[SU] Suncor: Q3 2026 Earnings Test Oil Sands Recovery and C$750M Buybacks

Suncor is an integrated Canadian energy company whose operations span oil sands mining and upgrading in northern Alberta, offshore production on Canada's East Coast, refining in Canada and the US, and the Petro-Canada retail and wholesale networks[1]. Ahead of Suncor Q3 2026 earnings, the company said it will report Third quarter 2026 (three months ended September 30, 2026) results after markets close on 2026-11-03 and hold its conference call the following day[2]. In the latest disclosed period, the second quarter of 2026, WTI averaged US$92.85 a barrel; Suncor generated C$5.329 billion of adjusted funds from operations (AFFO), or C$4.52 a share, adjusted operating earnings of C$3.804 billion, or C$3.23 a share, and net earnings of C$3.732 billion, while upstream production fell to 760,900 barrels a day and net debt dropped to C$4.481 billion at June 30[3]. The company issues only full-year guidance: its December 2025 outlook for 2026 called for upstream production of 840,000 to 870,000 barrels a day and capital expenditures of C$5.7 billion at the midpoint[4], refinery throughput guidance of 460,000 to 475,000 barrels a day was left unchanged after the nameplate capacity increase[5], and monthly buybacks rose to C$750 million starting in October[6]. Analyst estimates compiled by Drillr on 2026-10-23 put third-quarter earnings per share at 3.51 (six analysts, range 3.14 to 3.87) and revenue at 16.83 billion (four analysts); the compilation does not label the currency, but comparison with the second quarter indicates Canadian dollars on a basis close to adjusted earnings per share[7].

Three things matter most in this report. The first is whether oil sands volumes and unit costs recover together: in the second quarter, Fort Hills cash operating costs rose to C$44.50 a barrel and Oil Sands operations costs to C$32.70, both above the top of full-year guidance[3], while management said preliminary July production was back to about 870,000 barrels a day[8], so the third quarter will show whether costs fall with volume recovery or stay elevated. The second is the source of the record downstream cash flow: Refining and Marketing (R&M) AFFO reached C$2.299 billion in the second quarter, 3.7 times the C$615 million of a year earlier[3], as jet fuel sales and export cargoes both hit records[8], and only what remains once crack spreads ease will show whether the export capability is structural. The third is whether the buyback pace matches cash generation: repurchases of about C$2.25 billion a quarter from October[6] are already close to the C$2.347 billion of free funds flow in the third quarter of 2025[9], making third-quarter free funds flow and net debt at September 30 the first test of that pace.

Company Background and Business Structure

Suncor is built around the oil sands and links upstream production, upgrading, refining and retail in one chain. The company describes itself as Canada's leading integrated energy company, is listed in Toronto and New York, and reports in Canadian dollars on a calendar fiscal year[1]. In 2024 it produced 827,600 barrels of oil equivalent a day upstream and processed 465,000 barrels a day of crude at its refineries, up from 745,700 and 420,700 in 2023[1]. Rich Kruger is the chief executive[6].

Oil Sands is the largest segment and produces bitumen in northern Alberta through mining and in situ operations. The bitumen is either upgraded into synthetic crude oil (SCO) or blended with diluent for refinery feedstock or direct sale; the segment includes the wholly owned and operated Fort Hills mining and extraction operation and Suncor's 58.74% operated interest in Syncrude, which has two producing mines, Mildred Lake and Aurora North, plus integrated upgrading facilities[1]. Oil Sands operating revenues were C$29.26 billion in 2024[1]; in the second quarter of 2026 net SCO production was 482,200 barrels a day with upgrader utilization of 93%, and non-upgraded bitumen production was 207,900 barrels a day[3].

The other two segments are East Coast offshore production and refining and marketing. Exploration and Production holds interests in offshore fields on Canada's East Coast and had operating revenues of C$2.798 billion in 2024[1]; on October 5, 2026, Suncor agreed to sell its 48% interest in Terra Nova, 40% in White Rose and 38.6% in West White Rose to Ithaca Energy for C$1.2 billion of upfront cash plus a contingent payment of up to C$350 million tied to oil prices, while keeping Hebron and Hibernia[6]. Refining and Marketing runs a refinery network in Canada and the US whose nameplate capacity rose 10% from 466,000 to 511,000 barrels a day on January 1, 2026[5], and the segment had operating revenues of C$31.341 billion in 2024[1].

