The power contract is now a ten-year lease

On 8 July 2026 the price of power for a data centre in Portland General Electric's territory went up while every other class the filing prices went down. The OPUC approved Advice 26-24 at a public meeting on 7 July 2026, and the company's Form 10-Q for the quarter ended 30 September 2026 records the result: an average rate decrease of 1.3% for residential customers, 2.1% for commercial customers and 1.4% for industrial customers who do not qualify for the new data centre rate, against an average rate increase of 29.7% for data centre customers. The same filing names the instrument behind the number. Oregon HB 3546, passed in June 2025, directed the OPUC to require an electric company providing service to a large energy use facility to “enter into a contract with the retail electricity consumer that covers the provision of the electricity service”, and the statute sets that contract at 10 years or longer with a minimum payment attached. A utility bill became a commitment a CFO signs.

Specify the duration of the contract and be for a duration for 10 years or longer.

01The commission writes the contract, the utility only bills it

Control sits with the commission. HB 3546 defines a large energy use facility as one that “uses or is able to use 20 megawatts or more” and is primarily engaged in a service under NAICS code 518210, the code for computing infrastructure, data processing and web hosting. Section 2 requires a tariff schedule “separate and distinct” from other commercial and industrial classes, with the cost of serving the class allocated to it or assigned directly to the consumer, and section 2(3) directs the commission to weigh whether the rates “result in, or have the potential to result in, increased costs or unwarranted risk to other retail electricity consumers”. The utility proposes; the commission disposes.

Three more terms follow from section 5. A contract must specify the date service begins. It must oblige the consumer to pay a minimum amount or percentage, as the commission determines, based on that consumer’s projected electricity usage, for the whole duration of the contract. It may carry “a charge for excess demand” on top of the tariff. PGE’s earnings exhibit lists the contractual protections in four words: “Capacity deposits”, “Collateral”, “Minimum demand requirements” and “Exit Fees”.

The obvious exit is closed. Section 5(4) preserves direct access, a green power rate, a voluntary renewable tariff and a special contract negotiated with the utility, then attaches a condition to all of them: such a contract “must meet the requirements and be consistent with the provisions of this section”. A site that takes transmission and distribution service from the utility falls inside section 5(1)(a) whatever it signs with a third party, because the service the statute covers includes “transmission, distribution, energy, capacity or ancillary electricity services”.

02The load slowed and the minimum payment did not

PGE’s third quarter exhibit, filed with the Form 8-K of 29 October 2026, cuts its 2026 weather adjusted load growth guidance from a range of 1.5% to 2.5% to a range of 1.0% to 2.0%, and in the same deck it says the approved tariff “creates regulatory certainty and enables margin expansion from PGE’s highest growth customer class”. The two statements are compatible once the contract is in view, and that is the finding. A minimum demand requirement and an exit fee attach revenue to the commitment rather than to the meter, so a utility can guide lower volume and still claim a margin from the class. PGE does not disclose how much of its contracted load sits under a minimum payment.

What is contracted is large and slow. PGE reports 473 MW of 2025 and 2026 executed contracts under construction with five data centre customers, up to 420 MW executed in 2026 and not under construction with energisation expected in 2028 and a ramp to full capacity in 2033, and a further 1.3 GW of large load requests to be energised from 2028. The first tranche is being built now. The rest is a promise dated 2028 and beyond, and the minimum payment is calculated on projected usage for capacity that does not exist yet.

03Contracts signed before the law are not grandfathered

Section 6 carries the obligation backwards, and it is the clause a general counsel should read first. Section 5 applies to a consumer that signed before the Act if service “requires the electric company to make significant investments or incur costs after the effective date of this 2025 Act that could result in increased costs or risks to other retail electricity consumers”. A site that contracted in 2023 and is still waiting for its substation meets that condition as written if the investment is significant and the risk to other consumers is real. The Act declares an emergency and took effect on passage, so there is no transition period to wait for.

04The utility collects, and so does every other class on its system

The gain is not the data centre’s. Every other class PGE reports received a cut, and the mechanism is the one Advice 24-38 proposed in December 2024, when the company set out to “allocate the costs to the customers that are creating the costs” and to adopt contractual requirements that “mitigate the risk of stranded assets”. The utility gets contracted revenue against capital it would otherwise build on a forecast, and the remaining classes get a smaller number on their bills. The loser is the developer that priced a site on a standard industrial tariff and a forecast, and the enterprise that assumed AI capacity is constrained only by chips.

The capital follows the class. PGE forecasts $7.4bn of capital expenditure as of 30 September 2026. Alliant Energy raised its four year capital forecast by 19% to $15.9bn for 2027 through 2030, against 3.4 GW of contracted data centre demand at its two utilities and peak demand it expects to grow by approximately 60% by 2031. Exelon has proposed $15.3bn of ComEd investment for 2028 to 2031 to meet load growth, with a proposed order from an administrative law judge posted on 14 October 2026 and an order expected by 15 December 2026.

05In PJM the collateral arrived without a statute

Exelon’s exhibit to its Form 8-K of 30 October 2026 reports that Large Load Adjustments submitted in 2025 and 2026 were fully approved by PJM, and that its 2027 submission “reflects enhanced commitment criteria” for about 11 GW of high probability load. At ComEd the advanced phases of design amount to about 9 GW, and roughly 45% of that load sits behind FERC-approved transmission service agreements “backed by ~$1.2B in collateral”. The same deck says FERC endorsed the framework “as a model for protecting customers, improving queue certainty, and enabling efficient large-load growth”. Queue position at that scale now sits behind money rather than a forecast.

The same shape of term is being assembled elsewhere in filings rather than in a statute. Alliant’s Wisconsin utility, WPL, is still seeking approval of its large load tariff, and the company lists as a risk “the ability to obtain regulatory approval with acceptable conditions for individual customer rates for large load growth customers”. NorthWestern Energy filed a Large New Load tariff rule proposal with the Montana Public Service Commission in March 2026 and states that in South Dakota large load customers “would require incremental capacity with infrastructure rider to provide generation cost recovery”. Black Hills serves Wyoming large load customers under the LPSC and BCIS tariffs, reports a pipeline of more than 3 GW, and is progressing toward definitive agreements on a 1.8 GW project in Cheyenne, with a financial plan that includes 600 MW by 2030 driven by Microsoft’s expansion and Meta’s new AI data centre.

06What the CFO signs and what the counsel reads first

• CFO, by 15 December 2026: re-forecast the 2027 power line with any minimum payment treated as a fixed charge for the full contract term, and state it as committed capital rather than a rate. Exelon expects an order from the Illinois Commerce Commission by that date on ComEd’s $15.3bn of load-growth investment, which is the next decision on who pays for capacity built for this class.
• General Counsel, by 15 December 2026: test every Oregon-sited agreement against section 5 before the next large-load contract is signed, including direct access and special contracts, because section 5(4) requires any such contract to meet the section. Then test contracts signed before June 2025 against section 6 wherever the utility is still investing in the site.
• Treasurer, by 15 December 2026: get the collateral and deposit figures in writing from each utility in the queue and fund them. Exelon’s disclosure of about $1.2bn behind roughly 45% of 9 GW of advanced ComEd load is the only public benchmark for the size of that number.
• COO, by 31 December 2027: do not count PGE’s up to 420 MW of executed but unbuilt load, or the 1.3 GW of requests behind it, as available capacity for a 2028 plan. PGE dates energisation from 2028 with full capacity in 2033, and a contract signed in November 2026 covers capacity that does not exist yet.

07What a board should put to management

The board’s decision is the 2027 capital plan, taken on 15 December 2026, when the CFO, the general counsel and the treasurer report and the Illinois Commerce Commission is expected to rule on ComEd’s $15.3bn: approve it only with every minimum payment carried as a fixed charge for the full contract term.

• Which of our AI capacity commitments sit in a jurisdiction with a separate data centre class, and what does each oblige us to pay if the load does not arrive?
• What is the term of each contract, and which of them run for 10 years or longer?
• How much collateral and deposit is posted, who can draw it, and what does it secure?
• Which contracts were signed before the class existed, and what capital has the utility still to spend on our site?
• If the minimum payment is a fixed obligation for a decade, why is the cost in the operating budget rather than the capital plan?

08What to watch, and when

• 15 December 2026: the Illinois Commerce Commission’s expected order on ComEd’s $15.3bn of load-growth investment.
• 30 June 2027: if no utility outside Oregon has a tariff in force by then that obliges a data centre consumer to pay a minimum amount based on projected usage, the lease reading fails and Oregon is a cost-allocation rule rather than the shape of the contract.
• 2 January 2028: section 3 of HB 3546 is repealed, removing the exemption that lets an Oregon company and a covered consumer stay outside the class while no tariff schedule is approved.
• 2028: PGE expects up to 420 MW of executed but unbuilt load to energise, ramping to full capacity in 2033, with 1.3 GW of requests dated from 2028.

09Primary documents

• Oregon House Bill 3546 (2025), enrolled, sections 2, 3, 5, 6 and 9.
• Oregon Public Utility Commission, Advice 26-24, approved at a public meeting on 7 July 2026 and effective 8 July 2026, as recorded in PGE’s Form 10-Q.
• Portland General Electric Company, Form 10-Q for the quarter ended 30 September 2026, filed 29 October 2026.
• Portland General Electric Company, Form 8-K, Exhibit 99.2, third quarter 2026 earnings presentation, filed 29 October 2026.
• Exelon Corporation, Form 8-K, Exhibit 99.2, filed 30 October 2026.
• Alliant Energy Corporation, Form 8-K, Exhibit 99.1, release of 29 October 2026.
• NorthWestern Energy Group, Form 8-K, Exhibit 99.1, filed 9 September 2026.
• Black Hills Corp., Form 8-K, Exhibit 99, release of 5 August 2026.