The Champlain Hudson Power Express started commercial operation on 13 May 2026. It is a 1,250 MW high-voltage direct current line running from the Québec border to Astoria in Queens, and it carries Unforced Capacity Deliverability Rights that allow its rightsholder, H.Q. Energy Services (U.S.), to sell capacity inside the New York City locality of the NYISO market. Its effect on summer prices has already been reported: the city's spot capacity price fell from $32.53/kW-month in June to $12.41 in July, the first month the line's rights were counted.
The winter is more complicated, and the auctions held in the past four weeks show how. Under a one-time set of rules that FERC accepted on 24 August, NYISO is running two different capacity requirements for New York City this winter. In November, March and April the market assumes the line delivers its full 1,250 MW. From December to February it assumes zero. TEI pulled every strip, monthly and spot auction result from NYISO's public ICAP site for May 2023 to the present and compared them with the parameters in NYISO's filings. The data and scripts are saved with this article.
How the rule came about
NYISO's tariff has a mechanism for large new resources, which it calls Triggering Resources. When one is expected to enter the market, NYISO publishes two sets of capacity parameters for the year: one that assumes the resource is participating (for CHPE, the "CHPE-In" set) and one that assumes it is not ("CHPE-Out"). The two sets differ mainly in the Locational Minimum Installed Capacity Requirement for the city, the share of New York City's forecast peak load that must be covered by capacity located in or deliverable to the city. For 2026-27 that requirement is 86.4% of peak with CHPE in and 82.6% with CHPE out.
The difference matters because NYC's peak load forecast for the year is 11,061.9 MW. At 86.4% the minimum installed capacity requirement is 9,557.5 MW. At 82.6% it is 9,137.1 MW. Counting the line raises the city's requirement by about 420 MW and adds 1,250 MW of supply against it.
NYISO notified the market on 3 March that CHPE-Out parameters would apply from May. In January it had told its Installed Capacity Working Group that the switch to CHPE-In would follow once the rightsholder gave notice, with a 10 May deadline for July. The rightsholder's notice arrived in time, and the July spot auction ran on CHPE-In parameters. Without further action those parameters would have stayed in place through April 2027.
The problem was Hydro-Québec's winter. In a protest filed at FERC in March in Docket ER26-1431, HQUS described Hydro-Québec as "a strongly winter-peaking utility" whose export supplies are plentiful in summer "but much more limited in the winter, especially the peak winter months of December, January and February." It also told FERC that "in the near future, the peak-month available capacity from all of [Hydro Quebec] may be zero MW, despite a shoulder month availability of potentially more than 1,000 MW." NYISO's 25 June filing in Docket ER26-2959 added a plainer fact: HQUS supplied 0 MW of capacity to New York in each of the peak winter months of December 2024 to February 2025 and December 2025 to February 2026.
The New York State Reliability Council had already assumed 0 MW from CHPE in winter when it set the 2026-27 statewide installed reserve margin, and NYISO's draft 2026 Reliability Needs Assessment, released on 1 October, does the same: the line "is assumed to be providing its planned capability in summer periods, but not in winter."
What FERC accepted
NYISO's filing argued that running the CHPE-In requirement through December to February would set the city's minimum requirement against 1,250 MW of supply that was unlikely to show up. Pointing to the May and June spot auctions, which cleared with less than 10 MW of excess above the CHPE-Out requirement in each month (5.2 MW in May and 8.0 MW in June, by the auction summaries), the ISO said a requirement 3.8 percentage points higher "poses a material risk of producing artificial deficiencies in meeting the minimum capacity requirement for New York City."
Its fix, which FERC accepted in an order dated 24 August (196 FERC ¶ 61,154), effective 25 August, has two parts. The city's requirement drops to the CHPE-Out level of 82.6% for December 2026 through February 2027 only. And because the demand-curve formulas assume one requirement across a whole capability period, NYISO recalculated the city's winter reference point price so that the hypothetical new peaking unit used to set the curves (a 200 MW, two-hour battery this year) would still recover its annual revenue requirement across the year.
The result was a winter reference point price of $10.18/kW-month for the city, up from an earlier proposal of $8.81. NYISO's own revenue check, presented to its Management Committee on 29 April, shows the expected price at the tariff's prescribed level of excess would be $9.72/kW-month in the three shoulder months and $7.09 in the three peak months. The other localities keep a single requirement all winter and got lower winter curves, which the filing attributes to "the shrinking difference in the expected seasonal availability of capacity supply following the introduction of the CHPE UDRs."
Most changes to NYISO's capacity design go through a long stakeholder process. This one was described in the filing as "a one-time set of adjustments that apply only for the 2026-2027 Winter Capability Period."
