[TRP] TC Energy: Q3 2026 Earnings Test U.S. Pipeline and Bruce Power Growth

TC Energy runs a natural gas pipeline network across Canada, the U.S. and Mexico and owns an interest in Ontario's Bruce Power nuclear station; the company says it moves more than 30% of the natural gas used across North America every day[1]. Its TC Energy Q3 2026 earnings are scheduled for 2026-11-05 and cover the third quarter of 2026, the three months ended September 30, 2026 (2026年第三季度(截至2026年9月30日的三个月))[2]. In the latest reported quarter, the second quarter of 2026, comparable EBITDA was C$2.948 billion against C$2.625 billion a year earlier, and comparable EPS rose from C$0.82 to C$0.94[3]. On July 30, management said 2026 comparable EBITDA would land at the upper end of its C$11.6 billion to C$11.8 billion range, with net capital expenditures of C$5.5 billion to C$6.0 billion[4]; measured against full-year 2025 comparable EBITDA of C$10.952 billion[5], reaching the top of the range requires only about C$5.764 billion in the second half, roughly 2.6% more than the approximately C$5.618 billion earned in the second half of 2025. The consensus of 10 analysts compiled by Drillr calls for third-quarter EPS of C$0.88 (range C$0.85 to C$0.94) and EBITDA of about 2.868 billion[6], compared with comparable EPS of C$0.77 and comparable EBITDA of C$2.654 billion a year earlier[7]. The same data source, however, puts full-year 2026 EBITDA at about 12.24 billion, above the top of company guidance, which suggests the analysts' EBITDA definition may differ from the company's comparable EBITDA, so a direct comparison needs care.

Three things matter most in these results. The first is whether U.S. Natural Gas Pipelines can keep growing at a double-digit pace: the segment's comparable EBITDA was C$1.062 billion a year earlier[7] and grew 9.5% and 11.8% year over year in the first and second quarters of 2026[8][3], so a third quarter near C$1.168 billion would confirm that new pipelines and new rates are still driving growth. The second is Bruce Power's first full quarter since Unit 3 returned to commercial operation on June 12[9]; a year earlier the Power and Energy Solutions segment earned C$266 million of comparable EBITDA with 94% plant availability[10], so this quarter shows how much one more operating unit is actually worth. The third is whether the Mexico business can hold quarterly earnings near C$410 million now that Southeast Gateway has been collecting tolls for a full year since May 2025[11]; once Mexico's year-over-year increase disappears, second-half growth depends more heavily on the first two items.

Company Background and Business Structure

TC Energy is now an infrastructure company built mainly on natural gas pipelines, supplemented by a nuclear power interest, and its shares trade in Toronto and New York under the ticker TRP[1]. On October 1, 2024, the company spun off its liquids pipeline business, including Keystone, as the separately listed South Bow[5], and its quarterly statements since then present continuing operations only[3]. Its Coastal GasLink pipeline currently carries about 2.1 Bcf/d of natural gas to the LNG Canada export terminal[12], giving Western Canadian supply a direct route to overseas LNG markets.

The company reports four operating segments, each with a different way of earning money. Canadian Natural Gas Pipelines includes the NGTL System, the Canadian Mainline and Coastal GasLink; the Mainline's four-year settlement for 2027 through 2030 keeps a 10.1% return on equity on 40% deemed common equity and retains an incentive mechanism for outperformance[13], and the Canada Energy Regulator has approved it[14]. U.S. Natural Gas Pipelines includes interstate systems and regulated storage such as Columbia Gas, ANR, Great Lakes and Northern Border, with expansions usually backed by 20-year take-or-pay contracts[15]. Mexico Natural Gas Pipelines serves mainly the state power company CFE, which Southeast Gateway began billing in May 2025[11]; Power and Energy Solutions holds the Bruce Power interest, whose long-term contract with Ontario's Independent Electricity System Operator (IESO) runs to 2064[16], along with Alberta cogeneration plants and natural gas storage[17].

