A team at Lawrence Berkeley National Laboratory published a paper in the December 2025 issue of The Electricity Journal called "Factors influencing recent trends in retail electricity prices in the United States." If that title sounds like the kind of thing only economists read, fair. But the findings are quietly explosive, and almost nobody on the cable-news side of the data-center debate has bothered to look at them.
The short version: across the country, real retail electricity prices barely moved from 2019 to 2024. Adjusted for inflation, the U.S. average declined roughly 8% from 2010 and has been flat since 2019. Thirty-two of fifty states saw inflation-adjusted residential prices decrease over the five-year study window. The headlines about prices "soaring" rely entirely on nominal dollars, and the authors say so explicitly. The story most retail customers tell themselves — that runaway data centers and renewables have set their bills on fire — is, at the national level, not the story the data tells.
And then there's Texas, where residential rates ran from 11.7¢/kWh in 2020 to 15.84¢/kWh in September 2025 — a 35% nominal increase, well ahead of inflation, with another ~29% projected rise by 2030. Texas is not the national story. Texas is the leading edge of where the national story is about to go.
The Study Nobody on Cable News Will Read
The Berkeley paper, authored by Ryan Wiser, Eric O'Shaughnessy, Galen Barbose, Peter Cappers, and Will Gorman, is the closest thing to a definitive accounting of what actually moved U.S. retail rates between 2019 and 2024. The full summary PDF runs roughly 80 pages of regression, state-by-state breakouts, and bill-impact decomposition. The headline finding is the one nobody wants to put on a chyron: residential prices rose about 0.5¢/kWh in real terms over those five years, or roughly $54 per year for the average 10,791-kWh household. Commercial and industrial customers? Their real prices fell by 0.3¢ and 0.2¢/kWh respectively.
That gap matters. Residential customers are quietly subsidizing C&I, and the gap has widened every year since 2019. The political conversation about who's "paying" for the data-center buildout is missing the part where, in many states, large industrial and commercial users have already been paying less on a real, per-kWh basis than they did five years ago. The question isn't whether residential customers are bearing more cost — they are. The question is which costs, and why.
The Berkeley team ran the decomposition and ranked the drivers. The ranking is going to make a lot of people on both sides of the renewables debate uncomfortable, so let's just walk it.
Five Drivers, Ranked
Driver #1: Distribution capital expenditure. The single largest factor in residential price increases. Utility distribution-related capex rose roughly 50% nationally between 2019 and 2023, far outpacing inflation. Aging-infrastructure replacement accounts for about 28% of that spend. This isn't transmission, and it isn't generation. It's the wires running down your street, the substations on the edge of your neighborhood, and the long tail of poles and transformers that utilities have been pushing off since the 1990s. The bill is now due.
Driver #2: Climate and weather. California's wildfire mitigation alone added roughly $27 billion to utility rates between 2019 and 2023, with about 40% of that being insurance cost growth. Storm hardening in Florida and the Gulf Coast — including, as we'll get to, the CenterPoint Houston securitization after Hurricane Beryl — is the second-largest geographic driver of residential bill increases. This bucket grows for a while no matter what anyone does about policy. The damage is already in the asset base.
Driver #3: Fuel volatility. Real residential prices rose fastest in states that lean heaviest on natural gas. Most utilities pass 100% of fuel costs through to customers via fuel adjustment clauses, so when gas spikes, residential bills move within months. EIA reported October 2025 gas prices were up 45% year over year and the agency expects another ~16% increase by October 2026. If you live in a gas-heavy ISO — like, say, ERCOT — fuel pass-through is doing more to your bill than anything else short-term.
Driver #4: RPS-linked renewables in shrinking-load states. The one place the study lands a finger on clean-energy mandates. In states with both a binding renewable portfolio standard and flat or declining load, RPS compliance added about 0.25¢/kWh on average. That's a small number, and it's contained to a specific subset of states. The vast majority — roughly three quarters — of new wind and solar built between 2019 and 2024 was market-driven, not RPS-driven, and the paper finds that market-driven renewables build had no discernible impact on retail prices. In several models, it pushed prices down. The cable-news talking point that "renewables raised your bill" is, on the numbers, mostly wrong.
