Gas Carried the Quarter, the Mainline Slipped, and the Yield Reached Our Upgrade Line

Results vs. Consensus

Q3 2026 Scorecard

Consensus for adjusted EPS sat at C$0.48 across the two providers we checked, which modelled growth of roughly 4% on the prior-year C$0.46. The print delivered 6.5%. That is the first year-over-year increase in adjusted EPS in the three quarters we have covered, after declines of 4.9% in the first quarter and 3.1% in the second. The size of the beat deserves less weight than its direction: the C$29M reduction in adjusted income taxes is worth about 1.3 cents a share on 2,192 million shares, which is more than the one cent by which the Street was beaten. As before, neither adjusted EBITDA nor distributable cash flow carries a published quarterly point estimate, and the sell side underwrites the annual ranges.

Year-Over-Year Comparison

Revenue rose 44.0% and, as in every quarter we have covered, it tells the reader nothing. Commodity sales grew C$6,455M against commodity costs that grew C$6,529M, which is the crude and gas marketing book inside Liquids Pipelines grossing up and down with prices. The tolls that the business is underwritten on sit in transportation and other services, and that line fell 1.1%. GAAP interest expense fell 16.9% while adjusted interest expense rose 3.0%, because the reconciliation removes C$245M of non-operating items from the GAAP interest line. Strip that and the financing cost of the build phase is still rising, just more slowly than in the second quarter.

Nine-Month Comparison

Three months ago the half-year view read as adjusted EBITDA up 1.1%, distributable cash flow per share up 1.6% and capital expenditures up 49.5%. Nine months in, those figures are 1.9%, 2.4% and 49.6%. The operating line is accelerating and the spending line is not slowing, which is the shape a build phase should have and the reason the balance sheet discussion below has not moved.

Three-Quarter Trend

This is the table we would put in front of anyone who asks whether the investment case improved this year. Four of its seven rows moved the right way in every quarter: consolidated growth, per-share earnings, operating-segment growth, and the corporate hedge line's shrinking share of the result. One row, the Mainline, has now gone down, up and down again. The last two rows are the price of everything above them.

GAAP to Adjusted Bridge

The bridge between reported and adjusted EBITDA is the narrowest in our coverage at C$16M, against C$444M a year ago, C$790M in the first quarter and a reversed C$60M in the second. That makes the adjusted EBITDA figure unusually easy to trust this quarter. The larger gap sits below EBITDA: GAAP earnings exceeded adjusted earnings by C$214M. The filing attributes the non-operating difference mainly to a net unrealized derivative gain of C$245M before tax, against a C$394M loss a year earlier, and to a C$66M positive crude oil inventory adjustment that reversed part of the second quarter's C$121M negative one. None of that is operating income, and the adjusted framework removes all of it.

• Revenue: Not the metric. The C$6,438M increase is the marketing book and is offset almost dollar for dollar in commodity costs. Transportation revenue, the toll line, fell C$83M in the filing's revenue note: Liquids fell C$162M and Gas Transmission offset C$74M of it.
• Adjusted EBITDA: Up 3.9%. The four operating segments grew 4.6% and contributed C$196M, or 117% of the consolidated increase, while Eliminations and Other subtracted C$29M. That is the reverse of the first quarter, when the corporate line was the whole result.
• Margins and rate base: The East Tennessee settlement, approved by the federal regulator on August 3 with rates retroactive to November 1, 2025, the Texas Eastern step-up and favourable recontracting, and the Utah and North Carolina base-rate increases are the named drivers. Part of the Gas Transmission increase is a higher allowance for equity funds used during construction, which is a non-cash accounting credit on growth capital and is reversed out of distributable cash flow.
• Adjusted EPS: Up 6.5%. The bridge from the C$167M EBITDA increase to the C$77M adjusted earnings increase runs through C$92M of higher depreciation, C$38M of higher interest, C$29M of lower income tax, C$12M of lower noncontrolling interest and C$1M of higher preference dividends. Without the tax benefit, adjusted earnings would have grown 4.8%. The effective GAAP tax rate fell to 23.3% from 27.2%, which the filing attributes in part to Canada's reaccelerated investment incentive rules enacted in March.
• GAAP EPS: Nearly doubled to C$0.59 on the derivative marks, against a prior-year quarter that carried a C$394M unrealized loss. It carries no operating information.
• Distributable cash flow: Up 4.8%, of which C$72M came from maintenance capital falling to C$231M from C$303M. Without it, distributable cash flow grew about 2.0%. The company attributed the second quarter's lower maintenance spend to timing and this quarter's to enterprise-wide savings, which is a more durable claim if it holds through the fourth quarter. Cash from operations fell 5.8% on working capital, a reversal of the second quarter's swing.

Segment Performance

The composition shifted again, and in a direction that changes how we read the business. In the first quarter the operating segments fell and the hedge line covered for them. In the second quarter all four segments grew modestly and the hedge line helped. This quarter the two gas segments alone grew by more than the consolidated total, the largest segment shrank, and the hedge line went the other way. Liquids Pipelines is still half of adjusted EBITDA. It is no longer where the growth is.

Liquids Pipelines

Every Liquids sub-segment declined, which had not happened in either of the prior two quarters, and the largest decline was in the sub-segment we spent last quarter's note crediting with a recovery. The release names three drivers: lower Mainline volumes net of earnings sharing, lower Mainline tolls on Line 9 deliveries, and lower Market Access contributions "due to underutilized contracts to the U.S. Gulf Coast", partly offset by translating U.S. dollar earnings at a weaker Canadian dollar. The CFO's account on the call located the Market Access weakness on Flanagan South.

"The decrease in Liquids Pipelines results reflects impacts similar to the first 2 quarters, with lower tolls on the Line 9 deliveries and reduced throughput on the Flanagan South pipeline due to high PADD II utilization and market pricing dynamics." — Patrick Murray, EVP and Chief Financial Officer

On a nine-month basis the segment is down 5.7% at C$6,850M and Mainline and Market Access is down 4.9% at C$4,455M. The Southern Lights recontracting that depressed Gulf Coast and Other in the second quarter has now largely lapped, and that sub-segment fell only C$7M. The forward commentary was the most bullish of any segment on the call, centred on the oil sands rather than on the pipe that carries the barrels away from them.

"But I think we are on the cusp of a huge cyclical and hopefully sustaining growth wave up there." — Colin Gruending, EVP and President, Liquids Pipelines

The commercial evidence for that view this quarter was small and specific: the C$0.2B Long Lake Expansion for an existing oil sands customer, with an in-service date in 2028, and a successful open season on Flanagan South. The larger evidence was acquired rather than built. The Tallgrass crude business adds the Pony Express and Powder River Gateway systems from the Rockies into Cushing, and Salt Creek adds roughly 500 miles of Delaware Basin gathering upstream of Gray Oak and Ingleside.

