What changed in this filing

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Item 2. Management’s Discussion and Analysis

2022-05-04 compared with 2021-11-04 · 82 added, 152 removed, 151 unchanged (61% of the section changed)

2 unchanged sentences

Exploration and Production

Third quarter 2021 vs.

All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

United States E&P operations reported earnings of $168.1 million in the third quarter of 2021 compared to a loss of $172.6 million in the third quarter of 2020.

Results were $340.7 million favorable in the 2021 quarter compared to the 2020 period primarily due to higher revenues ($234.4 million), lower impairment charge ($205.1 million) and depreciation, depletion and amortization (DD&A:

$19.2 million), partially offset by higher income tax expense ($78.4 million), other operating expense ($16.6 million) and exploration expense ($15.5 million).

Higher revenues were primarily due to higher commodity prices.

The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in the third quarter of 2020.

Lower impairment charges were due to impairment charges recognized in the prior period related to Gulf of Mexico Cascade & Chinook field and no such charges in current period.

Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base.

Higher income tax expense is a result of pre-tax profits principally due to the recovering oil price.

Higher other operating expense is primarily due to unfavorable mark to market revaluation on contingent consideration (as a result of higher commodity prices) related to prior Gulf of Mexico (GOM) acquisitions.

Higher exploration expense is primarily due to dry hole costs related to Silverback in the current period.

Canadian E&P operations reported earnings of $73.9 million in the third quarter 2021 compared to a loss of $8.6 million in the third quarter of 2020.

Results were favorable $82.5 million compared to the 2020 period primarily due to a credit of $71.8 million reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project.

Results were also favorably impacted by higher revenue ($28.3 million) and lower DD&A ($19.9 million), partially offset by higher tax expense ($28.3 million) and higher transportation, gathering and processing ($4.2 million).

Higher revenue is primarily attributable to higher natural gas prices and higher natural gas volumes at Tupper Montney.

Lower DD&A is due to lower production volumes at Kaybob Duvernay due to normal well decline.

Higher transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss from continuing operations of $5.2 million in the third quarter of 2021 compared to a loss of $11.7 million in the third quarter of 2020.

The result was $6.5 million favorable in the 2021 period versus 2020 primarily due lower exploration expenses in Brazil and Mexico.

Nine months 2021 vs.

First quarter 2022 vs.

All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

United States E&P operations reported earnings of $481.8 million in the first nine months of 2021 compared to a loss of $1,011.7 million in the first nine months of 2020.

Results were $1,493.5 million favorable in 2021 period compared to the 2020 period primarily due to no impairment charges in the current period (2020:

$1,152.5 million).

Further, the change year over year is driven by higher revenues ($633.8 million), lower DD&A ($112.9 million), lower lease operating expenses (LOE:

United States E&P operations reported earnings of $252.9 million in the first quarter of 2022 compared to earnings of $119.0 million in the first quarter of 2021.

Results were $133.9 million favorable in the 2022 period compared to the 2021 period, driven by higher revenues ($217.1 million), lower DD&A ($23.1 million), lower lease operating expenses (LOE:

$16.2 million), partially offset by higher income tax expense ($29.7 million) and higher other operating expense ($81.3 million).

The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of lower oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment.

Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2021 compared to 2020.

The production impact of Hurricane Ida in the third quarter of 2021 is offset by the impact of multiple storms that occurred in 2020.

Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base.

Lower lease operating expenses were primarily due to higher GOM workover costs in the prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million).

Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2022 compared to 2021, offset by lower oil sales and production volumes driven primarily by a focused effort to reduce capital expenditures to prioritize corporate debt reduction.

Lower DD&A is a result of lower production volumes and lower rates driven by positive reserve revisions.

Lower lease operating expenses were primarily due to higher GOM workover costs in the prior year at St.

Higher income tax expense is a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE.

1 unchanged sentence

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

Canadian E&P operations reported a loss of $37.7 million in the first nine months of 2021 compared to a loss of $35.0 million in the first nine months of 2020.

Results were comparable year over year.

2021 results include an impairment charge ($171.3 million) recorded in the first quarter following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project.

The current year results also include higher revenue ($104.0 million) and lower DD&A ($33.3 million) offset by higher transportation, gathering and processing expenses ($15.3 million) and lease operating expenses ($9.4 million).

