12 in 2018.

The 2020 NYMEX natural gas price was lower compared to the 2019 price.

On an energy equivalent basis, the market continued to discount North American natural gas and NGLs compared to crude oil in 2020.

Natural gas prices in North America in 2021 have thus far been above those in the comparable period in 2020.

Results of Operations

Murphy Oil’s results of operations, with associated diluted earnings per share (EPS), for the last three years are presented in the following table.

Years Ended December 31,

(Millions of dollars, except EPS )

2020 2019 2018

(Loss) income from continuing operations before income taxes $ (1,549.0) 203.5 43.0

Net (loss) income attributable to Murphy (1,148.8) 1,149.7 411.1

(7.48) 6.98 2.36

(Loss) income from continuing operations attributable to Murphy (1,141.6) 85.2 160.7

(7.43) 0.52 0.92

Loss (income) from discontinued operations (7.2) 1,064.5 250.3

(0.05) 6.46 1.44

For the year ended December 31, 2020, the Company produced 175 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations.

The Company invested $826.6 million in capital expenditures (on a value of work done basis) in the year ended December 31, 2020, which included $21.7 million attributable to noncontrolling interest and $92.8 million to fund the development of the King’s Quay FPS.

The Company reported net loss from continuing operations of $1,255.3 million (which includes post tax impairment charges of $854.2 million and loss attributable to noncontrolling interest of $113.7 million) for the year ended December 31, 2020.

For the year ended December 31, 2019, the Company produced 186 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations.

The Company invested $2.7 billion in capital expenditures (on a value of work done basis) for the year ended December 31, 2019, which included the LLOG acquisition of $1.2 billion.

The Company reported net income from continuing operations of $188.8 million (which includes income attributable to noncontrolling interest of $103.6 million) for the year ended December 31, 2019.

Other key performance metrics

The Company uses other operational performance and income metrics to review operational performance.

The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA.

Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.

Also presented below is adjusted EBITDA per barrel of oil equivalent sold.

Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period.

Adjusted EBITDA per barrel of oil equivalent sold is a non-GAAP financial metric.

Other key performance metrics (Cont’d.)

Year Ended December 31,

(Millions of dollars, except per barrel of oil equivalents sold)

2020 2019 2018

Net (loss) income attributable to Murphy (GAAP) $ (1,148.8) 1,149.7 411.1

Income tax expense (benefit) (293.7) 14.7 (126.1)

Interest expense, net 169.4 219.3 180.4

Depreciation, depletion and amortization expense 1

932.6 1,076.5 770.6

EBITDA attributable to Murphy (Non-GAAP) (340.5) 2,460.2 1,236.0

Impairment of assets ¹ 1,072.5 — 20.0

Mark-to-market loss (gain) on crude oil derivative contracts 69.3 33.4 (33.9)

Restructuring expenses 50.0 — —

Accretion of asset retirement obligations 42.1 40.5 27.1

Unutilized rig charges 16.0 — —

Mark-to-market loss (gain) on contingent consideration (13.8) 8.7 (4.8)

Inventory loss 8.3 — —

Discontinued operations (income) loss 7.2 (1,064.5) (250.3)

Retirement obligation (gains) losses ¹ (2.8) — —

Seal insurance proceeds (1.7) (8.0) (21.0)

Foreign exchange losses (gains) 0.7 6.4 (15.8)

Business development transaction costs — 24.4 —

Write-off of previously suspended exploration wells — 13.2 4.5

Ecuador arbitration settlement — — (26.0)

Brunei working interest income — — (16.0)

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 907.3 1,514.3 919.8

Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)

60,189 63,128 44,598

Adjusted EBITDA per barrel of oil equivalents sold $ 15.07 23.99 20.62

1 Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest.

Impairment of assets and retirement obligation gains used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest.

Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2020, are presented by segment.

More detailed reviews of operating results for the Company’s exploration and production and other activities follow the table.

A summary of Net (loss) income is presented in the following table.

( Millions of dollars )

2020 2019 2018

Exploration and production – continuing operations

United States

$ (1,014.3) 518.4 242.9

(35.0) (4.3) 51.1

Other International

(85.6) (53.5) (16.6)

Total exploration and production – continuing operations

(1,134.9) 460.6 277.4

Corporate and other

(120.3) (271.8) (108.3)

Income (loss) from continuing operations

(1,255.2) 188.8 169.1

Loss (income) from discontinued operations (7.2) 1,064.5 250.3

Net (loss) income including noncontrolling interest (1,262.4) 1,253.3 419.4

Net (loss) income attributable to noncontrolling interest (113.7) 103.6 8.4

Net (loss) income attributable to Murphy $ (1,148.7) 1,149.7 411.0

A summary of oil and natural gas revenues is presented in the following table.

( Millions of dollars )

2020 2019 2018

United States – Oil and natural gas liquids

$ 1,335.8 2,285.8 1,277.7

– Natural gas

69.4 73.9 53.6

Canada – Oil and natural gas liquids 174.0 287.4 302.8

– Natural gas

170.6 158.4 166.3

Total oil and natural gas revenues

$ 1,751.6 2,817.1 1,806.5

Exploration and Production

Please refer to Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities in the Supplemental Oil and Natural Gas Information section for supporting tables.

Exploration and Production (Contd.)

United States E&P operations reported earnings of $766.3 million in 2021 compared to a loss of $1,014.3 million in 2020.

Results were favorable $1,780.6 million in 2021 compared to the 2020 period primarily due to no impairment charges in 2021 (2020 :

$1,152.5 million), higher total revenues ($925.7 million), lower DD&A ($132.9 million), and lower LOE ($70.5 million), partially offset by higher income tax expense ($428.1 million) and higher other operating expense ($77.9 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 were primarily due to higher realized prices (oil and condensate, natural gas and NGLs) year over year, partially offset by lower sales volume (7,514 barrels of oil equivalent per day lower) as a result of lower capital expenditures 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 ($63.2 million;

as a result of higher commodity prices) from prior GOM acquisitions.

Canadian E&P operations reported a loss of $16.1 million in 2021 compared to a loss of $35.0 million in 2020.

Results were favorable $18.9 million compared to 2020 primarily due to higher revenue ($130.5 million) and lower DD&A ($49.4 million), partially offset by an impairment charge ($171.3 million), higher lease operating expense ($14.7 million), transportation, gathering and processing ($15.8 million) and income tax charges ($19.7 million).

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 and reversal of the asset abandonment decision.

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 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 from continuing operations of $33.5 million in 2021 compared to a loss of $85.6 million in 2020.

Results were favorable $52.1 million in 2021 compared to 2020 primarily due to lower impairment charges ($21.7 million), lower income tax charges ($11.6 million), lower exploration expenses ($5.9 million) primarily in Brazil and Mexico and lower LOE ($4.8 million).

All amounts include amounts attributable to a noncontrolling interest in MP GOM (a subsidiary of Murphy Expro USA, operating and developing properties in the Gulf of Mexico) and exclude discontinued operations, unless otherwise noted.

Exploration and production (E&P) continuing operations recorded a loss of $1,134.9 million in 2020 compared to earnings of $460.6 million in 2019.

The results for 2020 were unfavorably impacted by impairment charges and lower oil and natural gas liquid prices and volumes, partially offset by lower depreciation and accretion expenses, general and administrative (G&A) expenses, exploration expenses and taxes.

See below for further details.

Based on an evaluation of expected future cash flows from properties as of December 31, 2020, the Company did not have any other significant properties with carrying values that were impaired at that date.

If quoted prices decline in future periods, the lower level of projected cash flows for properties could lead to future impairment charges being recorded.

