2026 Virginia Energy Plan

Every four years the Commonwealth is required to produce the Virginia Energy Plan. It is completed in the first year of every governor’s term. The 2026 Virginia Energy Plan (VEP) was released by Governor Abigail Spanberger’s administration on October 1, 2026. Each VEP  has a 10 year horizon and serves as the Commonwealth's energy roadmap.

While it is a policy framework rather than a binding regulatory document, it explicitly sets the state's legislative agenda to handle surging electricity demand—driven primarily by data centers—while remaining on a legally mandated path to a net-zero power sector by 2050. Unfortunately, what the VEP does is choose the assumptions that would give the exact result the Administration wanted; a paper-thin justification that a rapid clean energy transition is the most cost-effective path forward. In execution in the real world, this plan is unlikely to work and the gap between modeling assumptions and physical grid limits threatens to trigger severe reliability issues and dramatic, unmodeled rate hikes for Virginia consumers.

Virginia utilized advanced capacity expansion modeling to analyze the trade-offs of four distinct paths forward. The assumptions imbedded in the models have a tremendous impact on the results. For example, Virginia assumed a moderate annual growth rate which is lower than the PJM forecast. In truth, the actual growth rate will simply be how much of the forecast load growth from data centers gets connected.

In addition, a key factor in determining what scenario costs the least to Virginians is the social cost or carbon and the health impacts from burning fossil fuels. Climate modeling developed over the past 20 years—such as the EPA framework—relies on an what now appears to be an artificially low 2% long term discount rate to arrive at the central SCC value of $190 per metric ton. Right now the risk free 30 year rate is 5.4%. At a 2% discount rate, $1 million in climate damages 100 years from now is worth roughly $138,000 today. At a 5.4% discount rate, that same $1 million in future damages shrinks to a present value of just $5,200. So, by using a low discount rate you make carbon reductions more valuable.

The Core Challenge: Balancing Data Centers & The Grid

•  Rapid Demand Growth: Virginia is facing its fastest load growth in over 80 years. Data center electricity usage now accounts for roughly one-third of the state's total energy consumption.
• The "Cost-of-Service" Shift: The plan addresses rising retail utility bills by targeting infrastructure cost attribution. It explicitly mandates that large electricity users must pay for the specific transmission and infrastructure upgrades required to support their growth, protecting residential ratepayers from subsidizing industrial buildouts.
• The Virginia Clean Economy Act (VCEA): The VCEA mandates that the Commonwealth's major electric utilities transition to 100% renewable energy by 2045 or 2050 through a combination of solar, onshore and offshore wind, energy storage, and efficiency improvements.

The VEP focuses primarily on Virginia’s electricity system and the path to a carbon free electric power  under the Virginia Clean Economy Act (VCEA), with some additional consideration of transportation energy use and costs. Currently, Virginia’s largest energy use is electricity generation to power homes, businesses, and industry, with petroleum for transportation the second largest use. In 2024, Virginia’s electricity supply was primarily from natural gas, nuclear power, and electricity imports, with solar and offshore wind playing a growing role

Virginia has always imported a significant share of the electricity it uses annually. Since 2020, imports have grown to meet rising electricity demand primarily of data centers while retiring coal capacity. Virginia imports about 30-40% of its annual electricity use—the highest percentage in the nation—making regional transmission capacity and PJM Interconnection (PJM) market conditions important factors in the Commonwealth’s reliability and electricity costs.

High-voltage transmission infrastructure serves as the bulk delivery backbone of the Commonwealth’s electric grid, moving power from large-scale generation facilities to local distribution networks. Virginia’s transmission system is primarily comprised of 500 kV lines that move electricity across Virginia, anchored by interstate connections in Northern Virginia to PJM and in Western Virginia by two 765-kV lines operated by APCo that connect to AEP’s regional multi-state network.

In recent years, however, rapid load growth in Northern Virginia combined with permitting and construction delays on major regional transmission projects has significantly constrained interstate import capacity. PJM’s latest reliability modeling indicates that Virginia’s import demand will exceed its physical transmission capacity by 2028.

Which brings us to transmission. The modeled pathway costs explicitly exclude full transmission and distribution infrastructure costs- which are socialized to all customers. The 2026 VEP calculates only new generation capacity, energy storage, fuel, and the rest of the supply hardware. These baseline numbers omit critical cost components of distribution.  The VEP estimated costs exclude the transmission and localized distribution infrastructure investments. They also exclude federal tax credits or the guaranteed utility return on equity (ROE) that utilities add on top of infrastructure investments.

