Data Center Alley growth is stressing the grid. Residential customers are paying for it.

The chart shows three representative Dominion customer profiles. All three rose, but they diverged. Residential (1,000 kWh per month) climbed roughly 57%; mid-commercial (30,000 kWh per month, 75 kW peak) climbed roughly 51%; industrial transmission (8 million kWh per month, 15,000 kW peak) climbed roughly 44%. All three customer classes are paying for the buildout. Residential is paying the largest share of it.

Three structural events shape the trajectories. A mid-2022 fuel-price spike (the Russia-Ukraine pass-through) lifts all three lines roughly in parallel. A mid-2023 regulatory regime change (Virginia's HB 1770) restores biennial rate reviews after the prior rate-freeze era. And an early-2026 base-rate revision (Dominion's 2025 biennial review, PUR-2025-00058) drives the visible final step upward. The cross-class divergence widens over time: the 2022 fuel shock was an equalizer; the buildout-era growth that followed has not been.

The scale of the load growth is unprecedented and accelerating. For context, Dominion's all-time historical system peak is 24,678 MW (recorded January 23, 2025). Against that baseline, Dominion's 2024 Integrated Resource Plan (PUR-2024-00184) and its 2025 Update (PUR-2025-00184) project roughly 9 GW of new data-center peak demand within 10 years (more than 35% above today's peak), with total electricity usage rising more than 100% over a 15-year horizon. The volume of large-load requests Dominion is processing has grown faster still: from 8 GW in 2021, to 23 GW in July 2024, to 47 GW in July 2025, to roughly 70 GW by February 2026 per Dominion's application in PUR-2026-00011. That 70 GW figure is the volume of large-load delivery-point (DP) requests advancing through Dominion's connection process as of December 31, 2025; it is not 70 GW of contracted load. Per Dominion's Q4 2025 earnings disclosures, the 70 GW splits across Dominion's contract-process stages as follows. Each request is at one current stage; the rows don't overlap.

Separately, per Dominion's SCC filing, approximately 25,000 MW of the 70 GW total have been assigned projected connection dates through December 31, 2031; the remaining 45,000 MW are still under study to determine connection dates. Dominion also reports receiving roughly ten new large-load DP requests per month, representing 2,000-3,000 MW of additional requested load each month. The standards apply to requests serving data-center customers in the DOM Zone at approximately 100 MW or more.

A note on forecasts. Treat 70 GW as the stress signal at the top of the funnel, not a forecast of realized load. For external context, PJM's 2026 Load Forecast Report projects roughly 32 GW of total PJM-wide load growth through 2030, of which ~94% (30 GW) is data-center-driven; Dominion captures the largest geographic share of that growth. Realization rates from comparable markets reinforce that queues attrit: ERCOT applies a ~50% realization rate to its large-load queue, and SPP reports ~39% conversion of requests to signed service agreements. The Data Centers page covers the broader forecasting discussion.

That load growth requires infrastructure. The 2024 IRP lists 203 planned transmission projects totaling $7.595 billion; the 2025 Update carries the same inventory forward with refreshed PJM capacity-price assumptions and a sensitivity case excluding data-center demand. Of the 203 projects, 89 projects ($2.435 billion, about 44% of the project count and 32% of the spend) are directly tagged as data-center-driven (Dominion witness Harrison S. Potter, Day 2 hearing transcript). Another 37 projects worth $3.3 billion are mixed regional-reliability projects that include data-center load but cannot be attributed to a single customer type. The allocation work shows residential customers carry 55%of those transmission costs under Dominion's current rate-schedule allocations, with the remaining 45% spread across commercial and industrial classes.

Virginia's regulatory response is moving on multiple fronts: a new GS-5 rate class effective January 2027 (designed to shift more of the buildout cost onto customers above 25 MW), PJM's multi-year market-reform effort, and proposed alternative cost-recovery mechanisms in recent rate cases. But for the four years between 2022 and 2026, the existing cost-allocation rules sent the bulk of the visible bill growth onto residential customers, with commercial and industrial customers following the same pattern at attenuated magnitudes. The rest of this case study walks through why, what is pending through 2027, and where demand flexibility could change the trajectory.