The Company cannot predict the amount or timing of impairment expenses that may be recorded in the future.

E&P from continuing operations recorded a loss of $1,134.9 million in 2020 compared to earnings of $460.6 million in 2019.

As a result of the COVID-19 pandemic and certain major global suppliers announcing crude oil supply increases in the first quarter of 2020, commodity prices were generally lower in 2020 vs 2019.

Crude oil price realizations averaged $38.02 per barrel in the current year compared to $60.27 per barrel in 2019, a price decrease of 37% year over year.

natural gas realized price per thousand cubic feet (MCF) averaged $2.02 in the current year compared to $2.45 per MCF in 2019, a price decrease of 18% year over year.

Crude oil price realizations averaged $38.02 per barrel in 2020 compared to $60.27 per barrel in 2019, a price decrease of 37% year over year.

natural gas realized price per MCF averaged $2.02 in 2020 compared to $2.45 per MCF in 2019, a price decrease of 18% year over year.

Canada natural gas realized price per MCF averaged U.S.

$1.79 in the current year compared to U.S.

$1.79 in 2020 compared to U.S.

$1.60 per MCF in 2019, a price increase of 12% year over year.

Oil and natural gas production costs, including associated production taxes, on a per-unit basis, were $9.81 in 2020 excluding TGP (2019:

The increase in production costs in 2020 is primarily attributable to costs associated with well workovers at Cascade and Dalmatian in the U.S.

Gulf of Mexico (discussed below).

The increase in production costs in 2020 was primarily attributable to costs associated with well workovers at Cascade and Dalmatian in the U.S.

Gulf of Mexico.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Exploration and Production (Contd.)

United States E&P operations reported a loss of $1,014.3 million in 2020 compared to earnings of $518.4 million in 2019.

Results were $1,532.7 million unfavorable in 2020 compared to the 2019 period primarily due to higher impairment charges ($1,152.5 million), lower revenues ($955.2 million) and higher lease operating expenses ($15.4 million), partially offset by lower income tax expense ($359.8 million), depreciation, depletion and amortization (DD&A) ($129.3 million), G&A

Exploration and Production

($49.7 million), other operating expenses ($27.2 million) and transportation, gathering, and processing ($13.1 million).

The impairment charge is primarily the result of lower future prices at the time of calculation, as a result of decreased oil demand.

The impairment charge was primarily the result of lower future prices at the time of calculation, as a result of decreased oil demand.

Lower revenues were primarily due to lower commodity prices year over year and lower volumes in the U.S.

1 unchanged sentence

Higher lease operating expenses were due primarily to Gulf of Mexico well workovers at Cascade ($51.3 million) and Dalmatian ($20.5 million).

Lower income tax expense is a result of pre-tax losses driven by the impairment charge and lower commodity prices.

Lower other operating expense is primarily due to a favorable mark to market revaluation on contingent consideration (as a result of lower commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($13.8 million).

Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).

Lower income tax expense was a result of pre-tax losses driven by the impairment charge and lower commodity prices.

Lower other operating expense was primarily due to a favorable mark-to-market revaluation on contingent consideration (as a result of lower commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($13.8 million).

Lower G&A was due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).

Canadian E&P operations reported a loss of $35.0 million in 2020 compared to income of $4.3 million in 2019.

2 unchanged sentences

Lower DD&A and lease operating expenses were a result of lower sales.

Lower income tax expense is a result of pre-tax losses.

Lower G&A is due to cost reductions and lower headcount as a result of restructuring.

Lower income tax expense was a result of pre-tax losses.

Lower G&A was due to cost reductions and lower headcount as a result of restructuring.

Other international E&P operations reported a loss from continuing operations of $85.6 million in 2020 compared to a loss of $53.5 million in the prior year.

The 2020 results include an impairment charge of $39.7 million and lower revenues of $9.8 million in Brunei.

E&P continuing operations recorded a profit of $460.6 million in 2019 compared to a profit of $277.4 million in 2018.

The results for 2019 were favorably impacted by higher oil and natural gas volumes, lower exploration expenses, and no impairment charge, partially offset by higher lease operating expenses and transportation, gathering and processing expenses, higher G&A expenses, higher DD&A and higher taxes.

Crude oil price realizations averaged $60.27 per barrel 2019 compared to $65.87 per barrel in 2018, a price decrease of 9% year over year.

natural gas realized price per thousand cubic feet (MCF) averaged $2.45 in 2019 compared to $3.18 per MCF in 2018, a price decrease of 23% year over year.

Canada natural gas realized price per MCF averaged U.S.$1.60 in 2019 compared to U.S.

$1.71 per MCF in 2018, a price decrease of 6% year over year.

Oil and natural gas production costs, including associated production taxes, on a per-unit basis, were $9.66 in 2019 (2018:

$9.02), which together with higher oil and natural gas volumes sold, resulted in $247.2 million higher costs in 2019.

United States E&P operations reported earnings of $518.4 million in 2019 compared to earnings of $242.9 million in 2018.

Results were $275.5 million favorable in the 2019 period compared to the 2018 period due to higher revenues ($1,034.3 million), partially offset by higher DD&A ($359.2 million), lease operating expenses ($231.0 million), transportation, gathering and processing ($97.7 million) income tax expense ($47.5 million), other operating expenses ($29.2 million) and G&A ($25.3 million).

Higher revenues were primarily due to higher volumes from the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019.

Higher lease operating, transportation, gathering and processing expenses and DD&A were primarily due to higher volumes.

Higher income taxes were due to higher profits.

Higher other operating expense was due to higher business development, acquisition transaction costs and mark to market valuation on contingent consideration.

Higher G&A was due to higher long-term incentive charges.

Canadian E&P operations reported a loss of $4.3 million in 2019 compared to earnings of $51.1 million in 2018.

Results were unfavorable $55.4 million primarily due to lower revenues ($23.5 million), higher lease operating expense ($19.8 million), lower other income ($13.0 million) primarily related to more Seal insurance proceed received in 2018;

and partially offset by lower income tax charges ($17.4 million).

Lower revenues were due to lower oil and condensate prices than 2018 and a shut-in at Hibernia in the third quarter of 2019, partially offset by higher volumes at Kaybob Duvernay and Tupper Montney.

Higher lease operating expenses were due to higher costs at Tupper Montney as a result of transferring a gain on a previous natural gas processing plant sale and lease-back transaction to equity as a result of the implementation of ASC 842 (see Note B – New Accounting Principles and Recent Accounting Pronouncements).

In 2018, this gain was being credited to operating expenses equally over the life of the lease.

Other international E&P operations reported a loss from continuing operations of $53.5 million in 2019 compared to a net loss of $16.6 million in 2018.

The 2019 result included the write-off of previously suspended exploration costs of $13.2 million attributable to the CM-1X and the CT-1X wells (originally drilled in 2017) in Vietnam and lower revenues from Brunei ($10.6 million), and lower tax benefits ($12.9 million).

The 2020 results included an impairment charge of $39.7 million and lower revenues of $9.8 million in Brunei.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.

8 unchanged sentences

Lease operating expense 10.63 11.95 10.89

11.95 10.89 11.39

Severance and ad valorem taxes 0.07 — —

DD&A expense 9.51 13.48 16.43

5 unchanged sentences

Lease operating expense 13.04 17.86 14.95

17.86 14.95 15.21

DD&A expense 12.80 12.01 13.07

1 unchanged sentence

Lease operating expense 8.86 9.34 8.95

9.34 8.95 7.87

Severance and ad valorem taxes 0.68 0.44 0.71

2 unchanged sentences

Lease operating expense

8.65 9.10 8.81

Severance and ad valorem taxes 0.71 0.47 0.76

3 unchanged sentences

DD&A expense — — 4.60

1 For the year ended December 31, 2020, lease operating expense (LOE) per barrel of oil equivalents (BOE) sold for the U.S.