Assessment: Last quarter we concluded that the Mainline converts volume at the margin and that the first quarter's 13.2% decline was a toll-and-comparison event. This quarter weakens that reading. A volume decline on a system management describes as running "at or near capacity", combined with underutilized contracts on the pipe the company is simultaneously expanding, says that the constraint on Liquids earnings is downstream pricing and Line 9 tolls as much as Mainline throughput. Both of those are slower to fix than a volume shortfall. We move the Mainline bear point back to emerging.

Gas Transmission

The strongest segment result in our coverage, and every sub-segment contributed. U.S. Gas Transmission added C$94M on the East Tennessee settlement, the previously approved Texas Eastern rate increase and favourable Texas Eastern contracting. Canada added C$28M in the quarter in which the Aspen Point expansion of T-North entered service. The Other line, which holds Tomorrow RNG, the Gulf offshore assets and the DCP Midstream stake and which fell C$33M in the second quarter, rose C$43M with no explanation in either the release or the filing.

Two quality points sit underneath the headline. The first is the allowance for equity funds used during construction, which the release names among the drivers and does not size. The segment's other income line, which on the filing's consolidated definition consists primarily of that allowance and interest income, rose C$30M to C$94M, which suggests that roughly a fifth or less of the segment's increase is construction accounting rather than cash. The second is that the U.S. dollar translated at C$1.40 against C$1.38 a year ago, which helped this segment and was given back in the corporate hedge line.

"Despite some construction challenges on the Tennessee Ridgeline project, it entered service on time on November 1st." — Gregory Ebel, President and CEO

The in-service news was good on timing and mixed on cost. Aspen Point came in, in management's words, under budget and ahead of schedule at a C$1.2B estimate. Tennessee Ridgeline's estimate in the quarterly filing's project table rose to US$1.5B from US$1.4B, about 7%, and the project entered service on November 1, after the quarter closed, although the release describes both projects as having entered service during the quarter. Woodfibre LNG remains on track for first gas next year. The Bay Runner pipeline inside the Permian joint venture reached mechanical completion and Blackcomb entered service.

Assessment: This is the business the investment case increasingly rests on, and the quarter supports it. The rate-case uplift that we called durable but finite in August is still compounding, and the in-service wave is now arriving. The forward items to watch are the BC Pipeline toll settlement, which expires at year end and which management wants to reprice toward higher returns, and Project Beacon, whose commercialization has moved from "later in the year" to "very early in the New Year".

Gas Distribution and Storage

Ontario turned back up. Three months ago Enbridge Gas Ontario fell 3.6% and we worried that the segment's growth had narrowed to one geography. This quarter Ontario grew 14.7% on higher rates and customer growth net of earnings sharing, with weather negligible in both years, while the U.S. utilities grew 22.1% on the Utah and North Carolina base-rate increases. The third quarter is seasonally light for the heating utilities, so the percentages are large on small bases, but both halves moved in the same direction for the first time since the first quarter.

The regulatory calendar advanced on two fronts. In Ohio, the company filed a stipulation in September for an annual revenue increase of approximately US$145M on a 9.59% allowed return on equity and 52.87% equity thickness, with a decision expected in or before the first quarter of 2027 and new rates on March 1, 2027. In Wyoming, a settlement was reached with rates expected in early 2027. The segment also agreed to buy the producing assets of Laramie Energy for US$485M plus up to US$65M of contingent payments, folding them into the Wexpro cost-of-service supply model for Enbridge Gas Utah.

"The transaction leverages our existing successful Wexpro business model to provide our utility customers with a stable cost of service source of natural gas helping improve affordability and moderate commodity price volatility while providing us a utility return without taking on commodity exposure." — Gregory Ebel, President and CEO

Ontario's Phase 1 appeal moved the other way on disclosure. The quarterly filing still says Enbridge Gas Ontario is appealing the Ontario Energy Board's Phase 1 findings on depreciation, equity thickness and undepreciated capital, and that the hearing took place in the second quarter. The second-quarter filing added that "a decision is expected before the end of the year." This quarter's filing drops that clause.

Assessment: The utility had its best quarter in our coverage and the American rate base continues to compound. The Ohio stipulation, if approved as filed, locks in an equity thickness above 52% at a return near 9.6%, which is a constructive outcome in a state where a rate freeze was being floated three months ago. The risk we flagged in August, an adverse Ontario decision landing on the segment's weaker half, now sits on the half that recovered this quarter, and its timing has quietly become open-ended.

Renewable Power Generation

Adjusted EBITDA of C$127M grew 27.0% on the first phase of Sequoia Solar, placed in service in December 2025. The segment is 2.9% of the total and cannot move the consolidated result. What it can move is the capital line: Renewable Power capital expenditures were C$801M in the quarter against C$173M a year ago, 4.6 times, as Clear Fork Solar, Cowboy Phase 1, Easter and the 300 MW Cone wind project build out, and the second phase of Sequoia approaches its year-end in-service date.

"These projects under construction are supported by long term contracts with high quality counterparties, including 1.4 GW of generation capacity with Meta." — Gregory Ebel, President and CEO

Assessment: The contracted, hyperscaler-backed growth is real and the capital is now flowing. The trade-off is that the segment is the fastest-growing consumer of capital in the portfolio at the same time as the balance sheet sits above its target range. We continue to treat the 1.5 GW of safe-harboured opportunities as optionality rather than as part of the 5% growth case.

Eliminations and Other

Assessment: This is the mechanism we spent the first quarter explaining, now running in the opposite direction. A weaker Canadian dollar lifted the U.S. dollar earnings that the operating segments translate at spot, and both Liquids and Gas Transmission name the translation as a positive driver; the enterprise hedge then settled at a larger loss in this line. The consolidated result is therefore close to currency-neutral, and the operating segments' 4.6% growth slightly overstates their constant-currency performance. That is the correct way for the hedge to behave, and it is why we read the four-segment line and the consolidated line together rather than either alone.

Capital and Balance Sheet KPIs

Key Topics & Management Commentary

Overall Management Tone: Valedictory and forward-weighted, with a large share of the prepared remarks given to the chief executive's retirement, the succession and the opportunity set through 2030, and comparatively little to a Liquids segment that declined. Management was more specific than in either prior quarter on the numbers it chose to give, committing to the guidance midpoint, as it last did in May, and pre-announcing a fourth-quarter leverage figure, and less forthcoming than in either prior quarter on what it chose to leave out: the Mainline volume and every part of the Line 5 file. Analyst questioning was courteous, heavily weighted to the transition and to growth, and did not press the balance sheet or the Mainline decline.

1. Gas Did the Work, and Adjusted EPS Grew for the First Time in Our Coverage

The two gas segments added C$270M of adjusted EBITDA in a quarter in which the consolidated figure rose C$167M. Liquids subtracted C$101M and the corporate line C$29M, and Renewable Power added C$27M. Adjusted earnings per share rose to C$0.49 from C$0.46, the first increase in our three quarters of coverage, because the EBITDA growth outran the higher depreciation and interest that the build phase carries by C$37M, against C$16M in the second quarter, and adjusted income tax and noncontrolling interests fell rather than rose.