Higher revenue is primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay.

Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

expenditures throughout 2020.

Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss of $22.5 million in the first nine months of 2021 compared to a loss of $73.0 million in the prior year.

Results were $50.5 million favorable compared to the 2020 period primarily due to no repeat of an impairment charge of $39.7 million in the prior year.

Third quarter 2021 vs.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $98.8 million in the third quarter of 2021 compared to net loss of $72.9 million in the third quarter of 2020.

The $25.9 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021:

$59.2 million loss;

$5.3 million loss), partially offset by lower impairment charges ($14.1 million), higher tax benefits ($5.7 million), lower restructuring charges ($5.0 million), and lower DD&A ($2.3 million).

Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price.

Lower impairment and restructuring charges are due to the 2020 cost reduction efforts which included closing the Company’s previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.

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

Nine months 2021 vs.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $577.6 million in the first nine months of 2021 compared to earnings of $26.9 million in the first nine months of 2020.

The $604.5 million unfavorable variance is primarily due to realized and unrealized losses on derivative instruments in 2021 compared to gains in 2020 (2021:

Canadian E&P operations reported earnings of $22.7 million in the first quarter of 2022 compared to a loss of $124.3 million in the first quarter of 2021.

Results were $147.0 million favorable compared to the 2021 period.

Prior year results included an impairment charge ($171.3 million) recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment, and prior to the sanctioning of an asset life extension project in the third quarter of 2021.

The current year results also include higher revenue from production ($25.3 million) and lower DD&A ($10.6 million) offset by higher income tax expense ($49.7 million), lease operating expenses ($6.1 million) and transportation, gathering and processing expenses ($3.3 million).

Higher revenue is primarily attributable to higher oil prices at Hibernia and Kaybob Duvernay and higher natural gas prices and volumes at Tupper Montney.

Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital expenditures throughout 2020 and 2021.

Higher income tax expense is a result of higher pre-tax income principally due to higher revenue and no repeat of the impairment charge.

Higher lease oper ating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation rates and capacity.

Higher capacity is expected to be utilized by growth at Tupper Montney in the future.

Other international E&P operations reported a loss of $44.2 million in the first quarter of 2022 compared to a loss of $6.9 million in the prior year.

Results were $37.3 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were discovered.

First quarter 2022 vs.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $296.3 million in the first quarter of 2022 compared to a loss of $254.8 million in the first quarter of 2021.

The $41.5 million unfavorable variance is primarily due to higher realized and unrealized losses on derivative instruments in 2022 compared to 2021 (2022:

$320.8 million loss;

$319.5 million gain), and higher interest expense ($54.1 million), partially offset by higher tax benefits ($177.6 million), lower restructuring charges ($46.4 million), lower G&A ($15.0 million), lower impairment charges ($14.1 million) and lower DD&A ($7.2 million).

As of September 30, 2021, the average forward NYMEX WTI price for the remainder of 2021 was $74.87 and for 2022 was $70.87 (versus swap contract fixed hedge prices of $42.77 and $44.88, respectively).

Interest charges are higher in 2021 primarily due an early redemption premium incurred by the Company upon the early retirement of the notes originally due June and December 2022.

$214.4 million loss), partially offset by lower interest expense ($56.0 million) and higher tax benefits ($7.8 million).

Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price.

As of March 31, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $94.52 (versus swap contract fixed hedge price of $44.88).

Interest charges are lower in the first quarter of 2022 primarily due the prior year redemption premium ($34.2 million) incurred by the Company upon the early retirement of the notes originally due June and December 2022, lower overall debt and higher capitalized interest on GOM capital projects.

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

Lower restructuring charges, G&A expenditures and impairment charges are due to the 2020 cost reduction efforts which included closing its previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.

Production Volumes and Prices

Third quarter 2021 vs.

Total hydrocarbon production from continuing operations averaged 163,224 barrels of oil equivalent per day in the third quarter of 2021, which was in line with the 162,824 barrels per day produced in third quarter 2020.

Gulf of Mexico production in the current year was impacted by Hurricane Ida and the prior year was impacted by multiple storms.

The estimated storm impact in the third quarter of 2021 was 14,542 barrels of oil equivalent per day (including NCI) and 14,230 barrels of oil equivalent per day (including NCI) in the third quarter of 2020.