Gulf of Mexico excluding cost associated with well workovers was $9.52.

Workovers for the year ended December 31, 2020 included Dalmatian and Cascade.

2 For the year ended December 31, 2020, Canada Offshore LOE per BOE excluding the costs associated with the Terra Nova life extension project was $5.24.

3 For the year ended December 31, 2020, total LOE per BOE excluding cost associated with Gulf of Mexico well workovers was $7.91.

On May 6, 2020, the Company announced that it was closing its 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.

As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net loss in 2020.

These costs include severance, relocation, IT costs, pension curtailment and a write-off of the right of use asset lease associated with the Canada office.

Further, the office building in El Dorado is classified as held for sale.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a loss of $120.3 million in 2020 compared to a loss of $271.8 million in 2019.

The $151.5 million favorable variance is primarily due to higher realized gains on forward swap commodity contracts ($239.5 million), lower interest charges ($50.2 million), lower G&A ($14.5 million), and partially offset by higher tax charges ($55.3 million), restructuring charges ($48.8 million) related to the closure of the El Dorado and Calgary offices, and impairment charges ($14.1 million).

Higher realized gains on forward swap commodity contracts are due to lower market pricing whereby the contract provides the Company with a fixed price.

Interest charges are lower primarily due to 2019 temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the RCF borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business) and gains from the buy-back of debt in the second quarter 2020.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains and 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 $668.0 million in 2021 compared to a loss of $120.3 million in 2020.

The $547.7 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021:

$525.9 million loss;

$202.7 million gain) and higher interest expense ($53.0 million), partially offset by a higher tax benefit ($148.3 million), lower restructuring charges ($48.8 million), lower G&A expenses ($12.9 million), and lower impairment charges ($7.1 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, with variability in between the floor and ceiling.

Higher interest costs are principally due to debt redemption costs on the 2022 notes and $550.0 million issuance of new notes in March 2021 that bear interest at a rate of 6.375% and mature on July 15, 2028.

Higher income tax benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments.

Lower restructuring charges and G&A 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.

In 2020, the Company announced that it was closing its 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.

As a result, certain directly attributable costs and charges were recognized and reported as Restructuring charges as part of net loss in 2020.

These costs included severance, relocation, IT costs, pension curtailment and a write-off of the right of use asset lease associated with the Canada office.

Further, the office building in El Dorado was classified as held for sale.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains and losses on derivative instruments and corporate overhead not allocated to Exploration and Production, reported a loss of $120.3 million in 2020 compared to a loss of $271.8 million in 2019.

The $151.5 million favorable variance was primarily due to higher realized gains on forward swap commodity contracts ($239.5 million), lower interest charges ($50.2 million), lower G&A ($14.5 million), and partially offset by higher tax charges ($55.3 million), restructuring charges ($48.8 million) related to the closure of the El Dorado and Calgary offices, and impairment charges ($14.1 million).

Higher realized gains on forward swap commodity contracts were due to lower market pricing whereby the contract provides the Company with a fixed price.

Interest charges were lower primarily due to 2019 temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the RCF borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business) and gains from the buy-back of debt in the second quarter 2020.

As of December 31, 2020, the average forward NYMEX WTI prices for 2021 and 2022 were $48.34 and $46.76, respectively (versus fixed hedge prices of $42.77 and $44.88).

see Outlook section).

Corporate activities, as defined above, reported a net loss of $271.8 million in 2019 compared to a loss of $108.3 million in 2018.

The $163.5 million unfavorable variance is due to a 2018 income tax credit ($120.0 million, related to an IRS interpretation of the Tax Act), higher interest charges ($38.6 million) primarily due to early retirement of debt, foreign exchange losses ($6.6 million;

versus an $16.1 million gain in 2018), Ecuador arbitration income in 2018 ($26.0 million);

partially off-set by lower losses on forward crude contracts ($41.1 million) and lower income taxes (excluding the $120 million tax act credit;

$22.1 million).

Discontinued Operations

The Company has presented its Malaysia E&P operations and former U.K.

refining and marketing operations as discontinued operations in its consolidated financial statements.

In 2020, discontinued operations reported a loss of $7.2 million, primarily related to charges in Malaysia following the sale of this business in 2019 (see below).

Malaysia E&P operations reported earnings of $1,086.6 million in 2019 compared to $251.7 million in the 2018 period.

Results for 2019 were favorable by $834.9 million primarily as a result of the gain on sale of Malaysia to PTT Exploration and Production Public Company Limited (PTTEP) (see Note G – Property, Plant, and Equipment).

The sale closed on July 10, 2019.

The Company recognized a net gain of $985.4 million on the transaction.

Excluding the gain, Malaysia income was $168.2 million lower than the 2018 period principally due to lower revenues ($486.4 million), partially offset by lower operating expenses ($74.9 million), lower depreciation ($164.9 million) and lower income taxes ($73.1 million).

Lower revenues are principally due to lower volumes sold as a result of a partial year of operations and declining daily production.

The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale and partial year of operations.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Production Volumes and Prices

Total hydrocarbon production from all E&P continuing operations averaged 167,356 barrels of oil equivalent per day in 2021, which represented a 4% decrease from the 174,636 barrels per day produced in 2020.

Production in the Gulf of Mexico was significantly impacted by a record breaking hurricane year which resulted in shut-ins and loss of approximately 6.4 MBOED of production in 2020.

Lower volumes in the Eagle Ford Shale volumes were due to lower capital expenditures.

Average crude oil and condensate production from continuing operations was 95,705 barrels per day in 2021 compared to 103,966 barrels per day in 2020.

The decrease of 10,776 barrels per day was principally due to lower Eagle Ford Shale production (8,158 barrels per day) and lower volumes in the Gulf of Mexico (2,143 barrels per day) as stated above.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $38.02 per barrel in 2020 compared to $60.27 per barrel in the 2019 period, a decrease of 37% year over year, resulting from the global downturn triggered by the COVID-19 pandemic.

The decrease of 8,261 barrels per day was principally due to lower volumes in the Gulf of Mexico (2,703 barrels per day primarily due to reservoir decline), lower volumes at Kaybob Duvernay (2,272 barrels per day due to well decline) and lower Eagle Ford Shale production (765 barrels per day).

On a worldwide basis, the Company’s crude oil and condensate prices averaged $66.80 per barrel in 2021 compared to $38.02 per barrel in the 2020 period, an increase of 76% year over year.

Total production of natural gas liquids (NGL) from continuing operations was 10,385 barrels per day in 2021 compared to 11,541 barrels per day in the 2020 period.

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Natural gas sales volumes from continuing operations averaged 368 million cubic feet per day (MMCFD) in 2021 compared to 355 MMCFD in 2020.

The increase of 1 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (14 MMCFD) due to a full year contribution from the assets associated with the LLOG transaction.

The increase of 13 MMCFD was primarily the result of higher volumes in Canada.

Higher natural gas volumes in Canada are primarily due to bringing online 14 new wells at Tupper Montney in 2021.

Higher volumes at Tupper Montney were partially offset by lower gas volumes in the Gulf of Mexico.

Natural gas prices for the total Company averaged $2.74 per thousand cubic feet (MCF) in 2021, versus $1.85 per MCF average in the same period of 2020.