The three segments supply one another internally, and customers range from refiners and wholesalers to service-station drivers and overseas buyers. SCO and bitumen from the oil sands can feed Suncor's own refineries, which then sell gasoline, diesel and jet fuel through the Petro-Canada retail and wholesale networks; the company paid C$4.192 billion of royalties in 2024[1]. Petro-Canada retail volumes rose 9% year over year in the first quarter of 2026[10], and Suncor's product sales have expanded from about 20 countries to about 45[8].

Financial History and Current Position

The 2024 annual record shows modest revenue growth but a clear decline in net earnings. According to the 2024 annual report on Form 40-F, operating revenues net of royalties were C$50.689 billion in 2024, up from C$49.092 billion in 2023, while net earnings fell from C$8.295 billion to C$6.016 billion[1]. AFFO was C$13.846 billion, cash flow from operating activities C$15.960 billion, capital expenditures C$6.166 billion, free funds flow C$7.363 billion and returns to shareholders C$5.711 billion, and year-end net debt was C$6.861 billion, down from C$9.852 billion at the end of 2023[1]. The R&M LIFO gross margin was C$37.00 a barrel in 2024, below C$47.00 in 2023 and C$54.45 in 2022[1].

The second half of 2025 is the most direct comparison for this report. In the third quarter of 2025 AFFO was C$3.831 billion (C$3.16 a share), adjusted operating earnings were C$1.794 billion (C$1.48 a share), free funds flow was C$2.347 billion, upstream production set a third-quarter record of 870,000 barrels a day, and net debt was C$7.147 billion at September 30[9]. In the fourth quarter AFFO was C$3.218 billion, net earnings C$1.476 billion and upstream production 909,000 barrels a day, year-end net debt was C$6.337 billion, and the company said its 2026 guidance was unchanged[11].

In the first quarter of 2026, both production and refinery throughput set records for the period. AFFO was C$4.030 billion (C$3.39 a share) and adjusted operating earnings C$2.300 billion (C$1.93 a share); upstream production of 875,200 barrels a day and refinery throughput of 497,800 barrels a day were first-quarter records, refined product sales of 680,900 barrels a day were a quarterly record, and the company bought back C$825 million of shares and paid C$712 million of dividends[5].

Cash generation hit a new high in the second quarter of 2026 even as production fell sharply. AFFO was C$5.329 billion against C$2.689 billion a year earlier; adjusted operating earnings were C$3.804 billion (C$873 million a year earlier), net earnings C$3.732 billion, cash flow from operating activities C$5.655 billion, capital expenditures excluding capitalized interest C$1.310 billion and free funds flow C$3.980 billion[3]. First-half AFFO was C$9.359 billion and free funds flow C$6.893 billion, net debt fell from C$6.842 billion to C$4.481 billion at June 30, the company repurchased C$1.050 billion of shares and paid C$706 million of dividends in the quarter, and current income tax reached C$1.318 billion[3].

Operating Model

Suncor's revenue is driven mainly by oil sands volumes and realized prices anchored to WTI, plus refined product volumes and prices in the downstream business. Oil sands SCO is priced off the SYN-WTI differential and non-upgraded bitumen off the WCS-WTI heavy discount; in the second quarter of 2026 WTI averaged US$92.85, the SYN premium was US$8.40 and the WCS discount US$14.65, giving a weighted average oil sands realization of C$129.59 a barrel, with SCO at C$143.55 and bitumen at C$98.79[3]. For comparison, WTI averaged only US$64.95 in the third quarter of 2025[9], and price changes flow into revenue within the same quarter with almost no lag.

On the profit side, unit costs are mostly fixed, while refining profit depends on crack spreads and margin capture. Oil sands cash profit is roughly volume times the gap between realized price and cash operating cost per barrel, less royalties and transportation; because mining, upgrading and maintenance spending is largely fixed, unit costs rise when volume falls, and 2026 guidance calls for C$26 to C$29 at Oil Sands operations, C$33 to C$36 at Fort Hills and C$34 to C$37 at Syncrude[4]. Refining cash profit is roughly output times the 5-2-2-1 crack index multiplied by margin capture, less operating cost, which was C$6.35 a barrel in the second quarter; adjusted operating earnings then deduct depreciation, depletion and amortization (C$3.445 billion in the first half of 2026) and income tax, and reported net earnings also swing with the revaluation of US dollar debt[3].