Average crude oil and condensate production from continuing operations was 88,245 barrels per day in the third quarter of 2021 compared to 95,391 barrels per day in the third quarter of 2020.

The decrease of 7,146 barrels per day was associated with lower volumes in Canada (5,281 barrels per day lower primarily attributable to Kaybob Duvernay well decline), lower volumes in the Gulf of Mexico (3,506 barrels per day principally due to facility shut-ins as a result of Hurricane Ida), offset by higher Eagle Ford Shale production (1,342 barrels per day higher at Karnes due to 2021 capital expenditures in this area).

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

worldwide basis, the Company’s crude oil and condensate prices averaged $68.88 per barrel in the third quarter 2021 compared to $39.79 per barrel in the 2020 period, an increase of 73% quarter over quarter.

Total production of natural gas liquids (NGL) from continuing operations was 10,391 barrels per day in the third quarter 2021 compared to 10,523 barrels per day in the 2020 period.

The average sales price for U.S.

NGL was $32.01 per barrel in the 2021 quarter compared to $13.91 per barrel in 2020.

The average sales price for NGL in Canada was $45.12 per barrel in the 2021 quarter compared to $19.97 per barrel in 2020.

NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.

Natural gas production volumes from continuing operations averaged 387.5 million cubic feet per day (MMCFD) in the third quarter 2021 compared to 341.5 MMCFD in 2020.

The increase of 46 MMCFD was a result of higher volumes in Canada (49 MMCFD), offset by lower volumes in the Gulf of Mexico (7 MMCFD) and in the Eagle Ford Shale (4 MMCFD).

Higher natural gas volumes in Canada are primarily due to bringing online 10 new wells at Tupper Montney in the second quarter of 2021.

Lower volumes in the Gulf of Mexico are principally due to facility shut-ins as a result of Hurricane Ida.

Natural gas prices for the total Company averaged $2.78 per thousand cubic feet (MCF) in the 2021 quarter, versus $1.78 per MCF average in the same quarter of 2020.

Average natural gas prices in the U.S.

and Canada in the quarter were $3.99 and $2.47 per MCF, respectively.

Nine months 2021 vs.

Total hydrocarbon production from all E&P continuing operations averaged 170,209 barrels of oil equivalent per day in the first nine months of 2021, which represented a 6% decrease from the 180,443 barrels per day produced in the first nine months of 2020.

The decrease in production is principally due to lower capital expenditures throughout 2020 to support generating positive free cashflow.

Average crude oil and condensate production from continuing operations was 98,314 barrels per day in the first nine months of 2021 compared to 108,678 barrels per day in the first nine months of 2020.

The decrease of 10,364 barrels per day was principally due to lower Gulf of Mexico production (5,472 barrels per day) due to temporary operational issues at the Cascade & Chinook and Kodiak fields in the first quarter of 2021 and facility shut-ins as a result of Hurricane Ida in the third quarter of 2021.

Lower Canada production (3,628 barrels per day) is due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia and lower Eagle Ford Shale production (1,393 barrels per day) is due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $64.19 per barrel in the first nine months of 2021 compared to $36.88 per barrel in the 2020 period, an increase of 74% year over year.

Total production of natural gas liquids (NGL) from continuing operations was 10,498 barrels per day in the first nine months of 2021 compared to 11,901 barrels per day in the 2020 period.

Production Volumes and Prices

First quarter 2022 vs.

Total hydrocarbon production from Exploration and Production averaged 149,854 barrels of oil equivalent per day in the first quarter of 2022, which represented a 9% decrease from the 165,382 barrels per day produced in the first quarter of 2021.

The decrease in production is principally due to an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction.

Average crude oil and condensate production was 83,560 barrels per day in the first quarter of 2022 compared to 97,475 barrels per day in the first quarter of 2021.

The decrease of 13,915 barrels per day was principally due to lower Gulf of Mexico production (9,110 barrels per day) due to the focused effort to reduce capital expenditures and several planned downtime events including a facility upgrade which lowered current production at Neidermeyer and Marmalard as well as maintenance operations at Front Runner, Habanero and Chinook.

Canada production is lower (3,176 barrels per day) due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia.

