US Wholesale Electricity Prices 2026
By Axis Intelligence Research
Co-author: Aidan Jad | Last updated: September 2, 2026 | License: CC BY 4.0
Wholesale power at U.S. benchmark hubs averages $46.81 per megawatt-hour in summer 2026, down 5% year on year. Capacity is moving the other way. PJM’s 2028/2029 auction cleared at its $325/MW-day cap for a third straight year, and the same 100 MW of firm load now costs $12.01 million a year in PJM against $3.11 million in New England.
Quick Answer: What Do U.S. Wholesale Electricity Prices Look Like in 2026?
Energy prices are falling and capacity prices are not. The Federal Energy Regulatory Commission’s 2026 Summer Energy Market and Electric Reliability Assessment puts the load-weighted wholesale energy price across benchmark trading hubs at $46.81/MWh for summer 2026, a 5% decrease from summer 2025, with ERCOT (+11%), PJM (+5%) and SERC (+5%) the only regions rising.
Capacity markets tell the opposite story. According to Axis Intelligence Research, the annualized cost of holding one megawatt of firm capacity in PJM for delivery year 2026/2027 is $120,147, against $46,059 in MISO’s North/Central zones and $31,080 in New England — a 3.87-to-1 spread on what is nominally the same product. That spread, not the energy price, is now the largest controllable variable in siting a large load.
Key Findings
- According to Axis Intelligence Research, PJM’s Annualized Capacity Cost Benchmark (ACCB™) rose 11.2-fold in four delivery years, from $10,556 per MW-year in 2024/2025 to $118,625 per MW-year in 2028/2029.
- According to PJM Interconnection’s 2028/2029 Base Residual Auction Report, the auction cleared 138,317.8 MW of unforced capacity at the FERC-approved cap of $325.00/MW-day, leaving total procured capacity 6,831.3 MW below the RTO reliability requirement.
- According to the same report, PJM’s simulation of the auction without the price collar clears at $554.72/MW-day RTO-wide and $776.69/MW-day in ComEd, raising the cleared-megawatt value from $16.4 billion to $29.7 billion.
- According to the Federal Energy Regulatory Commission’s 2026 Summer Assessment, U.S. net summer capacity additions between October 2025 and September 2026 total roughly 75 GW, 78% above the five-year average, with ERCOT alone accounting for 25.6 GW.
- According to Axis Intelligence Research, annualizing MISO’s headline summer clearing price instead of its published annualized price overstates MISO capacity cost by a factor of 3.36 and reverses the PJM–MISO ranking — the single most common error in cross-RTO capacity comparisons.
How Much Does Wholesale Electricity Cost in the U.S. in 2026?
FERC staff, drawing on EIA Short-Term Energy Outlook data, forecast a load-weighted average of $46.81/MWh across benchmark hubs for June through September 2026. The regional dispersion inside that average is wider than the average itself.
| Region | Summer 2026 change vs summer 2025 | Direction | Source |
|---|---|---|---|
| Northwest | −41% | Down | FERC 2026 Summer Assessment |
| Southwest | −22% | Down | FERC 2026 Summer Assessment |
| MISO | −17% | Down | FERC 2026 Summer Assessment |
| ERCOT | +11% | Up | FERC 2026 Summer Assessment |
| PJM | +5% | Up | FERC 2026 Summer Assessment |
| SERC | +5% | Up | FERC 2026 Summer Assessment |
FERC expects the highest absolute summer prices in PJM, NYISO and ISO New England. The western declines trace to gas: futures at the Northwest Rockies hub and the PG&E Citygate were each expected to fall more than 30% year on year, and SoCal Gas Citygate 17%. Eastern hubs moved up — Algonquin Citygate, which serves Boston, was pricing at $3.29/MMBtu for the summer against $2.83 settled a year earlier, a 16% increase. Henry Hub itself was almost flat at $3.07/MMBtu, 1% below summer 2025.
The outlier is Waha, the Permian Basin point, trading at negative $1.26/MMBtu for summer 2026 against a positive $1.06 settled the summer before. That is a takeaway-capacity problem wearing a price tag.
