Investor-owned utilities asked regulators for a record $4.5 billion in electric and gas rate increases in the third quarter of 2026, according to the consumer advocacy nonprofit PowerLines, whose quarterly index was published October 7 and covered by Utility Dive on October 9. The cumulative value of third-quarter requests more than doubled from the third quarter of 2025, and the year’s total now stands at $23.1 billion. PowerLines estimates the quarter’s filings could affect the future bills of 45.5 million customers. It is easy to read the number as the bill for the wholesale cost shock — the PJM capacity auctions, the data-center load growth, the transmission buildout — finally arriving at the retail meter. That reading is partly true and mostly wrong.
Start with what the number actually counts. PowerLines tracks new rate increase requests filed each quarter by investor-owned utilities — requests, not approvals. A utility asking for $400 million has not yet received $400 million, and in the ordinary course of a rate case it will receive less. The index covers investor-owned utilities only, leaving out municipal utilities and cooperatives. And PowerLines itself describes the tally as approximately how much companies requested, because filings bundle different kinds of costs — base rates, riders, deferred cost recovery — that do not all reach bills in the same way or on the same schedule. A quarterly record of asking is a real signal of pressure in the system. It is not a measure of what bills will do.
What “more than doubled” doesn’t prove
The most important thing the quarter’s filings show is their composition, and it is not what the wholesale-shock story would predict. PowerLines dug into the individual filings and found that transmission and distribution spending was the dominant driver: at least 15 utilities cited T&D investments as a catalyst, and T&D spending stood behind at least part of $2.8 billion of the quarter’s requests. Profit considerations — including requests for a higher authorized return on investment and requests to make up earnings shortfalls, in several cases from gas utilities whose sales fell during a mild winter — were the second-largest factor, appearing in at least 13 filings worth $1.7 billion. Extreme weather costs appeared in five filings totaling $1.1 billion. These categories overlap, so they do not sum to $4.5 billion. But their order tells the story: the third quarter was, first and foremost, a capital-spending quarter.
That does not mean the wholesale market is absent from these filings. It means the wholesale market mostly reaches bills through a different door than the rate case, and conflating the two doors is the central confusion in reading the $4.5 billion figure.
How a rate case works
A regulated utility does not set its own prices. It files a case with its state commission, and the commission determines a revenue requirement — the total amount the utility is allowed to collect from customers. The formula is simple in structure: operating and maintenance expenses, plus depreciation, plus taxes, plus a return on rate base. Rate base is the depreciated value of the utility’s invested capital — the poles, wires, substations, and power plants it owns — and the return is rate base multiplied by an allowed rate of return, which currently averages around 9.84 percent, according to S&P Global data cited by PowerLines. A utility earns that return on the capital it invests, not on the electricity it buys and resells — which is why building a substation grows earnings and buying wholesale power does not, and why transmission and distribution spending dominates the rate-case docket.
The two doors to your bill
Here is the distinction that unlocks the $4.5 billion number. A utility’s costs reach your bill through two fundamentally different channels, and only one of them is the rate case.
The first door is the rate case itself: base rates that recover the revenue requirement — the return on wires and plants, plus fixed operating costs — reset every few years. This is where the T&D capex, the profit requests, and the storm recovery in this quarter’s filings live.
The second door is pass-through. Fuel costs, purchased power, and capacity costs are generally recovered dollar-for-dollar through adjustment clauses, supply auctions, or riders — with no return earned on them. The utility is a conduit, not a profiteer, for these costs. When PJM’s capacity auction clears high, that cost does not go through a rate case and does not grow rate base. It flows into the supply charge on the bill, through mechanisms like New Jersey’s Basic Generation Service auction or Maryland’s standard-offer-service procurement, or through a purchased-power adjustment clause. The wholesale shock arrives at your bill quickly and directly — but it arrives through the supply door, not the rate-case door. The $4.5 billion is a count of what came through the first door. The capacity shock came through the second, and it is not in that number at all.
One auction, two very different bills
The cleanest illustration of the pass-through door is what happened in New Jersey in 2025. When the state Board of Public Utilities certified the results of its annual Basic Generation Service auction on February 12, 2025, it projected average residential bill increases of 17 to 20 percent beginning June 1, depending on the utility. For a typical PSE&G customer using 650 kilowatt-hours a month, the bill rose from $155.84 to $182.71 — an increase of $26.87 a month. Jersey Central Power & Light customers saw $22.67, Atlantic City Electric customers $28.02, and Rockland Electric customers $25.48. Board president Christine Guhl-Sadovy put the cause in writing: “PJM’s recent capacity auction results are the main driver of these increases.” The underlying event was the PJM capacity auction for the 2025/26 delivery year, which had cleared at $269.92/MW-day, up from $28.92 the year before. One clarification matters: the $26.87 was the total increase in the supply charge, not a capacity-only line item. The board attributed the increase mainly to capacity, but the BGS auction buys energy and capacity together, and the bill does not separate them for the customer.
Now compare Maryland, served by the same grid operator, the same auction, the same capacity market. The Maryland Office of People’s Counsel estimated that for the 2026/27 delivery year — the auction that cleared at the $329.17 cap — capacity-related changes would produce an average bill decrease of $3.36 a month for BGE customers and an increase of $2.50 a month for Pepco customers, after credits related to reliability-must-run units. The reason is history: the BGE zone had already been paying a higher, constrained capacity price the prior year — $466/MW-day against a regionwide $270 — so the step up to $329 was, for BGE, a step down, and the RMR credits pushed it further into negative territory.