"So gas is there is no doubt gas is the big winner right now in this full electrification. You see that in our business just this quarter, the gas transmission business. Is up double digit. The gas distribution business is up double digit." — Gregory Ebel, President and CEO

The sources of the gas growth are the ones we called durable in August: the East Tennessee settlement now approved, the Texas Eastern step-up, and the Utah and North Carolina base rates, plus Ontario rate escalation. What is new is breadth. Every Gas Transmission sub-segment and every Gas Distribution sub-segment grew.

Assessment: This is the quarter that the "assets work" question we posed in May was waiting for. The answer is yes, but the assets that work are not the ones the market has historically paid for in this name. The investment case is migrating from a crude pipeline with a utility attached to a gas infrastructure company with a crude pipeline attached, and the valuation has not yet been asked to reflect that.

2. The Mainline Gave Back Its Second-Quarter Gain, and Nobody Quoted the Volume

Mainline and Market Access adjusted EBITDA fell 5.6% to C$1,439M. The release puts "lower Mainline volumes, net of earnings sharing" first among the causes, followed by lower Line 9 tolls and underutilized Market Access contracts to the Gulf Coast. In the second quarter the chief executive opened the call with "strong Q2 Mainline volumes averaging 3.1 million barrels per day." This quarter there was no volume figure in the release, in the quarterly filing or on the call. The prepared remarks offered a description instead.

"Regardless of evolving market conditions, or public sentiment for oil, our mainline system has continued to operate at or near capacity." — Gregory Ebel, President and CEO

Those two statements can both be true: an apportioned system can run near capacity and still move fewer barrels than a record prior-year quarter. But the company chose to give the number when it was good and the adjective when it was not, and the earnings-sharing mechanism that sits between the volume and the EBITDA has still not been quantified in any of the three quarters we have covered.

Assessment: Two declines in three quarters, with the one gain sandwiched between them, is not a structural cap in the sense we feared in May, but it is not a growth engine either. The Mainline is behaving like a fully contracted, fully utilized asset whose earnings drift with tolls and downstream spreads. That is fine for a yield investment and it is why the upside case now has to run through gas. We move Bear 1 from contained back to emerging.

3. C$5.2 Billion of Acquisitions and the First Common Equity in Our Coverage

Between August 25 and September 9 the company agreed three acquisitions: Laramie Energy's gas assets for US$485M plus contingent payments, Salt Creek Midstream's Delaware Basin crude gathering for US$625M (closed October 9 at C$892M), and Tallgrass Energy's crude business, including Pony Express and the Powder River Gateway, for US$2.55B, which the announcement put at an estimated 10 to 11 times forward enterprise value to EBITDA. In Canadian dollars the three total roughly C$5.2B before contingent payments. On September 9 the company launched a C$2.6B bought deal at C$66.85 a share, upsized to C$3.0B and 44.7M shares when the over-allotment was exercised in full.

"We continue to equity self fund our organic growth backlog while maintaining a strong balance sheet. As Greg mentioned earlier, we completed a $3 billion equity offering this quarter to derisk financing of our recent acquisitions." — Patrick Murray, EVP and Chief Financial Officer

The distinction management draws is between organic growth, which it still funds from internally generated equity, and acquisitions, which it funded with roughly C$2.9B of net proceeds against C$5.2B of purchase price, or 56%. The offering announcement itself said the proceeds would partially fund the acquisitions "and to create financial flexibility to fund potential future growth opportunities", and the quarterly filing repeats that some proceeds remain available for future growth. At quarter end C$4.9B of cash sat on the balance sheet pending the Tallgrass close.

Assessment: The deals are sensibly priced for contracted assets, extend existing corridors rather than open new ones, and the Tallgrass announcement says it is accretive to distributable cash flow per share in the first full year. The equity issue was the right way to keep leverage from going further above range. But the self-funding pillar was written for a company that grows within its own cash flow, and a company that issues 2.05% of its share count at a price 12.4% below our last note's close, in the same week it announced its chief executive's retirement, has shown that pillar has a boundary. We keep Bull 2 at risk.

4. Leverage at 5.1x Again: a Narrower Currency Defence and a Third Print Pre-Announced

Debt to EBITDA finished the quarter at 5.1x for the second consecutive quarter, with the same explanation: the quarter-end exchange rate of C$1.42 against a lower average. Last quarter the comparison was to the quarterly average of C$1.38. This quarter the release compares it to the trailing-twelve-month average of C$1.39, which is the more relevant rate for a trailing-twelve-month denominator, and a smaller gap.

"Looking ahead to the next quarter, we expect to be in a similar position in regards to leverage. As we close the previously mentioned acquisitions, but on a full year run rate EBITDA basis for these assets, expect to remain well within our leverage target." — Patrick Murray, EVP and Chief Financial Officer

The arithmetic is harder to reproduce than it was three months ago. Last quarter, netting cash and giving half equity credit to the C$16.4B of subordinated notes reproduced the disclosed 5.1x closely. Applied to this balance sheet, the same method gives 5.0x, because cash rose to C$4,898M on the equity proceeds. The gap closes if roughly C$2.9B of that cash, about the size of the net offering proceeds, is excluded, which would be consistent with the company treating cash held for the Tallgrass purchase as committed. That is our inference; the company does not publish the calculation. On the currency defence, at the roughly US$50B of U.S. dollar debt we inferred in August, a three-cent gap between spot and average is worth about C$1.5B of debt, or about 0.07x on the ratio. It brings the figure inside the range only if the unrounded number sits at the low end of 5.1x.

Assessment: The downgrade condition we set in August was a second consecutive print above 5.0x without a currency explanation. This print came with one, so the condition did not fire, and we are not going to rewrite it after the fact. What has changed is that the company has now told us the fourth quarter will look the same and offered a second, different reason, acquisition timing, for why it should not count. Three consecutive quarters above the range, counting the one already pre-announced, each with a reason, is a pattern, and the next defence will have to be the run-rate figure it has promised.

5. KKR and Apollo at Westcoast: the Monetization Lever, Pulled

On the July 31 call the CFO listed "potential asset sales, monetization" among the levers for managing leverage, the first time in our coverage. The lever was already in motion: the financing partnership was formed on July 30, the day before that call, and the previously announced deal closed within five weeks. On September 3, KKR, with funds managed by Apollo, invested C$729M in a vehicle that funds the Aspen Point and Sunrise expansions of the BC Pipeline, and committed roughly C$2.0B more. Its interest in the system rises to 29% when Sunrise enters service in 2028, and Enbridge holds an option to repurchase it between the seventh and fourteenth years.

"We're advancing the next generation of energy investments within our $10–11 billion annual investment capacity, while recycling capital opportunistically, through transactions like the $2.7 billion commitment from KKR and Apollo in the Westcoast system." — Gregory Ebel, President and CEO

The filing adds a detail the release does not. KKR's units carry contingently required distributions if, among other things, the expansions are delayed in commencing commercial operations, suffer force majeure or meet regulatory disallowances, which is why the stake is classified as redeemable noncontrolling interest outside permanent equity. Enbridge has sold a minority of the cash flows and kept a meaningful part of the construction and regulatory risk.