Aidan Jad: A falling national energy average in a year everyone is calling a demand crisis looks like a contradiction until you separate the two products. Energy price is a fuel-and-solar story, and both went the buyer’s way this summer. Capacity price is a fixed-cost-recovery story, and that one is set by how much accredited megawattage shows up against a reliability requirement that data center interconnections keep pushing upward. Reading the $46.81 average and concluding wholesale power got cheaper is reading one line of a two-line invoice.
What Did PJM’s 2026 Capacity Auction Clear At?
$325.00 per MW-day of unforced capacity, RTO-wide, for delivery year 2028/2029 — the FERC-approved cap, hit for the third consecutive auction. PJM’s 2028/2029 Base Residual Auction Report, published July 14, 2026, records 138,317.8 MW UCAP cleared through the Reliability Pricing Model plus 10,863.8 MW committed under the Fixed Resource Requirement.
Every modeled Locational Deliverability Area — MAAC, EMAAC, SWMAAC, PSEG, PS-NORTH, DPL-SOUTH, PEPCO, ATSI, ATSI-Cleveland, ComEd, BGE, PPL, DAY, DOM, DEOK and JCPL — cleared at the same $325.00. Zero constrained LDAs, which means Capacity Transfer Rights carry no value for the delivery year.
PJM Base Residual Auction Clearing Prices, 2018/2019 to 2028/2029
| Delivery year | Clearing price ($/MW-day UCAP) | Cleared UCAP (MW) | Cleared MW × price ($bn) | ACCB™ ($/MW-year) | Source |
|---|---|---|---|---|---|
| 2018/2019 | 164.77 | 166,836.9 | 10.9 | 60,141 | PJM 2028/2029 BRA Report |
| 2019/2020 | 100.00 | 167,305.9 | 7.0 | 36,500 | PJM 2028/2029 BRA Report |
| 2020/2021 | 76.53 | 165,109.2 | 7.0 | 27,933 | PJM 2028/2029 BRA Report |
| 2021/2022 | 140.00 | 163,627.3 | 9.3 | 51,100 | PJM 2028/2029 BRA Report |
| 2022/2023 | 50.00 | 144,477.3 | 3.9 | 18,250 | PJM 2028/2029 BRA Report |
| 2023/2024 | 34.13 | 144,870.6 | 2.2 | 12,457 | PJM 2028/2029 BRA Report |
| 2024/2025 | 28.92 | 147,478.9 | 2.2 | 10,556 | PJM 2028/2029 BRA Report |
| 2025/2026 | 269.92 | 135,684.0 | 14.7 | 98,521 | PJM 2028/2029 BRA Report |
| 2026/2027 | 329.17 | 134,205.3 | 16.1 | 120,147 | PJM 2028/2029 BRA Report |
| 2027/2028 | 333.44 | 134,478.1 | 16.4 | 121,706 | PJM 2028/2029 BRA Report |
| 2028/2029 | 325.00 | 138,317.8 | 16.4 | 118,625 | PJM 2028/2029 BRA Report |
Clearing prices, cleared UCAP and cleared-MW-times-price: PJM 2028/2029 Base Residual Auction Report, Table 2, July 14, 2026. ACCB™ column: Axis Intelligence Research. Axis-calculated dollar figures are shown rounded to the dollar throughout this article and carried at full precision in the dataset.
According to Axis Intelligence Research, the four auctions from 2025/2026 onward have transferred PJM capacity pricing from a decade-long band of $28 to $165 per MW-day into a band of $269 to $334, and the shift is now durable across three separate auction cycles rather than a single tight year.
The Shortfall Behind the Cap
Two consecutive PJM auctions have failed to procure enough capacity to satisfy the reliability requirement. The 2027/2028 auction fell 6,516 MW short; 2028/2029 fell 6,831.3 MW short against a requirement that itself rose from 152,400 MW to 156,013 MW UCAP. PJM attributes 1,374.5 MW of that requirement increase to higher forecast load, “largely due to additional Large Loads.”