Why the same auction produces different bills
At least six things stand between a PJM clearing price and any given household’s bill. The delivery year: New Jersey’s $26.87 reflected the 2025/26 auction; Maryland’s figures reflected 2026/27, a different auction at a different price. The zone: capacity prices are locational, and BGE’s history of high zonal prices is exactly what cushioned its customers. The procurement channel: New Jersey buys supply through its BGS auction, Maryland through standard-offer service, other states through purchased-power clauses — each with its own timing and hedging. Credits and offsets: RMR credits shaved Maryland’s numbers, and in JCP&L’s current rate filing, offsets are designed to cover the increase in 2027 and push the bill impact to 2028. The usage assumption: New Jersey’s figures assumed 650 kWh a month. And state policy: commissions can layer on bill credits, freezes, or phase-ins. A single regional price, passed through six different local machines, comes out as six different bills.
What the quarter’s filings actually were
Return to the filings themselves, because their specifics repay attention. The largest single case in the quarter was FirstEnergy’s Jersey Central Power & Light, which in July proposed a $253 million increase in base distribution rates plus recovery of $476 million in previously deferred storm costs, spread over a 10-year period through a separate storm recovery rider. The average residential customer would see a total bill increase of about 8.8 percent, the utility said, though it would not hit bills until 2028. Note the composition: more than half the ask is money the utility has already spent recovering from storms — backward-looking cost recovery, not new construction, and not wholesale markets.
The other large filings show the same pattern of wires and weather. Oklahoma Gas & Electric filed September 30 at the Oklahoma Corporation Commission to increase annual retail revenues by $395 million, which would raise average residential electric bills by $23.88 a month. The Potomac Edison Company, a FirstEnergy subsidiary, filed September 4 at the Maryland Public Service Commission for a $52.8 million increase in base distribution revenues, worth $9.47 a month to the average residential customer. And in Chicago, administrative law judges recommended that Peoples Gas be allowed $66 million — down from the $202 million it filed for in January — with the Illinois Commerce Commission to rule next month. Requests are opening bids. Commissions cut them, sometimes by two-thirds.
The regional and capital picture
The geography of the quarter is also instructive. Utilities in the South requested the most — $2.2 billion, covering about 11 million customers and bringing the region to $9 billion in requests so far in 2026. Northeast utilities requested $900 million covering 5.6 million customers, Midwest utilities $800 million covering 7.9 million, and Western utilities $600 million covering 20.8 million. The South’s ask was nearly four times the West’s while covering roughly half as many customers — a reminder that rate-case pressure is not evenly distributed.
Underneath the quarterly numbers sits the capital engine that generates them. Last year, the Edison Electric Institute said its member utilities were projected to spend more than $1.1 trillion between 2025 and 2029. A PowerLines analysis earlier this year found utility capital spending through 2030 had risen 21 percent, to $1.4 trillion. That spending is driven by real things: load growth that has returned after two decades of flat demand, much of it from data centers; transmission to connect new generation and serve new loads; distribution hardening against storms; and the replacement of aging infrastructure.
Requests are not approvals, and asking is not the same as needing
Two cautions belong in any honest reading of the $4.5 billion. The first is that commissions exist precisely to test these requests, and they regularly shrink them — the Peoples Gas recommendation is the quarter’s clearest example. The second is that the profit motive embedded in the rate-base model deserves scrutiny on its own terms. When utilities ask to raise their allowed return, or to recover earnings lost to a mild winter, they are asking customers to insure the company’s earnings against weather and markets. Commissions sometimes grant that insurance and sometimes refuse it.
The political context is catching up with the dockets. Affordability has become a central issue ahead of next month’s midterm elections, with voters focused on rising costs amid the spread of data centers. The Minnesota Public Utilities Commission has opened an investigation into the affordability of electric and gas service from rate-regulated utilities, with sessions scheduled for October 13, November 2, and December 8. New Jersey’s Board of Public Utilities voted to keep electricity rates level. And in Washington, a bipartisan Senate permitting bill would aim to make it easier to build large energy infrastructure while requiring data-center developers to pay for grid upgrades built to serve them.
What to watch
The next data points will test whether the third quarter was a peak or a plateau. The December auction for the 2029/30 delivery year, closing December 15, is the fourth and final auction under the FERC-approved price collar; it will presumably clear at its cap too, as the three before it did. PJM has told Utility Dive it intends to file a revised backstop procurement proposal at FERC by October 29, addressing the cost-allocation, exit-rule, and collateral defects that led the Commission to suspend the original plan for five months. And the commissions now sitting on the third quarter’s cases — including the JCP&L proceeding, where the bill impact is deferred to 2028 — will show how much of the asking survives review.
The $4.5 billion quarter is best read as two stories braided together. One is the wholesale story: capacity prices that went from an afterthought to a line item voters can see, passing through the supply door in amounts that differ wildly by state, zone, and procurement channel. The other is the wires story: a trillion-dollar capital program, a rate-base model that rewards building, and commissions deciding, case by case, how much of it customers should pay. Both stories end up on the same bill.
Sources: PowerLines, “What drove record-breaking utility rate requests in Q3 2026” (Oct. 7, 2026); Utility Dive, “US electric, gas utility rate requests spike to $4.5B in Q3: PowerLines” (Oct. 9, 2026); New Jersey Board of Public Utilities, BGS auction announcement (Feb. 12, 2025); Maryland Office of People’s Counsel, capacity auction bill-impact estimates (2026/27 delivery year). Prior Fracmoo coverage: “How Wholesale Prices Reach the Retail Bill”; “The Market Is Trying to Say $555. The Rules Only Let It Say $325.”