EX-99.2 3 q22023managementsdiscussio.htm EX-99.2 Document

Exhibit 99.2

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Cenovus Energy Inc.
Management’s Discussion and Analysis (unaudited)
For the Periods Ended June 30, 2023
(Canadian Dollars)










MANAGEMENT’S DISCUSSION AND ANALYSIS logo1b.gif
For the periods ended June 30, 2023

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated July 26, 2023, should be read in conjunction with our June 30, 2023 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2022 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2022 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of July 26, 2023, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (“the Board”), reviewed and recommended the MD&A for approval by the Board, which occurred on July 26, 2023. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.
Basis of Presentation
This MD&A and the interim Consolidated Financial Statements have been prepared in Canadian dollars, (which includes references to “dollar” or “$”), except where another currency has been indicated, and in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board. Production volumes are presented on a before royalties basis. Refer to the Abbreviations section for commonly used oil and gas terms.




Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
2



OVERVIEW OF CENOVUS
We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are the second largest Canadian-based crude oil and natural gas producer, with upstream operations in Canada and the Asia Pacific region, and the second largest Canadian-based refiner and upgrader, with downstream operations in Canada and the United States (“U.S.”).
Our upstream operations include oil sands projects in northern Alberta; thermal and conventional crude oil, natural gas and natural gas liquids (“NGLs”) projects across Western Canada; crude oil production offshore Newfoundland and Labrador; and natural gas and NGLs production offshore China and Indonesia. Our downstream operations include upgrading and refining operations in Canada and the U.S., and commercial fuel operations across Canada.
Our operations involve activities across the full value chain to develop, produce, refine, transport and market crude oil, natural gas and refined petroleum products in Canada and internationally. Our physically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil differentials and contribute to our net earnings by capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels.
Our Strategy and Key Priorities for 2023
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value through competitive cost structures and optimizing margins, while delivering top-tier safety performance and sustainability leadership. The Company prioritizes Free Funds Flow generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and share repurchases, reinvest in our business and diversify our portfolio. On December 6, 2022, we released our 2023 budget. Our 2023 guidance as updated on July 26, 2023, is available on our website at cenovus.com. For further details see the Operating and Financial Results section of this MD&A.
In 2023, we aim to deliver on our strategy through five key objectives.
Top-Tier Safety and Operational Performance
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, including top-tier health and safety performance.
We will continue to target improved operating performance, including the safe return of the Superior Refinery to full operations and integration of the Toledo Refinery with a focus on demonstrating consistent and reliable performance at all of our operated assets.
Sustainability Leadership
Sustainability has always been deeply engrained in Cenovus’s culture. We have established ambitious targets in our five environmental, social and governance (“ESG”) focus areas and continue to progress tangible plans to meet these targets. Our five ESG focus areas are:
Climate & GHG emissions.
Water stewardship.
Biodiversity.
Indigenous reconciliation.
Inclusion & diversity.
Additional information on Cenovus’s efforts and performance across the ESG focus areas, including our ESG targets and plans to achieve them, are available in Cenovus’s 2022 ESG report on our website at cenovus.com.
Cost Leadership
We aim to maximize shareholder value through competitive cost structures and optimized margins. While we strive to optimize our cost structure in all areas of our business, one of our focus areas is to optimize infrastructure, reduce operating and capital costs, and reduce GHG emissions at our conventional assets.
Financial Discipline and Free Funds Flow Growth
We are focused on achieving and maintaining targeted debt levels while positioning Cenovus for resiliency through all commodity price cycles. We plan to continue to deliver meaningful returns to shareholders in alignment with our financial and shareholder returns framework.
Returns-Focused Capital Allocation
We continue to take a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle and provide opportunities to sustainably grow shareholder returns.
We plan to materially progress the West White Rose project to deliver first oil in 2026.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Our Operations
The Company operates through the following reportable segments:
Upstream Segments
Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.
Conventional, includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.
Offshore, includes offshore operations, exploration and development activities in China and the east coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.
Downstream Segments
Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.
U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel, jet fuel and asphalt.
Corporate and Eliminations
Corporate and Eliminations, primarily includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices.
QUARTERLY RESULTS OVERVIEW
The second quarter was highlighted by significant milestones as well as challenges across our business. In our upstream business, we quickly responded to wildfires impacting the Conventional segment in early May. We temporarily shut-in approximately 85 thousand BOE per day of production to ensure the safety of our staff, local communities and assets. By the end of May, we were able to restart the majority of our wells and facilities impacted by the fire. Approximately 5 to 7 thousand BOE per day of production remained offline near the end of July due to the lack of third-party power infrastructure. In the Oil Sands segment, we began ramping up production on a total of three new wells pads at Foster Creek and Christina Lake in the second quarter, and completed a planned turnaround at Foster Creek. Offshore production was impacted by a planned turnaround in the Atlantic and a temporary unplanned outage in China related to the disconnection of the umbilical by a third-party vessel in early April, reconnected in May. In our Atlantic operations, we achieved another milestone on the West White Rose project, with the completion of the conical slip form operation for the concrete gravity structure in June.
In our downstream business, we achieved the safe restart of the Toledo Refinery, continued safely ramping up operations at the Superior Refinery, and completed planned turnarounds at the Wood River and Borger refineries. The Toledo Refinery was fully operational in June. Ramp-up of the Superior Refinery continued through the second quarter and start-up of the fluid catalytic cracking unit (“FCCU”) is underway. The Borger Refinery ran at reduced rates due to unplanned outages, and our Lima and Lloydminster refineries ran at or near full rates through the quarter.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Our financial results improved from the first quarter, primarily reflecting higher realized prices from the Oil Sands segment. WCS at Hardisty averaged $58.74 per barrel, an increase from $51.36 per barrel in the first quarter mainly due to the narrowing of the WTI-WCS differential by 39 percent to $15.04 per barrel. In the second quarter, crude oil prices were significantly lower compared with 2022 with WTI decreasing 32 percent to $73.78 per barrel, and the WTI-WCS differential at Hardisty widening $2.24 per barrel from $12.80 per barrel. Average refined product prices declined and average market crack spreads remained relatively consistent with the first quarter of 2023. Refined product prices and average market crack spreads declined compared with historic highs in the second quarter of 2022.
We returned $575 million to shareholders, including $265 million through common share base dividends of $0.140 per common share and the purchase of 14.0 million common shares for $310 million through our NCIB. Net Debt decreased $265 million during the quarter to $6.4 billion at June 30, 2023.
Summary of Quarterly Results
Six Months Ended
June 30,
202320222021
($ millions, except where indicated)
2023
2022
Q2Q1Q4Q3Q2Q1Q4Q3Q2
Upstream Production Volumes (1) (MBOE/d)
754.4 779.9 729.9 779.0 806.9 777.9 761.5 798.6 825.3 804.8 765.9 
Downstream Crude Oil Unit Throughput (2)
   (Mbbls/d)
498.1 479.4 537.8 457.9 473.3 533.5 457.3 501.8 469.9 554.1 539.0 
Downstream Production Volumes (Mbbls/d)
530.0 509.6 571.9 487.7 506.3 572.6 482.1 538.0 503.4 590.9 564.8 
Revenues
24,493 35,363 12,231 12,262 14,063 17,471 19,165 16,198 13,726 12,701 10,637 
Operating Margin (3)
4,502 8,142 2,400 2,102 2,782 3,339 4,678 3,464 2,600 2,710 2,184 
Cash From (Used In) Operating Activities1,704 4,344 1,990 (286)2,970 4,089 2,979 1,365 2,184 2,138 1,369 
Adjusted Funds Flow (3)
3,294 5,681 1,899 1,395 2,346 2,951 3,098 2,583 1,948 2,342 1,817 
Per Share - Basic (3) ($)
1.73 2.87 1.00 0.73 1.22 1.53 1.57 1.30 0.97 1.16 0.90 
Per Share - Diluted (3) ($)
1.69 2.79 0.98 0.71 1.19 1.49 1.53 1.27 0.97 1.15 0.89 
Capital Investment2,103 1,568 1,002 1,101 1,274 866 822 746 835 647 534 
Free Funds Flow (3)
1,191 4,113 897 294 1,072 2,085 2,276 1,837 1,113 1,695 1,283 
Excess Free Funds Flow (3)
n/an/a505 (499)786 1,756 2,020 2,615 1,169 1,626 1,244 
Net Earnings (Loss) (4)
1,502 4,057 866 636 784 1,609 2,432 1,625 (408)551 224 
Per Share - Basic ($)
0.78 2.04 0.45 0.33 0.40 0.83 1.23 0.81 (0.21)0.27 0.11 
Per Share - Diluted ($)
0.76 1.98 0.44 0.32 0.39 0.81 1.19 0.79 (0.21)0.27 0.11 
Total Assets53,747 55,894 53,747 54,000 55,869 55,086 55,894 55,655 54,104 54,594 53,384 
Total Long-Term Liabilities
19,831 20,742 19,831 19,917 20,259 19,378 20,742 21,889 23,191 22,929 22,972 
Long-Term Debt, Including Current Portion
8,534 11,228 8,534 8,681 8,691 8,774 11,228 11,744 12,385 12,986 13,380 
Net Debt
6,367 7,535 6,367 6,632 4,282 5,280 7,535 8,407 9,591 11,024 12,390 
Cash Returns to Shareholders
Common Shares – Base Dividends465 276 265 200 201 205 207 69 70 35 36 
Base Dividends Per Common Share ($)
0.245 0.140 0.140 0.105 0.105 0.105 0.105 0.035 0.035 0.018 0.018 
Common Shares – Variable Dividends —  — 219 — — — — — — 
Variable Dividends Per Common Share ($)
 —  — 0.114 — — — — — — 
Purchase of Common Shares Under NCIB350 1,484 310 40 387 659 1,018 466 265 — — 
Preferred Share Dividends 27 17 9 18 — 
(1)Refer to the Operating and Financial Results section of this MD&A for a summary of total upstream production by product type.
(2)Represents Cenovus’s net interest in refining operations.
(3)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(4)Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.























Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Upstream production averaged 729.9 thousand BOE per day in the second quarter, a decrease of 49.1 thousand BOE per day and 31.6 thousand BOE per day, respectively, from the first quarter of 2023 and second quarter of 2022. The decreases were primarily due to a planned turnaround at Foster Creek, our response to the wildfires in the Conventional segment and an unplanned outage in China, all impacting the second quarter of 2023. See the Operating and Financial Results section of this MD&A for a summary of upstream production by product type.
Downstream crude oil unit throughput (or “throughput”) averaged 537.8 thousand barrels per day in the second quarter (first quarter of 2023 – 457.9 thousand barrels per day; second quarter of 2022 – 457.3 thousand barrels per day). Consistent with increased throughput, downstream refined products production volumes averaged 571.9 thousand barrels per day in the quarter (first quarter of 2023 – 487.7 thousand barrels per day; second quarter of 2022 – 482.1 thousand barrels per day). The Toledo Refinery was fully operational in June. Ramp-up of the Superior Refinery continued through the second quarter and start-up of the FCCU is underway.
Realized crude oil and refined product prices declined significantly from the second quarter of 2022, a period of elevated benchmark prices. Revenues of $12.2 billion were relatively consistent with the first quarter of 2023, primarily due to higher realized bitumen and heavy crude oil prices, offset by lower realized conventional natural gas prices and decreased sales volumes in the Offshore and Conventional segments. Downstream revenues increased slightly from the first quarter of 2023. Revenue decreased 36 percent from the second quarter of 2022, primarily due to significantly lower commodity pricing in our upstream and downstream operations. Our realized sales price from our upstream operations was $71.15 per BOE in the second quarter of 2023, up 17 percent compared with $60.83 per BOE in the first quarter of 2023 and down 38 percent compared with $114.40 per BOE in the second quarter of 2022.
In our Canadian downstream operations, gross margin declined 33 percent from the first quarter of 2023 primarily due to changes in differentials between heavy oil feedstock and synthetic crude. Gross margin increased 6 percent from the second quarter of 2022, due to higher production volumes from the Lloydminster Refinery and the Lloydminster Upgrader (the “Upgrader”). Gross margin in our U.S. downstream operations was consistent with the first quarter of 2023, and decreased 54 percent from the second quarter of 2022 primarily due to significantly lower market crack spreads.
Operating margin was $2.4 billion, an increase of 14 percent from the first quarter of 2023, primarily due to higher realized crude oil prices. Operating margin decreased 49 percent from the second quarter 2022 primarily due to significantly lower commodity pricing and market crack spreads. Cash from operating activities was $2.0 billion, an increase of $2.3 billion from the first quarter of 2023, driven largely by the payment of a $1.2 billion income tax liability in the first quarter of 2023. Cash from operating activities decreased $989 million from the second quarter of 2022, primarily due to lower operating margin. Adjusted Funds Flow was $1.9 billion in the second quarter of 2023, an increase of 36 percent from the first quarter of 2023, and a decrease of 39 percent from the second quarter of 2022.
On June 14, 2023, we purchased and cancelled 45.5 million outstanding common share purchase warrants (“Cenovus Warrants”) for $711 million. We have the option to pay the aggregate warrant purchase price through the remainder of 2023, with full payment being made no later than January 5, 2024. Payments will be considered as part of our shareholder returns framework. No payments related to the purchased warrants were made in the second quarter.
On July 26, 2023, the Board declared a third quarter base dividend of $0.140 per common share. The dividend is payable on September 29, 2023, to common shareholders of record as at September 15, 2023. The Board also declared third quarter dividends for our preferred shares of $9 million, payable on October 3, 2023, to preferred shareholders of record as at September 15, 2023.

































Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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OPERATING AND FINANCIAL RESULTS
Selected Operating Results — Upstream
Three Months Ended June 30,
Six Months Ended June 30,
Percent ChangePercent Change
2023202220232022
Upstream Production Volumes by Segment (1) (MBOE/d)
Oil Sands
573.83 558.8581.61 577.9
Conventional
104.6(21)132.6114.2(11)128.8
Offshore
51.5(27)70.158.6(20)73.2
Total Production Volumes
729.9(4)761.5754.4(3)779.9
Upstream Production Volumes by Product
Bitumen (Mbbls/d)
554.63 540.3562.51 559.5
Heavy Crude Oil (Mbbls/d)
17.04 16.416.94 16.3
Light Crude Oil (Mbbls/d)
10.1(51)20.812.7(41)21.4
NGLs (Mbbls/d)
26.7(27)36.730.0(19)37.2
Conventional Natural Gas (MMcf/d)
729.4(17)882.2793.1(9)873.9
Total Production Volumes (MBOE/d)
729.9(4)761.5754.4(3)779.9
Total Upstream Sales Volumes (2) (MBOE/d)
642.1(6)684.5662.0(6)704.2
Netback (3) (4) ($/BOE)
38.87(45)71.0933.89(48)64.78
(1)Refer to the Oil Sands, Conventional or Offshore Reportable Segments section of this MD&A for a summary of production by product type.
(2)Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 521 MMcf per day and 534 MMcf per day for the three and six months ended June 30, 2023, respectively (506 MMcf per day and 516 MMcf per day for the three and six months ended June 30, 2022, respectively).
(3)Upstream revenue as found in Note 1 of the interim Consolidated Financial Statements was $6.8 billion and $13.6 billion for the three and six months ended June 30, 2023, respectively ($10.1 billion and $19.8 billion for the three and six months ended June 30, 2022, respectively).
(4)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
In the three and six months ended June 30, 2023, total crude oil, NGLs and natural gas production decreased compared with the same periods in 2022 due to:
The temporary shut-in of a significant portion of production in our Conventional operations in response to wildfire activity in May and into June.
A planned turnaround completed at Foster Creek in the second quarter of 2023.
Changes to the Liwan 3-1 gas sales agreement in China in the second quarter of 2022, concluding the amendment that temporarily increased sales volumes.
A temporary unplanned outage in China in the second quarter of 2023, related to the disconnection of the umbilical by a third-party vessel in early April, reconnected in May.
A planned turnaround completed in our Atlantic operations in the second quarter of 2023.
The decrease was partially offset by:
The acquisition of the remaining 50 percent interest in Sunrise (the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“bp Canada”) on August 31, 2022.
First oil at the Spruce Lake North thermal plant in the third quarter of 2022.
First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022.
























Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Selected Operating Results — Downstream
Three Months Ended June 30,
Six Months Ended June 30,
Percent ChangePercent Change
2023202220232022
Downstream Crude Oil Unit Throughput (Mbbls/d)
Canadian Manufacturing
95.318 80.997.09 89.4
U.S. Manufacturing
442.518 376.4401.13 390.0
Total Crude Oil Unit Throughput
537.818 457.3498.14 479.4 
Downstream Production Volumes (Mbbls/d)
Canadian Manufacturing
108.319 90.9110.610 100.7
U.S. Manufacturing
463.619 391.2419.43 408.9
Total Downstream Production
571.919 482.1530.04 509.6
In the Canadian Manufacturing segment, throughput increased in the second quarter of 2023 compared with 2022, primarily due to the Lloydminster Refinery operating at or near capacity in 2023 and the completion of planned turnarounds at the Upgrader and the Lloydminster Refinery in 2022. The increase was partially offset by an unplanned outage at the Upgrader in April that was resolved in May.
Year-to-date, throughput in the Canadian Manufacturing segment increased due to the 2022 planned turnarounds, partially offset by cold weather impacts and operational outages experienced in late 2022 at the Upgrader which returned to full rates by the middle of January. In addition, throughput at the Upgrader was impacted by maintenance activities in the first quarter of 2023.
In the U.S. Manufacturing segment, total crude oil unit throughput and refined products production increased in the three and six months ended June 30, 2023, compared with the same periods in 2022 due to:
Strong performance at the Lima Refinery with an increase in throughput quarter-over-quarter and on a year-to-date basis.
The purchase of the remaining 50 percent interest in the Toledo Refinery from BP Products North America Inc. (“bp”) on February 28, 2023 (the “Toledo Acquisition”). The refinery partially restarted in April and commenced full operations in June. In the second quarter of 2022, we commenced a significant planned turnaround at the Toledo Refinery that was completed in the third quarter of 2022.
The introduction of crude oil at the Superior Refinery in mid-March 2023, with throughput ramping up through the second quarter. Work is underway to start up the FCCU.
An increase in throughput at the Wood River Refinery. The planned turnaround completed in the second quarter had less of an impact than the turnaround in 2022. On a year-to-date basis, the increase in throughput was also due to the decision to operate at reduced rates early in 2022 to optimize margins as market conditions dictated.
Increased throughput and refined products output in the three and six months ended June 30, 2023, was partially offset by:
A planned turnaround at the Borger Refinery at the end of March and completed by late April. There were temporary unplanned outages at the refinery in the second quarter.
Unplanned outages at the Wood River and Borger refineries stemming from the fourth quarter of 2022 that were resolved in the first quarter of 2023.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Selected Consolidated Financial Results
Operating Margin
Operating Margin is a specified financial measure and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods.
Three Months Ended June 30,
Six Months Ended June 30,
($ millions)20232022 20232022
Gross Sales 14,960 22,404 29,743 41,417 
Less: Royalties637 1,582 1,233 2,767 
Revenues14,323 20,822 28,510 38,650 
Expenses
Purchased Product7,466 10,380 14,757 19,015 
Transportation and Blending2,750 3,238 5,744 6,432 
Operating Expenses
1,726 1,876 3,509 3,430 
Realized (Gain) Loss on Risk Management Activities(19)650 (2)1,631 
Operating Margin
2,400 4,678 4,502 8,142 
Operating Margin by Segment
Three Months Ended June 30, 2023
opmarginbyseg-3montha.jpg
Operating Margin decreased in the three months ended June 30, 2023, compared with the same period in 2022, primarily due to:
Lower realized crude oil, NGLs and natural gas sales prices resulting from significantly lower benchmark pricing.
Decreased gross margins in the U.S. Manufacturing segment resulting from lower market crack spreads and inventory build-up.
Lower sales volumes from our Offshore and Conventional segments.
These decreases in Operating Margin were partially offset by:
Decreased royalties in the Oil Sands and Conventional segments, resulting from lower crude oil and natural gas benchmark pricing.
Realized risk management gains in 2023 compared with significant realized risk management losses in 2022.
Lower blending costs due to decreased condensate prices.
Decreased operating expenses in our upstream and downstream operations mainly due to lower natural gas prices.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Six Months Ended June 30, 2023
opmarginbyseg-6montha.jpg
Operating Margin decreased in the six months ended June 30, 2023, compared with 2022, primarily due to the same reasons as discussed above.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations.
Three Months Ended June 30,
Six Months Ended June 30,
($ millions)2023202220232022
Cash From (Used in) Operating Activities1,990 2,979 1,704 4,344 
(Add) Deduct:
Settlement of Decommissioning Liabilities
(41)(27)(89)(46)
Net Change in Non-Cash Working Capital132 (92)(1,501)(1,291)
Adjusted Funds Flow
1,899 3,098 3,294 5,681 
Cash from operating activities was $2.0 billion in the second quarter of 2023, compared with $3.0 billion in 2022. The decrease was primarily due to lower Operating Margin, partially offset by lower cash taxes, changes in non-cash working capital and the 2022 contingent payment associated with the 2017 acquisition of a 50 percent interest in the FCCL Partnership.
Cash from operating activities was $1.7 billion in the first six months of 2023, compared with $4.3 billion in 2022. The change was primarily due to lower Operating Margin and changes in non-cash working capital, partially offset by lower cash taxes and the 2022 contingent payment as discussed above. The net change in non-cash working capital in the first half of 2023 was $1.5 billion (2022 – $1.3 billion) mainly due to paying a $1.2 billion income tax liability.
Adjusted Funds Flow was lower in the three and six months ended June 30, 2023, compared with the same periods in 2022, primarily due to decreased Operating Margin, as discussed above.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Net Earnings (Loss)
($ millions)Three Months EndedSix Months Ended
Net Earnings (Loss), for the Periods Ended June 30, 20222,432 4,057 
Increase (Decrease) due to:
Operating Margin(2,278)(3,640)
Corporate and Eliminations:
General and Administrative51 92 
Finance Costs2 37 
Integration and Transaction Costs11 15 
Unrealized Foreign Exchange Gain (Loss)432 279 
Revaluation Gain (Loss) (33)
Re-measurement of Contingent Payments16 235 
Gain (Loss) on Divestiture of Assets(52)(293)
Other Income (Loss), net(24)(388)
Other (1)
(59)(70)
Unrealized Risk Management Gain (Loss)
(390)(37)
Depreciation, Depletion and Amortization60 (15)
Exploration Expense6 18 
Income Tax (Expense) Recovery659 1,245 
Net Earnings (Loss), for the Periods Ended June 30, 2023866 1,502 
(1)Includes Corporate and Eliminations revenues, purchased product, transportation and blending expenses, operating expenses and (gain) loss on risk management; share of income (loss) from equity-accounted affiliates; interest income and realized foreign exchange (gains) losses.
Net earnings in the second quarter of 2023 decreased compared with the same period in 2022 due to declines in Operating Margin and unrealized risk management losses in 2023 compared with gains in 2022. The decrease in net earnings was partially offset by a lower income tax expense and unrealized foreign exchange gains in 2023 compared with losses in 2022.
Net earnings in the first six months of 2023 decreased compared with the same period in 2022 due to declines in Operating Margin, lower other income due to the 2022 insurance proceeds related to the Superior Refinery and Atlantic region incidents, gains on the divestiture of the Tucker and Wembley assets and the divestiture of 12.5 percent of our interest in the White Rose field in 2022, compared with minor divestitures in 2023. The decrease in net earnings was partially offset by a lower income tax expense, unrealized foreign exchange gains in 2023 compared with losses in 2022 and the re-measurement of our contingent payments.
Net Debt
As at ($ millions)
June 30, 2023
December 31, 2022
Short-Term Borrowings 115 
Current Portion of Long-Term Debt — 
Long-Term Portion of Long-Term Debt8,534 8,691 
Total Debt8,534 8,806 
Less: Cash and Cash Equivalents(2,167)(4,524)
Net Debt
6,367 4,282 
For further details see the Liquidity and Capital Resources section of this MD&A.























Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Capital Investment (1)
Three Months Ended June 30,
Six Months Ended June 30,
($ millions)2023202220232022
Upstream
Oil Sands539 376 1,174 751 
Conventional82 33 223 121 
Offshore184 91 284 144 
Total Upstream805 500 1,681 1,016 
Downstream
Canadian Manufacturing 34 38 61 53 
U.S. Manufacturing153 267 347 474 
Total Downstream187 305 408 527 
Corporate and Eliminations10 17 14 25 
Total Capital Investment1,002 822 2,103 1,568 
(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes cost incurred in our equity-accounted investment in Indonesia.
Oil Sands capital investment in the first six months of 2023 was mainly for sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal assets and Sunrise, and the drilling of stratigraphic test wells as part of our integrated winter program in the first quarter.
Conventional capital investment in the first half of 2023 continued to focus on drilling, completion and tie-in activities, and infrastructure projects to support multi-year development.
Offshore capital investment in the first six months of 2023 was primarily for the West White Rose project and Terra Nova asset life extension (“ALE”) project in the Atlantic region.
U.S. Manufacturing capital investment in the first half of 2023 focused primarily on the Superior Refinery rebuild, and refining and reliability initiatives at the Wood River, Borger, Lima and Toledo refineries.
Drilling Activity
 Net Stratigraphic Test Wells
and Observation Wells
Net Production Wells (1)
Six Months Ended June 30,2023202220232022
Foster Creek
87 68 10 11 
Christina Lake 53 — 11 20 
Sunrise38 15 7 
Lloydminster Thermal1  22 
Lloydminster Conventional Heavy Oil1 — 5 — 
Other (2)
3  — 
183 90 33 55 
(1)SAGD well pairs in the Oil Sands segment are counted as a single producing well.
(2)Includes new resource plays and the Tucker asset sold on January 31, 2022.
Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and to further progress the evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions.
Six Months EndedSix Months Ended
June 30, 2023June 30, 2022
(net wells)DrilledCompletedTied-inDrilledCompletedTied-in
Conventional17 21 22 13 28 22 
In the Offshore segment, we drilled and completed one (0.4 net) planned development well at the MAC field in Indonesia in the first six months of 2023 (first six months of 2022 — drilled and completed four (1.6 net) planned development wells at the MBH and MDA fields in Indonesia).






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Future Capital Investment
Future Capital Investment is a specified financial measure. See the Specified Financial Measures Advisory of this MD&A. Our 2023 guidance, as updated on July 26, 2023, is available on our website at cenovus.com.
Our updated guidance reflects lower production mainly due to the impact of wildfires on the Conventional segment in the second quarter of 2023 and year-to-date operating performance in our Oil Sands segment. Crude oil unit throughput guidance did not change as part of the update. Terra Nova production was removed from guidance as part of the April 25, 2023, update.
The following table shows guidance for 2023:
Capital Investment
($ millions)
Production
(MBOE/d)
Crude Oil Unit Throughput
(Mbbls/d)
Upstream
Oil Sands 2,200 - 2,400577 - 637
Conventional350 - 450115 - 130
Offshore600 - 70055 - 68
Downstream800 - 900580 - 610
Corporate and Eliminations40 - 50
2023 guidance for total capital investment is between $4.0 billion and $4.5 billion. This includes sustaining capital of approximately $2.8 billion, and between $1.2 billion and $1.7 billion in optimization and growth capital. Capital investment guidance did not change as part of the July 26, 2023, update.
Further information on the changes in our financial and operating results can be found in the Reportable Segments section of this MD&A. Information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the interim Consolidated Financial Statements.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, quality and location price differentials, refining crack spreads as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
Six Months Ended June 30,
(Average US$/bbl, unless otherwise indicated)2023Percent Change2022Q2 2023Q1 2023Q2 2022
Dated Brent
79.83 (26)107.59 78.39 81.27 113.78 
WTI74.96 (26)101.35 73.78 76.13 108.41 
Differential Dated Brent-WTI4.87 (22)6.24 4.61 5.14 5.37 
WCS at Hardisty55.05 (37)87.68 58.74 51.36 95.61 
Differential WTI-WCS19.91 46 13.67 15.04 24.77 12.80 
WCS (C$/bbl)
74.17 (34)111.54 78.90 69.44 122.07 
WCS at Nederland64.73 (33)96.26 66.98 62.49 103.34 
Differential WTI-WCS at Nederland10.23 101 5.09 6.80 13.64 5.07 
Condensate (C5 @ Edmonton)76.13 (26)102.21 72.39 79.87 108.34 
Differential WTI-Condensate (Premium)/Discount(1.17)(36)(0.86)1.39 (3.74)0.07 
Differential WCS (2)-Condensate (Premium)/Discount
(21.08)(45)(14.53)(13.65)(28.51)(12.73)
Average (C$/bbl)
102.61 (21)129.99 97.25 107.95 138.30 
Synthetic @ Edmonton77.42 (25)103.75 76.66 78.18 114.46 
Differential WTI-Synthetic (Premium)/Discount (2.46)(3)(2.40)(2.88)(2.05)(6.05)
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)101.07 (22)129.11 102.32 99.82 149.05 
Chicago Ultra-low Sulphur Diesel (“ULSD”)108.90 (24)143.11 102.40 115.39 166.62 
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)
28.72 (11)32.43 28.57 28.88 46.50 
Group 3 3-2-1 Crack Spread (3)
31.56 (2)32.15 31.78 31.35 44.35 
Renewable Identification Numbers (“RINs”)7.98 12 7.12 7.72 8.20 7.80 
Natural Gas Prices
AECO (C$/Mcf)
3.34 (38)5.43 2.35 4.34 6.28 
NYMEX (US$/Mcf)
2.76 (54)6.06 2.10 3.42 7.17 
Foreign Exchange Rates
US$ per C$1 - Average0.742 (6)0.787 0.745 0.739 0.783 
US$ per C$1 - End of Period0.755 (3)0.776 0.755 0.739 0.776 
RMB per C$1 - Average5.143 1 5.098 5.228 5.059 5.180 
(1)These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management results, refer to the Netback tables in the Reportable Segments section of this MD&A.
(2)WCS at Hardisty.
(3)The average 3-2-1 crack spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.
Crude Oil and Condensate Benchmarks
In the second quarter of 2023, Brent and WTI prices continued to decline compared with the first quarter of 2023 and all quarters in 2022. Prices declined due to ongoing macroeconomic concerns, crude oil supply growth outside of OPEC+ and diminished risk related to Russian export supply shortfall. Further OPEC+ production cuts and strong demand growth following the lifting of China’s COVID-19 restrictions were supportive of pricing in the second quarter of 2023.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties.
The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI differential narrowed in the second quarter of 2023 and on a year-to-date basis compared with 2022 as physical supply uncertainty and high marine fuel prices caused the differential to widen significantly in the months following Russia’s invasion of Ukraine in February 2022.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude and the cost of transport. The average WTI-WCS differential at Hardisty narrowed significantly compared with the first quarter of 2023 following the completion of refinery maintenance and OPEC+ cuts to medium and heavy crude production. Reduced supply in the Western Canadian Sedimentary Basin (“WCSB”) due to upstream turnarounds and forest fire activity also narrowed the differential.
During the three and six months ended June 30, 2023, the WTI-WCS differential at Hardisty widened compared with 2022 primarily due to wide light-heavy differentials at the U.S. Gulf Coast (“USGC”) as a result of high global refining utilization and volatile refined product pricing. In addition, lower heavy crude oil demand from planned and unplanned refinery maintenance in the first quarter of 2023 contributed to a wider differential.
WCS at Nederland is a heavy oil benchmark for sales of our product at the USGC. The WTI-WCS at Nederland differential is representative of the heavy oil quality discount and is influenced by global heavy oil refining capacity and global heavy oil supply. The WTI-WCS at Nederland differential narrowed significantly from the first quarter of 2023 and widened compared with 2022 due to the same factors impacting the WTI-WCS differential at Hardisty discussed above.
In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
In the second quarter of 2023, synthetic crude at Edmonton was at a lower premium to WTI compared with the second quarter of 2022. Year-to-date, the premium was relatively consistent with 2022. Synthetic crude prices were elevated in the second quarter of 2022 as a result of upgrader maintenance in Western Canada and strong refinery demand for light crude oil.
crudeoilbenchmarka.jpg
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated as diluent volumes as a percentage of total blended volumes, range from approximately 22 percent to 35 percent. The WCS-Condensate differential is an important benchmark as a wider differential generally results in a decrease in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending as well as timing of sales of blended product. The WCS-Condensate differential widened in the second quarter of 2023 and on a year-to-date basis compared with 2022.
Edmonton condensate traded at a discount to WTI in the second quarter of 2023 and 2022, and at a premium to WTI in the first quarters of 2023 and 2022, consistent with typical seasonal pricing patterns associated with increased diluent demand in winter months, which supports condensate pricing. In the first half of 2023, the average premium to WTI was consistent with the first half of 2022.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Refining Benchmarks
RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current-month WTI- based crude oil feedstock prices and valued on a last in, first out basis.
The Chicago 3-2-1 market crack spread reflects the market for the Toledo, Lima and Wood River refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries.
Refined product prices declined in line with crude oil prices in the three and six months ended June 30, 2023, compared with the same periods in 2022. Market crack spreads also declined during this period as 2022 saw periods of historically high refined product prices and refining margins. Reduced refinery outages and incremental global capacity additions have resulted in declining refined product prices relative to WTI in 2023, particularly in diesel markets. RINs costs remain high as a result of a tight biofuel market, high feedstock prices and uncertainty around policies that drive RINs demand.
North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices. The strength of refining market crack spreads in the U.S. Midwest and Midcontinent generally reflects the differential between Brent and WTI benchmark prices.
Our refining margins are affected by many other factors such as the variety of crude oil feedstock, refinery configuration and product output, where feedstocks are acquired and the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock, which is valued on a first in, first out (“FIFO”) accounting basis. The market crack spreads do not precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator.
chicago3-2x1csba.jpg
(1)There are no forward prices for RINs.
Natural Gas Benchmarks
Average NYMEX and AECO natural gas prices decreased significantly compared with the three and six months ended June 30, 2022, and the first quarter of 2023, due to mild winter conditions weighing on U.S. domestic demand coupled with record high natural gas production and inventories. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.
Foreign Exchange Benchmarks
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported revenue. In addition to our revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. In addition, changes in foreign exchange rates impact the translation of our U.S. and Asia Pacific operations.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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In the three and six months ended June 30, 2023, the Canadian dollar on average weakened relative to the U.S. dollar compared with the same periods in 2022, positively impacting our reported revenues. The Canadian dollar strengthened relative to the U.S. dollar as at June 30, 2023, compared with March 31, 2023 and December 31, 2022, resulting in unrealized foreign exchange gains on the translation of our U.S. dollar debt into Canadian dollars.
A portion of our long-term sales contracts in the Asia Pacific region are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. In the three and six months ended June 30, 2023, the Canadian dollar on average was relatively consistent with RMB compared with the same periods in 2022, resulting in minimal impact on our revenues.
Interest Rate Benchmarks
Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. An increase in interest rates could increase our net interest expense and affect how certain liabilities are measured, and could negatively impact our cash flow and financial results.
As at June 30, 2023, the Bank of Canada’s Policy Interest Rate was 4.75 percent, an increase from 4.50 percent on March 31, 2023, and from 4.25 percent on December 31, 2022, due to concerns over inflation. On July 12, 2023, the rate increased to 5.00 percent.
OUTLOOK
COMMODITY PRICE OUTLOOK
Global crude oil prices have continued to decline since the second quarter of 2022 due to demand concerns amid a weakening macroeconomic environment and adequate supply growth outside of OPEC+. The geopolitical premium associated with Russian supply uncertainty also faded in the back half of 2022 as Russian exports of crude oil and refined products remained resilient. Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers and government policy playing a large role in supply and demand dynamics. Policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shift global trade patterns. The OPEC+ announced production cuts will continue to be supportive of pricing with production quotas being a key driver of crude oil prices.
Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the timing and ability of producers and governments to replace reduced supply and the refilling or release of SPRs. In addition, weakening global economic activity, inflation and rising interest rates, and the potential for a recession remain a risk to the pace of demand growth.
In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
We expect the WTI-WCS at Hardisty differential will remain largely tied to global supply factors and heavy crude oil processing capacity as long as supply stays within Canadian crude oil export capacity. We expect the anticipated start-up of the Trans Mountain pipeline expansion in 2024 to have a narrowing impact on WTI-WCS differentials.
We expect market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies could impact demand. Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America.
NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and ample gas in storage. Weather will continue to be a key driver of demand and impact prices.
We expect the Canadian dollar to continue to be impacted by crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, and emerging macro-economic factors.
Most of our upstream crude oil and downstream refined products production are exposed to movements in the WTI crude oil price. Our physically integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Natural gas and NGLs production associated with our Conventional operations provide economic integration for the fuel, solvent and blending requirements at our Oil Sands operations. Crude oil production in our upstream assets is used as feedstock by our downstream operations, and condensate extracted from our blended crude oil production is sold back to our Oil Sands operations. The restart of the Superior and Toledo refineries provide further integration.
Our refining capacity is focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to the market crack spreads in all of these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our refining capacity, and to a lesser degree in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differentials, which could be subject to transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product differentials through the following:
Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.
Integration – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil as well as from spreads on refined products.
Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil price differentials.
Traditional crude oil storage tanks in various geographic locations.
REPORTABLE SEGMENTS
UPSTREAM
Oil Sands
In the second quarter of 2023, we:
Delivered safe and reliable operations, and completed a planned turnaround at Foster Creek.
Produced 571.6 thousand barrels of crude oil per day (2022 – 556.7 thousand barrels of crude oil per day).
Began ramping up production on a total of three new well pads at Foster Creek and Christina Lake.
Generated Operating Margin of $2.0 billion, a decrease of $885 million compared with 2022 primarily due to lower average realized sales prices.
Invested capital of $539 million primarily for sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal assets and Sunrise.
Achieved a Netback of $38.49 per BOE (2022 – $67.83 per BOE).
Financial Results
Three Months Ended June 30,
Six Months Ended June 30,
($ millions)2023202220232022
Revenues
Gross Sales
6,556 10,048 12,467 19,266 
Less: Royalties 620 1,491 1,136 2,573 
5,936 8,557 11,331 16,693 
Expenses
Purchased Product 533 1,071 1,092 2,283 
Transportation and Blending
2,700 3,200 5,641 6,356 
Operating
676 806 1,413 1,508 
Realized (Gain) Loss on Risk Management(9)559 (1)1,426 
Operating Margin2,036 2,921 3,186 5,120 
Unrealized (Gain) Loss on Risk Management
31 (323)(3)(57)
Depreciation, Depletion and Amortization730 690 1,445 1,325 
Exploration Expense2 (1)4 — 
(Income) Loss from Equity-Accounted Affiliates6 6 
Segment Income (Loss)1,267 2,547 1,734 3,844 