Four pieces of public evidence connect the rider growth to the data-center buildout in Dominion's service territory: Dominion's own IRP filings, PJM's capacity auction results, PJM's Independent Market Monitor analysis, and PJM's wholesale energy market congestion data.

When Dominion proposes new infrastructure (transmission lines, substations, generation, distribution), the SCC's Class Cost-of-Service Study (CCOSS) divides the cost among customer classes. Costs are typically separated into three categories and allocated differently:

• Capacity costs (generation, transmission, distribution infrastructure): allocated by each class's contribution to the system peaks that drive the investment
• Energy and fuel costs: allocated by each class's share of total kWh consumption
• Customer service costs: allocated by customer count

The first allocation, capacity by coincident peak, is the one that matters most here. Dominion's system peaks are typically summer afternoons (driven by residential air-conditioning) and winter mornings (driven by residential heating). Residential customers' contribution to those peak hours is large; their share of the peak determines their share of the demand-driven cost. The result, in numbers from the allocation evidence above: residential carries 41% of generation and 55% of transmission costs; GS-4 (most data centers) carries 26% and 16%; the remaining commercial and industrial classes split the balance. The Data Centers page section on who drives the peak walks through how PJM and Dominion measure these peak contributions across customer types, with a supporting chart.

Briefly: residential load is summer- and winter-peaking, with high coincidence with the system peaks that drive capacity allocation. Commercial peaks weekday afternoons (partial overlap). Data centers run flat 24/7 (lower coincidence with the short peak hours that drive transmission allocation, though they raise the baseline level of total load and drive capacity buildout for that reason). This is the structural twist: data centers' constant load is driving the infrastructure investments, but the per-class allocation of those infrastructure costs is determined by peak coincidence, which favors data centers over residential. Data centers drive the buildout; residential carries the larger share of the cost.

Several rate cases and regulatory actions already in motion will reshape Dominion bills through 2027 and beyond.

The pending July 2026 fuel-factor reset (cross-segment impact). Dominion has filed two scenarios for the July 2026 Rider A reset. Assuming all other charges remain flat:

The residential figures come from Dominion's April 2026 fuel-factor filing. The commercial and industrial figures are project calculations applying the same filed scenarios to the representative tariff profiles used throughout this case study. Dominion has flagged Scenario 2 as its preferred approach; whether the SCC approves it, modifies it, or selects Scenario 1 is still pending. Cardinal News has a plain-English summary of the filing.

The new GS-5 rate class takes effect January 1, 2027. Approved in Dominion's 2025 biennial review (PUR-2025-00058), GS-5 applies to customers with peak demand of 25 MW or more and at least 75% load factor (a profile that matches most hyperscale data centers). The terms include 85% minimum demand for transmission and distribution, 60% minimum for generation, and 14-year contracts. GS-5 is prospective only: it applies to new customer agreements signed on or after January 1, 2027. Most existing Dominion data centers remain on GS-3 or GS-4 schedules for years.

What happens after the 14-year contract. In direct testimony filed with the SCC, the Piedmont Environmental Council's expert witness Gregory Abbott analyzed the depreciation timeline of the $22.4 billion in projected incremental infrastructure that Dominion's 2024 IRP attributes to data-center load. The $22.4 billion is forward-looking, not yet spent; the majority of it would be built and rate-based after GS-5 takes effect January 1, 2027, meaning new data-center customers under GS-5 cover the bulk of that capital through the 14-year minimum-billing window. Assuming standard straight-line depreciation over a 36-year asset service life, Abbott calculated that $13.69 billion (61.1%) of that capital would still be undepreciated and unrecovered at the end of the 14-year contract. PEC's counter-proposal of a 20-year contract term would leave $9.96 billion (44%) undepreciated.