By earnings mix, the U.S. business is the largest pillar and Mexico is the most concentrated. In the first half of 2026, comparable EBITDA totaled C$6.036 billion, of which the U.S. contributed C$2.715 billion, Canada C$1.880 billion, Mexico C$841 million and Power and Energy Solutions C$604 million[3], or roughly 45%, 31% and 14% for the three gas segments. Mexico's revenue comes mainly from a single customer, CFE, and both U.S. and Mexican revenue is earned in U.S. dollars and reported in Canadian dollars. Over the same period, comparable funds generated from operations were C$4.332 billion, capital spending was C$2.430 billion and the quarterly dividend was C$0.8775 per share[18].

Financial History and Current Position

TC Energy's annual revenue has stayed broadly between C$12 billion and C$14 billion over the past five years, and the change in reporting scope around the spin-off matters more than revenue swings. According to Drillr's structured data from the 40-F annual filings, revenue was C$12.999 billion in 2020, C$12.309 billion in 2022 and C$13.771 billion in 2024, with 2024 operating income of C$5.786 billion and net income of C$4.698 billion[19]. Comparable EBITDA in 2024 was C$11.194 billion including the pre-spin liquids business, comparable EPS was C$4.27, and the company completed about C$1.6 billion of asset sales while placing about C$7 billion of assets into service, including Coastal GasLink[17].

In the first full year after the spin-off, EBITDA hit its target but EPS did not. Comparable EBITDA in 2025 was C$10.952 billion, above the C$10.8 billion compensation target, while comparable EPS of C$3.51 fell short of the C$3.55 target, which the company attributed to lower-than-expected allowance for funds used during construction (AFUDC); debt to EBITDA on the compensation basis was 4.87x[5]. As the year-over-year base for these results, third-quarter 2025 comparable EBITDA was C$2.654 billion, comparable EPS was C$0.77 and net income attributable to common shares was C$813 million[7].

Growth in the first half of 2026 ran clearly ahead of the pace implied by full-year guidance. First-half comparable EBITDA was C$6.036 billion, up about 13%, with C$3.088 billion in the first quarter[8] and C$2.948 billion in the second; first-half comparable EPS was C$1.93 versus C$1.76, but AFUDC was only C$99 million against C$362 million a year earlier[3]. On cash, first-half comparable funds generated from operations were C$4.332 billion (C$3.913 billion a year earlier) and capital spending was C$2.430 billion (C$3.188 billion); second-quarter net income attributable to common shares was C$987 million, and the quarterly dividend was C$0.8775 per share, or C$3.51 annualized[18].

Operating Model

TC Energy's revenue is set mainly by contracted capacity and regulator-approved rates, while volumes and commodity prices have a comparatively weak effect. Canadian pipelines use a cost-of-service model in which revenue covers operating costs and depreciation, earns a return on deemed equity and adds incentive earnings, with the Mainline earning 10.1% on 40% deemed equity[13]; U.S. pipelines charge FERC-approved rates and collect reservation fees on expansions under take-or-pay contracts, Mexico collects tolls under CFE contracts, and Bruce Power's earnings depend on output from operating units and a contract price that rises each year[20]. Growth therefore comes from three paths: expansions start collecting reservation fees as soon as they enter service; rate case settlements raise approved rates on existing pipelines, though the new rates are collected subject to refund until approval[16]; and refurbished Bruce Power units return to the grid. Because U.S. and Mexican earnings are in U.S. dollars, exchange-rate moves can amplify or offset operating growth when they are translated into Canadian dollars.

The bridge from comparable EBITDA to comparable EPS is long, and project completions change several items on it at once. In the first half of 2026, comparable EBITDA of C$6.036 billion less C$1.460 billion of depreciation and amortization and C$1.698 billion of interest, plus C$99 million of AFUDC, less C$632 million of income tax, C$369 million attributable to non-controlling interests and C$57 million of preferred dividends, produced comparable earnings of C$2.015 billion, or C$1.93 per share[3]. When a project moves from construction into service, AFUDC falls while depreciation and expensed interest rise, so comparable earnings can grow more slowly than EBITDA; the 2025 EPS shortfall came precisely from lower-than-expected AFUDC[5].