Average natural gas prices in the US and Canada in 2020 were $2.02 and $1.79 per MCF, respectively.

Total hydrocarbon production from continuing operations averaged 185,649 barrels of oil equivalent per day in 2019, which represented a 49% increase from the 124,337 barrels per day produced in 2018.

The increase was principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.

Average realized natural gas prices in the US and Canada in 2021 were $3.71 and $2.43 per MCF, respectively.

Total hydrocarbon production from continuing operations averaged 174,636 barrels of oil equivalent per day in 2020, which represented a 6% decrease from the 185,649 barrels per day produced in 2019.

Production in the Gulf of Mexico was significantly impacted by a record breaking hurricane year which resulted in shut-ins and loss of approximately 6.4 MBOED of production in 2020.

Lower volumes in the Eagle Ford Shale volumes were due to lower capital expenditures.

Average crude oil and condensate production from continuing operations was 103,966 barrels per day in 2020 compared to 114,742 barrels per day in 2019.

The increase of 51,304 barrels per day was principally due to higher volumes in the Gulf of Mexico (48,121 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $60.27 per barrel in 2019 compared to $65.87 per barrel in 2018, a decrease of 9% year over year.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $38.02 per barrel in 2020 compared to $60.27 per barrel in 2019, a decrease of 37% year over year, resulting from the global downturn triggered by the COVID-19 pandemic.

Total production of natural gas liquids (NGL) from continuing operations was 11,541 barrels per day in 2020 compared to 11,888 per day in 2019.

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Natural gas sales volumes from continuing operations averaged 355 million cubic feet per day (MMCFD) in 2020 compared to 354 MMCFD in 2019.

The increase of 42 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (38 MMCFD).

Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.

The increase of 1 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (14 MMCFD) due to a full year contribution from the assets associated with the LLOG transaction.

Natural gas prices for the total Company averaged $1.85 per thousand cubic feet (MCF) in 2020, versus $1.8 per MCF average in 2019.

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and Canada in 2020 were $2.02 and $1.79 respectively.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table contains hydrocarbons produced during the three years ended December 31, 2021.

Barrels per day unless otherwise noted 2021 2020 2019

2020 2019 2018

Continuing operations

Net crude oil and condensate

United States

26,420 34,578 31,787

United States Onshore 25,655 26,420 34,578

Gulf of Mexico 1

60,717 64,680 66,823

7,888 6,329 5,690

4,893 6,543 6,701

Canada Onshore 5,312 7,888 6,329

Offshore 3,765 4,893 6,543

Other 256 85 469

Total net crude oil and condensate - continuing operations 95,705 103,966 114,742

103,966 114,742 63,438

Net natural gas liquids

United States

5,248 5,731 6,578

United States Onshore 5,092 5,248 5,731

Gulf of Mexico 1

4,176 4,978 4,894

1,315 1,263 1,073

Canada Onshore 1,117 1,315 1,263

Total net natural gas liquids - continuing operations 10,385 11,541 11,888

11,541 11,888 8,798

Net natural gas – thousands of cubic feet per day

United States

27,985 30,692 31,832

United States Onshore 28,565 27,985 30,692

Gulf of Mexico 1

61,240 66,105 52,068

260,683 271,355 266,416

Canada Onshore 277,790 260,683 271,355

Total net natural gas - continuing operations 367,595 354,773 354,115

354,773 354,115 312,604

Total net hydrocarbons - continuing operations including NCI 2,3

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Net crude oil and condensate – barrels per day (8,623) (9,962) (11,226)

(9,962) (11,226) (1,134)

Net natural gas liquids – barrels per day (303) (416) (507)

(416) (507) (24)

Net natural gas – thousands of cubic feet per day 2

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Total noncontrolling interest (9,465) (11,019) (12,394)

(11,019) (12,394) (1,230)

Total net hydrocarbons - continuing operations excluding NCI 2,3

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Net crude oil and condensate – barrels per day — — 12,215

— 12,215 28,676

Net natural gas liquids – barrels per day — — 325

Net natural gas – thousands of cubic feet per day 2

— 50,758 110,223

Total discontinued operations — — 21,000

— 21,000 47,839

Total net hydrocarbons produced excluding NCI 2,3

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4 December 31, 2021, 2020 and 2019, include 18.4 MMBOE, 17.4 MMBOE and 24.6 MMBOE, respectively, relating to noncontrolling interest.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table contains hydrocarbons sold during the three years ended December 31, 2021.

Barrels per day unless otherwise noted 2021 2020 2019

2020 2019 2018

Continuing operations

Net crude oil and condensate

United States

26,420 34,578 31,787

United States Onshore 25,655 26,420 34,578

Gulf of Mexico 1

60,544 65,621 66,272

7,888 6,329 5,690

4,958 6,722 6,884

Canada Onshore 5,312 7,888 6,329

Offshore 3,559 4,958 6,722

Other 195 78 427

Total net crude oil and condensate - continuing operations 95,265 104,965 114,328

104,965 114,328 62,323

Net natural gas liquids

United States

5,248 5,731 6,578

United States Onshore 5,092 5,248 5,731

Gulf of Mexico 1

4,176 4,978 4,894

1,315 1,263 1,073

Canada Onshore 1,117 1,315 1,263

Total net natural gas liquids - continuing operations 10,385 11,541 11,888

11,541 11,888 8,798

Net natural gas – thousands of cubic feet per day

United States

27,985 30,692 31,832

United States Onshore 28,565 27,985 30,692

Gulf of Mexico 1

61,240 66,105 52,068

260,683 271,355 266,416

Canada Onshore 277,790 260,683 271,355

Total net natural gas - continuing operations 367,595 354,773 354,115

354,773 354,115 312,604

Total net hydrocarbons - continuing operations including NCI 2,3

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Net crude oil and condensate – barrels per day (8,605) (10,127) (11,115)

(10,127) (11,115) (940)

Net natural gas liquids – barrels per day (303) (416) (507)

(416) (507) (24)

Net natural gas – thousands of cubic feet per day 2

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Total noncontrolling interest (9,447) (11,184) (12,283)

(11,184) (12,283) (1,036)

Total net hydrocarbons - continuing operations excluding NCI 2,3

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Net crude oil and condensate – barrels per day — — 12,100

— 12,100 29,426

Net natural gas liquids – barrels per day — — 296

Net natural gas – thousands of cubic feet per day 2

— 50,758 110,223

Total discontinued operations — — 20,856

— 20,856 48,583

Total net hydrocarbons sold excluding NCI 2,3

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3 NCI – noncontrolling interest in MP GOM.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table contains the weighted average sales prices excluding transportation cost deduction for the three years ended December 31, 2021.

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Crude oil and condensate – dollars per barrel

United States

Onshore $ 36.54 59.45 67.80

United States Onshore $ 66.90 36.54 59.45

Gulf of Mexico 1

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Offshore 71.39 39.40 64.91

63.51 74.70 71.48

Other 69.21 63.51 74.70

Natural gas liquids – dollars per barrel

United States

Onshore 11.67 14.60 25.68

United States Onshore 26.97 11.67 14.60

Gulf of Mexico 1

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Natural gas – dollars per thousand cubic feet

United States

Onshore 1.95 2.47 3.11

United States Onshore 3.83 1.95 2.47

Gulf of Mexico 1

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3 Prices are net of payments under the terms of the respective production sharing contracts.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Financial Condition

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Net cash provided by continuing operating activities was $1,422.2 million in 2021 compared to $802.7 million in 2020.