Assessment: This is plausibly a cheaper source of growth capital than common equity for a regulated asset that management itself calls one of the lower-returning assets in its gas portfolio, and it is the right asset to recycle. It is also a third-party equity layer under a project in the secured backlog, which means the claim that the organic programme is self-funded now carries two qualifiers: common equity for acquisitions, and partner capital for the largest Canadian gas project.

6. A Midpoint Commitment, and What the Fourth Quarter Has to Deliver

For the first time since May, management named a point inside its guidance range rather than only reaffirming the range.

"Given our strong performance to date and confidence in the underlying business, I am pleased to reaffirm our 2026 guidance and expect results to finish at the midpoint of the range." — Patrick Murray, EVP and Chief Financial Officer

Nine-month adjusted EBITDA of C$15,020M leaves C$5,480M for the fourth quarter to reach C$20.5B, growth of 5.1% on the prior-year C$5,213M. Three months ago the midpoint needed 4.6% across the second half; the third quarter delivered 3.9%, so the remaining requirement rose. The Tallgrass announcement said the deal does not materially affect 2026 guidance, so the acquisitions are not doing the work, though Salt Creek contributes from October 9. On last year's seasonality the nine months imply C$20.33B, up from the C$20.17B the half year implied.

Assessment: A company with twenty consecutive years of meeting guidance does not volunteer a midpoint lightly, and that sentence is the most important one on the call for the fourth-quarter print. The arithmetic is achievable on the in-service cluster, Tennessee Ridgeline from November 1, Aspen Point and Blackcomb, the heating season in two growing utilities, and lower maintenance capital. It is not comfortable. We model C$20.4B, between the seasonal read and the commitment.

7. The Backlog Fell to C$38B Because C$3.3B Went Into Service

The secured growth backlog moved from approximately C$41B to approximately C$38B. That is the right direction for the right reason: Aspen Point at C$1.2B and Tennessee Ridgeline at US$1.5B left the backlog on entering service, roughly C$3.3B, against about C$1B of additions from Long Lake and the PXP2 expansion of Pony Express that comes with the Tallgrass purchase.

"Our secured growth backlog stands at $38 billion, even as we placed $3 billion of completed projects into service this quarter." — Gregory Ebel, President and CEO

The quarterly filing's table of material commercially secured projects still lists the same twenty projects it listed in June, now with the two completed projects marked in service. PXP2 is not in it; the acquisition that brings it has not closed. The bridge we asked for in August, from the approximately C$9B the chief executive said had been sanctioned year to date to the roughly C$3B of disclosed backlog additions, was not provided, and a questioner's observation that the company is "about halfway" through its C$10B to C$20B sanctioning target went neither confirmed nor corrected.

Assessment: Execution is visible and the conversion of backlog into earning assets is the thing an investor in a build phase most needs to see. The visibility problem we flagged last quarter is unchanged: the sanctioning figures quoted on calls and the backlog additions disclosed in releases still do not reconcile, and the C$10B to C$20B target is being measured by analysts rather than reported by the company.

8. Line 5: Rehearing Denied, Tunnel Permit Vacated, Relocation Unmentioned

The quarterly filing carries the only update on the company's most contested asset, and it is short.

"On September 14, 2026, Enbridge filed a petition for rehearing to the Seventh Circuit, which was denied on September 30, 2026. The Court set a scheduling conference for December; we expect legal proceedings to continue through 2027." — Enbridge Inc., quarterly report for the period ended September 30, 2026

Three facts sit around that paragraph. First, Enbridge sought rehearing of an appellate decision we described in August as favourable on balance, which suggests the company wanted more from the court than the remand gave it, most likely on the affirmed trespass finding. The same filing records the court's instruction that the District Court "develop a remedy that provides Enbridge a reasonable opportunity to complete the Line 5 reroute", which is the constructive part. Second, the Wisconsin relocation itself, sanctioned last quarter at US$1.0B with an early-2027 in-service date and described under its own heading in the June filing, no longer appears anywhere in this filing's project disclosures. Third, on the Michigan side, the state's Supreme Court in late July vacated the tunnel permit issued by the Michigan Public Service Commission and sent it back for a broader review, and in September the governor directed the state environmental regulator to revisit the water permit it had issued on July 15. None of the three documents mentions the Michigan tunnel.

Assessment: We said in August that we would have preferred one sentence on the appellate ruling. This quarter there is not a sentence on Line 5 in the release or on the call, the relocation project has dropped out of the disclosure set, and a state court has reopened the tunnel. On substance, a rehearing denial and a December scheduling conference are procedural and the reroute instruction is helpful; nothing here brings a shutdown closer. On disclosure, this is now a pattern rather than an omission, and the Michigan development is the kind of item that eventually arrives as a cost estimate rather than a ruling. We keep Bear 3 contained and flag the communication as the risk.

9. The Succession: a Utility Executive for a Pipeline Company

On September 8 the company announced that the chief executive will retire on December 31 and that Michele Harradence, who has run Gas Distribution and Storage since 2022 and led the integration of the U.S. utilities, will become chief executive and join the board on January 1, 2027. This was the outgoing chief executive's last earnings call.

"And last but not least, after a multiyear succession planning effort with the board, I am thrilled that we have an excellent leader in Michele Harradence to lead and advance Enbridge into its next growth chapter." — Gregory Ebel, President and CEO

The incoming chief executive's first answer on the call was a statement of continuity: disciplined capital allocation, the dividend record, the four franchises and "more of the above". An investor day at which the new chief executive "lays this all out" was promised without a date.

Assessment: An internal successor after a multi-year process, from the segment that just grew 18.8%, is the low-risk outcome, and we would not expect a change in dividend policy or leverage targets. The question for 2027 is emphasis. The utility platform the incoming chief executive has led is the part of the company with the clearest rate-base growth, and the acquisitions announced in the same fortnight were all in Liquids and utility supply. We expect the investor day to be the first place the capital allocation priorities are restated, and we will grade it against the 4.5x to 5.0x range rather than against the tone.

10. Mainline Egress: Downstream First, Upstream When Ottawa and Edmonton Agree

The resequencing of Mainline Optimization Phase 2 that surprised us in August has produced its first result. The Flanagan South open season closed successfully, a Southern Access Extension open season closes later this year, and management expects an investment decision on the downstream expansions "likely by the next quarterly call". The upstream Mainline expansion waits for producers, and producers wait for an agreement between Alberta and the federal government.

"Because it is important that these downstream contracts come with entitlements for downstream verification on the main line. So when the main line is apportioned, right, these contracts get filled. Which is very valuable in a time of apportionment, which we think will persist on the mainline for the foreseeable future." — Colin Gruending, EVP and President, Liquids Pipelines

That answer resolves an apparent contradiction in the quarter. Flanagan South's existing contracts are underutilized and its throughput fell, yet shippers signed up for more of it. They did so because the downstream contract carries a Mainline entitlement, and Mainline space is scarce. The chief executive put a date on the upstream catalyst: a settlement between producers, Alberta and Ottawa expected in mid-November, following a federal budget described on the call as positive.