Under standard utility cost-recovery rules, an undepreciated asset that remains in service continues to be recovered from the customer base. After the 14-year minimum-billing window expires in 2041, the cost of the infrastructure built to serve data centers during the contract period would shift to whichever customers are taking service from Dominion at that point. Under the existing class-allocation rules, that means residential customers carry the majority share. Two conditions are necessary for this outcome to apply: anticipated data-center demand must fully materialize during the contract period, and High Load customers must honor their contractual obligations. If either condition breaks (load forecasts miss, customers depart), additional stranded-cost risk falls back on existing customer classes.

One mechanism for that departure already exists: retail choice. Under Va. Code § 56-577, most Virginia customers are required to purchase generation from their incumbent utility, but large customers qualify to leave the utility and buy generation from a third-party competitive supplier if they (a) exceed 5 MW and account for less than 1% of the utility's peak load, or (b) exceed 90 MW outright. Retail choice applies to generation only; transmission and distribution still come from Dominion under the same tariff (and, for GS-5 customers, the same 85% T&D minimum demand). JLARC's 2024 data-center report (Chapter 4, Energy Costs) notes that “many existing data centers, and virtually all planned future ones, exceed 90 MW and are eligible to participate in retail choice.”

If data centers exercise that option in volume, the fixed cost of generation Dominion has already built (Brunswick, Greensville, and the new capacity being approved now) gets re-allocated across the remaining customer base. JLARC cites Dominion's own estimate: if all currently eligible customers (including non-data-center customers) chose to participate in retail choice, the cost shift to remaining customers would exceed $600 million annually, roughly $150 per year for a typical residential customer, a figure JLARC notes is likely to grow as data centers become a larger share of Virginia's customer base. Today only a small number of eligible customers participate, which is why the risk is forward-loaded: as more new data-center load comes onto the system above the 90 MW threshold, the option to leave the utility's generation service becomes more attractive, particularly if competitive markets offer lower-cost supply than the utility's increasingly capacity-heavy rates. JLARC's separate headline finding is that overall data-center-driven load growth (independent of retail choice) could add $14-$37/month to typical residential bills by 2040. The two effects compound rather than substitute.

Will transmission relief reduce future fuel and energy costs? In principle, yes: the buildout (funded by Rider T1 and base transmission rates) relieves the congestion driving DOM-zone wholesale-market premia, lets cheaper generation reach load, shrinks inter-zone price differentials, and lower wholesale costs eventually flow through Rider A into customer bills. In practice, the relief is on a delay. PJM's 2025 Regional Transmission Expansion Plan approved $11.8 billion in new transmission, roughly $4.8 billion across Dominion's coverage area, recovered through Rider T1 and the base transmission component (the “grid expansion and reliability” bucket in the bill stack chart above) and spread across decades, so monthly bill impact lands gradually rather than as a single spike. The major projects targeting Northern Virginia:

• Mid-Atlantic Resiliency Link (MARL): 500 kV line from Pennsylvania through West Virginia into Virginia; PJM's original required in-service date was June 1, 2027, now revised to the Woodside segment by December 31, 2028 and the full line by December 2031.
• Valley North 765 kV: 260-mile line from West Virginia through Maryland, developed by Valley Link Transmission (a joint venture of AEP, Dominion, and FirstEnergy). A sibling project (Joshua Falls-Yeat 500 kV, 115 miles within Virginia) is targeting end-2029 energization with a Virginia SCC filing planned for summer 2026; together the Valley Link portfolio delivers up to 3 GW into Loudoun County.
• Chanceford-Doubs 500 kV backbone rebuild: the Maryland segment is still in CPCN siting review at the Maryland PSC (Case 9773), not yet under construction. PJM's required in-service date remains June 1, 2027, but by October 2025 both PSEG (the Maryland developer) and PJM told the PSC the adopted procedural schedule would not allow approval in time. The PSC issued a proposed CPCN order in March 2026; a final decision is not expected before February 2027.
• 2025 RTEP Window 1 / 525 kV underground HVDC backbone: Heritage (Brunswick County) to Mosby (Loudoun County), ~186 miles, 3,000 MW bipolar link. PJM's 2025-W1-815 proposal records $3.79 billion for the line itself; trade press reports total portfolio cost (line plus converter stations) at roughly $4.8 billion. Selected by PJM in early 2026 over 765 kV overhead alternatives.