What the auctions have priced so far
NYISO's capability-period strip auction for the winter ran from 29 September and posted on 2 October. New York City cleared at $8.02/kW-month for the six months, against $6.40 a year earlier. The rest of the state cleared at $3.50, up from $2.71. On a strip basis the city's winter price rose 25% in the first winter with CHPE in service.
The monthly auction posted on 14 October shows how the strip averages out. Every NYISO monthly auction sells the coming month and each remaining month of the capability period, so the November auction priced six months at once:
- November: NYC $2.73, rest of state $2.72
- December: NYC $8.24, rest of state $4.04
- January: NYC $9.75, rest of state $4.75
- February: NYC $9.75, rest of state $4.75
- March: NYC $5.21, rest of state $2.97
- April: NYC $4.56, rest of state $2.30
The city's premium over the rest of the state is $0.01 in November and $5.00 in January and February. The January price is 3.57 times the November price. March and April, which are also CHPE-In shoulder months, sit between the two, at a premium of about $2.25.
November is the clearest change. In the November monthly auctions of the previous three years, the city cleared at $13.04 (2023), $8.52 (2024) and $6.15 (2025), against rest-of-state prices of $3.66, $1.01 and $1.90. A one-cent gap means the city's locational requirement was not the binding constraint in that auction for that month. Imports from the Hydro-Québec control area cleared 600 MW in the rest-of-state market for November in the same auction, and none for any later month.
The forward months are thinly traded. Only 53 MW cleared for New York City in January and February, against 609 MW for November. Most capacity for each month is settled in the spot auction held a few days before the month begins, and NYISO's calendar shows the offer window for the November spot auction closed on 27 October, with results due this week. The monthly results are best read as the market's expectation rather than a settlement price.
The size of the switch
The arithmetic behind the December step is simple, and it is the number TEI used to read the monthly results. Moving from the shoulder-month requirement to the peak-month requirement cuts the city's minimum installed capacity requirement by 420.4 MW (9,557.5 MW less 9,137.1 MW). Removing the line takes away 1,250 MW of supply. On 1 December the city's headroom above its requirement falls by roughly 830 MW in installed capacity terms, compared with November, before any change in the rest of the fleet. The figure ignores the conversion from installed to unforced capacity and any change in winter ratings of in-city generators, so it is an approximation, but its direction does not depend on those details.
For comparison, in the four summer spot auctions since CHPE was counted, the city cleared between 854.6 MW and 868.2 MW above its requirement, or about 10.2%. Dividing the reported excess by the reported percentage gives an implied city requirement of about 8,476 MW of unforced capacity in each of those months. A swing of 830 MW is roughly the size of the entire summer surplus.
The forward prices for January and February also sit above NYISO's own expectation. The ISO's revenue-sufficiency check assumed $7.09 in the peak months at the prescribed level of excess. The monthly auction has priced $9.75, which on the city's demand curve implies less excess than NYISO assumed. Whether spot prices land there depends on how much in-city capacity offers in December, and on whether NYISO's lower requirement leaves enough room. NYISO's stated aim was to avoid a repeat of May and June, when the city cleared within single megawatts of its requirement and the spot price reached $32.59.
Summer, in retrospect
The CHPE-Out months were expensive. New York City's spot price averaged $32.56/kW-month in May and June 2026 and $12.44 from July to October, by TEI's calculation from the posted spot results. Over the full summer capability period the average was $19.14, against $15.66 in summer 2025, a rise of 22%. Over July to October alone, the city's price was 21% below the same months of 2025, when it averaged $15.77.
The city's premium over the rest of the state followed the same pattern: $24.67 in May, $24.66 in June, then $8.27, $7.82, $6.42 and $6.60 from July to October. Rest-of-state prices rose through the summer as the city's fell, from $4.14 in July to $6.00 in October.
What it means for planning
None of this changes the longer outlook for the city. NYISO's draft 2026 Reliability Needs Assessment finds a transmission-constrained deficiency in New York City starting in summer 2032, about 400 MW for seven hours that year and about 1,850 MW for fifteen consecutive hours by summer 2036, with a winter deficiency of about 800 MW for sixteen hours in 2036. The assessment attributes the near-term margin to the retained Gowanus and Narrows barges and to CHPE, and the shrinking margin to load growth and the planned retirement of NYPA's small gas plants after 2030. Because it already models CHPE at zero in winter, the RNA's winter finding is not affected by how the capacity market treats the line this season.
The capacity rule FERC accepted applies only to the 2026-27 winter. A separate set of winter reliability changes to the capacity market, filed in February in Docket ER26-1431, was accepted by FERC on 26 June and took effect on 28 June.
NYISO will post the November spot results before 1 November and the December spot auction late in November. The December result will be the first settled price under the peak-month requirement.