On the cash side, free funds flow after capital spending sets the room for buybacks. Segment AFFO in the second quarter of 2026 was C$3.819 billion for Oil Sands, C$652 million for Exploration and Production and C$2.299 billion for R&M, which after C$123 million of corporate costs and C$1.318 billion of current income tax totaled C$5.329 billion[3]; full-year capital spending is guided at C$5.7 billion at the midpoint[4]. Management uses a guardrail of 1x net debt to cash flow at US$50 WTI rather than a fixed net debt target, so shareholder returns move with performance[8]. The East Coast asset sale is expected to close in early 2027, bringing about C$1.2 billion of upfront cash, with the buyer assuming about C$1.4 billion of abandonment and lease liabilities[6].

Industry and Competitive Position

Suncor's defining feature within the Canadian oil sands industry is its upstream-downstream integration. It mines the same resource basin and competes for the same takeaway capacity as Canadian Natural, Imperial Oil and Cenovus, but its SCO and bitumen can move into its own refineries and then through the Petro-Canada network[1]. The WCS heavy discount widened to US$14.65 in the second quarter of 2026[3] from US$10.40 in the third quarter of 2025[9]; integration lets the company absorb more heavy barrels internally, but the price of non-upgraded bitumen still takes the discount directly.

Downstream export capability is a competitive tool Suncor has added over the past two years. Management said exports reached 56 cargoes in the first half, close to the 58 for all of 2025, West Coast export capacity has grown from three or four cargoes a month to five or six, and the Montreal refinery can export up to 25,000 barrels a day of jet fuel[8]. Montreal began producing jet fuel in the first quarter and posted its best quarter at 155,000 barrels a day[10].

Both the growth runway and the peer comparison have clear limits. Management said the existing 100,000-barrel-a-day growth plan does not need new pipelines or regulatory reform, but further growth still depends on the final policy outcome of the trilateral memorandum of understanding with the federal and provincial governments[8]. Peer production, cost and downstream data are outside the company disclosures cited here, so these advantages can be measured only against Suncor's own history and the gap to peers cannot be quantified.

Core Debates

Rain and maintenance cut second-quarter output to 761,000 barrels a day and pushed Fort Hills costs to C$44.50 a barrel; can the third quarter get back to last year's 870,000?

This question decides whether the core of Suncor's cash flow recovers. The oil sands are the company's cash engine: Oil Sands operating revenues were C$29.26 billion in 2024[1], and segment AFFO of C$3.819 billion in the second quarter of 2026 was more than 70% of consolidated AFFO of C$5.329 billion[3]. Mining and upgrading costs are largely fixed, so every barrel lost raises the cost per barrel, and with WTI high, a volume recovery also has its biggest effect on cash flow.

The second-quarter production loss came mainly from weather and planned maintenance. Upstream production fell from 875,200 barrels a day in the first quarter[5] to 760,900[3]; management said record precipitation in Fort McMurray cost 50,000 to 60,000 barrels a day, and the Firebag turnaround, which covered two-thirds of the field's 250,000-barrel-a-day capacity, was finished in 44 days at a cost of C$118 million with a production impact of about 60,000 barrels a day, 25,000 better than planned[8]. In the same quarter Fort Hills produced 154,200 barrels a day at a cash cost of C$44.50 a barrel, Oil Sands operations ran at C$32.70 and Syncrude at C$40.15[3], all above the top of full-year guidance[4]. Management kept full-year production guidance of 840,000 to 870,000 barrels a day and said preliminary July output was about 870,000, the second-highest July on record[8].

An alternative reading holds that part of the cost increase has nothing to do with weather, so unit costs may not return to last year's level even if volumes recover. Fort Hills already cost C$34.10 a barrel, near the top of guidance, when it produced a record 187,200 barrels a day in the first quarter, and Syncrude reached C$42.20 in that quarter[5]; management tied the long-term improvement in Fort Hills unit costs to North Pit 2, expected to start in the first quarter of 2027[10]. The comparison base is the third quarter of 2025, when upstream production was 870,000 barrels a day, unit costs were C$24.85 at Oil Sands operations, C$30.65 at Fort Hills and C$31.45 at Syncrude, Oil Sands AFFO was C$2.900 billion and WTI averaged US$64.95[9]. The financial transmission is that higher volume spreads fixed costs over more barrels, lowers unit costs and, with oil prices above a year earlier, amplifies Oil Sands AFFO within the same quarter.