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Operating Margin Variance
Three Months Ended June 30, 2023
oswaterfallqtda.jpg
Six Months Ended June 30, 2023
oswaterfallytda.jpg
(1)Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses.
(2)Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
Operating Results
Three Months Ended June 30,
Six Months Ended June 30,
2023202220232022
Total Sales Volumes (MBOE/d)
578.1 563.9 577.5 586.7 
Total Realized Price (1) ($/BOE)
71.03 119.98 63.37 107.54 
Crude Oil Production by Asset (Mbbls/d)
Foster Creek167.0 187.8 178.4 192.8 
Christina Lake234.9 228.8 236.0 241.4 
Sunrise (2)
46.5 25.3 45.5 24.7 
Lloydminster Thermal106.2 98.4 102.6 97.4 
Lloydminster Conventional Heavy Oil17.0 16.4 16.9 16.3 
Tucker (3)
 —  3.2 
Total Crude Oil Production (4) (Mbbls/d)
571.6 556.7 579.4 575.8 
Natural Gas (5) (MMcf/d)
12.9 12.0 12.7 12.4 
Total Production (MBOE/d)
573.8558.8581.6577.9
Effective Royalty Rate (percent)
18.7 25.7 19.8 24.1 
Transportation and Blending Expense (1) ($/BOE)
8.04 7.51 8.55 7.36 
Operating Expense (1) ($/BOE)
12.72 15.70 13.37 14.05 
Per Unit DD&A (1) ($/BOE)
13.00 11.78 12.87 11.93 
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)On August 31, 2022, we acquired the remaining 50 percent interest in Sunrise from bp Canada.
(3)The Tucker asset was sold on January 31, 2022.
(4)Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.
(5)Conventional natural gas product type.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
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Revenues
Price
Our heavy oil and bitumen production must be blended with condensate to reduce its viscosity in order to transport it to market through pipelines. Our realized bitumen sales price does not include the sale of condensate; however, it is influenced by the price of condensate. As the cost of condensate increases relative to the price of blended crude oil, our realized heavy oil and bitumen sales price decreases. In the three and six months ended June 30, 2023, condensate pricing benchmarks were at a US$13.65 per barrel and US$21.08 per barrel premium, respectively, to WCS at Hardisty (2022 – US$12.73 and US$14.53, respectively). The increases had a negative impact on our realized bitumen sales price compared with 2022. Another significant factor is that up to three months may lapse from when we purchase condensate to when we sell our blended production.
Our realized sales price averaged $71.03 per BOE and $63.37 per BOE, respectively, in the three and six months ended June 30, 2023, (2022 – $119.98 per BOE and $107.54 per BOE, respectively) due to lower WTI benchmark prices and wider WTI-WCS differentials. In the three and six months ended June 30, 2023, the WTI-WCS differential at Hardisty widened to US$15.04 per barrel and US$19.91 per barrel, respectively (2022 – US$12.80 per barrel and US$13.67, respectively). To improve our realized sales price in the first half of 2023, we sold approximately 25 percent (2022 – 25 percent) of our crude oil volumes at U.S. destinations.
For the three and six months ended June 30, 2023, gross sales included $470 million and $968 million, respectively (2022 – $975 million and $2.1 billion, respectively), from third-party sourced volumes which are not included in our realized price or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.
For the three and six months ended June 30, 2023, gross sales included $106 million and $186 million, respectively (2022 – $117 million and $169 million, respectively), relating to construction, transportation and blending activities. These amounts are not included in our realized price or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.
Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification. To price protect our inventories associated with storage or transport decisions, Cenovus employs various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.
In the three and six months ended June 30, 2023, our realized risk management gains were $9 million and $1 million, respectively (2022 – losses of $559 million and $1.4 billion, respectively). The changes from 2022 are due to a rising commodity price environment in the first half of 2022 and management’s decision to liquidate our WTI positions related to crude oil sales price risk management in the second quarter of 2022. In the three and six months ended June 30, 2023, we recorded unrealized risk management losses of $31 million and gains of $3 million, respectively (2022 – gains of $323 million and $57 million, respectively), on our crude oil and condensate financial instruments primarily due to changes in forward benchmark pricing relative to our risk management contract prices that related to future periods.
Production Volumes
Oil Sands crude oil production was 571.6 thousand barrels per day and 579.4 thousand barrels per day in the three and six months ended June 30, 2023, respectively (2022 – 556.7 thousand barrels per day and 575.8 thousand barrels per day, respectively).
Production at Foster Creek decreased 20.8 thousand barrels per day and 14.4 thousand barrels per day in the three and six months ended June 30, 2023, respectively, compared with the same periods in 2022. The decreases were primarily due to a planned turnaround that commenced in mid-April and completed in early May. Production at Christina Lake increased slightly quarter-over-quarter and decreased slightly year-over-year. We completed a turnaround at Christina Lake in the second quarter of 2022. Production at Foster Creek and Christina Lake was impacted in the first six months of 2023 as we prepared for the start-up of new well pads. We began ramping up production on a total of three new well pads at Foster Creek and Christina Lake in the second quarter.
The Sunrise Acquisition was completed on August 31, 2022. Production at Sunrise increased 21.2 thousand barrels per day and 20.8 thousand barrels per day, respectively, in the three and six months ended June 30, 2023, compared with 2022. The increase in production related to the acquisition was partially offset by wells taken offline in preparation for a 2023 redevelopment program.
Production from our Lloydminster thermal assets increased in the three and six months ended June 30, 2023, compared with 2022. The increases are due to first oil at the Spruce Lake North thermal plant in August 2022, partially offset by wells taken offline for a redevelopment program and workover activity in the first six months of 2023.
Lloydminster conventional heavy oil production increased marginally in the three and six months ended June 30, 2023, compared with 2022.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 20