"Mid November is a good, you know, when we look for a settlement of deals between the producers, Alberta and the federal government on the full round of packages, if you will, that accelerates growth." — Gregory Ebel, President and CEO

Assessment: The downstream-first plan is commercially clever because it monetizes Mainline scarcity without building Mainline capacity, and it explains why the company can sanction Flanagan South while Flanagan South is underused. Its weakness is that it adds capital to the part of the system where earnings fell this quarter. Public reporting the day of the call suggested oil sands executives are prepared to let the mid-November target slip, so we do not put a date on the upstream decision.

11. BC Pipeline Tolls and Project Beacon Both Move to Early 2027

Two gas items carried timelines into the new year. The BC Pipeline toll settlement for 2022 to 2026 expires in December, interim tolls will be filed for January 1, and management expects a final agreement and regulatory approval early in 2027. The stated objective is a higher achieved return on an asset whose nameplate return management described as just above 10%.

"With the current West Coast toll settlement expiring at year end, negotiations are well advanced. With an agreement and CER approval expected to be realized in early 2027." — Gregory Ebel, President and CEO

Project Beacon, the oversubscribed Algonquin expansion into New England, moved from updates "later in the year" in August to "strong potential for commercialization" very early in the new year. Management cited letters from governors asking for accelerated federal permitting.

Assessment: The BC toll renewal is the larger near-term number. A higher return on a system that is absorbing C$4.0B of Sunrise capital and C$2.7B of partner money would lift the economics of the backlog's single largest Canadian project, and management's own words, "lower returning", set the bar. Beacon slipped by a quarter and remains the highest-optionality, longest-fuse item in the opportunity set.

12. Maintenance Capital: From Timing to Savings

Maintenance capital fell to C$231M from C$303M, contributing C$72M of the C$123M increase in distributable cash flow. Across nine months it is down 20.3% at C$676M. In the second quarter the release attributed the lower spend to "timing". This quarter it attributes it to "enterprise-wide saving initiatives".

"We have also been very focused on improving results within our existing assets continued cost discipline, optimization efforts and increased buying power help us mitigate inflationary pressures, with those efficiencies reflected across our operating costs, maintenance capital that I just spoke to, and our growth projects." — Patrick Murray, EVP and Chief Financial Officer

Assessment: If the reduction is a saving, it is worth roughly C$0.10 of distributable cash flow per share a year at the nine-month pace and it supports the dividend's coverage through the build. If it is timing, as the company said three months ago, it reverses in the fourth quarter. The fourth-quarter maintenance figure will tell us which, and it matters for the per-share guidance more than any single operating segment does.

Guidance & Outlook

Implied fourth-quarter ramp. Full-year 2025 adjusted EBITDA was C$19,952M, so the fourth quarter of 2025 delivered C$5,213M. The C$20.5B midpoint now needs C$5,480M in the fourth quarter of 2026, growth of 5.1%. The C$20.2B floor needs C$5,180M, a 0.6% decline, which is well within reach. The C$20.8B ceiling needs 10.9% and is unlikely without a contribution the company has said it does not expect. On distributable cash flow per share, nine months delivered C$4.34 against C$4.24; the C$5.90 midpoint needs roughly C$1.56 in the fourth quarter against C$1.47 a year earlier, about 6%, on a share count about 2% larger after the offering. Both midpoints require the fourth quarter to be the best quarter of the year on growth.

The bridge management offered was the same in shape as August's, with tailwinds in Gas Transmission and at Seaway and headwinds in Liquids market access and U.S. interest rates. The identifiable fourth-quarter items are Tennessee Ridgeline from November 1, Aspen Point and Blackcomb running for a full quarter, Salt Creek from October 9, the second phase of Sequoia Solar by year end, and the heating season in an Ontario utility that has just returned to growth. Against them, the Line 9 toll and Gulf Coast market access headwinds have shown no sign of easing, and a C$4.9B cash balance will shrink by the Tallgrass purchase price when that deal closes.

Street at: Consensus for the quarter was C$0.48 against C$0.49 delivered. We found no published quarterly point estimate for adjusted EBITDA or distributable cash flow, and nothing in the print gives the annual numbers a reason to move by more than the gap between the floor and the midpoint.

Guidance style: Changed, modestly. A company that has declined to revise in the first quarter as policy and declined again at the half has now named the midpoint again, in firmer words than May's "on track to achieve the midpoints", three months before the year closes. That is the most confident guidance language in our coverage, and it raises the cost of a miss. A fourth-quarter result below the midpoint would be the first miss in our coverage against a financial target management volunteered, and we would weight it accordingly.

Analyst Q&A Highlights

What Changes Under the Incoming Chief Executive

The call's first question went to the succession, asking what investors should expect to stay the same and where capital allocation or portfolio construction might change once the transition begins. The answer was a full statement of continuity, anchored in the dividend record and in the company's identity as a disciplined allocator, with a nod to both the utility acquisition of a few years ago and this quarter's liquids purchases. It contained no new priority, no change to the leverage range and no date for the promised investor day.

Q: "So Michelle, I know it is really early for this question, but what do you think investors should expect will remain the same under your leadership? And where could we see capital allocation priorities in portfolio construction evolve after the transition starts?"
— Robert Catellier, CIBC Capital Markets

A: "So that is just continuing to be what you already know us to be, disciplined capital allocators, attractive risk adjusted total returns, and a real suite of competitive projects that are meeting the demand for energy. I mean, we are talking about taking a great company and making it even better here."
— Michele Harradence, EVP and President, Gas Distribution and Storage (incoming President and CEO)

Assessment: The right answer for a first call in a new role, and an uninformative one. The second half of the question, where priorities might evolve, went unanswered, which is reasonable two months before the transition and leaves the investor day as the event that matters. Nothing here argues for a change in the dividend or balance-sheet framework.

Whether Three Tuck-Ins Signal a Shift Toward Acquisitions

A question on capital allocation asked whether the three acquisitions were opportunistic, whether the tuck-in pipeline was growing, and whether the company would keep allocating capital that way. The answer set out three tests, accretion, strategic fit and balance-sheet capacity, and tied the equity issue directly to the leverage range. The CFO added that the large majority of growth will still come from the organic programme and that the capital was raised to protect capacity for it.

Q: "So we have seen Enbridge be quite acquisitive of late with 3 relatively large tuck ins. Can you maybe, you know, provide some incremental color there Are these just opportunistic? Are you seeing increasing opportunities on the tuck in side, and could we continue to see Enbridge go away on that capital allocation side as well?"
— Robert Hope, Scotiabank

A: "They have got to be accretive. They have to add to our strategic footprint as well. And they have gotta be able to be carried on the balance sheet. Right? So those things are absolutely critical to keep within our 4.5 to 5 times, which is why you saw this issue, the equity with 3 pretty large deals."
— Gregory Ebel, President and CEO

Assessment: The most direct statement on the call of why the equity was issued: the acquisitions could not be carried on the balance sheet inside the range without it. That is a responsible answer and an admission in the same breath. It confirms that debt capacity, not opportunity, is the binding constraint on capital allocation through 2027, and that further acquisitions of this size would need further equity.