Little cash is left after capital spending and dividends, so the leverage target constrains the pace of new projects. First-half comparable funds from operations of C$4.332 billion less C$2.430 billion of capital spending, and less roughly C$1.83 billion of declared common dividends estimated from C$1.755 per share on about 1.042 billion shares[18], leave only about C$70 million, before distributions to non-controlling interests and preferred dividends. Full-year net capital spending guidance is C$5.5 billion to C$6.0 billion[4] and the long-term debt-to-EBITDA target is 4.75x[9]; recently approved projects carry build multiples from about 5.8x[15] to 7.3x[13], and asset sales offer another funding route, such as the roughly C$1.6 billion completed in 2024[17].

Industry and Competitive Position

North American gas demand growth is concentrated in regions where TC Energy already has strong networks, and that is the demand base for its expansion projects. The company forecasts about 51 Bcf/d of North American natural gas demand growth from 2025 to 2035, driven mainly by LNG exports, gas-fired power generation and industrial use[15], and management says nearly 70% of that growth falls in its incumbent regions of the U.S. heartland, Alberta and Mexico[20]. That demand has turned into specific projects: in June 2026 the company approved the Central Virginia Capacity project of up to 0.4 Bcf/d and the Clark project of up to 0.3 Bcf/d on its Columbia systems, together about US$0.4 billion at a weighted build multiple of about 5.8x[15]; it had earlier approved the Appalachia Supply Project of up to 0.8 Bcf/d at a 7.3x build multiple[13], along with the TCO Connector and Midwest Connector, which together provide about 0.6 Bcf/d for new gas-fired generation[21].

The company's competitive edge lies in expanding within existing corridors, but in Alberta that dominance is itself becoming a policy issue. In the U.S., new expansions compete with other interstate pipeline companies, while in Alberta NGTL is the dominant intra-provincial transmission system; according to CBC, a leaked Alberta cabinet report said NGTL's expansion plans are "misaligned" with the province's projected demand growth, that its dominant position has produced a "market failure," and that the system will reach capacity by 2029[22]. Management has also acknowledged that local pushback against data center development in some U.S. jurisdictions could affect the timing of related gas projects, though it has not changed the viability of projects in its backlog[20]. The available material contains no peer segment earnings or rate comparisons, so this assessment of competitive position rests mainly on the company's own project, contract and regulatory disclosures.

Core Debates

Can newly built pipelines and higher approved rates keep TC Energy's U.S. gas business growing at a double-digit pace in the third quarter?

U.S. Natural Gas Pipelines is TC Energy's largest business, and its growth rate determines whether the company can beat the top of full-year guidance. In the first half of 2026, the U.S. segment earned C$2.715 billion of comparable EBITDA, about 45% of the company total[3]; with guidance topping out at C$11.8 billion, the second half needs only about 2.6% more than the second half of 2025[4]. Once Mexico's year-over-year increase disappears in the third quarter, the question of whether the U.S. business can sustain its first-half growth of about 10% becomes the main source of second-half growth. The quarterly baseline is third-quarter 2025 U.S. segment comparable EBITDA of C$1.062 billion[7], along with average daily flows of 26.3 Bcf/d and deliveries to LNG export facilities of 3.7 Bcf/d in the same quarter[10].

New pipelines and new rates were already contributing in the first half, so the direction of growth is documented. In November 2025, the roughly US$0.5 billion VR project on the Columbia system[10] and the roughly US$0.7 billion WR project on the ANR system entered service[21], and the roughly US$0.4 billion Bison XPress project (US$0.2 billion net to TC Energy) followed in the first half of 2026[9]. On rates, the new ANR and Great Lakes rates took effect on November 1, 2025, subject to refund[16]; FERC approved the ANR settlement in July 2026 and approval of the Great Lakes settlement is anticipated in the fourth quarter[14], while the Columbia Gas rate case settlement was approved on October 30, 2025[21]. As a result, U.S. segment comparable EBITDA grew 9.5% and 11.8% year over year in the first and second quarters[8][3], and management attributed second-quarter growth to additional contract sales and higher earnings from ANR and Columbia Gas[20]; average daily flows rose 5% in both quarters, and LNG deliveries rose 12% and 13%[13][23].