The auction cleared at a 14.4% RPM reserve margin against a 20.0% installed reserve margin target — 5.6 percentage points below the level PJM calculates as necessary for a one-day-in-ten-years loss-of-load expectation. PJM’s own tariff language makes this consequential: a Reliability Backstop Auction is triggered when three consecutive Base Residual Auctions clear more than one percentage point below the installed reserve margin. PJM announced it would seek FERC approval for a special Backstop Procurement in September 2026.
Supply is responding, slowly. Offered capacity rose 3,447 MW UCAP year on year to 139,594.6 MW. But new generation and uprates contributed only 524.7 MW UCAP of that — down from 774.3 MW the prior auction. Natural gas offered rose 5,550 MW UCAP, largely from accreditation-factor increases, coal-to-gas fuel conversions and units returning after must-offer exceptions, while coal offered fell 3,541 MW UCAP on planned deactivations.
Aidan Jad: Look at the new-build line, not the offered line. Offered capacity went up 3,447 MW; genuinely new steel accounted for 525 MW of it. The rest is accounting — better accreditation factors, a coal unit that now burns gas, a unit that skipped last year and showed up this year. Three consecutive auctions at the cap have produced roughly half a gigawatt of new capacity per cycle in a market of 138 gigawatts. Whatever the price signal is doing, it is not yet doing the thing capacity markets exist to do.
The Axis Annualized Capacity Cost Benchmark (ACCB™)
Capacity markets quote prices in units that cannot be compared. PJM publishes dollars per megawatt-day of unforced capacity. ISO New England publishes dollars per kilowatt-month. MISO publishes a seasonal price and a separate annualized price. Comparisons across these markets are made constantly, in siting decisions and in press coverage, and they are usually wrong.
ACCB™ — the Annualized Capacity Cost Benchmark — converts every capacity market’s published clearing price into a single unit: dollars per megawatt of capacity per delivery year.
ACCB = clearing price ($/MW-day) × 365 Where the market publishes $/kW-month: ACCB = price × 12 × 1,000 Where the market publishes seasonal prices: the market operator’s own published annualized price is used, never a seasonal price multiplied by 365.
Inputs. PJM: resource clearing price, 2028/2029 Base Residual Auction Report, Table 2. ISO New England: Forward Capacity Auction clearing prices, ISO-NE key market statistics. MISO: annualized Planning Resource Auction clearing prices, MISO 2026 Planning Resource Auction results.
Scope. The benchmark covers the three U.S. markets that publish a single administratively determined capacity clearing price for a defined delivery year. ERCOT is excluded because it runs no capacity market; FERC’s 2026 Summer Assessment records ERCOT relying instead on price-responsive demand during tight supply periods, so its capacity cost is structurally zero and its fixed-cost recovery arrives through energy scarcity pricing. NYISO is excluded because its capacity market clears through monthly and seasonal auctions rather than one forward price for a delivery year, and no single annual figure would be faithful to it. Publishing those two as blanks is more useful than publishing a number that means something different from the ones beside it.
Reproducibility check. PJM independently publishes its price collar in annual terms: $120,147/MW-year for 2026/2027 and $121,705/MW-year for 2027/2028. ACCB reproduces both to the dollar from the daily prices. The conversion is not a modelling choice; it is the same arithmetic the operator already uses.