In the third quarter, three sets of figures matter: whether upstream production is at least 862,000 barrels a day and Fort Hills is back above 175,000; whether Oil Sands operations and Fort Hills cash costs return to their guidance ranges of C$26 to C$29 and C$33 to C$36[4]; and whether the company keeps its full-year production guidance. If volumes recover while Fort Hills costs stay above C$36, the cost problem lies in the mine plan rather than the weather; if both volumes and costs return to guidance, that supports the view that the second quarter was a one-off shock. Before this disclosure, neither outcome can be ruled out.

Was the record second-quarter downstream cash flow driven by crack spreads, or by Suncor's new export and jet-fuel capability?

This question decides how much normal cash the other half of the integrated model can contribute. Refining and Marketing sends Suncor's own SCO into its refineries and sells the products through the Petro-Canada network and export channels[1]; R&M AFFO was C$2.299 billion in the second quarter of 2026, 3.7 times the C$615 million of a year earlier[3], and management said it was about C$200 million above the previous record set in the second quarter of 2022[8]. Management describes the export expansion as the result of several years of work, so the key is how much remains after the index falls.

Second-quarter volume and channel data both point to new capability. Refinery throughput was 470,600 barrels a day, 92% utilization on the new nameplate capacity, and refined product sales were 654,800 barrels a day, both second-quarter records; the LIFO gross margin was C$61.50 a barrel against a 5-2-2-1 index of C$69.30, for margin capture of 89%[3]. Jet fuel sales reached 51,000 barrels a day, 90% above the first-quarter record of 27,000, and exports totaled 56 cargoes in the first half, close to the 58 for all of 2025[8].

An alternative reading holds that the extra volume was mostly opportunistic arbitrage of unusually wide spreads. Second-quarter capture of 89% was below the 92% of the third quarter of 2025, suggesting export barrels may earn less per barrel than domestic channels; in that earlier quarter the 5-2-2-1 index was US$31.20, refined product sales 646,800 barrels a day, throughput 491,700 barrels a day, the LIFO margin C$39.55 a barrel and R&M AFFO C$1.216 billion[9], while the index rose to US$50.10 in the second quarter of 2026[3]. Management attributed the stronger spreads to lower Russian refinery output and export cuts plus strong diesel and jet fuel demand, and said it sees them staying resilient over the medium term[8]; but if the index returns to near last year's third-quarter level, export cargoes and jet fuel sales may shrink with it and R&M cash flow may revert to a normal level of about C$1.2 billion. In transmission terms, index moves reach the margin per barrel in the same quarter, and if volume and capture hold, downstream cash flow should fall less than the index.

In the third quarter, the questions are whether refined product sales exceed 646,800 barrels a day and jet fuel sales and export cargoes hold at first-half levels; whether margin capture stays at or above 89%, read against the direction of the 5-2-2-1 index; and how much of any R&M AFFO gain over the C$1.216 billion of the third quarter of 2025 comes from factors other than the index. If volumes fall below last year's level once the index eases and capture stays low, the second-quarter record came mainly from the market; if the index eases while volume and capture hold, that supports a structural gain from the export capability.

Buybacks have risen from C$275 million to C$750 million a month within a year; can third-quarter free funds flow carry them?

Buybacks are Suncor's main way of returning cash, and their pace depends directly on free funds flow. Monthly repurchases rose from C$275 million in December 2025[4] to C$350 million in May[5], C$500 million in August[3] and C$750 million in October[6]. Repurchases of about C$2.25 billion a quarter from October are close to the C$2.347 billion of free funds flow in the third quarter of 2025[9], so the third quarter is the first test of whether cash generation at high oil prices can cover that pace.

First-half cash generation and the asset sale created room for the step-up. AFFO was C$9.359 billion and free funds flow C$6.893 billion in the first half of 2026, net debt fell from C$6.842 billion to C$4.481 billion during the second quarter, and when the company raised buybacks to C$500 million a month in August it projected C$4.7 billion of repurchases for the year[3]. On October 5 Suncor announced the sale of three East Coast interests, with an effective date of July 1, 2026 and closing expected in early 2027, and on the same day raised buybacks to C$750 million a month[6]. In August management said investors can model the C$500 million monthly buyback for the foreseeable future and pointed to its guardrail of 1x net debt to cash flow at US$50 WTI[8].

An alternative reading holds that the C$750 million monthly pace rests on unusually high second-quarter prices. WTI averaged US$92.85 and the 5-2-2-1 index US$50.10 in that quarter, and current income tax was C$1.318 billion[3], against current income tax of C$412 million and dividends of C$688 million in the third quarter of 2025[9]. If prices returned to third-quarter 2025 levels, free funds flow of about C$2.3 billion, less about C$700 million of dividends, would not cover C$2.25 billion of buybacks, leaving the gap to sale proceeds and net debt. The transmission is that prices and volume lift AFFO but income tax rises with them; AFFO less capital spending of C$5.7 billion at the midpoint[4] gives free funds flow, and any shortfall against dividends plus buybacks is filled by net debt or the roughly C$1.2 billion of sale proceeds due in early 2027.

In the third quarter, the questions are whether free funds flow is at least C$2.25 billion and net debt at September 30 is no higher than C$4.481 billion; whether third-quarter buybacks are about C$1.35 billion (C$350 million in July and C$500 million each in August and September) and the C$750 million monthly plan from October is maintained; and whether second-half capital spending is consistent with the C$5.7 billion midpoint and the East Coast sale stays on schedule. If net debt rises and the buyback plan is cut, the pace has outrun cash generation; if free funds flow covers dividends and buybacks and net debt keeps falling, that supports a sustainable pace.

Risks and Falsifiers

The first risk is regulatory and pipeline uncertainty in Western Canada, which bears directly on realized revenue from non-upgraded bitumen. Faster growth depends on the final policy outcome of the trilateral memorandum of understanding, and management said the existing 100,000-barrel-a-day growth plan does not rely on new pipelines[8]; meanwhile the WCS-WTI discount widened to US$14.65 in the second quarter, when bitumen sales were about 19.99 million barrels[3], so every US$5 of extra discount (roughly C$6.9) cuts quarterly realized revenue by about C$140 million. This risk is falsified if the discount narrows to around the US$10.40 of the third quarter of 2025[9] and the company leaves its growth plan unchanged.

The second risk comes from US dollar debt and affects net earnings rather than AFFO. A stronger Canadian dollar produces revaluation gains on US dollar debt but also lowers the Canadian dollar value of crude and products priced in US dollars; in the first half of 2026 the unrealized foreign exchange loss on US dollar debt was C$271 million, against a gain of C$475 million in the first half of 2025[3], and these amounts hit net earnings but not AFFO. If the Canadian dollar averages about US$0.72 to US$0.73 in the third quarter and the unrealized foreign exchange effect on net earnings stays within C$200 million, this risk matters little for reading the quarter.

The third risk is that rising mining intensity keeps unit costs above the top of guidance even after volumes recover. Fort Hills cost C$34.10 a barrel and Syncrude C$42.20 in the first quarter[5], and C$44.50 and C$40.15 in the second[3], against guidance ceilings of C$36 and C$37[4]; on Fort Hills' full-year production guidance of 175,000 to 185,000 barrels a day, each extra C$5 a barrel adds roughly C$80 million of cash costs a quarter. This risk is falsified if Fort Hills costs return below C$36 and Syncrude below C$37 in the third quarter.

The fourth risk is that crack spreads fall from their second-quarter highs and export volumes cannot make up the difference. The 5-2-2-1 index was US$50.10 in the second quarter[3] and US$31.20 in the third quarter of 2025[9]; on the 491,700 barrels a day of throughput in the third quarter of 2025, each C$5 drop in the LIFO margin per barrel cuts quarterly gross margin by about C$230 million, exposing R&M AFFO. This risk is falsified if third-quarter R&M AFFO falls less than the index and refined product sales exceed 646,800 barrels a day.

The fifth risk is that oil prices or spreads fall while buybacks stay at C$750 million a month, pushing net debt back up toward the 1x guardrail. On third-quarter 2025 free funds flow of C$2.347 billion and dividends of C$688 million[9], C$2.25 billion of quarterly buybacks would leave a gap of about C$600 million, and the roughly C$1.2 billion of upfront sale cash[6] would cover about two quarters of it. This risk is falsified if net debt at the end of both the third and fourth quarters is no higher than the C$4.481 billion of June 30[3].

What to Watch Next

• Oil sands recovery: upstream production was 760,900 barrels a day and Fort Hills 154,200 in the second quarter[3]; a third-quarter figure of at least 862,000 with Fort Hills above 175,000 would support a one-off shock, and a clear shortfall would weaken it.
• Oil sands unit costs: Oil Sands operations ran at C$32.70 and Fort Hills at C$44.50[3] against guidance of C$26 to C$29 and C$33 to C$36[4]; recovering volumes with Fort Hills still above C$36 would point to the mine plan.
• Downstream exports: refined product sales were 654,800 barrels a day[3], with jet fuel at 51,000 barrels a day and 56 cargoes in the first half[8]; holding above 646,800 as the index eases would support a structural gain.
• Margin capture and R&M AFFO: capture was 89% and R&M AFFO C$2.299 billion[3], against C$1.216 billion in the third quarter of 2025[9]; volumes below last year with low capture would mean the record came mainly from the market.
• Buyback funding: free funds flow was C$3.980 billion and net debt C$4.481 billion in the second quarter[3]; free funds flow of at least C$2.25 billion with net debt no higher than C$4.481 billion supports the pace, while rising debt and a cut plan would not.
• Buyback plan and asset sale: buybacks run at C$750 million a month and the sale is expected to close in early 2027[6]; watch for third-quarter repurchases of about C$1.35 billion and an unchanged plan.

Conclusion

Suncor's business runs on two cash engines: oil sands volume times a WTI-anchored realized price, less unit costs that are mostly fixed, and refined product volume times crack spreads and margin capture. In the second quarter of 2026 the company still generated C$5.329 billion of AFFO and C$3.980 billion of free funds flow while upstream output fell to 760,900 barrels a day, and it cut net debt to C$4.481 billion[3] before raising buybacks to C$750 million a month[6]. The unresolved relationship is whether a volume recovery brings unit costs back to guidance, how much of the downstream record survives lower spreads, and whether the two together can cover about C$2.25 billion of buybacks a quarter.

On outside interpretation, the material available between the 2026-08-05 second-quarter release and 2026-10-24 consisted mainly of recaps of the results, buyback and asset-sale announcements, brokers' adjustments to their share-price views and climate litigation news, and no outside analysis with verifiable original text and independent reasoning on the three debates above could be found. No outside institution's interpretation is therefore cited here, and scattered opinions are not stitched into a market consensus; readers can compare only against the company's own disclosures and the analyst figures compiled by Drillr[7].

The observations that would materially change the current understanding come as a combination. If third-quarter upstream production returns above 862,000 barrels a day, Fort Hills and Oil Sands operations unit costs come back into their guidance ranges, R&M AFFO falls less than the index while refined product sales exceed 646,800 barrels a day, and free funds flow covers dividends plus buybacks with net debt no higher than C$4.481 billion, the current understanding is strengthened. Conversely, if volumes recover but Fort Hills costs stay above C$36, downstream volume and capture fall with the index, and net debt rises or the buyback plan is cut, the second quarter's cash generation came more from prices than from the company's own operating improvement.

Sources

[1] SU FY2024 40-F filed 2025-02-27 · 2025-02-27 · 40-F · https://www.sec.gov/Archives/edgar/data/311337/000155837025001644/su-20241231xex99d3.htm

[2] SU Q3 2026 results date 6-K filed 2026-10-20 · 2026-10-20 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[3] SU Q2 2026 6-K filed 2026-08-05 · 2026-08-05 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[4] SU 2026 corporate guidance 6-K filed 2025-12-11 · 2025-12-11 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[5] SU Q1 2026 6-K filed 2026-05-06 · 2026-05-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[6] SU East Coast asset sale 6-K filed 2026-10-05 · 2026-10-05 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[7] Drillr analyst_financial_estimates (updated 2026-10-23) · SU quarter ending 2026-09-30 · 2026-10-23 · Drillr analyst estimates · https://gateway.drillr.ai/mcp/private

[8] SU Q2 2026 earnings call 2026-08-05 · 2026-08-05 · earnings-call · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[9] SU Q3 2025 6-K filed 2025-11-04 · 2025-11-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[10] SU Q1 2026 earnings call 2026-05-06 · 2026-05-06 · earnings-call · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40

[11] SU Q4 2025 6-K filed 2026-02-04 · 2026-02-04 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000311337&type=6-K&dateb=&owner=include&count=40