Royalties
Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Saskatchewan.
Our Alberta oil sands royalty projects (Foster Creek, Christina Lake and Sunrise) are based on government prescribed pre- and post-payout royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.
Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.
Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales revenues less diluent costs and transportation costs. Net revenues are calculated as sales revenues less diluent costs, transportation costs, and allowed operating and capital costs.
Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.
For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes each project's Crown and freehold split. For Crown royalties, the pre-payout calculation is based on a one percent rate and the post-payout calculation is based on a 20 percent rate. The freehold calculation is limited to post-payout projects and is based on an eight percent rate.
Effective royalty rates decreased compared with 2022 primarily due to lower realized pricing and lower Alberta oil sands sliding scale royalty rates. For the three and six months ended June 30, 2023, royalties were $620 million and $1.1 billion, respectively (2022 – $1.5 billion and $2.6 billion, respectively).
Expenses
Transportation and Blending
In the second quarter of 2023, blending costs decreased $556 million to $2.3 billion compared with 2022. In the first half of 2023, blending costs decreased $864 million to $4.7 billion compared with 2022. The declines in both periods were largely due to lower condensate prices, partially offset by higher volumes.
Transportation costs increased $56 million to $450 million in the second quarter of 2023 compared with 2022, due to higher costs as discussed below combined with increased sales volumes. In the first six months of 2023, transportation costs rose $149 million to $940 million, due to higher costs as discussed below.
Per-unit Transportation Expenses
Transportation costs were $8.04 per BOE and $8.55 per BOE in the three and six months ended June 30, 2023, respectively (2022 – $7.51 per BOE and $7.36 per BOE, respectively).
At Foster Creek, per-unit transportation costs increased 23 percent and 30 percent to $12.80 per barrel and $13.13 per barrel in the three and six months ended June 30, 2023, respectively. The increases were mainly due to higher tariff rates and lower sales volumes. In the three and six months ended June 30, 2023, we shipped 47 percent and 48 percent, respectively (2022 – 46 percent and 42 percent, respectively) of our volumes from Foster Creek to U.S. destinations.
At Christina Lake, transportation costs were $5.91 per barrel and $6.81 per barrel in the three and six months ended June 30, 2023 (2022 – $6.75 per barrel and $6.55 per barrel, respectively). The quarter-over-quarter decrease was primarily due to lower fixed rail costs, partially offset by higher sales to the U.S. and increased tariff rates. Year-to-date, per-unit transportation costs increased slightly, primarily due to higher volumes shipped to the U.S. and increased tariff rates, partially offset by lower fixed rail costs. In the three and six months ended June 30, 2023, we shipped 17 percent and 18 percent, respectively (2022 – 14 percent and 15 percent, respectively) of our volumes from Christina Lake to U.S. destinations.
At Sunrise, transportation costs in the three and six months ended June 30, 2023, were $12.58 per barrel and $12.62 per barrel, respectively (2022 – $12.48 per barrel and $12.82 per barrel, respectively). In the three and six months ended June 30, 2023, we shipped 50 percent and 48 percent, respectively (2022 – 48 percent and 58 percent, respectively) of our total volumes to the U.S.
At our other Oil Sands assets, transportation costs in the three and six months ended June 30, 2023, were $3.60 per barrel and $3.67 per barrel, respectively (2022 – $3.28 per barrel and $3.39 per barrel, respectively).






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 21



Operating
Primary drivers of our operating expenses in the first six months of 2023 were fuel, workforce, chemicals, and repairs and maintenance. Total operating expenses decreased due to lower fuel costs as a result of significant declines in AECO benchmark prices in the three and six months ended June 30, 2023, compared with 2022. The decreases were partially offset by higher repairs and maintenance, and workforce costs.
Unit Operating Expenses (1)
Three Months Ended June 30,
Six Months Ended June 30,
($/BOE)
2023Percent
Change
20222023Percent
Change
2022
Foster Creek
Fuel
3.40 (50)6.74 4.27 (25)5.71 
Non-Fuel
8.81 16 7.57 8.34 19 7.02 
Total
12.21 (15)14.31 12.61 (1)12.73 
Christina Lake
Fuel
2.77 (55)6.13 3.26 (38)5.27 
Non-Fuel
5.32 (6)5.64 5.34 4 5.15 
Total
8.09 (31)11.77 8.60 (17)10.42 
Sunrise
Fuel4.52 (52)9.32 5.49 (30)7.89 
Non-Fuel
12.86 8 11.90 14.00 26 11.14 
Total
17.38 (18)21.22 19.49 2 19.03 
Other Oil Sands (2)
Fuel
3.97 (60)9.81 4.91 (41)8.38 
Non-Fuel
16.33 11 14.77 16.73 18 14.18 
Total
20.30 (17)24.58 21.64 (4)22.56 
Total12.72 (19)15.70 13.37 (5)14.05 
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.
Per-unit fuel prices decreased overall due to lower natural gas prices as discussed above. Per-unit fuel prices are also impacted by the timing and value of sales out of inventory.
Foster Creek per-unit non-fuel costs increased in the three and six months ended June 30, 2023, compared with 2022 due to lower sales volumes combined with costs related to the planned turnaround in the second quarter of 2023.
Christina Lake per-unit non-fuel costs declined slightly quarter-over-quarter primarily due to lower electricity costs. Year-to-date, per-unit non-fuel costs increased slightly primarily due to lower sales volumes.
Sunrise per-unit non-fuel costs increased in the three and six months ended June 30, 2023, compared with 2022 mainly due to lower gross sales volumes in 2023, combined with higher electricity, workforce, and repairs and maintenance costs, partially offset by lower workover activity. Gross sales volumes in the first half of 2023 were 43.5 thousand barrels per day (2022 – 49.0 thousand barrels per day).
Per-unit non-fuel costs at our other Oil Sands assets increased in 2023 from 2022, primarily due to higher workover activity and repairs and maintenance costs, partially offset by higher sales volumes.
Netbacks
Three Months Ended June 30,
Six Months Ended June 30,
($/BOE)2023202220232022
Sales Price (1)
71.03 119.98 63.37 107.54 
Royalties (1)
11.78 28.94 10.87 24.18 
Transportation (1)
8.04 7.51 8.55 7.36 
Operating Expenses (1)
12.72 15.70 13.37 14.05 
Netback (2)
38.49 67.83 30.58 61.95 
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 22