Projects of this scale typically take 5-10 years from approval to in-service, and data-center load growth has been faster than that. PJM attributes the recent decline in the Dominion zone's peak-import headroom primarily to northern Virginia load growth (not to any specific project delay), and the broader regional transmission delays compound the pressure across MAAC. Once MARL, Valley North, and the Heritage-Mosby HVDC backbone come online, they would in principle relieve the constraint that data-center load growth has stressed: more cheap power flowing into Virginia from neighbor zones, and less renewable generation curtailed in those zones because it can finally reach the load that needs it. How much of that relief actually shows up depends on whether new data-center load fills the new headroom as fast as it arrives. The 2027/2028 capacity auction already cleared at the FERC-approved $333.44/MW-day price cap for the Dominion zone, and PJM's load forecast adds roughly 5,100 MW of additional Dominion-zone data-center demand in that single delivery year alone, more than any individual project in the queue is sized to relieve. No analyst publishes a year-by-year DOM-zone relief forecast. The buildout is racing load, not catching it.

How the 2022 fuel shock compares to what is coming. The 2022 spike was a commodity-price event: gas prices jumped, the next quarterly fuel-factor filing passed the cost through, the summer bill jumped, and when global gas prices fell back the next year, Rider A trued up. Fast, loud, and reversible. The current cost pressure is structurally different. The dominant driver is the cost of new generation and transmission built to serve data-center load, not a one-time commodity shock. It lands more slowly (through capacity riders, base-rate proceedings, and transmission true-ups rather than a single fuel-factor adjustment), it is larger in cumulative dollars, and it does not revert when global conditions normalize. The capital sits in rate base and is recovered across decades.

The fuel factor itself is set to rise materially again in July 2026 (Scenario 2: +$9.77/mo +5.7%; Scenario 1: +$21.79/mo +12.7%), but not because of a 2022-style commodity spike. Most of that increase is recovering Dominion's accumulated ~$1.08 billion fuel-cost deferral and reflects wholesale-market premiums driven by the same load-growth pressure the buildout is responding to. Two complications tighten the loop: gas-fired peakers typically set the marginal clearing price in PJM's energy market during scarcity hours, so a future Henry Hub spike would push both Rider A and the next capacity-auction clearing price up simultaneously, and the gas-price outlook is not pointed downward. EIA's May 2026 Short-Term Energy Outlook puts Henry Hub at roughly $3.50/MMBtu in 2026 and $3.18/MMBtu in 2027 (above the pre-2021 ~$2.50/MMBtu baseline), with LNG-export growth (projected to rise from 17.0 Bcf/d in 2026 to 18.2 Bcf/d in 2027) and rising data-center gas demand pointing to continued upward pressure. Easing fuel costs going forward requires relieving wholesale-market stress, which itself requires the transmission and generation buildout. The buildout costs then flow through other parts of the bill.

Short term (next 12-24 months), fuel and energy prices are more likely to rise than fall, per Dominion's April 2026 fuel-factor filing. Medium term, the outlook depends on whether the transmission buildout catches up to demand, with no independent forecast currently projecting that it will during the next-3-years planning horizon. Among the structural levers available, reducing peak demand directly is one of the few that does not require multi-year permitting and construction.

PJM's May 2026 market-design paper ( Powering Reliability Through Market Design) outlines a multi-year capacity-market reform effort, citing three drivers behind the region's move from surplus to scarcity: data-center demand growth that outpaces generation buildout, rising capital costs and longer construction timelines, and policy uncertainty. The 2027/2028 BRA cleared at $333.44/MW-day, near the FERC-approved cap; without market reform or new generation, capacity-cost pressure will continue to feed into Dominion's base rates at each biennial review.

The bill outcomes documented above are not an accident. They are the system working as designed. A capacity-recovery framework built around stable load growth, supplied by a class-allocation structure set decades ago, is producing exactly the outcomes its rules predict when applied to one of the fastest load-growth moments the US grid has ever seen. Every Dominion customer class is paying for the buildout; residential is paying the largest share.

On a typical Dominion residential bill in June 2026, demand-driven infrastructure (base rates, grid-expansion riders, clean-energy mandates) accounts for roughly $138/mo (80% of the bill), while fuel and energy costs account for roughly $30/mo (17%). The commercial and industrial profiles show the same ratio: the buildout dominates, not the commodity. This matters for where flexibility creates leverage. Reducing kilowatt-hours a customer consumes affects the smaller share of the bill; reducing the customer's contribution to system peak hours affects the larger share, by reducing the capacity Dominion has to build to serve that peak.

Flexibility programs operational or filed in Dominion's territory today, with their reach across customer classes:

• Smart Thermostat Rewards (residential, active): Dominion's bring-your-own-thermostat demand-response program. Customers who enroll a compatible smart thermostat receive a $25 enrollment incentive and $25/year for participating; in exchange, Dominion can dispatch the thermostat (typically by raising the set-point a few degrees) during peak events. Dominion's own event log shows 17 events totaling 50 hours of dispatchable load reduction in 2025. (The legacy switch-based Smart Cooling Rewards program was retired after the 2022 cycling season.)
• Voluntary time-of-use rates (residential): Schedule 1G (the Off-Peak Plan) and Schedule 1EV (EV charging) are SCC-approved tariffs available now, requiring an advanced meter. Schedule 1G was approved as an experimental TOU rate in SCC Case PUR-2019-00214 (May 2020 order), launched in early 2021, and expanded from a 10,000 to 20,000 customer cap in 2023. The 2022 DNV evaluation found 9.4% peak load reduction in summer and 2.9% in winter among the roughly 7,700 retained enrollees in that year's sample. Newer enrollment figures are not publicly disclosed.
• Statutory Virtual Power Plant Pilot (all classes, ramping): Va. Code § 56-585.1:16 (the 2025 Community Energy Act) directs Dominion to operate a VPP pilot of up to 450 MW of aggregated distributed energy resources across residential and C&I customers, with aggregator participation permitted. Dominion filed the pilot tariff at the SCC in December 2025; ramp through August 2026; pilot concludes July 1, 2028. (This sits within the FERC Order 2222 framework that allows distributed resources into PJM capacity and energy markets.)
• Large-customer rate structures (commercial and industrial): Schedule MBR (the Market-Based Rate Pilot that passed PJM wholesale rates through to large C&I customers) is no longer accepting new participants. The new GS-5 rate class effective January 1, 2027 introduces minimum demand commitments for customers above 25 MW. Bring-your-own-generation (BYOG) and bring-your-own-capacity (BYOC) interconnection models are the national pattern for new hyperscale loads; no publicly-confirmed Dominion BYOC tariff structure exists beyond GS-5 today.
• Class-cost-of-service reform that updates the allocation factors deciding who pays for what within the existing capacity-recovery system. GS-5 is one example; deeper reforms (decoupling, performance-based ratemaking) have been adopted by other states but not yet by Virginia.

The capex bias is a structural headwind for flexibility. A regulated utility earns a guaranteed return on capital investments but typically does not earn a return on operational solutions like demand flexibility. This is the Averch-Johnson effect documented in regulatory economics since the 1960s: utilities have an incentive to prefer building infrastructure over operating it differently, even when flexibility would be cheaper for customers. The regulatory reforms that address this directly are decoupling (separating utility revenue from sales volume), performance-based ratemaking (paying utilities for outcomes rather than for capital deployed), and shared-savings mechanisms (utilities keep a portion of the savings flexibility programs deliver). Several states have implemented forms of these reforms; Virginia has not adopted comprehensive performance-based ratemaking.

The grid Dominion is operating today is more constrained than it was four years ago. PJM's own forecast captures the shift: the 10-year summer peak growth rate for the Dominion zone rose from 2.2% in PJM's 2022 Load Forecast Report to 5.4% in the 2026 report (winter growth rose similarly, from 2.6% to 5.1%). The planning horizon for the projects that would relieve those constraints stretches into the 2030s, and demand has been growing faster than the planning cycle. Among the available tools, demand flexibility operates on both timescales: it can be deployed in months rather than years (immediate peak-shaving and load-shifting that reduces the buildout pressure now), and it builds toward a longer-term grid where capacity is not the only lever and where customers who can move their consumption are paid for the grid value they create.

What to watch through 2027:

• The SCC's ruling on Dominion's July 2026 fuel-factor scenarios (Scenario 2 +$9.77 vs Scenario 1 +$21.79 for residential), pending.
• The 2025 Update to the IRP (PUR-2025-00184) and the large-load connection-queue docket (PUR-2026-00011) as both advance through SCC review.
• Dominion's GS-5 tariff sheet filing, with the rate class taking effect January 1, 2027.
• PJM's 2028/2029 Base Residual Auction in December 2026, which sets the capacity-cost level that flows into Dominion bills roughly a year later.
• The Dominion VPP Pilot enrollment ramp and dispatch performance from August 2026 onward, which will demonstrate whether residential and C&I aggregated flexibility can offset some of the buildout demand.

Until something changes, every Dominion customer class will continue to absorb the buildout costs the grid is financing on their behalf, residential most prominently. That has been the pattern. The case for demand flexibility is that it doesn't have to be.

Sources

Every dollar figure in this case study was reconstructed from Virginia State Corporation Commission tariff filings, with additional context from PJM Interconnection reports, Federal Energy Regulatory Commission orders, the Joint Legislative Audit and Review Commission's 2024 data-center study, and Piedmont Environmental Council expert testimony. Each Dominion rate component (base rates, the fuel factor, and the 15 active rate adjustment clauses) was traced to a specific SCC docket: for every rider, the approved cents-per-kilowatt-hour value, effective period, legal authority, and underlying revenue requirement come from the filing record. Original PDF filings are preserved with cryptographic checksums so that any future change to a primary source can be detected.

Calculation

Bills were reconstructed for three representative customer profiles month by month from June 2022 through June 2026: residential at 1,000 kWh per month (Schedule 1); mid-commercial at 30,000 kWh per month with a 75 kW peak (Schedule GS-2, mid-market); industrial transmission at 8 million kWh per month with a 15,000 kW peak (Schedule GS-4, transmission voltage). Each monthly bill sums every approved per-kWh tariff component (base generation, transmission, distribution, customer charge, fuel factor, and all active rider charges). State and local taxes and fee assessments are an unmodeled line item, which produces a small gap between the reconstructed tariff stack and the customer's total bill.

One scope note. The “clean energy mandates” bucket appears small in early 2022 because most of the explicit clean-energy riders were authorized under Virginia's 2020 Clean Economy Act and ramped onto bills beginning in late 2021. Pre-VCEA renewable compliance costs sat inside base generation rates and were progressively reclassified into the explicit clean-energy bucket as the new riders came online. The chart reflects what appeared on a customer's bill statement; the magnitude of post-2022 growth still primarily reflects real new buildout costs (offshore wind, utility-scale solar, small-modular-reactor pre-development).

Validation

The reconstruction was cross-validated against two independent anchors: (1) EIA Form 861 annual realized revenue per customer class for Dominion, 2018-2023; and (2) the SCC Voluntary Electric Utility Regulation annual typical-bill reports. Both anchors agreed with the tariff-stack reconstruction within the modeled scope. The 2023 SCC typical-bill figure was $129.01/mo for residential 1,000 kWh; the tariff-stack reconstruction averaged $117.86/mo for the same window, with the difference consistent with the unmodeled taxes and fee assessments noted above. The full source-document inventory, extraction code, per-month component dataset, and chart-rendering scripts are available on request pending publication of the project repository.