The decreased cash from operating activities is primarily attributable to lower revenue from sales to customers ($1,065.4 million), partially offset by higher cash payments received on forward swap commodity contracts ($239.5 million), lower general and administrative expenses ($92.5 million) and lower lease operating expenses ($5.1 million).

The increased cash provided by continuing operating activities of $619.5 million is primarily attributable to higher revenue from sales to customers ($1,049.5 million), positive effect of movements on payable and receivable working capital balances ($118.5 million), lower lease operating expenses ($60.5 million), lower general and administrative and cash restructuring expenses ($50.7 million), partially offset by higher cash payments made on forward swap commodity contracts (2021:

realized loss of $413.7 million;

realized gain of $272.0 million).

Higher revenues were primarily due to higher commodity prices driven by OPEC+ supply constraints and the increase in demand.

Cash flow provided by continuing operations was $686.4 million lower in 2020 than in 2019 primarily due to lower revenues, partially offset by higher cash payments received on forward swap commodity contracts.

Lower revenues were primarily due to lower commodity prices resulting from lower demand triggered by the COVID-19 pandemic and lower volumes (due to reduced capital expenditures).

See above for further explanation of underlying business reasons.

Cash flow provided by continuing operations was $739.7 million higher in 2019 than in 2018 due to higher Sales volume and higher realized gain on forward crude contracts partially off-set by higher lease operating, transportation, gathering and processing expenses.

Higher revenues, lease operating, transportation, gathering and processing expenses and higher depreciation expenses are principally a result of the LLOG acquisition and a full year of the 2018 MP GOM transaction, which was completed in the fourth quarter 2018.

The total reductions of operating cash flows for interest paid during the three years ended December 31, 2020, 2019, and 2018 were $191.6 million, $179.7 million, and $158.1 million, respectively.

The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in Financing activities) during the three years ended December 31, 2021, 2020, and 2019 were $165.7 million, $191.6 million, and $179.7 million, respectively.

Lower cash interest paid in 2021 was due to the repayment of the $200 million outstanding on the revolving credit facility, the early redemption of the 2022 notes and the early redemption of $300 million of the 2024 notes, partially offset by interest paid on the issuance of 2028 notes in the first quarter of 2021.

Higher cash interest paid in 2020 was due to the new 2027 notes paying interest at 5.875% and revolver borrowing during the year.

Higher cash interest paid in 2019 was due to maintaining a higher average outstanding revolver balance 2019 (timing of LLOG acquisition and Malaysia disposition) and also the cost of the $500 million term loan outstanding from May to July 2019.

Cash Used for Investing Activities

Cash used for property additions and dry holes, which includes amounts expensed, were $688.2 million and $872.8 million in 2021 and 2020, respectively.

In 2020, this includes $113.0 million used to fund the development of the King’s Quay FPS, which is expected to be refunded on the closing of a transaction to sell this asset to a third party.

Lower property additions in 2020 are a result of a significant (approximately 50%) reduction to the 2020 capital spending budget in response to the reduced commodity price environment.

In 2019 and 2018, property additions included the LLOG and MPGOM acquisitions, respectively.

The accrual basis of capital expenditures, which includes $1,261.1 million for proved property acquisitions (principally the LLOG acquisition) in 2019 and the $794.6 million MP GOM acquisition in 2018, were as follows:

These amounts include $17.7 million and $113.0 million used to fund the development of the King’s Quay FPS in 2021 and 2020.

In March 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.

2021 also includes proved property acquisitions for an additional interest in the Lucius property of $19.9 million.

Lower property additions in 2021 are principally due to lower capital spending at Eagle Ford Shale and lower spend on King’s Quay.

In 2019, property additions included $1,261.1 million for the LLOG acquisition.

The accrual (value of work done) basis of capital expenditures were as follows:

Year Ended December 31,

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A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Financial Condition (Contd.)

Year Ended December 31,

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Property additions King's Quay per cash flow statements 17.7 113.0 100.2

Acquisition of oil properties per the cash flow statements — 1,212.3 794.6

Geophysical and other exploration expenses 26.9 32.3 48.5

Capital expenditure accrual changes and other (3.9) (78.5) 93.1

Acquisition of oil properties per the cash flow statements — — 1,212.3

Total capital expenditures $ 711.2 826.6 2,698.2

Capital expenditures in the exploration and production business in 2020 compared to 2019 have decreased as a result of the 2019 LLOG acquisition and in response to the current commodity price environment, resulting in lower capital expenditures in

Financial Condition (Contd.)

the Eagle Ford Shale.

The King’s Quay FPS development project is expected to be refunded on the closing of a transaction to sell this asset to a third party.

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 free cash flow.

Cash Used by and Provided by Financing Activities

Net cash provided by financing activities was $39.7 million in 2020 compared to net cash used by financing activities of $1,130.0 million during 2019.

In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($200.0 million), partially offset by dividends paid ($96.0 million) and distributions to noncontrolling interest ($43.7 million).

Net cash required by financing activities was $794.5 million in 2021 compared to net cash provided by financing activities of $39.7 million during 2020.

In 2021, the cash required by financing activities was principally due to the repayment of the balance outstanding on the revolving credit facility ($200.0 million), the early redemption of the remainder of the 2022 notes ($576.4 million), the early redemption of a portion of the 2024 notes ($300.0 million), costs associated with early redemption ($39.3 million), dividends paid ($77.2 million) and distributions to noncontrolling interest ($137.5 million), partially offset by issuance of 2028 notes ($541.9 million).

The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital.

The Company generally uses its internally generated funds to finance its capital and operating expenditures, but it also maintains lines of credit with banks and will borrow as necessary to meet spending requirements.

At December 31, 2020, the Company has a $1.6 billion senior unsecured guaranteed credit facility (RCF) with a major banking consortium, which expires in November 2023.

As of December 31, 2021, the Company has a $1.6 billion senior unsecured guaranteed credit facility (RCF) with a major banking consortium, which expires in November 2023.

As of December 31, 2021 and in the event it is required to fund investing activities from borrowings, the Company has approximately $1.6 billion available on its committed revolving credit facility.

In 2019, the cash required by financing activities of $1,130.0 million was principally from borrowings on our revolver and short-term loan ($1,725.0 million) to fund the LLOG acquisition.

These borrowings, along with the opening revolver balance ($325.0 million) of $2,050.0 million were repaid in July 2019 following the completion of the Malaysia divestment.

The Company issued $550 million notes due December 2027 that bear a rate of 5.875%, for net proceeds of $542.4 million;

these proceeds were used to redeem a portion of the Company’s $500 million 4.00% notes due June 2022 and a portion of the Company’s $600 million 4.45% notes due December 2022 ($521.3 million in the aggregate).

The Company paid an early retirement premium of $26.6 million in relation to the retirement of the debt.

Finally, in 2019, the Company also used cash to buy back issued ordinary shares ($499.9 million), pay dividends ($163.7 million) and make distributions to noncontrolling interest ($128.2 million).

In 2018, net cash provided by financing activities of $143.6 million consisted of $325.0 million of borrowings on the Company’s revolving credit facility to partially fund the MP GOM transaction, which was fully repaid following the completion of the Malaysia divestment in 2019, offset by dividends paid ($173.0 million).

In 2020, net cash provided by financing activities of $39.7 million was principally from borrowings on the Company’s RCF ($200.0 million), partially offset by dividends paid ($96.0 million) and distributions to noncontrolling interest ($43.7 million).

In 2019, net cash required by financing activities of $1,130.0 million consisted of $548.0 million to redeem a portion of the 2022 notes, $499.9 million to buy back issued ordinary shares, $325.0 million to repay the RCF, $163.7 million to pay dividends, and $128.2 million to cover distributions to noncontrolling interest, net of proceeds of $542.4 million from the issuance of the 2027 notes.

