BEFORE THE
PUBLIC SERVICE COMMISSION
OF THE DISTRICT OF COLUMBIA
IN THE MATTER OF THE INVESTIGATION INTO ENERGY AFFORDABILITY IN THE DISTRICT OF COLUMBIA
Formal Case No. 1186
TESTIMONY OF MATTHIAS PAUSTIAN ON BEHALF OF THE SIERRA CLUB
Chairman Thompson and Commissioners of the Public Service Commission of the District of Columbia, thank you for the opportunity to testify. My name is Matthias Paustian, I am with the Sierra Club DC Chapter, and I want to make one central point today: local regulators absolutely do have significant control over the generation-related portion of DC electricity bills.
Too often, generation costs are treated as if they are simply dictated by PJM Interconnection wholesale markets or global fuel prices. But procurement strategy, distributed generation policy, demand response design, and rate structure all materially affect what District residents ultimately pay for the generation portion of their bill. Leading jurisdictions around the country no longer treat generation costs as something simply imposed on them by wholesale markets; instead, they actively manage procurement risk, shape load curves, deploy flexible demand, and use distributed energy resources (DERs) strategically to reduce wholesale market exposure and customer bills. DC has the tools to do the same, but we must act with far greater urgency and scale.
I. OPTIMIZING STANDARD OFFER SERVICE PROCUREMENT STRATEGIES
Most DC residential customers receive power through Standard Offer Service (SOS), meaning the utility procures electricity on their behalf under Commission-approved rules. Today, default retail supply remains heavily exposed to short- and medium-term wholesale market pricing—a reality that represents a major missed opportunity for District ratepayers.
- Around 2020, renewable PPAs in PJM were being signed at prices near $35 per megawatt-hour.
- By comparison, in the first quarter of 2026, average PJM locational marginal prices (LMP) soared to roughly $88 per megawatt-hour.
- If DC had locked in a substantial portion of SOS supply through long-term, fixed-price renewable contracts several years ago, customers today could be paying substantially lower and more stable generation prices.
- If 50 percent of the SOS load had been secured near those earlier PPA prices, District ratepayers could plausibly be saving tens of millions of dollars annually today.
This baseline cost difference illustrates a critical economic principle: renewable energy is not only climate policy; it is price stability policy. Because solar and wind have no fuel costs, once contracts are signed, prices remain stable for decades. This stands in sharp contrast to fossil-fuel-based generation, which remains continuously exposed to commodity and wholesale market volatility.
Commission and Jurisdictional Precedent: This Commission has recently taken a commendable step toward fixing this issue. In Order No. 22702 (released August 14, 2025), the Commission expanded its initial 5% renewable pilot program and formally ordered Pepco to procure an additional twenty percent (20%) of the SOS load via long-term Renewable Power Purchase Agreements (PPAs), bringing the cumulative default procurement target to twenty-five percent (25%).[1]
While this order is an important step forward for ratepayers, Pepco must be ordered to execute these PPAs immediately. Market dynamics require fast implementation to lock in favorable pricing before wholesale markets experience further strain. Furthermore, the Commission should not stop at 25%. Given the ongoing commodity price risk within PJM, the Commission should immediately map out an expansion of this framework to target fifty percent (50%) of the default SOS load under long-term, fixed-price renewable hedges.
II. STRATEGIC DEPLOYMENT OF LOCAL SOLAR AND BATTERY STORAGE
Local solar generation directly reduces PJM generation costs and wholesale market purchases because every megawatt-hour generated locally is a megawatt-hour not purchased from the wholesale market. Solar output aligns strongly with high-demand summer afternoons (roughly 4 PM–7 PM), precisely when PJM wholesale prices can spike into the hundreds of dollars per megawatt-hour during grid stress events.
Those are exactly the hours when solar is still producing and co-located batteries can discharge into the grid. Together, a synchronized solar-plus-storage strategy reduces high-cost wholesale purchases during peak hours; peak demand that drives PJM capacity charges; transmission congestion and system losses; and future utility distribution infrastructure investment needs.
The cost of installing solar in DC is about two to three times as high as in Europe or Australia, and a key driver of the cost difference is permitting and interconnection related costs. The PSC must act to interconnect expeditiously and limit Pepco charges for grid related upgrades. In doing so, the PSC can speed up the pace of building out local solar and hence lower RPS compliance costs by driving down SREC prices.
Batteries effectively extend these economic benefits into evening peak periods when prices remain elevated. Leading states increasingly treat distributed solar and storage as active grid cost management tools rather than only environmental resources, and the District should follow their blueprint.