ACCB™ by Market and Delivery Year
| Market | Delivery year | Published clearing price | ACCB™ ($/MW-year) | Cost of 100 MW firm load ($/year) | Source |
|---|---|---|---|---|---|
| PJM RTO | 2026/2027 | $329.17/MW-day | 120,147 | 12,014,705 | PJM 2028/2029 BRA Report |
| PJM RTO | 2027/2028 | $333.44/MW-day | 121,706 | 12,170,560 | PJM 2028/2029 BRA Report |
| PJM RTO | 2028/2029 | $325.00/MW-day | 118,625 | 11,862,500 | PJM 2028/2029 BRA Report |
| MISO LRZ 1–7 (North/Central) | 2026/2027 | $126.19/MW-day annualized | 46,059 | 4,605,935 | MISO 2026 PRA results |
| MISO LRZ 9 | 2026/2027 | $123.12/MW-day annualized | 44,939 | 4,493,880 | MISO 2026 PRA results |
| MISO LRZ 8 and 10 | 2026/2027 | $116.06/MW-day annualized | 42,362 | 4,236,190 | MISO 2026 PRA results |
| ISO New England | 2026/2027 | $2.590/kW-month | 31,080 | 3,108,000 | ISO-NE FCA 17 results |
| ISO New England | 2027/2028 | $3.580/kW-month | 42,960 | 4,296,000 | ISO-NE FCA 18 results |
| ERCOT | 2026/2027 | No capacity market | Not applicable | Not applicable | FERC 2026 Summer Assessment |
Published clearing prices as cited. ACCB™ and 100 MW columns: Axis Intelligence Research.
According to Axis Intelligence Research, for delivery year 2026/2027 the ACCB spread between the most and least expensive U.S. capacity market is $89,067 per MW-year — $8.91 million annually on a 100 MW load, before a single kilowatt-hour of energy is purchased. For delivery year 2027/2028, where PJM and ISO New England both have settled forward prices, PJM’s ACCB of $121,706 runs 2.83 times New England’s $42,960.
Why the Seasonal Trap Matters
MISO’s headline number in April 2026 was $424.30/MW-day for the summer season in Local Resource Zones 1–7. Multiply that by 365 and MISO appears to cost $154,870 per MW-year — 29% more than PJM. MISO’s published annualized price is $126.19/MW-day, giving an ACCB of $46,059, which is 62% less than PJM.
According to Axis Intelligence Research, the naive annualization overstates MISO’s capacity cost by a factor of 3.36 and inverts the ranking between the two largest U.S. capacity markets. MISO runs a seasonal construct under its Reliability-Based Demand Curve; summer carries the scarcity and the other three seasons do not. Any comparison that treats a summer price as an annual price is comparing a peak to an average.
Aidan Jad: This is the number that gets quoted wrong in board decks, and it gets quoted wrong in the direction that changes decisions. A site selection team told MISO is more expensive than PJM will site in PJM. The published annualized price has been sitting in the same MISO release the whole time, one paragraph below the headline. Read the second paragraph.
What Does Capacity Actually Add to a Wholesale Power Bill?
Converting ACCB into energy terms makes the comparison legible against the $46.81/MWh benchmark. A 100 MW load running at a 90% annual load factor consumes 788,400 MWh.
| Market (2026/2027) | ACCB™ ($/MW-year) | Capacity adder at 90% load factor ($/MWh) | Share of the $46.81/MWh summer benchmark | Source |
|---|---|---|---|---|
| PJM RTO | 120,147 | 15.24 | 32.6% | Axis Intelligence Research |
| MISO North/Central | 46,059 | 5.84 | 12.5% | Axis Intelligence Research |
| ISO New England | 31,080 | 3.94 | 8.4% | Axis Intelligence Research |
ACCB™ inputs as cited above. Benchmark energy price: FERC 2026 Summer Assessment, citing EIA STEO Table 7a.
One boundary on that last column. The $46.81/MWh figure is a national, load-weighted, summer-only average across benchmark hubs; the ACCB figures are market-specific and annual. The ratio indicates the scale of the capacity component relative to a typical energy price — it is not a PJM all-in delivered cost, and this dataset does not present it as one. Building an all-in number would require hub-specific annual energy settlements that are not yet published for the full delivery year.
How Much Did the Price Collar Suppress PJM Capacity Costs?