Working Capital

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net working capital liability of $29.4 million).

The total working capital liability reduction of $49.6 million in 2020 is primarily attributable lower accounts receivable ($164.7 million) and lower inventory ($10.0 million) offset by lower accounts payable ($195.0 million) and lower other accrued liabilities ($46.9 million).

Lower accounts receivable is due to both lower sales volumes and lower commodity sales prices.

Lower accounts payable is due to overall lower business activity, principally lower capital expenditures in the fourth quarter 2020 compared to 2019 resulting in both lower trade payables and capital expenditure accruals, and lower volumes resulting in lower royalties payable.

Lower other accrued liabilities is principally due to lower liabilities associated with compensation awards and benefits.

The total working capital liability increase of $269.5 million in 2021 is primarily attributable to higher accounts payable ($216.0 million) and higher other accrued liabilities ($210.3 million), partially offset by higher cash and cash equivalents ($210.6 million).

The higher accounts payable is due to the increase in unrealized losses on derivative instruments (commodity swap and collar) maturing in the next 12 months.

The higher other accrued liabilities are principally due to higher liabilities associated with current asset retirement obligations, and contingent consideration liabilities related to prior GOM acquisitions.

Cash and cash equivalents as of December 31, 2021 totaled $521.2 million (2020:

$310.6 million).

Borrowings of $200.0 million from the revolving credit facility were outstanding at the end of the year (2019:

no borrowings).

Cash and invested cash are maintained in several operating locations outside the United States.

At December 31, 2020, Cash and cash equivalents held outside the U.S.

There were no borrowings from the RCF outstanding at the end of the year (2020:

$200.0 million).

Cash in the year benefited from a positive working capital inflow of $118.5 million principally due to increasing liabilities associated with a major U.S.

Offshore capital project expected to begin production mid-2022.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Financial Condition (Contd.)

Cash and invested cash are maintained in several operating locations outside the U.S.

As of December 31, 2021, Cash and cash equivalents held outside the U.S.

included U.S dollar equivalents of approximately $242.9 million (2020:

$116.5 million), the majority of which was held in Canada.

In addition, approximately $10.2 million of cash were held in Brunei, respectively, and has been classified as part of Assets held for sale in the Consolidated Balance Sheets at year-end 2020.

$119.3 million), the majority of which was held in Canada ($175.0 million).

In addition, approximately $26.2 million and $14.0 million of cash was held in Brazil and the U.K., respectively.

In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S.

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Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

See Note J – Income Taxes for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

See Note I – Income Taxes for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

Capital Employed

At December 31, 2020, long-term debt of $2,988.1 million had increased by $184.7 million compared to December 31, 2019, as a result of net borrowing of $200.0 million on the revolving credit facility.

As of December 31, 2021, long-term debt of $2,465.4 million had decreased by $522.7 million compared to December 31, 2020, as a result the net repayment of the $200.0 million outstanding on the revolving credit facility December 31, 2020, the early redemption of the 2022 notes and the early redemption of $300.0 million of the 2024 notes, partially offset by issuance of 2028 notes.

The fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.2%.

A summary of capital employed at December 31, 2020 and 2019 follows.

Financial Condition (Contd.)

A summary of capital employed as of December 31, 2021 and 2020 follows.

December 31, 2021 December 31, 2020

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$4.21 billion).

Shareholders’ equity decreased in 2020 primarily due to the net loss ($1.15 billion), which was driven by impairment charges ($1.21 billion) as a result of lower future prices at the time of calculation, as a result of decreased oil demand.

Shareholders’ equity decreased in 2021 primarily due to dividends paid ($77.2 million) and a 2021 net loss ($73.7 million), partially offset by a favorable revaluation of pension assets and liabilities ($59.8 million).

A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 72 of this Form 10-K report.

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Other significant changes in Murphy’s balance sheet at the end of 2021, compared to 2020 are discussed below.

Property, plant and equipment, net of depreciation decreased $1,700.7 million principally due to impairment charges ($1,206.3 million) primarily the result of lower forecast future prices, as a result of decreased oil demand triggered by the COVID-19 pandemic and an annual charge of depreciation, depletion and amortization.

Property, plant and equipment, net of depreciation decreased $141.2 million principally due to an annual charge of depreciation, depletion and amortization ($795.1 million) of these balances and impairment charges ($196.3 million), offset by capital expenditures in the year.

Capital expenditures are discussed above in the ‘Cash Used for Investing Activities’ section.

An impairment charge of $171.3 million was triggered when the operator at Terra Nova provided notice of abandonment in the first quarter of 2021, before a commercial resolution in the third quarter of 2021 led Murphy to acquire an additional 7.525% in a commercial settlement with the other partners.

The commercial resolution would have meant the Terra Nova impairment charge was not required.

In the fourth quarter of 2021, a further impairment charge of $25.0 million was recorded on non-core assets.

Murphy had commitments for capital expenditures of approximately $520.1 million at December 31, 2021 (2020:

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This amount includes $175.9 million for approved expenditure for capital projects relating to non-operated interests in deepwater U.S.

Gulf of Mexico, principally at St Malo ($392.5 million) and Lucius ($113.2 million).

Operating lease assets and liabilities increased $329.4 million principally due to the addition of a 5-year lease for the Cascade/Chinook FPSO in the U.S.

Gulf of Mexico ($268.8 million) and a 20-year lease related to a gas plant expansion in Canada ($168.4 million).

Deferred income tax assets increased $266.0 million as a result of the increase in the estimated U.S.

net operating loss of $2.8 billion at year-end 2020, up from $2.4 billion at year-end 2019.

Long-term asset retirement obligations decreased $9.5 million to $816.3 million, principally due to lower cost estimates.

Deferred credits and other liabilities increased $67.2 million primarily as a result of the pension remeasurement which was triggered by the restructuring.

The Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction of force.

At December 31, 2020, the Company had $200.0 million of outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

Gulf of Mexico, principally at St.

Malo ($173.0 million), non-operated Canada interests, mainly offshore ($84.7 million), non-operated Eagle Ford Shale ($18.1 million), Brazil ($16.3 million), Vietnam ($6.1 million), and Brunei ($2.6 million).

Assets held for sale of $15.5 million decreased $312.3 million due to the March 2021 sale of King’s Quay FPS to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million.

Operating lease assets ($881.4 million) and liabilities ($900.6 million) decreased $46.3 million principally due to an annual charge of depreciation, depletion and amortization and 2021 annual payments reducing the operating lease liabilities.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Financial Condition (Contd.)

Long-term asset retirement obligations increased $23.5 million to $839.8 million, principally due to inflationary pressures from higher oil prices and associated demand for services.

Deferred credits and other liabilities decreased $110.0 million primarily as a result of the pension fair value remeasurement and cash pension contributions to the plan in 2021.

At December 31, 2021, the Company had no outstanding borrowings under the RCF and $31.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

Borrowings under the RCF bear interest at rates, based, at the Company’s option, on the “Alternate Base Rate” of interest in effect plus the “ABR Spread” or the “Adjusted LIBOR Rate,” which is a periodic fixed rate based on LIBOR with a term equivalent to the interest period for such borrowing, plus the “Eurodollar Spread.” The “Alternate Base Rate” of interest is the highest of (i) the Wall Street Journal prime rate, (ii) the New York Federal Reserve Bank Rate plus 0.50%, and (iii) one-month LIBOR plus 1.00%.