Eagle Ford Shale production is lower (1,835 barrels per day) due to normal well decline and temporary operational issues impacting production in the first quarter of 2022.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $95.17 per barrel in the first quarter of 2022 compared to $58.08 per barrel in the 2021 period, an increase of 64% year over year.

Total production of natural gas liquids (NGL) was 9,342 barrels per day in the first quarter of 2022 compared to 9,845 barrels per day in the 2021 period.

The average sales price for U.S.

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NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.

Natural gas sales volumes from continuing operations averaged 368.4 million cubic feet per day (MMCFD) in the first nine months of 2021 compared to 359.2 MMCFD in 2020.

The increase of 9.2 MMCFD was primarily the result of higher volumes at Tupper (18.8 MMCFD) driven by the 10 new wells at Tupper Montney in the second quarter of 2021, partially offset by lower volumes in the Gulf of Mexico (4.3 MMCFD), other Canada assets (4.0 MMCFD), and in the Eagle Ford (1.3 MMCFD).

Lower volumes in the Gulf of Mexico are principally due to temporary operational issues at the Cascade & Chinook and Kodiak fields.

Lower volumes at Eagle Ford Shale are due to normal well decline, lower capital expenditures throughout 2020 and the effects of a winter storm impacting Eagle Ford Shale production in the first quarter of 2021.

Natural gas prices for the total Company averaged $2.56 per thousand cubic feet (MCF) in the first nine months of 2021, versus $1.68 per MCF average in the same period of 2020.

Average natural gas prices in the U.S.

Natural gas production volumes averaged 341.7 million cubic feet per day (MMCFD) in the first quarter of 2022 compared to 348.4 MMCFD in 2021.

The decrease of 6.7 MMCFD was primarily the result of lower volumes in the Gulf of Mexico (16.6 MMCFD) partially offset by higher volumes at Eagle Ford Shale (5.3 MMCFD) and Canada (4.6 MMCFD).

The lower natural gas volumes in the Gulf of Mexico are principally due to planned facility and maintenance downtime.

Natural gas prices for the total Company averaged $3.13 per thousand cubic feet (MCF) in the first quarter of 2022, versus $2.56 per MCF average in the same period of 2021.

Average realized natural gas prices in the U.S.

and Canada in the quarter were $5.00 and $2.52, respectively.

Additional details about results of oil and natural gas operations are presented in the tables on pages 25 and 26.

Average realized gas prices in Canada are lower as a result of certain fixed price sales volume contracts.

Additional details about results of oil and natural gas operations are presented in the tables on page 24.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2021 and 2020.

The following table reports hydrocarbons produced during the three-month periods ended March 31, 2022 and 2021.

Three Months Ended

September 30, Nine Months Ended

September 30,

Barrels per day unless otherwise noted 2022 2021

Continuing operations

Net crude oil and condensate

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Offshore 3,321 4,589

Other 299 — 243 114

Total net crude oil and condensate - continuing operations 83,560 97,475

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Gulf of Mexico 1

3,459 3,521 4,296 5,131

Canada Onshore 983 1,233

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Results of Operations (contd.)

The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month and nine-month periods ended September 30, 2021 and 2020.

Comparative periods are conformed to current presentation.

The following table reports the weighted average sales prices excluding transportation cost deduction and sales of purchased natural gas for the three-month periods ended March 31, 2022 and 2021.

Three Months Ended

September 30, Nine Months Ended

September 30,

2021 2020 2021 2020

Weighted average Exploration and Production sales prices

3 unchanged sentences

Gulf of Mexico 1

68.93 40.82 64.44 38.08

Onshore 93.09 52.84

Offshore 110.66 59.39

Other — — — 63.51

Natural gas liquids – dollars per barrel

1 unchanged sentence

Gulf of Mexico 1

34.71 14.71 27.17 9.43

Onshore 55.02 35.92

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Gulf of Mexico 1

4.09 2.01 3.28 1.91

Onshore 2.52 2.26

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Cash Provided by Operating Activities

Net cash provided by continuing operating activities was $1,091.3 million for the first nine months of 2021 compared to $578.0 million during the same period in 2020.

The increased cash from operating activities is primarily attributable to higher revenue from sales to customers ($727.3 million), lower working capital ($143.6 million), lower lease operating expense ($74.6 million), and lower general and administrative and cash restructuring expense ($47.4 million), partially offset by higher cash payments made on forward swap commodity contracts (2021:

realized loss of $271.3 million;

realized gain of $215.0 million).

