ENB Enbridge 10-Q 2026-09-30 section summaries

Enbridge Inc. — Q3 and nine months ended September 30, 2026

Amounts are Canadian dollars unless stated otherwise; unaudited. Figures in millions except per-share data.

Consolidated results

Revenue growth substantially reflected higher commodity sales, with corresponding commodity costs rising to $14,736 million in Q3 from $8,207 million, and to $49,979 million for 9M from $25,550 million. Total Q3 operating expenses were $18,939 million versus $12,368 million. Consequently, operating income declined in Q3 despite sharply higher revenue. Nine-month interest expense was $3,666 million, down from $3,777 million. The 2025 Gas Distribution and Storage results included a $330 million impairment following Ohio utility regulatory disallowances.

Reportable segments — nine months

Liquids Pipelines’ revenue increased substantially while its EBITDA fell. Gas Distribution and Storage, which includes primarily regulated public utilities, increased EBITDA.

Cash flow and investment

Capital expenditures on the company’s broader reported basis—cash spending plus the equity component of allowance for funds used during construction—were $9,040 million versus $6,041 million. Investing cash outflow was $9,585 million versus $7,187 million. Financing provided $4,183 million, compared with a $2,292 million outflow in 9M 2025; it included $5,717 million of debenture and term-note issuance, $1,080 million of repayments and $6,355 million of common dividends.

Balance sheet, funding and shares

Combined short-term borrowings, current long-term debt and long-term debt were $114,283 million at September 30, versus $105,024 million at year-end. Approximate tangible equity—total equity less goodwill and intangible assets—was $30,117 million. Cash and restricted cash totaled $5,143 million, up from $1,320 million at the start of 2026.

Committed credit facilities totaled $23,221 million, of which $16,309 million was drawn and $6,912 million available. Commercial paper and facility draws classified as long-term debt were $14.8 billion, up from $12.1 billion. Enbridge reported covenant compliance. It issued 44.735 million common shares at $66.85 each on September 14 for $3.0 billion gross proceeds, partly to fund the subsequent acquisition and otherwise for growth opportunities.

Business developments and contracted revenue

On October 9, after quarter-end, Enbridge acquired Salt Creek Midstream’s FS Crude for approximately $892 million (US$625 million). The roughly 500 miles of Delaware Basin crude-gathering assets are intended to connect Permian production with Enbridge’s Gray Oak and Cactus II pipelines and Ingleside Energy Center. Preliminary allocation included about $600 million of PP&E and $300 million of other net assets.

KKR, with Apollo-managed funds and affiliates, invested $729 million for all Class II units of Westcoast Expansion Financing LP and committed approximately $2.0 billion more for the Aspen Point and Sunrise Expansion programs. The investment is recorded as redeemable noncontrolling interest; Enbridge continues to operate the BC Pipeline system.

Revenue from unfulfilled performance obligations was $56.4 billion, including $2.6 billion expected in the remainder of 2026 and $8.9 billion in 2027. This excludes several significant revenue streams, including certain pass-through, variable, short-term and regulated revenues.

Risk management and other considerations

At September 30, the net derivative position was a $1,678 million liability, compared with an $823 million liability at year-end; the net foreign-exchange derivative liability was $1,616 million versus $1,104 million. Non-qualifying derivatives generated a Q3 unrealized fair-value loss of $270 million, compared with a $351 million loss in Q3 2025. Enbridge caps floating-rate debt exposure at 30% of total debt. Level 3 commodity derivative liabilities were $475 million current and $71 million long-term; valuations rely on less-observable forward prices and, for gas options, volatility. A $11 million cash-flow-hedge gain in AOCI was expected to be reclassified to earnings over the next 12 months.

Nine-month translation of U.S.-dollar debt designated as net-investment hedges produced a $525 million unrealized OCI loss, versus a $297 million gain in 2025. The nine-month effective tax rate was 23.4%, compared with 22.9%; cited factors included U.S. minimum tax, the absence of U.S. investment tax credits and rate-regulated tax accounting effects. Foreign-currency losses were $82 million for 9M, versus $366 million. Management cautions that interim results can be affected by seasonal gas demand and commodity-market conditions. Insurance coverage has exclusions and significant deductibles and may not remain available on acceptable terms; litigation and regulatory outcomes are uncertain, though management does not expect pending ordinary-course matters to materially affect results.