When Mainline Egress Beyond Phase 1 Gets an Answer

Asked about longer-term egress expectations beyond Mainline Optimization Phase 1 and the timing of updates, management described the downstream-first plan in operation: a successful Flanagan South open season, a Southern Access Extension open season still running, and investment decisions on both likely by the next call. The upstream expansion was explicitly parked on Canadian policy uncertainty, with the option to return to it later in a different form.

Q: "So just wanna get a sense of your longer term expectations for incremental egress beyond MLO1 and when might we see updates on that front?"
— Elias (for Jeremy Tonet), JPMorgan

A: "But given policy uncertainty in Canada, it was untimely to align customers to underpin, that mainline capital investment at the time. So we disaggregated, focused on the downstream part, which is trending successfully. And so that will pull incremental barrels through our mainline path"
— Colin Gruending, EVP and President, Liquids Pipelines

Assessment: The answer converts August's resequencing into a schedule: downstream decisions by the fourth-quarter call early in 2027, upstream when policy allows. That is more concrete than three months ago and confirms the upstream expansion has no date. Investors should model Mainline capacity additions after Phase 1 as contingent on the Alberta and federal agreement.

Whether the C$20B Sanctioning Target Moves Higher or Lower

A question noted that the company appeared about halfway through its target of sanctioning up to C$20B across 2026 and 2027 and asked what could push the figure up or down. The answer did not confirm the halfway figure, distinguished sanctioned capital from the larger opportunity set, pointed to the forthcoming investor day, and restated 5% growth through the end of the decade, noting that the gas businesses were each up double digits.

Q: "I think you are about halfway through your target of sanctioning up to $20 billion for 2026 and 2027. Is this $20 billion target still something you are looking at What are some of the push and takes or even, areas within your pillars of growth that you are looking at that might push this $20 billion higher or lower?"
— Maurice Choy, RBC Capital Markets

A: "I think you will get a great opportunity investor day when Michele comes forward and lays this all out at just how great the opportunity is on a go forward basis. As we have said, we see that continued 5% growth right through the end of the decade."
— Gregory Ebel, President and CEO

Assessment: A clean question with a number in it received an answer without one. The halfway estimate is consistent with the roughly C$9B the company cited in August plus this quarter's additions, but the company will not say so, and the sanctioning target that we told investors to hold management to is now being tracked by the sell side rather than reported. That is a small thing and a persistent one.

What Returns the BC Pipeline Toll Renewal Is Targeting

A question on the expiring BC Pipeline toll settlement asked what the company is targeting in the new agreement and whether higher returns are part of the negotiation. The answer was unusually candid about the asset's economics, conceding that it is one of the lower-returning assets in the gas portfolio while absorbing heavy capital, and committing to seek higher achieved returns while keeping tolls competitive. Finalization was guided to year end or very early in the new year.

Q: "Switching to the BC pipeline, referenced a 2027 expiring year end. And you are working on a new agreement into 2027. Could you perhaps highlight what you are targeting in this new set of months? And the I know you referenced you like to see better returns in BC in previous remarks. Is that is that a part of the conversation as well?"
— Benjamin Pham, BMO Capital Markets

A: "Of course, the BC assets are 1 of the lower returning assets in our gas portfolio, and we have got a lot of capital we are putting in there. So we are definitely looking for higher achieved returns there, to compete with all the great US opportunities that we have."
— Matthew Akman, EVP and President, Gas Transmission

Assessment: This is the most underappreciated item on the call. A higher achieved return on the system that holds both Aspen Point and the C$4.0B Sunrise expansion raises the value of capital already committed, and it does so through a negotiated settlement with customers who, on management's account, want growth. It is also consistent with the choice to sell the KKR and Apollo stake in this system rather than in a higher-returning one.

Where Project Beacon Stands After the Open Season

Asked for an update on Project Beacon's commercial discussions and its gating items, management described the brownfield complexity, said commercialization has strong potential very early in the new year, and framed the project as an affordability case with bipartisan political support, including letters from governors seeking faster permitting.

Q: "And then turning to the gas side of things, would you be able to provide an update on Project Beacon following its successful open season? And how have those commercial discussions progressed to date? And what are the key gating items from here?"
— Theresa Chen, Barclays

A: "Of course, you know, these brownfield projects have a fair bit of complexity. there is some subtlety in that. We are making good progress and working through that while talking to our customers. We do see a strong potential for commercialization of this by very early in the New Year."
— Matthew Akman, EVP and President, Gas Transmission

Assessment: A one-quarter slip described as progress. The gating items question was answered with complexity and subtlety rather than with a list, and permitting, which management volunteered as the number one hurdle in August, came up only as something governors want accelerated. Treat Beacon as a 2027 commercialization event with an unknown capital figure.

How Big the Oil Sands Opportunity Is, and Whether Enbridge Wants the Carbon Pipe

The final question asked for the total regional oil sands opportunity over the next few years, following the Long Lake sanction, and for the company's interest in the Pathways carbon pipeline that supports the proposed Pacific Link oil pipeline. Management answered yes to both: a large wave of Alberta production needs to reach the Edmonton and Hardisty hubs, the company has prebuilt capacity on seven trunk lines, and it is interested in the carbon pipeline "with the right risk package".

Q: "For your regional oil sands franchise and also while you are at it, maybe your interest level in perhaps becoming involved in the Pathways Pipeline just given your expertise and, you know, vested interest in seeing the Pacific Link pipeline going ahead to support more production growth out of the oil sands?"
— Patrick Kenny, National Bank

A: "Secondly, on the carbon pipe opportunity, yes. We are, interested in that with the right risk package, obviously. I think we have a lot of capabilities to bring to bear."
— Colin Gruending, EVP and President, Liquids Pipelines

Assessment: The regional oil sands system has the operating leverage the Mainline lacks, prebuilt pipe with headroom, and is the most capital-efficient way for Enbridge to participate in Alberta growth. Interest in the carbon pipeline is a different matter: it is a policy-dependent project whose risk package would have to be unusually favourable to clear a balance sheet already above its range. We would treat a commitment there as a negative until its terms are known.

Whether Ohio's Election Changes the Data-Centre Opportunity

A question tied the week's election results to Ohio, where the company has highlighted roughly 10 GW of data-centre and power opportunities, and asked whether the outcome changes the pace or nature of that opportunity. The answer described a state that had already introduced a large-load framework to make data centres pay their own way, repeated that Enbridge Gas Ohio is the lowest-cost of the state's four utilities, and characterized the data-centre load as upside on a modernization programme that is already in riders.