District-Specific Data and Regional Precedent: The District’s Department or Energy and the Environment (DOEE) has modeled these significant cost-mitigation opportunities. In a comprehensive study entitled 'The Benefits of Energy Storage for Washington, D.C.', released by DOEE and prepared by the Pacific Northwest National Laboratory (PNNL), researchers explicitly modeled how scaling local storage within the District suppresses rising PJM wholesale obligations.[2] According to the DOEE/PNNL findings, deploying behind-the-meter and front-of-the-meter battery storage systems can lower electricity costs. Under realistic market sensitivities, the study demonstrates that local energy storage serves as an effective mechanism to reduce costs associated with buying power from PJM.
Regionally, the Maryland Public Service Commission pioneered implementation of this strategy via its Energy Storage Pilot Program under Case No. 9619.[3] Under this directive, Maryland utilities deployed varied ownership models for storage assets specifically tailored to defer traditional distribution infrastructure investments, smooth peak load curves, and lower PJM capacity clearing liabilities, returning value directly to ratepayers.
III. DEMAND RESPONSE EXPANSION AND VIRTUAL POWER PLANTS (VPPS)
PJM capacity costs are fundamentally driven by a small number of peak hours each year, meaning that small reductions in peak demand can yield outsized cost savings. The District already possesses the necessary advanced metering infrastructure (smart meters) but severely underuses it. A modern, targeted demand response portfolio should encompass automated thermostat programs, EV managed charging initiatives, commercial load controls, smart water heaters, and coordinated battery dispatch. A modest 3% to 5% reduction in peak demand during critical PJM peak hours could save tens of millions of dollars annually in capacity costs.
Jurisdictional Precedent: Vermont has moved forward in this space. The Vermont Public Utility Commission approved Green Mountain Power’s (GMP) innovative regulatory framework that aggregates distributed, customer-owned home batteries, EVs, and smart appliances into Virtual Power Plants (VPPs) Similarly, the Maine Public Utilities Commission has advanced virtual power plant initiatives establishing frameworks to aggregate distributed energy resources to participate as wholesale market capacity hedges, reducing the overall system cost burden for non-participating ratepayers. DC should adopt these exact models at scale.
IV. IMPLEMENTATION OF REAL-TIME AND DYNAMIC RATE DESIGN
Most DC customers still face relatively flat utility rates that fail to reflect real, fluctuating system costs. In reality, wholesale electricity prices vary dramatically by the hour.
Jurisdictional Precedent: The California Public Utilities Commission (CPUC) has started to change retail rate architectures through its Demand Flexibility Rulemaking (R.22-07-005).[4] By implementing advanced 'Price-Based Grid Coordination' systems, California has shifted toward deployment of real-time, dynamic retail rates. These hourly price profiles allow customer-owned flexible demand technologies—such as building automated management systems and networked EV chargers—to automatically shift load in response to real-time grid and wholesale price signals.
Modern systems allow thermostats, EV chargers, and batteries to respond automatically to these real-time price signals. By establishing clear economic incentives for customers to shift usage away from high-priced hours, the District can reduce overall peak demand and significantly lower generation, transmission, and capacity costs. Total ratepayer savings from these market-responsive mechanisms could plausibly reach tens of millions of dollars annually over time.
V. CONCLUSION
The core takeaway is clear: generation charges are not outside local regulatory control. Procurement design matters, distributed energy policy matters, demand response matters, and rate design matters. Leading jurisdictions actively manage these levers to shield consumers from market volatility. DC can and should do the same.
Thank you.
Date submitted: June 2, 2026
Respectfully submitted,
Matthias Paustian, Ph.D.
FOOTNOTES
[1] See Public Service Commission of the District of Columbia, In the Matter of the Designation and Development of Standard Offer Service in the District of Columbia, Formal Case No. 1017, Order No. 22702
[2] See Pacific Northwest National Laboratory (PNNL) for the District Department of Energy and Environment (DOEE), Benefits of Energy Storage for Washington, D.C.: Analysis for the Department of Energy and Environment (Report No. PNNL-38942.)
[3] See Maryland Public Service Commission, In the Matter of the Maryland Energy Storage Pilot Program, Case No. 9619, Order No. 89664 .
[4] See California Public Utilities Commission, Order Instituting Rulemaking to Advance Demand Flexibility Through Electric Rates, Rulemaking (R.) 22-07-005.