 The Four Modeled Energy Pathways

Each pathway evaluates a different supply mix to achieve net-zero power sector emissions.

Pathway	Core Strategy	Key Mechanics & Impacts
Current Policies	Baseline Compliance	Adheres strictly to the Virginia Clean Economy Act (VCEA) targets and state participation in the Regional Greenhouse Gas Initiative (RGGI).
Distributed Flexibility	Demand Management & Small-Scale Gen	Administration's Preferred Approach. Targets 10 GW of distributed energy (e.g., rooftop solar, batteries) by 2045 and mandates a 10% demand flexibility threshold for data centers. Cuts total system costs by roughly 10% ($37 billion) through 2050 by shaving peak demand.
Distributed Flexibility + In-State Priority	Localization	Reduces reliance on out-of-state power imports by half, limits utility-scale solar land footprint, and aggressively replaces it with in-state advanced nuclear and offshore wind.
Distributed Flexibility + No New Gas	Accelerated Elimination	Completely prohibits new gas generation infrastructure. Relies entirely on immediate clean firm resources and intensive battery storage.

 Key Strategies & Structural Reforms

Utility Procurement & Regulatory Reform: Proposes moving away from traditional cost-of-service regulations that reward monopolies (like Dominion Energy) purely for capital spending. Instead, it recommends performance-based utility incentives tied directly to cost-effective ratepayer outcomes.

Clean-First Deployments: Prioritizes dual-use land strategies, including rooftop solar, parking canopies, brownfield redevelopments, and agrivoltaics to minimize the rural land footprint.

Non-Combustion Bridges: To maintain reliability during severe peak grid strain, the plan permits up to 5 GW of shorter-lived, low-emission, non-combustion natural gas resources (such as linear generators or fuel cells) as a bridge, avoiding multi-billion dollar commitments to long-lived fossil fuel infrastructure.

 

Political and Legislative Friction

The plan faces immediate pushback as the administration prepares legislative proposals for the upcoming General Assembly session. Legislative critics argue that the plan relies too heavily on solar infrastructure, depends on "social costs" rather than hard utility bill metrics to calculate affordability, and fails to adequately insulate everyday ratepayers from grid upgrade expenses driven by tech companies.

To make any of the plan’s four pathways achievable, Virginia and PJM must build generation at an unprecedented, historic pace. However, the physical process of connecting new power to the grid is structurally broken. PJM’s "interconnection queue" (the waiting list for new power projects to get approved to plug into the grid) is severely backlogged. It currently takes an average of 5 years for a solar or battery project to move from proposal to operation. In addition, there is an equipment problem. There is a severe global shortage of high-voltage transformers, circuit breakers, and specialized labor. Lead times for critical grid transformers are currently 3 to 4 years, making the rapid scale-up required by the "Distributed Flexibility" pathway nearly impossible to execute.

The Solar Surge: Historically, Virginia has deployed roughly 0.6 GW of utility-scale and distributed solar per year. To meet the preferred path, that pace must jump immediately to 2.5 GW per year—a 4.1x acceleration.

Other assumptions that challenge reality:

• Battery storage requires an even steeper logistical steepening. Moving from a negligible historical baseline (~0.05 GW/year) to the target required pace of 0.50 GW per year demands a massive 10x acceleration factor.
• Meeting these specific buildout targets under current supply chain constraints remains the plan's highest risk hurdle.
• Even distributed resources like commercial solar require massive local zoning battles. In Virginia, local county boards are increasingly passing strict setback rules and moratoria on new solar and battery storage facilities due to rural land preservation concerns.
• The plan relies on up to 5 GW of advanced non-combustion gas (like hydrogen or fuel cells) to act as a bridge. However, these technologies are not yet manufactured or deployed at the commercial utility scale. This is counting on energy technology that is yet to be developed commercially. 
• SMRs are required in all the plans, but are still entirely in the planning and licensing phases in the United States. Commercial deployment is not expected until the mid-to-late 2030s at the absolute earliest. Relying on up to 17 unbuilt, unpermitted reactors to balance the grid is not realistic.

The biggest assumption is that Virginia can reliably import 30% of its annual electricity consumption from its neighbors while simultaneously choking off its own fossil-fuel generation.