Enbridge — Q3 and nine months ended September 30, 2026

Consolidated performance

Reported earnings comparisons were significantly affected by non-operating items. In Q3, infrequent and non-operating factors added $529M to common-shareholder earnings; excluding them, earnings increased $77M. A principal factor was a non-cash unrealized derivative fair-value gain of $245M ($193M after tax), compared with a $394M loss ($299M after tax) in Q3 2025. Crude-inventory adjustments were also positive $66M ($51M after tax), versus negative $7M ($5M after tax). For 9M, non-operating items reduced earnings by $694M; excluding them, earnings decreased $71M. Derivatives recorded a $189M unrealized loss ($146M after tax), versus a $944M gain ($742M after tax) in 9M 2025.

At the EBITDA level, 9M non-operating items reduced results by $1.6B, mainly reflecting a $528M unrealized derivative loss versus a $962M gain in 2025. Excluding these factors, EBITDA increased $163M, primarily because realized foreign-exchange losses on hedge settlements were lower. These mark-to-market changes contribute to reported earnings volatility despite the company’s hedging objective of supporting stable long-term cash flows.

Segment EBITDA

Liquids Pipelines was pressured by lower Mainline volumes and Line 9 tolls, and reduced Market Access contributions from underutilized U.S. Gulf Coast contracts. Derivative and inventory items also affected comparisons. Gas Transmission benefited from the East Tennessee rate settlement, the Texas Eastern rate increase, favorable contracting and higher allowance for equity funds used during construction. Foreign-exchange translation helped Q3 results for both segments.

Gas Distribution and Storage’s Q3 growth reflected higher Utah and North Carolina base rates and Ontario distribution margin growth. Renewable Power Generation EBITDA increased $24M, mainly from Sequoia Solar Phase 1, which entered service in December 2025. In Eliminations and Other, Q3 non-operating factors added $457M, principally reflecting an $84M derivative gain versus a $397M loss; excluding those factors, EBITDA declined $29M, mainly due to higher realized FX hedge-settlement losses.

Cash flows, liquidity and financing

Higher capital expenditures drove the increase in investing outflows, partly offset by lower equity-investment contributions. The financing improvement reflected $2.9B of net proceeds from common-share issuance, higher net commercial-paper and credit-facility draws, and lower long-term debt repayments, partly offset by lower debt issuance.

At September 30, 2026, committed credit facilities totaled $23.221B: $16.309B was drawn or supported commercial paper, leaving $6.912B available. Net available liquidity was $11.8B, up from $10.8B at December 31, 2025; unrestricted cash increased to $4.9B from $1.1B, while available facilities declined to $6.9B from $9.7B. A further $776M was unused under $1.5B of uncommitted demand letter-of-credit facilities. Enbridge was in compliance with debt covenants. Working capital, excluding current debt maturities, improved to positive $2.5B from negative $2.8B, largely due to cash raised in partial pre-funding of the Tallgrass and Salt Creek crude acquisitions.

Nine-month long-term debt issuance was $3.0B and US$2.0B; coupons were 3.57%–5.10% on Canadian-dollar notes and 4.85%–5.45% on U.S.-dollar notes, with maturities spanning 2031–2056. Repayments were $955M, US$64M and €22M. Enbridge also redeemed $400M of 3.00% notes at par in May and renewed approximately $22.3B of credit facilities. In September it issued 44.735 million common shares at $66.85 per share for $3.0B gross proceeds. Enbridge said its 2025–2026 financing activities were expected to fund current capital projects and working capital through a potentially extended market disruption without requiring capital-market access. Enbridge Gas North Carolina issued US$500M of senior notes in October, maturing in 2036 and 2056. Approximately $5.7B of services, pipe and other materials is contracted for payment over the next five years.

Acquisitions and growth program

Enbridge agreed to acquire Tallgrass’s crude business for approximately $3.62B cash, subject to adjustments. The assets include 75% of Pony Express, 51% of Powder River Gateway, approximately 8.4 million barrels of storage across nine terminals, and Stanchion Energy. The transaction includes the approximately $0.4B PXP2 expansion, expected in service in 2027; closing was expected in Q4 2026, subject to approvals. In October, Enbridge acquired Salt Creek’s FS Crude for approximately $892M, adding about 500 miles of Delaware Basin gathering infrastructure and connections to Gray Oak, Cactus II and Ingleside. It also agreed to acquire substantially all Laramie Energy assets for $689M plus up to $92M in contingent payments, to expand Wexpro production and provide cost-of-service gas for Enbridge Gas Utah.