Note that in July 2017, the Financial Conduct Authority in the U.K.

announced a desire to phase out LIBOR as a benchmark by the end of 2021.

Some USD LIBOR tenors (overnight, 1-month, 3-month, 6-month and 12-month) will continue to be published until June 30, 2023.

See “Risk Factors – Financial Risk Factors – Capital Financing” for further discussion.

The “Eurodollar Spread” ranges from 1.075% to 2.10% per annum based upon the Corporation’s senior unsecured long-term debt securities credit ratings (the “Credit Ratings”).

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At December 31, 2021, the Company was in compliance with all covenants related to the RCF.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Environmental, Health and Safety Matters

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These plans are presented to, reviewed and approved by a Health, Safety, Environmental and Corporate Responsibility Committee consisting of certain members of Murphy’s Board of Directors.

Environmental Matters (Cont’d.)

The oil and natural gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations.

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The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials;

the emission and discharge of such materials to the environment, including greenhouse gas emissions;

the emission and discharge of such materials to the environment, including GHG emissions;

wildlife, habitat and water protection;

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Further information on environmental, health and safety laws and regulations applicable to Murphy are contained in the Business section beginning page 11.

Climate Change

Climate Change and Emissions

The world’s population and standard of living is growing steadily along with the demand for energy.

Murphy recognizes that this generates increasing amounts of greenhouse gases (GHGs), which raise important climate change concerns.

Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the Task Force for Climate-related Financial Disclosures (TCFD) core elements.

Murphy recognizes that this may generate increasing amounts of greenhouse gases, which raise important climate change concerns.

Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the Task Force on Climate-related Financial Disclosures (TCFD) core elements.

The TCFD was created by the Financial Stability Board to focus on climate-related financial disclosures to improve and increase reporting of climate-related financial information.

Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2020 Sustainability Report issued on October 9, 2020, which is not incorporated by reference hereto.

Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2021 Sustainability Report issued on August 5, 2021, which is not incorporated by reference hereto.

During 2021 the Company made significant strides in our sustainability efforts, including:

• Establishing a further goal of reducing our GHG emissions intensity 15 percent to 20 percent by 2030 from our 2019 levels, excluding divested assets from the 2019 baseline, for an aggregate of 35 percent to 40 percent reduction from our reported 2019 levels;

• Expanding our GHG, air quality, climate risk management and biodiversity management public disclosures;

• Expanding the purview of our health, safety, environmental and corporate responsibility committee consisting of certain members of Murphy’s Board of Directors to include environmental, social and governance (ESG) issues, and creating a director of sustainability role.

• Setting a goal to achieve zero routine flaring by 2030;

• Obtaining third-party assurance of our 2020 Scope 1 and 2 gross-operated GHG emissions;

• Decreasing our 2020 Scope 1 and 2 GHG emissions intensity by 10% from our 2019 baseline;

• Publishing our estimated Scope 3, Category 11 - Use of Sold Products GHG emissions;

• Updating our 2008 established climate change position;

• Adding an annual GHG emissions intensity goal as a performance metric, to the already established safety and spills metrics, in our Company’s renumeration policy;

• Including processes to stress-test our GHG emissions under various portfolio scenarios.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Environmental, Health and Safety Matters (Contd.)

During 2020, the Company:

• Established a goal of reducing our GHG emissions intensity 15% to 20% by 2030 from our 2019 levels, excluding divested assets from the 2019 baseline, for an aggregate of 35% to 40% reduction from our reported 2019 levels;

• Expanded our GHG, air quality, climate risk management and biodiversity management public disclosures;

• Expanded the purview of our Health, Safety, Environmental and Corporate Responsibility Committee to include sustainability issues;

• Created a Director of Sustainability role

Other Matters

Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates;

however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas and allied industries than by changes in general inflation.

Impact of inflation – In 2021, data indicates a sharp rise in inflation globally in most countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021).

(and other parts of the globe), inflation has been triggered by constrained supplies and increasing demand of certain goods and services as recovery from the COVID-19 pandemic begins.

The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry and allied industries rather than by changes in general inflation.

Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC+ production levels and/or attitudes of traders concerning supply and demand in the future.

Prices for oil field goods and services are usually affected by the worldwide prices for crude oil.

In 2020, some downward service cost relief was observed.

In 2019 the cost of goods and services in the oil and natural gas industry were stable.

Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of natural gas is generally restricted to specific geographic areas.

As a result of increasing commodity prices for oil and natural gas, in 2021 and at the start of 2022, higher costs for goods and services in the oil and gas natural gas industry are being observed.

Murphy has a dedicated procurement department focused on managing supply chain and input costs.

Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from increasing price of services.

However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher prices.

Murphy continues to strive toward safely executing our work in an ever increasing efficient manner to mitigate possible inflationary pressures in our business.

In 2020, some downward service cost relief was observed during a year of depressed commodity prices.

Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of natural gas can be restricted to specific geographic areas.

Natural gas demand is also impacted by demand driven by lower carbon emission and a view that natural gas is one option to transition from higher carbon emitting fuels.

As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

Accounting changes and recent accounting pronouncements – see Note B – New Accounting Principles and Recent Accounting Pronouncements

SEC Rules Adopted

SEC Disclosures Modernization of Regulation S-K Items 101, 103, and 105.

The new rules, which are part of the U.S.

Securities and Exchange Commission’s (SEC) broader project to modernize Regulation S-K, became effective November 9, 2020.

As a result, 2020 Form 10-Ks and other filings subject to Regulation S-K filed on or after this date need to include the new disclosures.

The new disclosures include principles-based disclosure of information material to an understanding of the general development of the business, and eliminating the previously prescribed five-year timeframe, a description of the registrant’s human capital resources to the extent such disclosures would be material to an understanding of the registrant’s business, and disclosure of any alternative threshold chosen for disclosure of environmental proceedings.

SEC Disclosures Update and Simplification .

In August 2018, the U.S.

Securities and Exchange Commission (SEC) adopted the final rule under SEC Release No.

33-10532 Disclosure Update and Simplification, to eliminate or modify certain disclosure rules that are redundant, outdated, or duplicative of U.S.

GAAP or other regulatory requirements.

Among other changes, the amendments eliminated the annual requirement to disclose the high and low trading prices of our common stock and the ratio of earnings to fixed charges.

In addition, the amendments provide that disclosure requirements related to the analysis of shareholders’ equity are expanded for interim financial statements.

An analysis of the changes in each caption of shareholders’ equity presented in the balance sheet must be provided in a note or separate statement, as well as the amount of dividends per share for each class of shares.

This rule was effective on November 5, 2018;

and the expanded interim disclosure requirements for changes in shareholders’ equity was effective for the Company for our quarterly reporting beginning March 31, 2019.

SEC Rules Not Yet Adopted

SEC Disclosures Management’s Discussion and Analysis (MD&A), Selected Financial Data, and Supplementar y Financial Information.

The new rules, which are part of the SEC’s broader project to modernize Regulation S-K, were published January 11, 2021 and became effective February 10, 2021.

The rules can be applied 30 days after publication in the Federal Register, and compliance is mandatory 210 days after publication.

Before the mandatory compliance date, registrants can choose which amended items to apply.

The amendments are intended to modernize, simplify, and enhance certain financial disclosure requirements in Regulation S-K.

Specifically, they eliminate the requirement for Selected Financial Data, streamline the requirement to disclose Supplementary Financial Information, and amend MD&A.

These amendments are intended to eliminate duplicative disclosures and modernize and enhance MD&A disclosures for the benefit of investors, while simplifying compliance efforts for registrants.