Net cash provided by continuing operating activities was $338.3 million for the first three months of 2022 compared to $237.8 million during the same period in 2021.

The increased cash from operating activities is primarily attributable to higher revenue from production ($242.0 million), offset by the timing of working capital settlements ($80.9 million;

primarily higher revenue received in cash following the end of the quarter) and higher realized losses on derivative instruments ($71.4 million).

Cash Required by Investing Activities

Net cash required by investing activities was $311.9 million for the first nine months of 2021 compared to $723.7 million during the same period in 2020.

Property additions and dry hole costs, which includes amounts expensed, were $582.0 million and $723.7 million in the first nine months of 2021 and 2020, respectively.

These amounts include $17.7 million and $74.9 million used to fund the development of the King’s Quay FPS in the first nine months of 2021 and 2020, respectively.

In the first quarter of 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimbursed the Company for previously incurred capital expenditures.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)

Financial Condition (contd.)

Net cash required by investing activities was $244.9 million for the first three months of 2022 compared to net cash provided by investing activities of $9.7 million during the same period in 2021.

The first quarter of 2021 included sales proceeds for the King’s Quay FPS of $268.0 million, which was sold to ArcLight Capital Partners, LLC (ArcLight).

Property additions and dry hole costs (excluding King’s Quay), which includes amounts expensed, were $244.9 million and $240.5 million in the first three months of 2022 and 2021, respectively.

Total accrual basis capital expenditures were as follows:

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars) 2022 2021

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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.

Nine Months Ended

September 30,

MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)

Financial Condition (contd.)

Three Months Ended

(Millions of dollars) 2022 2021

4 unchanged sentences

Total capital expenditures $ 304.7 251.1

Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as a result of capital expenditure reductions to support generating positive free cash flow.

Cash Used in/ Provided by Financing Activities

Net cash required by financing activities was $585.6 million for the first nine months of 2021 compared to net cash provided by financing activities of $59.1 million during the same period in 2020.

In 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million).

As of September 30, 2021 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF.

In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($450.0 million), offset by repayments on the revolving credit facility ($250.0 million), cash dividends to shareholders ($76.8 million), and distributions to our noncontrolling interest ($43.7 million).

The increase in capital expenditures in the exploration and production business in 2022 compared to 2021 is primarily attributable to expenditures related to the Cutthroat-1 exploration well in Brazil, capital invested at the Khaleesi, Mormont, Samurai field development project and higher development drilling activities in Tupper Montney and Kaybob Duvernay assets.

Cash Required by Financing Activities

Net cash required by financing activities was $133.9 million for the first three months of 2022 compared to $327.8 million during the same period in 2021.

In 2022, the cash used in financing activities was principally for payment of contingent consideration related prior Gulf of Mexico acquisitions ($55.2 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($39.9 million), and cash dividends to shareholders of $0.15 per share ($23.3 million).

Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.175 per share, or $0.70 per share on an annualized basis.

This amount represents a 17% increase from the first quarter of 2022 and a 40% increase from fourth quarter 2021.

As of March 31, 2022 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF.

In first three months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 ($576.4 million ), early redemption cost of the notes due 2022 ($34.2 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($36.0 million), and cash dividends to shareholders ($19.3 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million).

Working Capital

Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at September 30, 2021 was a deficit of $344.9 million, $315.5 million lower than December 31, 2020, with the decrease primarily attributable to higher accounts payable ($208.3 million), higher other accrued liabilities ($165.6 million), higher operating lease liabilities ($53.5 million), partly offset by a higher cash balance ($194.5 million) and lower accounts receivable ($75.3 million).

Higher accounts payable is primarily due to the increase in unrealized losses on derivative instruments (swaps and collars) maturing in the next 12 months.

Higher other accrued liabilities are associated with contingent consideration obligations (from 2018 and 2019 Gulf of Mexico acquisitions).

Higher operating lease liabilities are associated with a rig contract to support the Khaleesi-Mormont and Samurai developments which will utilize the King’s Quay FPS.

Lower accounts receivable are principally due to the timing of cash received from our joint venture partners to fund joint operations.