PJM runs a counterfactual with every capped auction, and the gap has widened every cycle.
| Delivery year | Actual clearing price | Simulated price with no cap or floor | Suppressed ($/MW-day) | Suppressed (ACCB™ $/MW-year) | Source |
|---|---|---|---|---|---|
| 2026/2027 | $329.17 | $388.57 | 59.40 | 21,681 | PJM 2028/2029 BRA Report |
| 2027/2028 | $333.44 | $529.80 | 196.36 | 71,671 | PJM 2028/2029 BRA Report |
| 2028/2029 | $325.00 | $554.72 | 229.72 | 83,848 | PJM 2028/2029 BRA Report |
Actual and simulated prices: PJM 2028/2029 Base Residual Auction Report, Appendix Table 2. Suppression columns: Axis Intelligence Research.
According to Axis Intelligence Research, the collar held back $83,848 per MW-year in the 2028/2029 auction — $8.38 million a year on a 100 MW load — and the suppressed amount has grown 3.87-fold in two auction cycles. In ComEd, where the unconstrained simulation clears at $776.69/MW-day, the implied uncapped ACCB reaches $283,492 per MW-year.
PJM’s own framing is worth quoting exactly as written: the simulation used the offers sellers actually submitted, and PJM states it does not know how those offers would have changed without the collar. That caveat is load-bearing. The counterfactual is a lower bound on price discovery, not a forecast of what an uncapped market would have produced.
Which Regions Are Actually Building New Capacity?
The supply response is real and it is concentrated in one market.
| Region | Net summer capacity additions Oct 2025–Sep 2026 (GW) | Retirements (GW) | Net (GW) | Source |
|---|---|---|---|---|
| ERCOT | 25.6 | 0.0 | 25.6 | FERC 2026 Summer Assessment |
| WECC excluding CAISO | 12.6 | 2.3 | 10.3 | FERC 2026 Summer Assessment |
| MISO | 10.8 | 3.2 | 7.6 | FERC 2026 Summer Assessment |
| CAISO | 7.0 | 0.0 | 7.0 | FERC 2026 Summer Assessment |
| SERC | 5.0 | 0.0 | 5.0 | FERC 2026 Summer Assessment |
| PJM | 4.8 | 1.8 | 3.0 | FERC 2026 Summer Assessment |
| SPP | 4.2 | 0.5 | 3.7 | FERC 2026 Summer Assessment |
| Rest of U.S. | 3.7 | 0.0 | 3.7 | FERC 2026 Summer Assessment |
| ISO-NE | 1.1 | 0.1 | 1.0 | FERC 2026 Summer Assessment |
| NYISO | 0.4 | 0.0 | 0.4 | FERC 2026 Summer Assessment |
According to Axis Intelligence Research, the three eastern capacity markets that pay the highest capacity prices in the country — PJM, ISO New England and NYISO — together account for 8.4% of U.S. net summer capacity additions this year, while ERCOT, which pays no capacity price at all, accounts for 34%. ERCOT’s 25.6 GW represents a 16% increase on its 2025 net summer capacity of roughly 158 GW.
Nationally, additions total about 75 GW, 78% above the five-year average. Retirements run 8.1 GW of nameplate capacity, 55% faster than the prior year, and 60% of that is coal with 38% natural gas. FERC notes what the megawatt totals conceal: solar, battery and wind additions do not replace thermal capacity one for one.
More than 4,300 MW of coal and gas capacity is still running under Department of Energy orders issued pursuant to section 202(c) of the Federal Power Act, including Eddystone Units 3 and 4 in Pennsylvania, Centralia Unit 2 in Washington, R.M. Schahfer Units 17 and 18 and F.B. Culley Unit 2 in Indiana, Craig Station Unit 1 in Colorado, and J.H. Campbell in Michigan.
Why Are Wholesale Prices Rising When Retail Prices Rise Faster?
ISO New England publishes the cleanest available answer, because it reports both halves. In 2025, wholesale market costs across the New England states ranged from 8.61 to 9.14 cents per kWh, while annual average residential prices across the same states ranged from 22.92 to 30.48 cents per kWh.
According to Axis Intelligence Research, wholesale market cost accounted for between 28.2% and 39.9% of the average New England residential rate in 2025, computed from ISO New England’s published market statistics. Everything else — transmission and distribution recovery, stranded costs, long-term contract obligations, efficiency and solar program adders — sits outside the wholesale market entirely.