DD&A
In the three months and six months ended June 30, 2023, DD&A was $730 million and $1.4 billion, respectively (2022 – $690 million and $1.3 billion, respectively). The average depletion rate for the three and six months ended June 30, 2023, was $13.00 per BOE and $12.87 per BOE, respectively (2022 – $11.78 per BOE and $11.93 per BOE, respectively).
Conventional
In the second quarter of 2023, we:
Delivered safe operations.
Produced 104.6 thousand BOE per day (2022 – 132.6 thousand BOE per day).
Responded to wildfires in northern Alberta. In early May, we temporarily shut-in approximately 85 thousand BOE per day of production in the operating areas of Rainbow Lake, Elmworth-Wapiti, Kaybob-Edson and Clearwater to ensure the safety of our staff, local communities and assets. The majority of our wells and facilities impacted by the fire were restarted by June. Approximately 5 to 7 thousand BOE per day of production remains offline near the end of July due to the lack of third-party power infrastructure.
Generated Operating Margin of $73 million, a decrease from $434 million in 2022 due to lower average realized sales prices and lower sales volumes.
Invested capital of $82 million with continued focus on drilling, completion and tie-in activities, and infrastructure projects to support multi-year development.
Averaged a Netback of $5.89 per BOE (2022 – $36.78 per BOE).
Financial Results
Three Months Ended June 30,
Six Months Ended June 30,
($ millions)2023202220232022
Revenues
Gross Sales
615 1,079 1,646 2,191 
Less: Royalties4 89 58 160 
611 990 1,588 2,031 
Expenses
Purchased Product352 390 862 996 
Transportation and Blending
46 34 94 68 
Operating144 128 294 262 
Realized (Gain) Loss on Risk Management(4)4 
Operating Margin73 434 334 697 
Unrealized (Gain) Loss on Risk Management
(1)(1)(21)(1)
Depreciation, Depletion and Amortization87 99 182 179 
Exploration Expense  
Segment Income (Loss)(13)335 173 518 
Operating Margin Variance
Three Months Ended June 30, 2023
convwaterfallqtda.jpg






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 23



Six Months Ended June 30, 2023
convwaterfallytda.jpg
(1)Reflects Operating Margin from processing facilities.
Operating Results
Three Months Ended June 30,
Six Months Ended June 30,
2023202220232022
Total Sales Volumes (MBOE/d)
104.6 132.6 114.2 128.8 
Total Realized Price (1) ($/BOE)
25.83 57.11 35.80 50.22 
Light Crude Oil ($/bbl)
104.40 134.66 103.48 123.27 
NGLs ($/bbl)
46.59 73.47 47.39 64.53 
Conventional Natural Gas ($/Mcf)
2.79 7.87 4.82 6.77 
Production by Product
Light Crude Oil (Mbbls/d)
4.8 7.5 5.6 7.9 
NGLs (Mbbls/d)
18.0 24.7 20.0 24.6 
Conventional Natural Gas (MMcf/d)
491.4 601.2 531.9 578.3 
Total Production (MBOE/d)
104.6 132.6 114.2 128.8 
Conventional Natural Gas Production (percentage of total)
78 76 78 75 
Crude Oil and NGLs Production (percentage of total)
22 24 22 25 
Effective Royalty Rate (percent)
2.5 13.6 11.5 14.5 
Transportation Costs (1) ($/BOE)
4.82 2.97 4.56 3.07 
Operating Expense (1) ($/BOE)
14.59 10.02 13.77 10.65 
Per Unit DD&A (1) ($/BOE)
9.01 8.21 8.76 8.20 
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Revenues
Price
Our total realized sales price decreased in the three and six months ended June 30, 2023, due to lower crude oil and natural gas benchmark prices. The AECO benchmark price declined 63 percent and 38 percent, respectively, for the three and six months ended June 30, 2023 compared with the same periods in 2022.
For the three and six months ended June 30, 2023, gross sales included $352 million and $862 million, respectively (2022 – $390 million and $996 million, respectively), relating to third-party sourced volumes, which are not included in our realized prices or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.
For the three and six months ended June 30, 2023, gross sales included amounts relating to processing and transportation activities undertaken for third parties of $17 million and $44 million, respectively (2022 – $14 million and $27 million, respectively), which are not included in our realized prices or our Netbacks. Refer to the Specified Financial Measures Advisory of this MD&A for more detail.
Production Volumes
For the three and six months ended June 30, 2023, production volumes decreased 28.0 thousand BOE per day and 14.6 thousand BOE per day, respectively, primarily due to the impact of wildfires discussed above.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 24



Royalties
The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Effective royalty rates decreased in the three and six months ended June 30, 2023, compared with the same periods in 2022, primarily due to sharp declines in natural gas pricing, increased gas cost allowance (“GCA”) deductions and the impact of wildfires. In Alberta, natural gas wells benefit from GCA which reduces royalties to account for capital and operating costs incurred to process and transport the Crown’s portion of natural gas production. Total royalties decreased compared with 2022 due to the same factors impacting effective royalty rates combined with lower sales volumes.
Expenses
Transportation
Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. In the second quarter of 2023, transportation costs increased $12 million to $46 million, compared with 2022, and per-unit transportation costs averaged $4.82 per BOE in 2023, compared with $2.97 per BOE in 2022. Year-to-date, transportation costs increased $26 million to $94 million, and per-unit transportation costs averaged $4.56 per BOE, compared with $3.07 per BOE in 2022. The increases were due mainly to incremental costs related to the wildfires and additional storage contracts.
Operating
Primary drivers of our operating expenses in the first half of 2023 were repairs and maintenance, workforce, property taxes and lease costs, and electricity. Operating expenses per BOE increased in the three and six months ended June 30, 2023, compared with 2022, primarily due to lower sales volumes and higher total operating expenses. Total operating expenses increased $16 million to $144 million quarter-over-quarter and $32 million to $294 million year-over-year. The increases were primarily due to higher repairs and maintenance and workforce costs. The wildfires had minimal impact on total operating expenses.
Netbacks
Three Months Ended June 30,
Six Months Ended June 30,
($/BOE)2023202220232022
Sales Price (1)
25.83 57.11 35.80 50.22 
Royalties (1)
0.53 7.34 2.84 6.83 
Transportation and Blending (1)
4.82 2.97 4.56 3.07 
Operating Expenses (1)
14.59 10.02 13.77 10.65 
Netback (2)
5.89 36.78 14.63 29.67 
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
DD&A
For the three and six months ended June 30, 2023, total Conventional DD&A was $87 million and $182 million, respectively (2022 – $99 million and $179 million, respectively). The average depletion rate for the three and six months ended June 30, 2023, was $9.01 per BOE and $8.76 per BOE, respectively (2022 – $8.21 per BOE and $8.20 per BOE, respectively).
Offshore
In the second quarter of 2023, we:
Delivered safe operations.
Produced 51.5 thousand BOE per day (2022 – 70.1 thousand BOE per day).
Generated Operating Margin of $148 million, a decrease of $328 million compared with 2022, largely due to decreased sales volumes from our Atlantic and China operations. We had no sales volumes from our Atlantic operations due to timing differences between production and sales, and planned turnaround activity.
Earned a Netback of $45.11 per BOE (2022 – $76.48 per BOE).
Invested capital of $184 million mainly for the West White Rose project and Terra Nova ALE project in the Atlantic region.
The West White Rose project was around 70 percent complete as at June 30, 2023. Since our decision to restart the project, we have invested approximately $300 million. We reached a major milestone on the project in June with the completion of the conical slip form operation for the concrete gravity structure.
At Terra Nova, quayside preparation and maintenance activities continue on the floating production, storage and offloading unit (“FPSO”) and we are evaluating the schedule.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 25