Driver #5: Load growth direction. This is the one almost nobody talks about, and it's the one Texas should care about most. States where load grew, real residential prices fell. North Dakota — which absorbed crypto, oilfield electrification, and data center demand — saw real residential prices drop about 3¢/kWh because fixed costs were spread over more megawatt-hours. PG&E told regulators that each new gigawatt of California data-center load could lower residential bills by 1–2%, for the same reason. The intuition is straightforward: a utility's fixed cost base doesn't shrink, so more demand means lower per-kWh cost recovery. The question is whether the new load brings new capital cost with it, and at what ratio.
If the new load comes with $40 billion in transmission and $15 billion in generation built almost entirely to serve it, and if the rate design lets the new load avoid paying its share of those investments, then load growth isn't a deflator anymore. It's an accelerant. Welcome to Texas.
The Texas Carve-Out — Where the National Story Stops
Texas doesn't fit the national average on any of the five drivers cleanly. It's worse than average on three of them and structurally different on the other two.
Distribution capex: Oncor announced its 2026–2030 base capital plan at $47.5 billion in February 2026, up sharply from the prior plan. CenterPoint Houston's storm-hardening + resiliency request was $5.75 billion; PUCT approved $2.9 billion of it in November 2025. Layered on top, CenterPoint received $1.2 billion in securitization for Hurricane Beryl restoration in October 2025, with an immediate ~$2/month residential bill impact. Oncor's June 2025 base rate case was settled by the Commission in April 2026 at $560 million in annual increases on a 9.75% authorized return on equity.
That is roughly $52 billion of utility capex pre-approval or under construction in two service territories, on a horizon of five to seven years. Most of it lands on residential and small-commercial customers under current rate design.
Weather: Beryl alone produced enough storm damage to qualify CenterPoint for a one-billion-dollar securitization. The Berkeley paper's "climate and weather" bucket captures California fires and Florida hurricanes; Texas is now firmly in the same cohort.
Fuel: ERCOT's marginal price-setter is almost always natural gas, and Texas residential REPs (TXU, Reliant, Gexa, Cirro, and the long tail) pass fuel costs through with limited regulatory friction. ERCOT North average wholesale prices were around $27–34/MWh in 2025, but EIA's December outlook projected a 45% wholesale price spike between 2025 and 2026, and a high-demand scenario where data center load pushes ERCOT North wholesale prices 79% above baseline by 2027. That spike flows directly into the variable component of residential REP plans the next time those customers shop.
Renewables: Texas has no binding RPS. The 1999 RPS goal was met in 2009 and isn't binding on anything. So the one factor the Berkeley paper isolates as a real (if small) price driver is essentially absent here. Whatever is moving Texas residential bills, it isn't a clean-energy mandate.
Load growth: This is the structural divergence. ERCOT load grew about 5% from 2024 to 2025 and is forecast to grow roughly 10% per year through 2027, with data centers accounting for about 73% of large-load interconnection requests. Under the Berkeley model's logic, this should push real residential rates down — fixed costs spread over more megawatt-hours. Texas residential rates have done the opposite. The question is why, and the answer lives in the rate design.
Who's Subsidizing Whom: 4CP, SB 6, and the March 2026 Rule
Texas allocates wholesale transmission costs using a method called 4CP — the four coincident peaks. A large industrial or data-center customer's annual share of ERCOT transmission costs is based on its average demand during the four 15-minute intervals of highest system load each summer. If you can predict those intervals and curtail through them, your transmission allocation drops dramatically. Residential customers cannot curtail their air conditioning at 5:00 p.m. on a 105-degree day in August. Industrial customers can, and do.
The result, documented in detail in NRG's February 2025 PUCT remarks, is that residential and small-commercial customers in ERCOT pay a larger share of transmission costs than their share of energy consumption would suggest. The 4CP method, designed when the grid had a handful of large industrial sites and predictable peaks, has become a structural subsidy from households to large flexible loads in an era of 75-megawatt-and-up data center interconnections.