The rest of the New England picture, for scale: $11.3 billion traded across the region’s wholesale markets in 2025, $9.9 billion in energy and $1.4 billion in capacity and ancillary services, with the average real-time price at $65.88/MWh. Natural gas supplied 54% of the region’s generation.
Aidan Jad: Twelve percent of New England’s wholesale market value is capacity and ancillary services. Wholesale is under 40% of the retail bill. Multiply those and the capacity auction everyone argues about is a low-single-digit slice of what a household pays. That is not an argument for ignoring it — capacity is the fastest-moving line and the one large loads pay closest to par on. It is an argument against the shorthand that capacity auction results explain residential rate increases. The utility rate case explains residential rate increases. The auction explains the industrial and interconnection conversation.
What Is Driving Capacity Demand Higher?
Load, and specifically the kind of load that arrives 300 megawatts at a time.
FERC’s assessment puts summer 2026 U.S. electricity consumption at 1,587 TWh, 4.5% above the 2021–2025 average and 3% above summer 2025 — the largest year-on-year increase since summer 2022. The sectoral split is where the signal lives: commercial-sector summer consumption of 561 TWh runs 7.3% above its five-year average, against 4.1% for residential and 3.0% for industrial. Data centers report as commercial load.
NERC’s forecast, as recorded in the FERC assessment, projects North American summer peak demand growing about 224 GW over the next decade — a 24% increase over 2025 peak, and a ten-year forecast 69% higher than the one NERC published a year earlier. NERC attributes most of the new load to data centers.
Transmission is following. Of 8,665 line-miles of new and upgraded transmission in service for summer 2026, load growth is the stated driver for 1,997 line-miles, behind system reliability at 2,244 and asset renewal at 2,019. ERCOT leads on project count with 684, ahead of PJM at 481 and MISO at 450, and 44% of ERCOT’s line-miles are driven by load growth. Only SPP and MISO built congestion-relief projects in the period, totalling 209 line-miles.
For a deeper read on where that load is physically landing, see our data center grid impact statistics and the data center electricity demand tracker. The queue side of the problem is covered in our grid interconnection queue statistics.
Methodology
Collection. Every figure in this article was retrieved on September 2, 2026 from a primary document opened during production: PJM Interconnection’s 2028/2029 Base Residual Auction Report (July 14, 2026) and the accompanying PJM Inside Lines results release; the Federal Energy Regulatory Commission’s 2026 Summer Energy Market and Electric Reliability Assessment (May 21, 2026); ISO New England’s key market statistics page; MISO’s 2026 Planning Resource Auction results release (April 28, 2026); and the U.S. Energy Information Administration’s Electric Power Monthly, whose most recent data month is June 2026, released August 26, 2026. No figure came from a secondary compilation.
One retrieval note, stated because it affects verifiability. MISO’s news release serves an automated-access challenge; the page is live and public in a browser but blocks programmatic retrieval. The four MISO values used here — summer prices of $424.30, $412.10 and $384.10/MW-day and annualized prices of $126.19, $123.12 and $116.06/MW-day — were read from the indexed text of that release and are internally consistent with MISO’s stated 42% year-on-year annualized decline. Anyone reproducing this dataset should open the release directly rather than fetch it.
Formulas.
- ACCB™ (Annualized Capacity Cost Benchmark) = clearing price ($/MW-day) × 365. For markets publishing $/kW-month: price × 12 × 1,000. For seasonal markets: the operator’s published annualized price, never a seasonal price × 365.
- Cost of 100 MW firm load = ACCB × 100.
- Capacity adder in $/MWh = (ACCB × 100) ÷ (100 MW × 8,760 h × 0.90 load factor).
- Collar suppression = (simulated uncapped price − actual clearing price) × 365.
- Wholesale share of residential rate = ISO-NE wholesale cost per kWh ÷ ISO-NE state residential price per kWh, computed at both ends of each published range.
- Net capacity change by region = FERC-reported additions − FERC-reported retirements.