The financial transmission is clear, but the weight of exchange rates within it has not been separated out. Long-term contracts signed by power plants, data center-related generation, LNG export terminals and local distribution companies turn into reservation fees once expansions enter service, and rate settlements on existing pipelines raise approved rates; together they produce U.S.-dollar segment earnings, which are translated into Canadian dollars and flow into company comparable EBITDA. An alternative reading is that part of first-half growth came from translating U.S. dollars into Canadian dollars, which the quarterly reports do not break out; if third-quarter growth relies mainly on currency and management says growth excluding currency slowed noticeably, the real contribution from new projects and rates would be weaker than the first half suggested. In addition, according to news reports, Columbia Gas declared force majeure on its Mountaineer XPress pipeline on September 24 after a mechanical failure, affecting about 1.8 MMDth/d of firm transportation service from September 25; the impact falls mainly in the fourth quarter, and the company's filings have not yet disclosed any financial figures for it.

The third-quarter report can test this debate on three levels. The first check is whether U.S. segment comparable EBITDA reaches at least about C$1.168 billion, or 10% growth, and whether management breaks out the currency effect; the second is whether average daily flows and LNG deliveries keep growing by more than 5% and 10% year over year; the last is whether the Great Lakes settlement is approved in the fourth quarter and whether final ANR rates involve refunds. If U.S. growth falls well below the first-half pace and comes mainly from currency translation, or if Great Lakes approval slips or ANR refunds appear, the view that new pipelines and new rates keep driving double-digit growth would weaken.

In the first full quarter after Unit 3's return, can Bruce Power lift TC Energy's power earnings by 20% or more?

The pace of Bruce Power's refurbishment program drives quarterly power earnings, and the third quarter is the cleanest window for measuring what one additional unit is worth. Bruce Power's contract runs to 2064, and its Major Component Replacement (MCR) program takes units offline in rotation for several years at a time; the Unit 5 MCR is scheduled to begin in the fourth quarter of 2026 and return to service in early 2030 at a cost of C$1.1 billion[16]. The third quarter therefore has one more operating unit than a year earlier, Unit 3, while the fourth quarter will lose one as Unit 5 begins refurbishment. This quarter is also the first full test of whether the company's claimed MCR cost and schedule improvements show up in earnings.

Second-quarter data show that Unit 3 returned early and that power earnings rose sharply as a result. Unit 3 was declared commercially operational on June 12, 2026, seven months ahead of the schedule committed to the IESO, with TC Energy's share of equity contributions at C$1.1 billion, 15% lower in cost than the Unit 6 MCR[9]; Bruce Power achieved 98.5% availability in the second quarter with no forced outage days[23]. Power and Energy Solutions comparable EBITDA rose about 20% year over year to C$361 million in the second quarter[3], which management attributed to Unit 3's early return, strong overall availability and an annual price increase[20]. For comparison, the segment earned C$266 million of comparable EBITDA in the third quarter of 2025[7] with Bruce Power availability of 94%[10], a quarter that included planned maintenance on Unit 2[16]; first-quarter 2026 availability fell to 88.2% because of a planned outage on Unit 8[13].

The earnings path is fairly direct, but there are two ways to read the source of second-quarter growth. One more operating unit than a year earlier raises output, which multiplied by the annually escalating IESO contract price produces Bruce Power earnings that flow into Power and Energy Solutions comparable EBITDA; once Unit 5 goes offline in the fourth quarter, part of that gain is offset. An alternative reading is that second-quarter growth came mainly from high availability and pricing rather than from Unit 3 itself; if third-quarter availability falls and segment earnings grow by less than 10%, Unit 3's full-quarter contribution would be smaller than the second quarter implied. Because the quarterly reports do not show earnings by unit, this attribution still depends on management's explanation.

