Fortis is a regulated utility compounder whose equity is a claim on roughly seven percent annual rate base growth funded by a record five year capital plan, delivered through formulaic cost recovery across five Canadian provinces and ten U.S. states.
The most consequential recent development is the British Columbia provincial approval of the Tilbury Phase 1B liquefied natural gas expansion, an order in council that authorizes a cost allowance of up to $2.2 billion and folds the project and its marine jetty into FortisBC Energy's regulated rate base. The mechanism is decisive: the allowance caps the cost Fortis can recover, the jetty inclusion brings marine fueling infrastructure inside the regulated return, and customer protection mechanisms transfer the rate risk to the utility. For shareholders the consequence is new rate base that was entirely absent from the five year plan, adding a potential second growth pillar in Canada alongside the existing U.S. transmission story.
The central tension is that first half 2026 EPS of $1.76 came in flat year on year, and most of the promise sits in rate cases that have not yet converted into rates. The TEP general rate application carries a November 2026 target and the MISO transmission incentive question sits with FERC. The first quarter results already slipped a cent against the year earlier, which is the drag these pending decisions have to overcome.
The catalyst window is late 2026, when three decisions land close together. The FERC ruling on the competitive bidding complaint, the TEP rate order, and the FortisAlberta PBR appeal decision each resolve a distinct piece of the near term uncertainty.
Fortis operates ten regulated utilities plus a 39 percent stake in Wataynikaneyap Power, with roughly two thirds of its assets in the United States and a third in Canada after selling its Turks and Caicos and Belize interests in 2025. The portfolio spans interstate electric transmission under FERC jurisdiction at ITC, integrated electric and gas distribution at UNS Energy in Arizona, electric and gas at Central Hudson in New York, gas transmission and distribution at FortisBC Energy, electric distribution at FortisAlberta, and smaller integrated utilities in eastern Canada and the Cayman Islands.
The 2026-2030 capital plan is the largest in company history. The plan totals $28.8 billion, roughly $2.8 billion above the prior five year budget. The profile is one management labels low risk and highly executable, because only a fifth is major capital projects.
Geography concentrates the plan in North American load corridors. 63 percent of spend lands in the U.S. and 34 percent of the total sits at ITC. The Canadian businesses supply the LNG and gas transmission upside that the U.S. plan does not capture, which is why the mix between the two footprints matters more than any single year's numbers.
The strategic model is a small holding company in St. John's that funds capital growth through regulated debt and dividend reinvestment while each subsidiary runs its own management team and a majority independent board. That structure buys regulator goodwill and local credibility, and it keeps corporate overhead negligible, but it also means the holding company is a pass through for whatever the subsidiaries earn, so value creation is entirely a function of rate base growth and the returns allowed on it. The strategic pivot to write down is the arrival of load growth as a structural variable rather than a seasonal one. Data centers, electrification, and manufacturing are reshaping the investment case for regulated utilities, and Fortis is positioned at the intersection of two of the strongest corridors, MISO region transmission in the Midwest and Arizona load growth.
The product is a regulated franchise, and the moat is the rate base itself, a stock of customer funded assets that earns an allowed return and is protected from competition by territorial exclusivity. ITC operates high voltage transmission across eight midwestern states and sits on the first tranche of the MISO long range transmission plan, the federally mandated regional plan that pays for new transmission to relieve congestion and serve new generation. That placement converts regulatory uncertainty into an asset backlog with FERC level pricing.
FortisBC Energy holds the Tilbury LNG facilities in British Columbia, a coastal storage and liquefaction complex that is becoming the anchor of a marine fueling strategy for the Port of Vancouver. The Phase 1B expansion approved in July 2026, the storage tank expansion under environmental review, and the Eagle Mountain gas pipeline make British Columbia a genuinely differentiated position, one where the regulated gas infrastructure carries upside that the five year plan understates. The marine jetty inclusion in the Phase 1B approval matters because it pulls port infrastructure into the regulated rate base for the first time, giving the utility a regulated return on assets that pure LNG players do not have access to.
At UNS Energy, the technology story is storage and generation conversion. The Roadrunner Reserve II battery came into service in June 2026, a 200 megawatt facility. It is sized to serve roughly 42,000 homes for four hours at full deployment, which makes it one of the largest utility scale storage assets in Arizona. The Springerville coal to gas conversion, approved in March 2026, extends the life of an existing station while cutting emissions. A third party gas pipeline arrives in 2029. It carries 1.9 billion in 25 year purchase commitments, underwriting the Arizona buildout and converting the planned capacity into contracted cash flow.