Q: "Has the election outcome changed how you think about the pace or nature of that opportunity, either within the utility or on the gas infrastructure side?"
— Aaron MacNeil, TD Cowen

A: "Now in Ohio, they introduced recently the concept of a large load framework. So they have been getting ahead of this for a while, and they have introduced this concept of large load framework that is really intended to address those sorts of concerns that folks have."
— Michele Harradence, EVP and President, Gas Distribution and Storage (incoming President and CEO)

Assessment: The right framing for a regulated utility: the base case is a modernization programme recovered through riders, and data-centre load is incremental. Coming the same quarter as a filed stipulation with a 9.59% return and nearly 53% equity, it supports the view that Ohio has moved from a regulatory risk in 2025 to a constructive jurisdiction in 2026.

What They're NOT Saying

1. Line 5, for a second consecutive quarter: The release and the call do not contain the words "Line 5". The quarterly filing discloses that Enbridge petitioned the Seventh Circuit for rehearing and was denied on September 30, and that the District Court has set a December scheduling conference with proceedings expected through 2027. The Wisconsin relocation, sanctioned in the second quarter at US$1.0B, is no longer described anywhere in the filing's project disclosures. The Michigan Supreme Court's vacatur of the tunnel permit and the state's reopening of the water permit appear in none of the three documents.
2. Where the Liquids capital went: Liquids Pipelines capital expenditures more than doubled to C$661M from C$307M. The only liquids project in the secured table with meaningful spending, Mainline Optimization Phase 1, moved from US$143M to a rounded US$0.2B of expenditures to date. The Line 5 relocation, under construction since the second quarter, is the obvious candidate for much of the difference. The filing does not say.
3. The Mainline volume: Named first among the causes of the Liquids decline in both the release and the filing, quoted to one decimal place on the second-quarter call when it was 3.1 MMbpd, and quoted nowhere this quarter. The earnings-sharing mechanism that sits between volume and EBITDA remains unquantified after three quarters.
4. The Debt-to-EBITDA calculation: A second quarter above range, a second currency explanation, and a third print pre-announced. The company still publishes neither the numerator, the treatment of C$16.4B of subordinated notes, the treatment of C$4.9B of cash held for an acquisition, nor the currency mix of its debt. Last quarter's reconstruction no longer reproduces the reported figure without an assumption about that cash.
5. The backlog arithmetic: The release credits "$1 billion" of backlog additions to PXP2 and Long Lake. On the company's own estimates those two projects total about C$0.6B, C$0.4B for PXP2 and C$0.2B for Long Lake. The bridge from the approximately C$9B the company said in August it had sanctioned year to date to its disclosed additions is still absent, and the progress against the C$10B to C$20B sanctioning target is not reported.
6. The non-cash share of Gas Transmission growth: A higher allowance for equity funds used during construction is named as a driver of the segment's C$165M increase and is not sized in the release or the filing. The segment's other income line, where the allowance sits, rose C$30M. The C$43M increase in the segment's Other sub-line, after a C$33M decline in the second quarter, is not explained at all.
7. The Ontario decision date: The second-quarter filing said a decision on the Phase 1 appeal over depreciation, equity thickness and undepreciated capital was "expected before the end of the year." The third-quarter filing describes the same appeal and drops the clause. The appeal concerns the allowed return on the company's largest single rate base.
8. A new Dakota Access complaint: On October 8 the Standing Rock Sioux Tribe filed a new complaint seeking vacatur of federal approvals and a shutdown of the Dakota Access Pipeline, in which Enbridge holds an effective 27.6% interest through the Bakken system. It is disclosed in the filing's legal section and was not mentioned in the release or on the call. We regard it as low-probability, but it is a second pipeline-shutdown proceeding sitting only in the filing.

Market Reaction

• Pre-print setup: Closed at C$67.33 on the TSX on November 5, equivalent to US$48.11 on the New York line. The Toronto line entered the print up 2.5% year to date against 12.3% for the S&P/TSX Composite, up 1.6% over twelve months and up 2.9% over thirty days, inside a 52-week closing range of C$62.71 to C$80.21. The New York line was up 0.6% year to date against 7.4% for the S&P 500, inside a US$45.23 to US$58.04 range.
• Since our last note: From C$76.28 at the second-quarter reaction close to C$67.33, down 11.7%, while the S&P/TSX Composite rose 1.1%. Over the same window TC Energy fell 7.1%, Keyera 14.2% and Pembina 2.5%. The deal-and-equity session was September 10, the morning after the Tallgrass and equity announcements, when the stock fell 3.7% against declines of 1.6% to 2.7% for those peers, a 1.1% fall in the index and an 11 basis point rise in the U.S. ten-year yield. The offering priced at C$66.85, 3.5% below the prior close.
• Prior session: On November 5 the S&P 500 fell 4.36% and the S&P/TSX Composite fell 2.03%. The Toronto line fell 1.01%.
• Reaction session (before-open print, same-day reaction): The Toronto line opened at C$66.86, 0.7% below the prior close and half an hour after the 9:00 a.m. call began, traded between C$65.40 and C$67.00, and closed at C$66.14, down 1.77% or C$1.19. The New York line closed at US$46.89, down 2.54% or US$1.22, after a range of US$46.38 to US$47.75.
• Volume: 10.1M shares in Toronto against an 8.2M thirty-day average, 1.2 times. New York traded 10.5M against 4.2M, 2.5 times normal.
• Index and peers: The S&P/TSX Composite rose 0.52% and the S&P 500 rose 0.31%. TC Energy fell 0.23% and Keyera 0.82%; Pembina rose 1.97% and Suncor 0.36%.

The stock underperformed a rising Toronto index by roughly 230 basis points on its own print day, on a beat with a reaffirmed guide and a midpoint commitment, and the New York line did worse on two and a half times normal volume. That pattern is consistent with a print that disappointed on composition rather than on the headline. The items a seller could point to were all on the first pages of the release: Liquids down 4.4%, a second leverage print above the range, and no Line 5 update. Intraday market commentary grouped Enbridge with the banks in a broad mid-session selloff; the index recovered to close higher and Enbridge did not.

The larger move happened before the print. Over three months the shares lost 11.7% while the Toronto index gained 1.1%, and the move was not unique to Enbridge: a Canadian midstream group of TC Energy, Keyera and Pembina lost between 2.5% and 14% over the same window. Enbridge-specific events accounted for part of it. The deal-and-equity session cost 3.7%, roughly a point and a half more than the peer average, and the offering then set a C$66.85 reference price that the stock has traded around since, with a low close of C$65.43 on October 7 and a close of C$69.11 on October 30.

What the market has done, in effect, is price the equity issue, the leverage and the Liquids weakness into a multiple of 11.2 times guidance-midpoint distributable cash flow per share, against 12.4 times when we initiated in May and 12.9 times in August, on the same 2026 midpoint. The yield moved from 5.29% to 5.09% to 5.87% across our three notes. On the November 5 session, when the S&P 500 fell more than 4%, the stock fell 1.0%; that is the defensive behaviour an investor in this name is paying for, and it is now available at a lower price than at either of our previous notes.

Street Perspective

Debate: Is the De-Rating an Entry Point or a Warning?

Bull view: A 5.87% yield on a 66% payout of guided distributable cash flow, at 11.2 times the guidance midpoint, from a company that just grew adjusted EPS, committed to the midpoint of guidance and is on track for its 21st consecutive year of meeting it, is the cheapest this franchise has been at any of our three notes. Several desks moved to buy-equivalent ratings around the September offering, and the post-offering target set sits entirely above the reaction-day close.