The commercially secured capital program includes the $4.0B T-South Expansion (Sunrise), under construction after approvals in April 2026; Woodfibre LNG, in which Enbridge has a 30% interest, with an estimated US$2.9B cost and construction underway; and the 25 Bcf Tres Palacios storage expansion, expected to enter service in stages from 2028–2030. Enbridge expects to invest about US$2.3B in Woodfibre and finance the balance with non-recourse project debt. T-North Birch Grove, estimated at $0.4B, received approval in September, with construction expected to start in Q1 2027. The 300 MW, fully contracted Cone wind project in Texas is estimated at $0.7B and targeted for 2027 service. KKR, alongside Apollo-managed funds and affiliates, invested $729M in Westcoast Expansion and committed approximately $2.0B toward Aspen Point and Sunrise expansions. Enbridge retains control and operates the BC Pipeline; KKR and Apollo are expected to hold a 29% indirect cumulative interest after Sunrise enters service.

Regulatory and legal matters

The BC Pipeline toll settlement expires in December 2026; interim tolls are expected to be filed in Q4 for January 2027 effectiveness, with a new settlement anticipated in early 2027. Enbridge Gas Ontario continues to appeal Phase 1 findings on depreciation, equity thickness and undepreciated capital. Enbridge Gas Ohio filed a rate-case stipulation proposing a US$145M annual revenue increase, 9.59% ROE and 52.87% equity thickness; approval was expected by Q1 2027, with rates effective March 1, 2027. FERC approved the East Tennessee rate settlement in August, with rates effective retroactively from November 1, 2025.

In the Line 5 Bad River Band case, the Seventh Circuit’s July 2026 ruling affirmed trespass on allotted parcels but rejected the nuisance claim and immediate shutdown. It remanded damages and injunction issues, vacated monitoring and shutdown requirements, and directed a remedy allowing reasonable time to complete the reroute. Enbridge’s rehearing petition was denied September 30; proceedings are expected to continue through 2027. The continuing trespass finding, possible restitution and future injunction remain material risks, although the ruling gives the company time to pursue rerouting.

For Dakota Access Pipeline, Enbridge has an effective 27.6% interest in the Bakken Pipeline System. The Army Corps’ May 2026 decision adopted conditions for continued operation, including groundwater monitoring and leak detection. A new Standing Rock Sioux Tribe lawsuit filed October 8 seeks to overturn agency approvals and shut down DAPL, leaving permitting and operating-continuity risk.

Enbridge identifies capital-market volatility as a potential funding constraint given its sizable growth program; it relies on operating cash flow, commercial paper, credit facilities and debt/equity offerings while seeking to preserve investment-grade ratings and diversified bank access. Some subsidiary cash may not be readily available elsewhere. Partnership guarantees of certain Enbridge notes and credit facilities contain liability limits and may be released in specified circumstances; Enbridge’s guarantees of Partnership notes end when the relevant debt is discharged or defeased.

Market Risk

Enbridge stated that its exposure to market risk had not changed materially since its 2025 Form 10-K. The detailed market-risk disclosures remain in Part II, Item 7A of that annual report; this section provides no new market-risk metrics or specific changes.

Controls and Procedures

As of September 30, 2026, management, including the CEO and CFO, concluded that disclosure controls and procedures were effective. During the quarter, no changes materially affected, or were reasonably likely to materially affect, internal control over financial reporting.

No material modifications were made to ENB’s previously disclosed risk factors. The company refers readers to the risk factors in its FY2025 Form 10-K and Q1 and Q2 2026 Form 10-Q filings. This section reports no new financial metrics, business risks, or strategic developments.

Q3 2026 — Insider Trading Arrangements

No Enbridge directors or officers adopted or terminated a Rule 10b5-1 trading plan or a non-Rule 10b5-1 trading arrangement during the quarter. Certain directors and officers participate in compensation and benefit plans involving Enbridge securities, including the 401(k) and directors’ compensation plans; elections made under those plans may qualify as trading arrangements.

This section reports no financial results or material business developments.