The real moat is not any single asset but the regulatory architecture: formulaic rate mechanisms in Arizona, performance based regulation in Alberta, cost of service with cost recovery adjustors in New York, and FERC formula rates for transmission. Each mechanism narrows the gap between incurred cost and recovered cost, which is what makes rate base growth compound rather than erode.
For 2025, Fortis reported revenue of $12 billion. Common equity earnings of $1,714 million work out to $3.40 per share. That is up from $3.24 a year earlier. Adjusted EPS rose $0.25 to $3.53 after stripping out disposition losses and a retroactive MISO rate of return adjustment. The year set records on both operating cash flow and capital spending, with the latter funding the fastest rate base growth in company history.
First half 2026 shows the compounding still working, at a modest pace. Revenue of $6,334 million rose 3 percent on a year ago of prior period basis. EPS of $1.76 was flat, with the first quarter slipping a cent and the second quarter rising two cents. The drivers are familiar: rate base growth at ITC and Central Hudson, warmer weather lifting UNS Energy retail sales, and offsetting items from the 2025 dispositions and a weaker U.S. dollar. The flat print is the expected consequence of spending ahead of rate recovery, not a break in the compounding trend.
Segment earnings for 2025 show ITC at $592 million. UNS Energy contributed $437 million, and Central Hudson added $191 million. ITC earnings for the first half of 2026 reached $305 million, modestly above the prior year figure. The pattern is a broad based rate base story with no single utility carrying the growth. Central Hudson's 49 percent jump came from the July 2024 cost rebasing and a new delivery rate structure approved by the New York Public Service Commission, which lifted the utility's earnings base without a change in service territory or customer count.
The dividend is the financial anchor: 52 consecutive years of increases. The annual payment reached $2.49 per share in 2025. The fourth quarter raise lifted the quarterly payment to $0.64, a 4.1 percent increase. The payout ratio sits at roughly 70 percent of adjusted EPS. Management has guided dividend growth to 4 to 6 percent annually. The credit ratings sit at S&P A- and Fitch BBB+ with stable outlooks. That combination of a long dividend track record and investment grade credit makes the payout the most predictable element of the capital structure.
The five year plan projects midyear rate base from $42.4 billion in 2025 to a substantially larger level by the end of the decade. That is a compound annual growth rate of 7.0 percent, and ITC carries the largest absolute increase in the portfolio over that span. Beyond the plan, ITC has identified a 3.3 billion to 3.8 billion U.S. dollar range of MISO tranche 2.1 projects. The projects are in Michigan and Minnesota, where rights of first refusal are in effect, with most of the spend landing after the plan horizon.
The data center opportunity at TEP is the most concrete above plan growth. The 300 megawatt energy supply agreement was approved by the Arizona Corporation Commission in late 2025. The initial phase of a data center campus is expected to be operational as early as 2027 and ramping through 2029. In the spring of 2026 the parties added a $40 million termination payment secured by a letter of credit, which de risks the customer commitment. Negotiations continue for the full build at the first site. A potential second site of 500 to 700 megawatts is also on the table, and TEP is fielding interest from manufacturing and mining customers. The significance of the termination payment is that it converts a signed but terminable contract into a funded obligation: if the customer walks, TEP collects the credit, and the associated generation and transmission investments are protected from being stranded.
The Tilbury 1B approval changes the Canadian math. The project carries up to $2.2 billion of allowable cost. Construction could start as early as mid 2027 and reach in service status by 2031. The project adds a gas and LNG growth pillar that was previously only a $350 million line item in the five year plan. The order in council also approves the equity partnership with the Musqueam Indian Band, which matters because it removes the land and community consent risk that has stalled similar coastal infrastructure in British Columbia, and it locks in customer protection mechanisms that limit how much of the cost lands in rates. The storage tank expansion adds a further $300 million of upside, contingent on the environmental review that continues through 2026.
Execution risk concentrates in three areas: the TEP rate case outcome targeted for November 2026, the FERC response to the competitive bidding complaint, and the FortisAlberta PBR appeal decision due in Q3 2026. An unfavorable landing on any of these would reduce the effective return on the capital already committed.
Regulatory lag is the core risk, and it concentrates at UNS Energy, where the Arizona regulator has historically used stale test years. The TEP general rate application filed in June 2025 seeks formulaic rates, but the Residential Utility Consumer Office challenged the commission's authority and the Arizona Court of Appeals allowed that challenge to proceed in November 2025. If formula rates fail, the utility falls back on adjustor mechanisms that recover costs more slowly, compressing the return on the Arizona rate base during the transition. The practical consequence is that the Arizona rate base, the largest single growth engine after ITC, earns a below allowed return until the next rate case closes the gap, which is exactly the drag visible in the flat first half 2026 EPS.