Other Matters (Cont’d.)

Significant accounting policies – In preparing the Company’s consolidated financial statements in accordance with U.S.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Critical Accounting Estimates – In preparing the Company’s consolidated financial statements in accordance with U.S.

GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.

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See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2021 beginning on pages 4 and 110 of this Form 10-K report.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Critical Accounting Estimates (Contd.)

Property, Plant & Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, plant and equipment (PPE) in the Consolidated Balance Sheet to make sure that they are fairly presented.

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Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs, and future inflation levels.

Other Matters (Cont’d.)

Significant accounting policies (Cont’d.)

The need to test a long-lived asset for impairment can be based on several factors, including, but not limited to, a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental, health and safety laws and regulations, tax laws or other regulatory changes.

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Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated.

In 2021 and 2020, the Company recognized pretax noncash impairment charges of $196.3 million and $1,206.3 million, respectively, to reduce the carrying values at select properties.

In 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans and $25.0 million for assets reported as Assets held for sale in the Consolidated Balance Sheets.

In 2020, declines in future oil and natural gas prices (principally driven by reduced commodity demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers) led to impairments in certain of the Company’s U.S.

Offshore and Other Foreign properties and assets.

In 2020, the Company recognized pretax noncash impairment charges of $1,206.3 million to reduce the carrying values at select properties.

There were no impairments in 2019.

As a result of management’s assessments during 2018, the Company recognized a pretax, noncash impairment charge of $20.0 million at select Midland properties.

See also Note G – Property, Plant, and Equipment for further discussion of impairment charges.

See also Note D – Property, Plant and Equipment for further discussion of impairment charges.

Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates.

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(b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle;

(c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.

and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.

The Company has deferred tax assets mostly relating to U.S net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant & equipment.

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Negative evidence includes losses in recent years.

As at December 31, 2020 the Company had a U.S.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Critical Accounting Estimates (Contd.)

As of December 31, 2021 the Company had a U.S.

deferred tax asset associated with net operating losses of $577.5 million.

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The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries.

The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of

Other Matters (Cont’d.)

Significant accounting policies (Cont’d.)

return on plan assets.

The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets.

For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate.

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Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

Based on bond yields at December 31, 2020, the Company has used a weighted average discount rate of 2.47% at year-end 2020 for the primary U.S.

This weighted average discount rate is 0.9% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago.

Although the Company presently assumes a return on plan assets of 5.50% for the primary U.S.

Based on bond yields as of December 31, 2021, the Company has used a weighted average discount rate of 2.83% at year-end 2021 for the primary U.S.

This weighted average discount rate is 0.4% higher than prior year, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago.

The Company presently assumes a return on plan assets of 5.25% for the primary U.S.

plan, it periodically reconsiders the appropriateness of this and other key assumptions.

The Company’s retirement and postretirement plan expenses in 2021 are expected to be $12.3 million lower than 2020 primarily due to termination benefit charges recorded relating to the restructuring in 2020 and lower interest charges.

Cash contributions are anticipated to be $9.9 million higher in 2021.

The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2022 are expected to be $9.9 million lower than 2021 primarily due to the increase in expected return assumptions for the US pension plan from 5.25% in 2021 to 6.60% in 2022, coupled with the impact of 2021 pension plan gain on reducing the amount of accumulated loss to be amortized as expense.

Cash contributions to all plans are anticipated to be $5.5 million higher in 2022.

In 2021, the Company paid $36.5 million into various retirement plans and $1.1 million into postretirement plans.

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Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected.

Recent Accounting Pronouncements

See Note B – New Accounting Principles and Recent Accounting Pronouncements our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure plans, and other long-term liabilities.

Total payments due after 2021 under such contractual obligations and arrangements are shown in the table below.

Amounts are undiscounted and therefore may differ to those presented in the financial statements.

(Millions of dollars) Amount of Obligations

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Total $ 8,061.9 1,085.8 1,208.8 1,325.8 4,441.5

1 Other leases refers to a finance lease in Brunei, which is classified as held for sale as of December 31, 2020 (see Note E – Assets Held for Sale and Discontinued Operations).

2 Capital expenditures, drilling rigs and other includes $529.0 million and $31.5 million in the years 2021 to 2023 for approved capital projects in non-operated interests in U.S.

Gulf of Mexico and U.S.

1 Other leases refers to a finance lease in Brunei (see Note U – Leases to the financial statements).

2 Capital expenditures, drilling rigs and other includes $175.9 million, $84.7 million, $24.9 million, and $18.1 million in 2022 for approved capital projects in non-operated interests in U.S.

Gulf of Mexico, Canada Offshore, Other Foreign Offshore, and U.S.

Onshore, respectively.

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Future required minimum annual payments under these arrangements are included in the contractual obligation table above.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Prices for the Company’s primary products are often volatile.

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As of close on February 24, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were $86.31 and $77.72 per barrel, respectively;

however we cannot predict what impact the ongoing COVID-19 pandemic and other economic factors may have on future commodity pricing.

Lower prices are expected to result in lower profits and operating cash-flows.

The Company is closely monitoring the impact of lower commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note H – Financing Arrangements and Debt).

The Company’s response to COVID-19 is discussed in more detail in the Risk Factors – General Risks.

The Company’s capital expenditure spend for 2021 is expected to be between $675.0 million and $725.0 million.

Capital and other expenditures will be routinely reviewed during 2021 and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year.

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.

The Company’s capital expenditure spend for 2022 is expected to be between $840.0 million and $890.0 million, excluding the amount attributable to noncontrolling interest.

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 capital program in 2021 using operating cash flow and available cash, but will supplement funding where necessary with borrowings under available credit facilities.

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 might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company will primarily fund its 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 currently expects average daily production in 2022 to be between 172,600 and 180,600 barrels of oil equivalent per day (including noncontrolling interest of 8,600 BOEPD).

If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.

The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, or payment to noncontrolling interests) to repay outstanding debt and return to shareholders through dividends.

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 G – Financing Arrangements and Debt ).

The Company continues to monitor the effects of the COVID-19 pandemic and is encouraged by the increase in oil and natural gas demand through 2021 and into 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:

(MMcf/d) Price/Mcf Remaining Period

Area Commodity Type Start Date End Date

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$2.36 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 1/1/2022 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

Commodity Type Volumes

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United States WTI ¹ Fixed price derivative swap 20,000 $44.88 1/1/2022 12/31/2022

1 West Texas Intermediate

(MMcf/d) Price

(CAD/Mcf) Remaining Period

(Bbl/d) Average

(USD/Bbl) Average

(USD/Bbl) Remaining Period

Area Commodity Type Start Date End Date

Montney Natural Gas Fixed price forward sales at AECO 160 C$2.54 1/1/2021 1/31/2021

Montney Natural Gas Fixed price forward sales at AECO 203 C$2.55 2/1/2021 5/31/2021

Montney Natural Gas Fixed price forward sales at AECO 212 C$2.55 6/1/2021 12/31/2021

Montney Natural Gas Fixed price forward sales at AECO 222 C$2.41 1/1/2022 12/31/2022

Montney Natural Gas Fixed price forward sales at AECO 192 C$2.36 1/1/2023 12/31/2023

Montney Natural Gas Fixed price forward sales at AECO 147 C$2.41 1/1/2024 12/31/2024

United States WTI ¹ Derivative collars 25,000 $63.24 $75.20 1/1/2022 12/31/2022

1 West Texas Intermediate

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Forward-Looking Statements

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adverse foreign exchange movements;

political and regulatory instability in the markets where

we do business;

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;

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis