Practical solutions for managing affordability amid rapid demand growth
Electricity demand is no longer a distant planning assumption. It is arriving—faster and more unevenly than many forecasts predicted.
Electrification of buildings is accelerating. Data centers are clustering in specific service territories. Industrial reshoring is adding large point loads. In some regions, overall demand could rise by as much as 25% by 2030.
Nowhere are these dynamics more visible than in the PJM Interconnection, the nation’s largest wholesale electricity market, serving utilities across 13 states and the District of Columbia. Participation in PJM by utilities provides important benefits, including access to a large regional pool of generation resources and competitive pricing.
At the same time, PJM faces retirements of existing resources and long timelines to bring new capacity online. As a result, the risk to resource adequacy in PJM is high.
While all participating states share in the market implication of capacity prices, the impacts will not be uniform. Some states have already experienced significant load growth, while others are just beginning to account for sharper increases in their forecasts. Generation capacity also varies across the region—some states are long, others short. States facing both rapid load growth and limited in-state generation are likely to be the most exposed.
This article examines how Maryland has been especially impacted. For many years, Maryland policymakers have raised concerns about how regional capacity market outcomes affect local costs and reliability and do not provide policy flexibility. While Maryland has largely chosen to work within PJM’s market structure, it has also recognized that the tools available to manage near‑term risk at the state level are limited. Demand growth from data centers, especially in neighboring states, and the retirement of aging power plants is driving a surge in PJM capacity prices. For Maryland households, this translates to an expected 1.5%–5% increase in electricity bills by mid-2026 due to higher capacity charges alone.
Why PJM capacity conditions matter for Maryland
Maryland does not meet all of its capacity needs with resources located within the state. Instead, it relies on the regional nature of PJM, importing capacity from neighboring states when it is economical and available. This has worked well historically and is one of the strengths of a regional market.
However, that dynamic becomes more fragile when neighboring states face the same pressures at the same time. States that have traditionally supplied surplus capacity—such as Pennsylvania—are also experiencing strong load growth and planning for their own future needs. As more states compete for the same resources, the assumption that capacity will always be readily available from elsewhere becomes less certain.
For Maryland, this means that tightening PJM capacity conditions translate directly into higher prices and greater uncertainty for customers, even if some of the underlying drivers originate outside the state.
The near‑term reality: Limited ability to add supply quickly
The natural response to capacity concerns is to build more generation. Over the long term, new generation is an essential part of maintaining reliability. But the near‑term reality in PJM is that new supply cannot arrive fast enough to fully offset the scale and speed of demand growth.
Recent PJM projections show a widening gap between load growth and the pace at which firm, reliable new capacity can enter service over the next several delivery years. Even under optimistic assumptions, development timelines—including permitting, interconnection, financing, and construction—limit how much new generation can realistically be available in the near term.
This means that upcoming capacity auctions may clear under tighter conditions, not because markets are failing, but because physical solutions take time. Price signals alone cannot accelerate steel‑in‑the‑ground outcomes when the constraints are structural.
Three ways the near term could unfold
One way to think about the next few years is through three simplified scenarios:
- The best‑case scenario is that enough new generation enters service quickly and in the right locations to ease regional tightness. This outcome would stabilize prices and reduce risk, but current timelines suggest it is very difficult to achieve at scale in the near term.
- Some new generation arrives—primarily projects with advanced queue positions arrive, but not enough to fully offset rising demand. Capacity remains tight, prices stay elevated, and consumers remain exposed to volatility.
- This scenario assumes persistent shortages in the near term, with new generation facing development delays that prevent timely commercial operation while load materializes.
Across all three scenarios, generation helps—the addition of 1.5 to 2 GW of capacity has the potential to benefit consumers in Maryland’s Southwestern Mid-Atlantic Area Council Load Delivery Area, representing roughly 75% of Maryland’s demand, by $900,000 to $1,000,000 in each of the years examined. But generation additions alone are not sufficient in the near term.
Maryland’s options: Using more than one lever
Because near‑term solutions are limited, states like Maryland are actively considering a broader set of options to manage risk and protect consumers. This does not mean abandoning PJM markets. Those markets remain central to reliability and investment signals. But it does mean recognizing their limits under tight timelines.
One option is to preserve flexibility to evaluate a wider range of development approaches over time, rather than relying on a single path. Keeping multiple options available allows the state to respond as conditions evolve.
Another important lever is energy efficiency. Efficiency often receives less attention in capacity discussions, but it offers something rare in a tight market: speed. Efficiency programs can ramp within months. Managed charging can scale within a year. Community solar and storage deployments can be targeted to constrained nodes. Large-scale generation, by contrast, often requires multi-year development and interconnection timelines.
Reducing demand can often happen faster than building new supply, and it delivers immediate bill savings for customers. In a period of rising capacity prices, avoiding the need to procure incremental capacity can have meaningful affordability benefits. To be clear, even efficiency measures that have limited impact on peak demand have a very effective role in reducing customer bills and are critical counterbalance available for utilities and states to proactively pursue.
Strategic investments in storage and firm capacity remain essential for reliability, particularly during extreme weather events or prolonged peak periods. At the same time, distributed generation—such as community solar—can play a complementary role in diversifying supply and expanding access to locally sourced energy.
Community solar programs provide incremental capacity that can be deployed more quickly than large-scale generation projects and can broaden participation in the energy transition. However, the system value of distributed solar depends heavily on how it is integrated. When paired with storage or aligned with utility demand management programs, community solar can contribute more meaningfully to peak management and reduce exposure to wholesale price volatility.
In regions where interconnection timelines for utility-scale resources are extending and siting constraints are intensifying, distributed generation can provide portfolio flexibility. But like all supply-side investments, it must be evaluated within the broader context of load growth projections, transmission capability, and system reliability requirements.
States can also pursue measures that improve how the system uses existing infrastructure, such as demand flexibility, improved load forecasting, and targeted grid improvements. These actions do not replace long‑term supply, but they can reduce pressure on the system and buy time.
Looking ahead
Maryland’s challenge is not unique, but its impacts are local. Electric prices affect every household and business, and capacity outcomes in PJM flow directly through to customer bills. In a period of tightening conditions, the most resilient approach is a balanced one—leveraging markets, preserving state‑level flexibility, and deploying near‑term tools that protect affordability.
PJM markets remain important and reform must be actively pursued to provide a long-term solution, but states need to be prepared to manage risk when markets alone cannot resolve near‑term constraints, or when markets cycle, as they will. As capacity conditions tighten, prudence favors flexibility. Keeping doors open to a broad set of options—including new generation, targeted infrastructure investments, and demand‑side solutions—enables practical responses to near‑term constraints while helping manage cost and reliability risks faced by consumers.