Definitions and scope. Unforced capacity (UCAP) is a resource’s accredited capability, not its nameplate rating; PJM’s cleared UCAP totals are not comparable to installed capacity figures. PJM’s 2027/2028 and 2028/2029 auctions were conducted on a compressed schedule roughly 23 months before delivery rather than the standard three years, which affects how much new generation could qualify. MISO’s Reliability-Based Demand Curve produces four seasonal prices; only the operator’s annualized figure enters ACCB. ISO New England conducted its final Forward Capacity Auction in 2024 and is transitioning to a prompt/seasonal construct, so FCA 18 for delivery year 2027/2028 is the last forward-auction reading in this series. FERC’s regional wholesale price changes are summer-season comparisons drawn from EIA STEO Table 7a, not calendar-year settlements.
What is not published here. No all-in delivered wholesale cost by RTO appears in this dataset, because settled annual energy prices for delivery year 2026/2027 do not yet exist. No NYISO ACCB reading appears, because NYISO’s auction structure does not produce a comparable single forward price. Both gaps are left as gaps.
About This Dataset
us-wholesale-electricity-prices-2026.csv contains 202 rows covering RTO capacity auction clearing prices and volumes, ACCB™ readings by market and delivery year, price-collar suppression figures, regional wholesale energy price changes, capacity additions and retirements by region, and U.S. summer consumption by sector. Each row carries the observation, its unit, its as-of date, the issuing organization, the source document, an absolute HTTPS source URL, the retrieval date, whether the source is primary, and whether Axis Intelligence Research calculated the value. Rows flagged axis_calculated = yes carry a method note pointing to the formula disclosed above.
License: CC BY 4.0. Reuse, redistribution and adaptation are permitted with attribution.
Citation: Axis Intelligence Research, US Wholesale Electricity Prices 2026: RTO Capacity Auction Costs, Energy Market Rates and Regional Spreads, 2026, axis-intelligence.com/us-wholesale-electricity-prices/
Citation formats
APA: Axis Intelligence Research. (2026). US wholesale electricity prices 2026: RTO capacity auction costs, energy market rates and regional spreads. https://axis-intelligence.com/us-wholesale-electricity-prices/
MLA: Axis Intelligence Research. “US Wholesale Electricity Prices 2026: RTO Capacity Auction Costs, Energy Market Rates and Regional Spreads.” Axis Intelligence, 2026, axis-intelligence.com/us-wholesale-electricity-prices/.
Chicago: Axis Intelligence Research. “US Wholesale Electricity Prices 2026: RTO Capacity Auction Costs, Energy Market Rates and Regional Spreads.” Axis Intelligence, 2026. https://axis-intelligence.com/us-wholesale-electricity-prices/.
Frequently Asked Questions
Is it cheaper to site a 100 MW data center in MISO or PJM on capacity cost alone?
MISO, by $7.41 million a year for delivery year 2026/2027. PJM’s ACCB™ of $120,147 per MW-year puts a 100 MW firm load at $12.01 million; MISO’s North/Central annualized price of $126.19/MW-day puts the same load at $4.61 million. That gap covers capacity only. It says nothing about energy basis, interconnection cost allocation, transmission service charges or time to power, and in ERCOT — where capacity cost is structurally zero — the fixed-cost recovery reappears as energy scarcity pricing rather than disappearing.
Why did PJM’s clearing price fall 2.5% if the market got tighter?
Because the price was administratively set, not discovered. All three of the last auctions cleared at the FERC-approved cap, and the cap is recalculated each cycle from the accredited capacity of PJM’s reference resource. It moved from $329.17 to $333.44 to $325.00 for that reason, not because supply improved. PJM’s uncapped simulation for 2028/2029 clears at $554.72 — 70.7% above the actual result, against 58.9% the prior auction and 18.0% the auction before that. The market got tighter; the reported price could not show it.
What does a 6,831 MW capacity shortfall mean for a load-serving entity in PJM?
It means PJM enters delivery year 2028/2029 with a 14.4% RPM reserve margin against a 20.0% target, and that reserves are thinner rather than that load will go unserved. PJM’s language is that it would operate “with slimmer reserves and greater level of risk.” The tariff consequence is mechanical: three consecutive auctions clearing more than a percentage point below the installed reserve margin triggers a Reliability Backstop Auction, and PJM has said it will seek FERC approval to run one in September 2026. Cost allocation from that procurement is the open question for load-serving entities, not physical adequacy.
Do capacity auction results explain rising household electricity bills?
Not primarily, and the wholesale data shows why. In New England in 2025, total wholesale market cost ran 8.61 to 9.14 cents per kWh against residential rates of 22.92 to 30.48 cents — wholesale is 28% to 40% of the retail rate, and capacity plus ancillary services is 12.4% of wholesale market value. Capacity is the fastest-moving component and it matters most to large customers exposed near par. Household rate movement is dominated by transmission and distribution recovery, long-term contract costs and state program charges, which are set in rate cases rather than auctions.
Why does ERCOT have no capacity price?
ERCOT is energy-only: it runs no forward capacity auction and recovers generator fixed costs through scarcity pricing in the energy and ancillary services markets. FERC’s 2026 Summer Assessment records ERCOT relying on price-responsive demand to maintain reliability during tight supply periods, and forecasts ERCOT wholesale energy prices up 11% this summer while most regions fall. The absence of a capacity charge is not a discount; it is a relocation of the same cost into hours when the system is short.
Is the interconnection queue or the capacity market the binding constraint on new supply?
The auction data points at neither cleanly. PJM’s 2028/2029 auction procured 524.7 MW UCAP of new generation and uprates from a market of 138,318 MW, down from 774.3 MW the previous cycle, while offered capacity rose 3,447 MW almost entirely through accreditation changes and fuel conversions. Three auctions at the cap have not produced a supply wave. That pattern is consistent with a development bottleneck — queue position, equipment lead times, siting — rather than an insufficient price signal, but the auction results alone cannot separate those causes.
How should a seasonal capacity price be compared with an annual one?
It should not be, without conversion. MISO’s summer 2026/2027 price of $424.30/MW-day for Zones 1–7 multiplied by 365 gives $154,870 per MW-year, which would make MISO 29% more expensive than PJM. MISO’s own annualized price of $126.19/MW-day gives $46,059, which makes MISO 62% cheaper. The naive method is wrong by a factor of 3.36 and reverses the ranking. Where an operator publishes an annualized price, use it; where it does not, publish the seasonal price as a seasonal price.
What happens to New England’s capacity price now that the Forward Capacity Auction has ended?
FCA 18, held in February 2024 and clearing at $3.580/kW-month for delivery year 2027/2028, is the last forward auction under the old construct — an ACCB™ of $42,960 per MW-year and a 38% increase over FCA 17. ISO New England is moving to a prompt/seasonal schedule with auctions held closer to the commitment period, and has filed the first phase of those reforms with FERC. Until results clear under the new rules, New England has no published forward capacity price beyond 2027/2028, and any figure presented as one is an estimate.
Which regions are adding the most generating capacity in 2026?
ERCOT, by a wide margin: 25.6 GW of net summer capacity between October 2025 and September 2026, a 16% increase on its 2025 base and 34% of the roughly 75 GW added nationally. Non-CAISO WECC follows at 12.6 GW and MISO at 10.8 GW. PJM adds 4.8 GW against 1.8 GW of retirements. MISO carries the largest retirement volume at 3.2 GW. Nationally, retirements of 8.1 GW nameplate are running 55% faster than the prior year, and 60% of retiring capacity is coal.
Will the PJM price collar be extended past 2029/2030?
The collar negotiated with the governors of all 13 PJM states and FERC covers four auctions and runs through the 2029/2030 Base Residual Auction, scheduled for December 2026. Nothing published to date establishes what replaces it. PJM’s stated position is that the collar reduces volatility without addressing the supply-demand imbalance, and its market reform proposals are set out in its Powering Reliability Through Market Design report of May 2026. Any statement about post-2029/2030 pricing is speculation until a filing exists.