The third quarter needs to be read across earnings, availability and refurbishment progress together. Whether segment comparable EBITDA reaches at least about C$319 million (20% growth), whether Bruce Power availability stays at or above 94% without forced outages, whether the Unit 5 MCR begins on schedule in the fourth quarter, and whether Unit 4 remains on time and on budget[9] together decide whether the view holds. If availability falls clearly below last year, segment comparable EBITDA stalls below about C$293 million, or the Unit 5 start slips or its cost rises, the view that Unit 3's return lifts power earnings by 20% would weaken.

With Southeast Gateway now a year in service, can TC Energy's Mexico business hold quarterly earnings near C$410 million?

Mexico was the largest single source of first-half growth, and losing its year-over-year increase in the third quarter determines how much the company's growth slows. In the first half of 2026, Mexico segment comparable EBITDA rose by C$289 million while the company total rose by C$702 million[3], so Mexico supplied more than 40% of the increase because Southeast Gateway began billing CFE in May 2025[11]. That increase disappears from the third quarter onward, and whether the Mexico segment settles at its new baseline also tests the stability of a contract with a single large customer.

The three full quarters since start-up show broadly stable Mexico earnings but fluctuating volumes. Mexico segment comparable EBITDA was C$416 million in the third quarter of 2025[7], C$432 million in the first quarter of 2026[8] and C$409 million in the second[3]. Average flows were 3.3 Bcf/d in the third quarter of 2025[10], then 2.8 Bcf/d in the first quarter of 2026 and 3.4 Bcf/d in the second, which the company said were lower than a year earlier mainly because of adjustments to pipeline flows, while deliveries to power plants of 1.2 and 1.4 Bcf/d were in line with the prior year[13][23].

Earnings come from contracted tolls rather than volumes, but shifting volumes could signal longer-term contract issues. CFE pays contracted tolls in U.S. dollars on Southeast Gateway and other pipelines, which become Mexico segment comparable EBITDA after translation into Canadian dollars, and the year-over-year increase from the May 2025 start-up vanished after the second quarter of 2026, which directly lowers growth in company comparable EBITDA. An alternative reading is that lower volumes reflect changes in how CFE uses gas, which could create pressure to renegotiate contracts over time even if tolls are paid in full in the near term. In addition, according to news reports, the company announced on September 21 the sale of the Guadalajara-Manzanillo pipeline for about US$400 million, which would reduce Mexico's existing earnings after closing, but the company has not yet disclosed its EBITDA contribution or closing date in SEC filings.

Whether the third-quarter report confirms the new baseline depends on disclosures about earnings, volumes and the asset sale. The three direct checks are whether Mexico segment comparable EBITDA stays at or above C$409 million, whether flows recover above 3.3 Bcf/d while power plant deliveries hold at 1.4 Bcf/d, and whether the company explains the closing date and EBITDA impact of the Guadalajara-Manzanillo sale. If Mexico earnings fall outside the post-start-up range of about C$409 million to C$432 million, or the company reports CFE payment or contract adjustment problems, the view that Mexico has settled at a new baseline would weaken.

With NGTL running near capacity while a new investment framework is negotiated, can TC Energy's Canadian gas business keep growing about 4%?

Canadian gas pipeline earnings are stable, but their growth depends on expansion, and the return framework for that expansion has not been agreed. The Canadian segment produced about 31% of company comparable EBITDA in the first half of 2026[3], earning returns on rate base, flow-through depreciation and incentive earnings. Gas demand from Alberta data centers, oil sands and LNG has pushed NGTL close to capacity, and management acknowledged that the regulatory and investment return framework for new NGTL projects is still under discussion with customers and has not been finalized[20]; the leaked Alberta cabinet report in September also criticized the company's expansion plans as lagging demand[22]. Third-quarter segment earnings and progress on the framework will show whether this business keeps growing steadily or begins to face regulatory and competitive pressure.

First-half growth was modest and steady, and there was new progress on both expansion and demand. Canadian segment comparable EBITDA grew 3.3% year over year in the first quarter[8] and 4.1% in the second[3], which management attributed to higher flow-through depreciation on NGTL and the Canadian Mainline and higher NGTL incentive earnings[20]. The Berland River compressor unit entered service on July 14, 2026, and together with the Valhalla North section placed in service in the third quarter of 2025 it adds about 400 MMcf/d of NGTL capacity, while the Greater Edmonton Area offering of about 0.26 Bcf/d of delivery service was fully subscribed[9]; the company is also advancing NGTL service offerings totaling about 1.0 Bcf/d, and the Mainline settlement for 2027 through 2030 has been approved[14]. On September 29, Coastal GasLink Phase 2 was confirmed to proceed after the positive final investment decision on the LNG Canada expansion, and it will nearly double the pipeline's capacity[12].

Financial transmission depends on whether new capacity enters rate base at an adequate return, and the quality of current growth remains in question. Gas demand from Alberta power generation, oil sands, industry and LNG drives NGTL deliveries and expansion needs; expansions enter rate base once in service and earn the approved return, which together with flow-through depreciation and incentive earnings forms Canadian segment comparable EBITDA, while the new investment framework determines the level and ownership of returns on future expansion. An alternative reading is that EBITDA growth comes mainly from flow-through depreciation, which contributes little to EPS; if incentive earnings fall back, the Canadian segment's real profit growth could be close to zero.

The third-quarter checks center on the composition of earnings, system use and progress on the framework. They are whether Canadian segment comparable EBITDA reaches at least about C$950 million (C$913 million a year earlier[7]) and how much of the growth comes from flow-through depreciation versus incentive earnings; whether NGTL receipts exceed 14.3 Bcf/d, above the 14.0 Bcf/d of a year earlier, when Canadian pipeline deliveries averaged 23.0 Bcf/d[10]; and whether a new NGTL investment framework is reached or filed with regulators, and what capital commitments and return arrangements accompany Coastal GasLink Phase 2. If the framework stalls, the provincial government intervenes in expansion arrangements, or segment growth proves to come almost entirely from flow-through depreciation, the view that the Canadian business can grow steadily at about 4% would weaken.

Risks and Falsifiers

The tension between capital spending and leverage is the largest company-level risk. The company is spending C$5.5 billion to C$6.0 billion of net capital a year[4] while targeting long-term debt to EBITDA of 4.75x[9], against 4.87x in 2025 on the compensation basis[5]; management acknowledged that a funding gap could exist in 2029 through 2031, before Bruce Power's refurbishment program ends in 2031-2032 and frees C$2 billion to C$3 billion a year of additional free cash flow, and that it could then use capital rotation and capital markets[20]. If leverage does not move toward 4.75x, the company may need asset sales or capital market funding, which could dilute EPS or limit new project approvals. If the third-quarter report confirms that debt to EBITDA keeps falling toward 4.75x and the 2027 capital spending outlook stays within its existing range, this risk would ease.

A gap between comparable earnings and EBITDA would keep EBITDA growth from converting proportionally into EPS. First-half 2026 AFUDC was C$99 million versus C$362 million a year earlier[3], depreciation and interest rise as projects enter service, and the 2025 shortfall in comparable EPS of C$3.51 came precisely from lower-than-expected AFUDC[5]. The exposure sits on comparable earnings and EPS. If third-quarter growth in comparable EPS from C$0.77 is at least half the growth in comparable EBITDA from C$2.654 billion[7], the drag from depreciation, interest and AFUDC is being absorbed.

U.S. growth could be offset by currency translation or changes in existing contracts, slowing well below the first-half pace of about 10%. On our arithmetic, every C$50 million by which third-quarter U.S. segment comparable EBITDA falls short of about C$1.168 billion equals about 0.9% of the second-half EBITDA needed to reach the top of full-year guidance, so this risk bears directly on whether guidance is exceeded. If third-quarter U.S. segment comparable EBITDA reaches at least about C$1.168 billion and management explains that growth came from contracts and rates rather than currency, the risk is falsified.

Unplanned outages at Bruce Power's operating units, or constrained output from Unit 3 after its return, could hold power earnings growth below 10%. The exposure is Power and Energy Solutions comparable EBITDA: if the segment stalls below about C$293 million, it would be at least about C$26 million short of the 20% growth case. If Bruce Power's third-quarter availability is at least 94% and segment comparable EBITDA reaches at least about C$319 million, the risk is falsified.

If the Mexico segment loses its year-over-year increase and also runs into CFE contract or payment problems, earnings could fall out of the post-start-up range. On our arithmetic, every C$20 million by which third-quarter Mexico segment comparable EBITDA falls below the prior-year base of C$416 million lowers the company's third-quarter comparable EBITDA growth by about 0.8 percentage points, which is the direct financial exposure to single-customer concentration. If third-quarter Mexico segment comparable EBITDA is at least C$409 million and the company reports no CFE payment issues, the risk is falsified.

Delays in negotiating the investment return framework for new NGTL projects, or an Alberta government decision to bring in other builders for expansion, would slow TC Energy's rate base growth in Canada. The Canadian segment produces about 31% of company comparable EBITDA, so each percentage point of slower segment growth lowers company comparable EBITDA growth by about 0.3 percentage points, a small effect that would persist for years. If the company announces a new NGTL investment framework with customers in the third quarter, or files an expansion application with regulators, the risk is falsified.

What to Watch Next

• U.S. growth: segment comparable EBITDA against C$1.062 billion a year earlier, with about C$1.168 billion as the 10% growth mark; flows against 26.3 Bcf/d and LNG deliveries against 3.7 Bcf/d; whether currency effects are broken out; Great Lakes settlement approval and any ANR refunds.
• Bruce Power: Power and Energy Solutions comparable EBITDA against C$266 million, with about C$319 million as the 20% growth mark and about C$293 million as the weak case; availability against 94%; forced outages; the Unit 5 MCR start in the fourth quarter.
• Mexico: segment comparable EBITDA against C$416 million a year earlier and C$409 million last quarter; flows against 3.3 Bcf/d; power plant deliveries against 1.4 Bcf/d; closing timing and EBITDA impact of the Guadalajara-Manzanillo sale.
• Canada: segment comparable EBITDA against C$913 million, with about C$950 million as the 4% growth mark; the split between flow-through depreciation and incentive earnings; NGTL receipts against 14.0 Bcf/d and the 14.3 Bcf/d mark; any new NGTL investment framework or regulatory filing.
• Company level: whether growth in comparable EPS from C$0.77 is at least half the growth in comparable EBITDA, whether debt to EBITDA keeps moving from 4.87x toward 4.75x, and whether the 2027 capital spending outlook stays within its range.

Conclusion

TC Energy's earnings are driven jointly by contracted capacity, regulator-approved rates and Bruce Power's operating units, a structure that makes growth depend more on project completions and rate settlements than on volumes or gas prices. In the first half of 2026, comparable EBITDA was C$6.036 billion, up about 13%, and comparable EPS was C$1.93[3], and management narrowed full-year comparable EBITDA guidance to the upper end of C$11.6 billion to C$11.8 billion[4]. More than 40% of first-half growth, however, came from the start-up of Mexico's Southeast Gateway, while lower AFUDC made EPS grow more slowly than EBITDA; the central question for the third quarter is therefore whether new U.S. pipelines and rates and Bruce Power's Unit 3 can take over from Mexico while turning EBITDA growth into genuine EPS growth.

Independent outside judgment is currently concentrated on the Canadian business, and it sharply contradicts management's account. According to CBC, a leaked Alberta cabinet report argued that NGTL's expansion plans are "misaligned" with the province's projected demand growth, that the company's dominant position has produced a "market failure," and that the system will reach capacity by 2029[22]; management, by contrast, says it is advancing about 1.0 Bcf/d of service offerings[9] and that the return framework for new projects is still under discussion with customers[20]. This disagreement maps directly onto the debate over NGTL growth and the investment framework: an announced framework or expansion application in the third quarter would sit closer to management's account, while continued delay would sit closer to the provincial report's criticism. Among the coverage gathered since July 30, the remaining news mostly restates company announcements, and no independent reading of results for the U.S. business, Bruce Power or Mexico has appeared, so the other three debates can be judged only on company disclosures.

Taken together, the view that new projects are replacing Mexico's increase and that EBITDA growth is converting into EPS would be strengthened if third-quarter U.S. segment comparable EBITDA reaches about C$1.168 billion with growth coming mainly from contracts and rates, power earnings reach about C$319 million with availability of at least 94%, Mexico holds above C$409 million, comparable EPS growth is at least half of EBITDA growth, and debt to EBITDA keeps moving toward 4.75x. Conversely, the view would be materially weakened if U.S. growth relies mainly on currency, Bruce Power availability falls, Mexico drops out of its post-start-up range, or the NGTL investment framework keeps stalling under provincial pressure.

Sources

[1] TRP 6-K filed 2026-10-13 · Coastal GasLink Indigenous investment · 2026-10-13 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[2] TRP earnings calendar updated 2026-10-30 · 2026-10-30 · Drillr earnings calendar

[3] TRP Q2 2026 6-K filed 2026-07-30 · results table · 2026-07-30 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[4] TRP Q2 2026 6-K filed 2026-07-30 · outlook · 2026-07-30 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[5] TRP 6-K filed 2026-03-20 · 2026 management information circular · 2026-03-20 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[6] Drillr analyst estimates TRP Q3 2026 retrieved 2026-10-30 · 2026-10-30 · Drillr analyst estimates · https://gateway.drillr.ai/mcp/private

[7] TRP Q3 2025 6-K filed 2025-11-06 · results table · 2025-11-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[8] TRP Q1 2026 6-K filed 2026-05-01 · results table · 2026-05-01 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[9] TRP Q2 2026 6-K filed 2026-07-30 · Bruce Power and in-service · 2026-07-30 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[10] TRP Q3 2025 6-K filed 2025-11-06 · outlook and operations · 2025-11-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[11] TRP Q2 2025 6-K filed 2025-07-31 · 2025-07-31 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[12] TRP 6-K filed 2026-09-29 · Coastal GasLink Phase 2 · 2026-09-29 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[13] TRP Q1 2026 6-K filed 2026-05-01 · operations and settlements · 2026-05-01 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[14] TRP Q2 2026 6-K filed 2026-07-30 · regulatory · 2026-07-30 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[15] TRP Q2 2026 6-K filed 2026-07-30 · CEO message · 2026-07-30 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[16] TRP Q1 2025 6-K filed 2025-05-01 · 2025-05-01 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[17] TRP 6-K filed 2025-03-21 · 2025 management information circular · 2025-03-21 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[18] TRP Q2 2026 6-K filed 2026-07-30 · cash flows · 2026-07-30 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[19] TRP 40-F filed 2025-02-14 · 2025-02-14 · 40-F · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=40-F&dateb=&owner=include&count=40

[20] TRP Q2 2026 earnings call 2026-07-30 · 2026-07-30 · earnings_call · https://www.tcenergy.com/investors/

[21] TRP Q3 2025 6-K filed 2025-11-06 · projects and rate cases · 2025-11-06 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40

[22] CBC News on leaked Alberta cabinet report 2026-09-14 · 2026-09-14 · CBC News · https://www.cbc.ca/news/canada/calgary/tc-energy-alberta-9.7343325

[23] TRP Q2 2026 6-K filed 2026-07-30 · operational and project highlights · 2026-07-30 · 6-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001232384&type=6-K&dateb=&owner=include&count=40