Working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) as of March 31, 2022 was a deficit of $654.5 million, $355.7 million lower than December 31, 2021, with the decrease p rimarily attributable to higher accounts payable ($316.8 million), higher other accrued liabilities ($80.5 million), a lower cash balance ($40.6 million) and higher operating lease liabilities ($34.5 million), partially offset by higher accounts receivable ($113.7 million).

Higher accounts payable is primarily due to the increase in unrealized losses on derivative instruments (commodity price swaps and collars) maturing over the remainder of 2022.

Higher other accrued liabilities are associated with higher contingent consideration obligations due to higher commodity prices (from prior Gulf of Mexico acquisitions).

Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project which will utilize the King’s Quay FPS.

Higher accounts receivable are principally due to higher crude oil pricing.

Capital Employed

At March 31, 2022, long-term debt of $2,466.1 million had increased by $0.7 million compared to December 31, 2021, primarily as a result of normal debt issuance cost amortization.

The total of the fixed-rate notes had a weighted average maturity of 7.2 years and a weighted average coupon of 6.2%.

MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)

Financial Condition (contd.)

Capital Employed

At September 30, 2021, long-term debt of $2,613.7 million had decreased by $374.4 million compared to December 31, 2020, primarily as a result of repayment of the borrowings on the RCF ($200.0 million) and the redemption of the notes due 2022 and 2024 ($726.4 million) in excess of the issuance of notes due 2028 ($550.0 million) in the first quarter of 2021.

The total of the fixed-rate notes in issue had a weighted average maturity of 7.5 years and a weighted average coupon of 6.3% percent.

A summary of capital employed at September 30, 2021 and December 31, 2020 follows.

September 30, 2021 December 31, 2020

A summary of capital employed at March 31, 2022 and December 31, 2021 follows.

March 31, 2022 December 31, 2021

(Millions of dollars) Amount % Amount %

4 unchanged sentences

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

At September 30, 2021, Cash and cash equivalents held outside the U.S.

As of March 31, 2022, Cash and cash equivalents held outside the U.S.

included U.S.

dollar equivalents of approximately $119.4 million in Canada and $6.2 million in Brunei.

dollar equivalents of approximately $144.3 million in Canada.

In addition, approximately $28.4 million of cash was held in Brazil.

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

2 unchanged sentences

Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements

As discussed in the Summary section on page 23, average crude oil prices continued to recover during the second half of 2021 versus 2020 (Q3 2021 WTI:

As of close on November 2, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $83.91 and $76.27 per barrel, respectively;

however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic and OPEC+ decisions) may have on future commodity pricing.

As discussed in the Summary section on page 21, several factors continue to provide upward pressure to the average crude oil price, which directly impacts the Company’s product revenue from sales (Q1 2022:

As of close on May 2, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were $99.44 and $86.38 per barrel, respectively;

however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and production sector investment and the Russia/Ukraine conflict) may have on future commodity prices.

Lower prices, should they occur, will result in lower profits and operating cash-flows.

For the fourth quarter, production is expected to average between 145.5 and 153.5 MBOEPD, excluding noncontrolling interest (NCI).

For the second quarter, production is expected to average between 156.0 and 164.0 MBOEPD, excluding noncontrolling interest (NCI).

The Company’s capital expenditure spend for 2022 is expected to be between $900.0 million and $950.0 million.

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.

The increase from the original 2022 guidance of $840.0 million to $890.0 million is principally a result of inflationary pressures, scope changes and rig standby costs related to the Cutthroat-1 exploration well in Brazil.

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

Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.

The Company will primarily fund its remaining capital program in 2021 using operating cash flow and available cash.

The Company plans to fund its remaining capital program in 2022 using operating cash flow and available cash.

If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

1 unchanged sentence

The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F).

The Company continues to monitor the effects of the COVID-19 pandemic and is encouraged by the progress of the vaccination roll-outs globally.

As of November 2, 2021, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

As of May 2, 2022, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

Commodity Type Volumes

3 unchanged sentences

United States WTI ¹ Fixed price derivative swap 20,000 $44.88 4/1/2022 12/31/2022

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

(Bbl/d) Average

13 unchanged sentences

Montney Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024

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 4/1/2022 12/31/2022

22 unchanged sentences

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-Q

Item 2. Management’s Discussion and Analysis