Bear view: The stock de-rated for reasons, not by accident. The company issued equity, kept leverage above its range for a second quarter and guided to a third, lost a chief executive, and reported a Liquids decline on its largest asset. A cheaper multiple on a business that needs outside capital to grow is not obviously a better risk-reward than a fuller multiple on one that did not.

Our take: The bull has the better of it this time, by a clear margin. The bear's list is real but mostly priced: the equity is issued and the overhang is gone, the leverage was already our materializing risk at a higher price, and the succession is internal. What the bear cannot explain is why a quarter with the best growth in our coverage should sit at the lowest multiple of our three notes. We set a 5.75% to 6% yield as the upgrade condition in August precisely so that we would not have to re-argue the business case when the price arrived. It has arrived.

Debate: Does the Equity Raise Break the Self-Funding Story?

Bull view: The equity funded acquisitions, not the organic backlog, and was priced only 3.5% below the prior close. Partner capital at Westcoast adds funding beyond the C$10B to C$11B base capacity, and the company is now pre-funded for the Tallgrass close with C$11.8B of liquidity. Self-funding of the organic programme is intact.

Bear view: Capital spending is running at a C$12.1B annual pace including maintenance, roughly C$11.2B without it, at or above the company's own stated growth capacity, while debt sits above range. The Westcoast partner holds contingent distribution rights tied to construction delays and regulatory outcomes. And the offering explicitly reserved part of the proceeds for "future growth opportunities", which is organic growth by another name.

Our take: The bear is right on the definition and the bull is right on the consequence. The organic programme is no longer funded purely from retained cash flow and debt capacity; it now leans on partner capital and, at the margin, on surplus common equity. But the dilution was 2.05%, the acquisitions are accretive on the company's own account, and the alternative was a leverage ratio well above 5.0x. We keep Bull 2 at risk rather than broken.

Debate: Does the Mainline Decline Matter if Gas Carries the Growth?

Bull view: The gas businesses grew by more than the whole company this quarter, and their growth comes from rate cases and in-service projects that annualize. The Mainline is apportioned, and the downstream expansions monetize that scarcity through Mainline entitlements. An Alberta and federal agreement would reopen upstream expansion, and the regional oil sands system has prebuilt capacity to capture the first wave.

Bear view: Liquids is still half of adjusted EBITDA and it is down 5.7% over nine months. A segment that size shrinking at that rate needs the gas businesses to grow at double digits indefinitely to deliver 5% consolidated growth, and the upstream catalyst depends on a political timeline that oil sands executives are already prepared to let slip.

Our take: The bear's arithmetic is right for 2026 and wrong for the medium term. The Liquids decline traces to three things: Line 9 tolls and Gulf Coast market access, both of which have now been in the comparison for three quarters, and a volume dip the company would not size. The gas growth is structural. We would want the Liquids decline to narrow in the fourth quarter, and we have written that into the triggers below.

Debate: Does a Utility Chief Executive Change the Capital Allocation?

Bull view: The successor ran the best-performing segment, integrated the U.S. utility acquisition, and was involved in each of this quarter's deals. The board ran a multi-year process and chose continuity. Nothing about the dividend, the leverage range or the 5% outlook is in question.

Bear view: A transition in the same fortnight as three acquisitions and a share issue leaves the incoming chief executive inheriting a balance sheet above its range and a capital programme above its stated capacity, with an investor day promised but not dated. Every new chief executive is tempted to reset expectations, and the first reset is rarely upward.

Our take: Continuity is the base case and we do not expect a guidance reset. The investor day is the risk event: if it restates the 4.5x to 5.0x range with a dated path back inside it, the equity re-rates; if it adds capital to the programme without one, the leverage pillar gets worse. We treat it as a catalyst in both directions and do not need it to underwrite the rating.

Model Update & Valuation Framework

Valuation: At C$66.14 the shares trade at 11.2 times the C$5.90 guidance-midpoint distributable cash flow per share and 11.3 times our C$5.85, with a 5.87% dividend yield. On the same 2026 midpoint basis the multiple was 12.4 times when we initiated in May and 12.9 times in August, so the de-rating is a like-for-like 13% compression rather than an artefact of rolling the estimate year. On our new 2027 estimate of C$6.10 the shares trade at 10.8 times. At constant multiple, a 5.87% yield plus approximately 5% guided growth is roughly 10.9%, already above the roughly 10% total return we described as market-like at initiation. A return to the 12.4 times at which we initiated, applied to the 2026 midpoint, gives C$73.16, 10.6% above the reaction-day close; 12.0 times our 2027 estimate gives C$73.20. We use C$73 as our twelve-month value, which with the dividend implies a total return of roughly 16%.

What changes the call. Back to Hold, any one of: a fourth-quarter adjusted EBITDA result that puts the full year below C$20.3B; a fourth-quarter debt-to-EBITDA figure above 5.2x, or a first-quarter 2027 figure above 5.0x after the acquisitions close, since that is the run-rate test management set itself; a further common equity issue within twelve months that is not tied to an announced acquisition; a fourth-quarter Liquids decline of more than 6%; or a re-rating to C$73 without an increase in our estimates, at which point the upside is consumed. To Underperform, the conditions from August stand unchanged: a leverage print above 5.0x without a currency or acquisition explanation, a reversion to operating-segment declines masked at the corporate line, a large Michigan tunnel estimate, an adverse Ontario decision on equity thickness and depreciation, or a full-year outcome below the C$20.2B floor. If a Hold trigger and a midpoint delivery arrive together in February, the Hold trigger governs: this upgrade is a valuation call, and it does not survive a balance sheet that misses its own run-rate promise.

August Triggers and Commitments, Graded

Thesis Scorecard Post-Earnings

Overall: The thesis is modestly stronger on the business and unchanged on the balance sheet, and the price has moved a long way in our favour. The gas businesses answered the question we asked in May about whether the assets can grow without help from treasury, and adjusted EPS turned positive. The Mainline moved back to a watch item and the self-funding pillar showed its boundary, which together explain why the market de-rated the stock. One bear point moved the wrong way, one bull pillar was challenged without changing its tag, and the remaining five held. None of that is worth a 13% compression in the multiple on the same earnings year.

Action: Upgrade to Outperform. In August we said a de-rating to a 5.75% to 6% yield would change the call, and that the case for revisiting toward Underperform was a second consecutive leverage breach without a currency explanation. The first condition has been met and the second has not, and we are honouring the trigger rather than arguing around it. At 11.2 times guidance-midpoint distributable cash flow per share and a 5.87% yield, we expect the shares to beat the market over twelve months on income and a partial re-rating toward C$73, with the fourth-quarter midpoint delivery, the BC toll settlement and the downstream Mainline decisions as the catalysts. The risk we are being paid to carry is the balance sheet; the test is whether leverage moves inside the range on the run-rate basis management has promised once the acquisitions close.