Virginia does not import electricity in a vacuum; it imports it through PJM Interconnection, the regional grid network that spans 13 states. The 2026 Energy Plan treats PJM as an infinite, clean power supply but PJM’s own data shows the pool is drying up:

• While Virginia is electrifying and building data centers, neighboring states like Ohio, Illinois, and Pennsylvania are experiencing their own data center booms and factory electrifications.
• PJM has repeatedly warned that fossil-fuel plants are retiring faster than new clean generation can get permitted and built. PJM projects that by 2030, the region could face a reliable capacity shortfall of up to 10 GW during peak weather events.
• When neighboring states face their own supply crunches, they will restrict exports to keep their own lights on. Virginia cannot import power that does not exist.

The for all of the above reasons, the VEP’s model functions as a closed math problem rather than an executable engineering plan. By holding the import cap at 30% while drastically underpricing the power, ignoring the physical 5,992 MW transmission bottleneck, and utilizing what appears to be a very low discount rate of 2%, the model successfully outputs the exact result the administration sought: a paper-thin justification that a rapid clean energy transition is the most cost-effective path forward.

The 2026 Virginia Energy Plan is an exercise in political and environmental signaling, designed to show how a net-zero grid could theoretically coexist with a massive tech boom on paper. I am disappointed. 

PJM and Dominion Energy are treating it as exactly that: a theoretical paper. In the real world, they are executing a pragmatic, "all-of-the-above" strategy that relies on physical steel in the ground, conventional natural gas, large-scale transmission lines, and strict data center mandates to ensure that when a citizen or a tech company flips a switch, the power actually comes on.

The entire plan can be found at this link: 2026 Virginia Energy Plan -For Publishing.pdf

Winter Forecast from NOAA

From the National Oceanic and Atmospheric Administration,NOAA.  El Nino Looms Large over U.S. Winter Outlook

URL: https://www.noaa.gov/news-release/el-nino-looms-large-over-us-winter-outlook

NOAA’s U.S. Winter Outlook shows the current El Nino will likely influence the upcoming winter months (December 2026 to February 2027), with warmer-than-average temperatures expected across the northern U.S.; wetter-than-average conditions likely across the southern U.S., from California to Florida, and along the Eastern Seaboard; and drought improving for the majority of the country, including areas in the East, Southern Great Plains and Southwest. After, the devastating rain last weekend in Florida, I thought to take a look.

“As we know from decades of observations, a very strong El Nino will likely bring a southward and eastward shift to the jet stream for the contiguous U.S., which tilts the odds toward stormier weather across the South,” said Ken Graham, director of NOAA’s National Weather Service. “While higher chances of rain and snow may bring relief to drought-afflicted areas, too much precipitation on dry soil can fuel destructive flash floods and mudslides. Now is the time for communities and individuals to plan ahead for the upcoming winter.” 

Precipitation Outlook

• Wetter-than-average conditions are most likely across the southern tier, from the Southwest to the Southeast, and along the East Coast.
• Elevated odds for drier-than-average conditions for Hawaii, much of Alaska, the northern Mountain West, some areas in the Great Lakes and the western Pacific Islands.
• Areas in the Intermountain West, northern Plains, Ohio Valley and Puerto Rico / U.S. Virgin Islands have equal chances of below-average, near-average or above-average seasonal total precipitation amounts. 

They weren’t kidding about that forecast. Over last weekend more than two feet of rain fell along portions of Florida in just a day and a half, from Sunday afternoon to Monday evening.

As reported in the Washington Post an event like this so rare that it had a recurrence interval of more than 1-in-1,000 years in some areas. This could be a sign of what’s to come with the powerful El Niño this winter. Nothing like Florida is expected here (though it was not expected there, either), but we are forecast to have above average precipitation this winter and above average temperatures- so it’s rain.

 

Temperature Outlook

• Warmer-than-average temperatures are favored for northern California, the Pacific Northwest, Midwest, Mississippi Valley, much of the East, Alaska and for Puerto Rico / U.S. Virgin Islands.
• Near-normal temperatures are most likely for parts of the Southeast including Florida.
• Hawaii and much of the Southwest have equal chances of below-average, near-average or above-average seasonal mean temperatures.

Drought Outlook

• Drought conditions are forecast to improve or end in the Southwest, Southern Great Plains, Southeast and parts of the East Coast.
• Drought conditions are favored to develop or worsen across parts of the northern Rockies, along with northeastern Oregon and eastern Washington.

About NOAA's seasonal outlooks

NOAA’s seasonal outlooks provide the likelihood that temperatures and total precipitation amounts will be above-, near- or below-average, and how drought conditions are anticipated to change in the months ahead. The outlook does not project seasonal snowfall accumulations as snow forecasts are generally not predictable more than a week in advance. NOAA’s Weather Prediction Center updates its three-month outlook monthly.

 

Water Is One System: Understand the Cumulative Risk Before Development Proceeds

 

The central question is not whether development should ever occur. It is whether Prince William County should approve large-scale development outside the 2040 Comprehensive Plan before it understands the cumulative consequences for the Occoquan watershed—a drinking-water source for nearly one million people. When the potential harm is regional, long-lasting, and difficult or impossible to reverse, uncertainty is not a reason to proceed. It is a reason to pause.

Water does not recognize parcel lines, zoning districts, or regulatory silos. Groundwater, streams, wetlands, stormwater, treated wastewater, reservoir chemistry, and drinking-water treatment are parts of one connected hydrologic system. A decision that reduces groundwater recharge, increases polluted runoff, alters stream flow, or diverts treated return flow affects the same finite supply. Dividing those impacts among separate permits and agencies does not divide the physical risk.

That is why watershed-scale warnings must guide parcel-level decisions. Cumulative damage is created one rezoning, one permit, and one project at a time. No single approval may appear decisive, but together they can push the watershed beyond a threshold that cannot be undone. Evaluating each proposal in isolation obscures the central issue: the combined effect of all approved, pending, and reasonably foreseeable development.

The recently completed LIMA, land-use analysis, may actually understate that combined effect. Its development assumptions were based largely on past growth patterns during the 2013-1015 period of extremely low construction, and on the zoning and development framework reflected in the Comprehensive Plan. Yet, what is happening on the ground is major rezonings and proposals outside that framework. Longleaf, Alderwood, and Hawthorn at Kettle Run alone account for more than 1,200 acres, with additional rezonings advancing in the central Broad Run area and high density residential or data center rezonings under construction or approved in Gainesville, Haymarket and Mid County. If the model does not include the intensity, location, and timing of these exceptions, it cannot reliably describe the future being approved on a one off basis by the Board of County Superviosors.

The consequences are not limited to a single pollutant or stream segment. Clearing, blasting, mass grading, and soil compaction can permanently alter infiltration, groundwater recharge, and stream baseflow. Additional impervious cover increases runoff, sediment, nutrients, dissolved salts, and heat. Industrial cooling can consume or evaporate water that would otherwise remain in the system, while reduced or degraded return flows can weaken reservoir inflow during drought. These effects interact; they must be evaluated as a system.

Mitigation does not eliminate this concern. Stormwater ponds, filters, operating rules, and treatment upgrades can reduce some impacts, but they cannot recreate intact headwaters, uncompacted soil horizons, mature root systems, or the original subsurface pathways that store, filter, and slowly release water. Nor can conventional treatment easily remove every dissolved salt or persistent chemical introduced by more intensive development. Once the natural system is replaced, the public inherits the residual risk and the long-term cost.

This is also an issue of who benefits and who bears the consequences. Developers may capture the immediate financial gain from rezoning and construction, while water customers and taxpayers bear the cost of treatment upgrades, lost storage, drought vulnerability, and damage that may not appear until years later. Public officials should not transfer an irreversible regional risk to residents without first establishing, through credible cumulative analysis, that the watershed can absorb the proposed growth.

We Have Seen This Pattern Before

The rapid expansion of data centers offers a warning. Localities approved projects in a piecemeal fashion before fully accounting for their combined demand on generation, transmission lines, substations, land, and ratepayers. Only after many approvals were in motion did the scale of the strain on the power grid become clear. We should not repeat that sequence with water: approve first, discover the systemwide consequences later, and then ask the public to pay for emergency infrastructure or live with diminished reliability.

The wiser course is informed development within the Comprehensive Plan unless and until updated modeling accounts for the full buildout now being proposed, the interaction of water quantity and water quality, more intense storms and drought, industrial water use, wastewater return flows, and the combined effect of projects already approved or pending. The analysis must come before irreversible land disturbance, when public officials still have meaningful choices.

Water is one system. Before approving development that could permanently alter the Occoquan watershed, the County should understand the cumulative impact—not gamble a regional drinking-water supply so private developers can realize immediate gains while the public absorbs the long-term damage and costs.