The legislature noticed. Governor Abbott signed Senate Bill 6 in June 2025, requiring PUCT to evaluate the 4CP method and finalize rule changes by December 31, 2026. SB 6 also sets new interconnection standards for loads of 75 MW and above, gives the Commission new authority over backup generation registration, and ties large-load curtailment obligations into ERCOT's reliability framework. PUCT published draft rule §25.194 on March 12, 2026; comments are running now.
The cost-allocation language is where the residential-versus-data-center fight gets decided. If PUCT replaces 4CP with a 12CP, a demand-ratchet, or a causation-based method, hundreds of millions of dollars of annual transmission cost recovery shift between customer classes. If PUCT leaves 4CP largely intact and only tightens the curtailment definitions, the residential subsidy of large loads continues — through the entire $33 billion Strategic Transmission Expansion Plan, of which the first $9.4 billion 765-kV phase was approved by the ERCOT Board in December 2025.
That's the real fight. Not whether data centers come to Texas — they're here, and the queue is full. The fight is over who pays the wire bill.
The 2026–2030 Capex Cliff
The Berkeley study is retrospective. The data window closes in 2024. None of the numbers above — Oncor's $47.5 billion, CenterPoint's $2.9 billion resiliency plan, the ERCOT STEP $33 billion, the Beryl securitization, the SB 6 rulemaking — show up in the regressions. The paper measures a national real-rate baseline that was, by its own findings, mostly flat. Texas is about to spend the next five years showing what happens when distribution capex doubles, transmission capex enters $30-billion-plus territory, and load growth runs at 10% a year through it all.
The math runs both ways. If 4CP gets replaced with a method that puts the new transmission costs on the loads driving them, then the load-growth dilution effect the Berkeley team found in North Dakota kicks in and Texas residential rates flatten — maybe even decline in real terms. If 4CP survives mostly intact, the capex cliff lands on residential customers and the 29%-by-2030 projection from the Texas Chemistry Council brief starts looking conservative.
The Berkeley paper does not predict either outcome. It just lays out what made rates do what they did over the past five years, and it provides the framework for thinking about which dial moves next. The frameworks are useful. The conclusions are honest. The part most retail customers will care about — what their bill looks like in 2028 — depends entirely on a PUCT rulemaking that closes 19 months from now.
Read the paper. Or at least read the summary. It's free.
What to Watch Next Week
PUCT draft rule §25.194 comments. The comment period on the SB 6 large-load interconnection and cost-allocation rule is the single most consequential proceeding for Texas residential rates over the next five years. Final rule must be in place by December 31, 2026. Watch for big-load coalition filings (data center hyperscalers, crypto miners, refiners) versus consumer-advocate filings (Office of Public Utility Counsel, Texas Coalition for Affordable Power).
EIA Short-Term Energy Outlook update. STEO refreshes monthly and is currently projecting another roughly 5% nominal residential price increase in the South region for 2026 on top of 2025. The May 2026 STEO will likely raise that figure as Q1 utility rate-case settlements get baked in.
PUCT 4CP methodology decision. Separate from the §25.194 rulemaking, PUCT was required under SB 6 to evaluate 4CP within 90 days of the bill's effective date. The Commission has been working through the evaluation; a decision memo or open-meeting item naming a successor methodology — or formally extending 4CP — is overdue.
CenterPoint and AEP Texas next rate filings. Both are expected to follow Oncor's playbook with comprehensive base rate cases in 2026, citing storm hardening, load growth, and the same distribution-capex driver the Berkeley paper ranked first.
The LBNL 2026 edition. The Berkeley team typically refreshes the dataset annually. The March 2026 update already pulls in Q3 2025 EIA-861 data. Texas-specific tabs in the next version, expected this fall, will be the first time the academic literature catches up with what's happening on the ground here.
Disclaimer: The Grid Report is Barrio Energy's market intelligence product. Nothing here is investment advice. Links go to primary sources wherever possible; form your own view.