The MISO transmission incentive question cuts both ways. FERC's 2021 supplemental notice proposes eliminating the 50 basis point rate of return adder for long standing RTO members, a change that would directly reduce ITC's allowed return. Every 10 basis point move shifts Fortis EPS by roughly $0.01. A full 50 basis point cut would therefore remove about $0.05 of annual EPS. The April 2026 complaint by ITC and other transmission owners asks FERC to exempt certain projects from competitive bidding or suspend solicitations for five years. The agency's response, requested by September 2026, is the largest binary catalyst in the thesis. A favorable ruling also expands the above plan backlog, since more projects flow to the existing RTO owner rather than to competitors.
Physical and wildfire risk remains a standing exposure across the western and mountainous service territories, particularly in British Columbia and Arizona. S&P revised the outlook from negative to stable in November 2025, explicitly citing progress on wildfire risk mitigation at the subsidiaries, which signals that the rating agencies are watching this variable. A major weather event would pressure earnings and could accelerate capital spending in ways that outpace rate base growth.
Currency risk runs the other direction: 58 percent of revenue is U.S. dollar denominated while the company reports in Canadian currency. A five cent move in the exchange rate shifts the five year capital plan by roughly $0.7 billion. The same move shifts rate base by $1.4 billion. The 2026 average exchange rate of 1.38 already compressed reported earnings growth by a meaningful amount. The prior year rate of 1.41 shows the direction of the drift. A stronger Canadian dollar is therefore a silent tax on the compounding story, and it deserves as much monitoring as the rate cases themselves.
Fortis trades at C$54.48 for a market capitalization of roughly $27.8 billion. On GAAP EPS of $3.40 that is a trailing price to earnings of about 22 times. On adjusted EPS of $3.53 it is closer to 19 times. For a regulated utility with 7 percent rate base growth, the multiple sits modestly above the historical range of large North American utilities. The premium reflects the data center and MISO optionality.
In a bear case, the MISO adder is removed, TEP formula rates fail, and the Tilbury projects stall. Earnings growth drops to the low single digits and the multiple compresses toward 17 times. Total shareholder return over five years lands near 4 percent annualized, roughly matching the 3.4 percent dividend yield plus a cent of price appreciation.
The base case holds the plan: rate base compounds at 7 percent, the dividend grows 5 percent, and the multiple is unchanged. The share count and payout ratio keep EPS growth tracking the dividend at roughly 5 percent. The result is about 10 percent annualized total return, or a price near C$75 by the end of the decade. That is a 20 times multiple applied to 2030 EPS. The arithmetic is straightforward enough that the base case does not depend on any single variable moving in Fortis's favor.
The bull case adds the MISO tranche 2.1 awards, the 600 megawatt data center build, and Tilbury 1B into the rate base. Rate base growth accelerates toward 8 to 9 percent. EPS reaches the low $5 range by the end of the decade. A re rate to 22 times produces a price near C$100. The total return works out to roughly 14 percent annualized. The spread between bear and bull is the MISO outcome and the data center ramp.
Fortis is not a stock that offers a cheap entry; it offers a verifiable compounding machine with a 52 year dividend record and a capital plan that has a named project, a named regulator, and a named approval date for every major piece. The question is not whether the company can execute the plan, it has a track record, but whether the returns allowed on the new rate base match the returns already priced in.
The honest answer is that the multiple already assumes most of the plan works. The MISO tranche 1 projects are in the plan. The 7 percent rate base growth is the plan, and the 52 year dividend streak is the plan. What is not priced in is the above plan growth: the 3.3 billion to 3.8 billion U.S. dollar MISO tranche 2.1 package, the data center ramp beyond 300 megawatts, and the Tilbury LNG expansion. That optionality is what justifies the trailing multiple, and it is what the FERC decision in September and the 2027 data center load validate or invalidate.
The counter case is straightforward: if FERC removes the RTO adder and TEP loses on formula rates, the effective return on the Arizona and MISO rate base drops, the dividend growth guidance gets pulled toward 4 percent, and the multiple compresses to match. In that scenario the stock is a 3.4 percent yielder with modest capital appreciation, plain but not broken. The equity has enough asset quality behind the yield that even the bear case does not threaten the capital structure, which is why the downside is a multiple story rather than a solvency story.
The judgment is that Fortis is a fair value for the plan and a bargain for the optionality. The risk is not execution, it is regulatory outcome, and the near term catalysts in the next two quarters resolve most of that uncertainty. A portfolio that can hold a five year compounding commitment can use Fortis as a core regulated utility holding, with the MISO and data center upside functioning as free optionality rather than as the base case.