Financial Results
Three Months Ended June 30,
20232022
($ millions)AtlanticAsia Pacific
Offshore
AtlanticAsia Pacific
Offshore
Revenues
Gross Sales5223228207351558
Less: Royalties
11213(16)182
4211215223333556
Expenses
Transportation and Blending
4444
Operating
263763472976
Operating Margin (1)
(26)174148172304476
Depreciation, Depletion and Amortization91159
Exploration Expense210
(Income) Loss from Equity-Accounted Affiliates(12)(6)
Segment Income (Loss)67313
(1)Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Specified Financial Measures Advisory of this MD&A.
Operating Margin Variance
Three Months Ended June 30, 2023
offshorewaterfallqtda.jpg
Six Months Ended June 30,
20232022
($ millions)AtlanticAsia Pacific
Offshore
AtlanticAsia Pacific
Offshore
Revenues
Gross Sales1545477013797461,125
Less: Royalties
93039(6)4034
1455176623857061,091
Expenses
Transportation and Blending
9988
Operating
143622059356149
Operating Margin (1)
(7)455448284650934
Depreciation, Depletion and Amortization219309
Exploration Expense425
(Income) Loss from Equity-Accounted Affiliates(18)(10)
Segment Income (Loss)243610
(1)Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Specified Financial Measures Advisory of this MD&A.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 26



Operating Margin Variance
Six Months Ended June 30, 2023
offshorewaterfallytda.jpg
Operating Results
Three Months Ended June 30,
Six Months Ended June 30,
2023202220232022
Sales Volumes
Atlantic (Mbbls/d)
 15.57.815.1
Asia Pacific (MBOE/d)
China31.246.837.250.1
Indonesia (1)
15.010.014.39.6
Total Asia Pacific46.256.851.559.7
Total Sales Volumes (MBOE/d)
46.272.3 59.374.8 
Total Realized Price (2) ($/BOE)
73.12 95.16 79.51 92.74
Atlantic - Light Crude Oil ($/bbl)
 146.38 108.73 138.92
Asia Pacific (1) ($/BOE)
71.86 81.16 75.07 81.09
NGLs ($/bbl)
84.95 120.75 91.43 115.33
Conventional Natural Gas ($/Mcf)
11.47 11.76 11.85 12.00
Production by Product
Atlantic - Light Crude Oil (Mbbls/d)
5.313.37.113.5
Asia Pacific (1)
NGLs (Mbbls/d)
8.712.010.012.6
Conventional Natural Gas (MMcf/d)
225.1269.0248.5283.2
Total Asia Pacific (MBOE/d)
46.256.851.559.7
Total Production (MBOE/d)
51.570.158.673.2
Effective Royalty Rate (percent)
Atlantic (8.0)5.3 (1.6)
Asia Pacific (1)
10.1 13.1 10.1 11.9 
Operating Expense (2) ($/BOE)
19.48 12.27 18.88 11.94
Atlantic 30.57 85.02 33.22
Asia Pacific (1)
10.96 7.27 8.82 6.58
Per Unit DD&A (2) ($/BOE)
25.31 30.11 25.81 29.98
(1)Reported sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.
(2)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Revenues
Price
The price we receive for natural gas sold in Asia is set under long-term contracts. Our realized sales price on light crude oil and NGLs decreased in the three and six months ended June 30, 2023, compared with 2022, primarily due to lower Brent benchmark pricing.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 27



Production Volumes
Atlantic production decreased 8.0 thousand barrels per day and 6.4 thousand barrels per day in the three and six months ended June 30, 2023, respectively, compared with 2022. The decreases were due to turnaround work on the SeaRose FPSO completed in March and April of 2023. Operations partially resumed in late April and we returned to full operations in mid-June. In addition, the decrease in Cenovus’s working interest at the White Rose field and satellite extensions effective May 31, 2022, lowered production year-over-year. Light crude oil from production at the White Rose fields is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales. There were no sales volumes in the second quarter of 2023 due to this timing and the planned turnaround activity.
Asia Pacific production decreased 10.6 thousand barrels per day and 8.2 thousand barrels per day in the three and six months ended June 30, 2023, respectively, compared with 2022. The decrease was due to a temporary unplanned outage early in the second quarter in China, related to the disconnection of the umbilical by a third-party vessel in early April and reconnected in May. In addition, we completed planned maintenance in China in June 2023. Changes to gas sales agreements at Liwan 3-1 and Liuhua 29-1 in the second quarter of 2022 also resulted in a net decrease in production. The decrease was partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022, and planned maintenance in China in the second quarter of 2022. At our equity-accounted assets in Indonesia, we drilled and completed the third of three planned development wells at the MAC field in the first quarter of 2023. We expect first gas production from the field in the third quarter of 2023.
Royalties
In the three and six months ended June 30, 2023, Atlantic royalties were $1 million and $9 million, respectively (2022 – recoveries of $16 million and $6 million, respectively). In 2022, royalties at the White Rose field included year-to-date adjustments based on an amended agreement between our working interest partners and the Government of Newfoundland and Labrador.
Royalty rates in China and Indonesia are governed by production sharing contracts in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for the three and six months ended June 30, 2023, declined slightly to 10.1 percent (2022 – 13.1 percent and 11.9 percent, respectively) as a result of first gas production at the MBH and MDA fields starting in the fourth quarter of 2022.
Expenses
Operating
Primary drivers of our Atlantic operating expenses in the first half of 2023 were vessel and helicopter costs, repairs and maintenance, and workforce. In the second quarter of 2023, operating costs decreased $21 million in the Atlantic compared with 2022, primarily due to lower production and sales volumes, partially offset by costs related to turnaround work on the SeaRose FPSO and costs related to continued preparation and maintenance activities for the Terra Nova FPSO. Operating expenses in the first six months of 2023 increased $50 million due to the ramp-up of the West White Rose project leading up to the start of major construction in late March, costs related to turnaround work on the SeaRose FPSO and costs related to continued preparation and maintenance activities for the Terra Nova FPSO. Per-unit operating expenses increased in the three and six months ended June 30, 2023, compared with the same periods in 2022 mainly due to lower sales volumes.
Primary drivers of our Asia Pacific operating expenses in the first six months of 2023 were repairs and maintenance, insurance and workforce. Total operating expenses increased in the three and six months ended June 30, 2023, compared with 2022 primarily due to costs related to the unplanned outage in the second quarter. Per-unit operating expenses increased in the three and six months ended June 30, 2023, mainly due to the same factors that impacted total operating expenses combined with lower sales volumes.
Transportation
Transportation costs in the Atlantic region remained consistent compared with 2022 and includes the cost of transporting crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs.






















Cenovus Energy Inc. – Q2 2023 Management's Discussion and Analysis
 28



Netbacks
Three Months Ended June 30, 2023
($/BOE, except where indicated)
Atlantic (1) ($/bbl)
China
Indonesia (2)
Total Offshore
Sales Price (3)
 78.48 58.05 73.12 
Royalties (3)
 4.23 13.60 7.47 
Transportation and Blending (3)
   1.06 
Operating Expenses (3)
 11.91 8.98 19.48 
Netback (3)
 62.34 35.47 45.11 

Three Months Ended June 30, 2022
($/BOE, except where indicated)
Atlantic ($/bbl)
China
Indonesia (2)
Total Offshore
Sales Price (3)
146.38 82.25 76.06 95.16 
Royalties (3)
(11.50)4.44 39.69 5.89 
Transportation and Blending (3)
2.40 — — 0.52 
Operating Expenses (3)
30.57 5.89 13.70 12.27 
Netback (4)
124.91 71.92 22.67 76.48 
(1)No sales volumes from our Atlantic operations in the second quarter of 2023.
(2)Reported sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.
(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(4)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.

Six Months Ended June 30, 2023
($/BOE, except where indicated)
Atlantic ($/bbl)
China
Indonesia (1)
Total Offshore