Solar demand charges: what panels and batteries change

Solar demand charges hinge on one number: your building’s highest short-term power draw, in kilowatts (kW). Panels trim it only if they’re producing when that peak hits. In a 2020 Berkeley Lab study, solar sized for half of annual use cut billing demand by a median 7 percent.¹ Solar plus storage cut it 42 percent, an upper bound.²

What does a demand charge look like on Pepco, BGE and Dominion bills?

A demand charge bills the highest power a building drew in one short interval, in kilowatts. The energy charge bills total use in kilowatt-hours (kWh). Pepco, Baltimore Gas and Electric (BGE) and Dominion Energy Virginia each measure a 30-minute interval on the schedules covered here, so the schedule name on your bill sets the rules.^3,4,5,6

The U.S. Energy Information Administration (EIA) defines a demand charge as the part of a bill “based on the consumer’s maximum electric capacity usage.”³ Your bill can carry several kilowatt lines. One covers the wires. Others can cover supply and transmission, depending on the utility and on whether you buy supply from a competitive supplier.^5,6

The table shows where the kilowatt charge sits on four business schedules. Rates are as of October 25, 2026, and each utility publishes them by date, so read the column that covers your billing month.

The delivery-side charges run from $3.316 to $5.52 per kilowatt-month.^4,5,6,7 Supply-side kilowatt lines come on top of that. A demand rate on a vendor slide, or from another utility’s tariff, won’t match yours, so pull the kilowatt lines off your own schedule before you judge what a peak costs.

Two of these numbers have an expiry date. Pepco’s tariff lists its rate columns by date, and its filing carries them only through October 31, 2026. The $3.7982 kilowatt charge is the same figure the tariff shows from April 1, 2024 through August 10, 2026, with a $4.1991 column for August 11 to 27, 2026 in between.⁴ Check Pepco’s current filing for November onward. BGE has a rate case open. The Maryland Public Service Commission (PSC) announced on July 6, 2026 that BGE had filed one, docketed as Case No. 9888. It expected a decision in January 2027 and said current BGE rates are frozen until then.⁸ The PSC scheduled public comment hearings for October 26, November 4 and November 18, 2026, each at 6:30 p.m.; the case page on the PSC site shows what came of them and what happens next.⁹

Can panels alone cut a demand charge?

Only a little. One 30-minute peak sets the charge, and in many buildings that peak lands in the late afternoon or evening, when panels produce less. In the 2020 Berkeley Lab study, solar sized to produce half of a building’s annual use cut billing demand by a median of 7 percent.¹

The same study put the cut under 15 percent in about 90 percent of its commercial cases.¹ It simulated 15 commercial building types in 15 cities, Baltimore among them, using weather data from 1998 to 2014.^10,1 The buildings and weather are generic, so no result describes a particular Maryland or Virginia site.

How the utility writes the demand charge changes the answer. Panels did best when the billed peak was limited to a daytime window.

Median commercial cut, solar alone

• Basic: monthly maximum at any hour7 percent of billing demand
• Peak limited to 12 to 4 p.m.19 percent

View the data as a table

Demand-charge design in the 2020 study	Median commercial cut, solar alone
Basic: monthly maximum at any hour	7 percent of billing demand
Peak limited to 12 to 4 p.m.	19 percent

Rows without a single number are not drawn: Basic, 2-hour averaging interval.

Now hold that up against the schedules above. Pepco’s MGT LV II and Dominion’s GS-2 bill the monthly maximum at any hour.^4,6 BGE’s Schedule GL splits it. Delivery demand counts in any rating period, but generation and transmission demand count only in the peak period. That period runs 10 a.m. to 8 p.m. on summer weekdays, so it covers the whole solar day. In the non-summer months it shrinks to 7 to 11 a.m. and 5 to 9 p.m. on weekdays, and the 11 a.m. to 5 p.m. stretch, when panels produce the most, is an intermediate period that carries no generation or transmission demand.⁵ None of the four schedules averages over two hours, so read the 2-hour row as a caution, not a forecast.

Turning panels west to chase a later peak helped only a little. For a school in Phoenix under the 12 to 4 p.m. design, the cut was 31 percent with south-facing panels and 34 percent with southwest- or west-facing panels.¹

Net metering leaves the demand line alone too. Pepco’s net energy metering rider says “only the per kilowatt-hour charge components of the Customer’s bill are affected,” and that the customer charge and demand charge are not.¹¹ BGE’s Rider 18 bills a customer-generator under the charges that would apply without the generator.¹² Solar lowers the energy line first. The demand line moves only when the sun and the peak overlap.

How does a battery trim a peak?

A battery charges while demand is low and discharges as the building nears its highest 30-minute draw, so the utility meter records a lower peak. Two ratings matter: power in kilowatts, to cut the peak, and stored energy in kilowatt-hours, to last through it. Its controls decide whether it acts in time.¹⁰

Power caps what the battery can deliver at once; usable energy caps how long it keeps delivering. The worked example further down shows two battery sizes holding the same power for different lengths of time.

Small can be enough. In a 2015 report, the National Renewable Energy Laboratory (NREL, now the National Laboratory of the Rockies, or NLR) simulated 98 commercial facilities. Small, short-duration batteries were the most cost-effective, trimming load spikes on the order of 2.5 percent of peak demand.¹³ That result rests on 2015 equipment costs and one set of rate structures, so test it against current prices and your own tariff.

Two limits show up in practice:

• Perfect foresight. The Berkeley Lab study dispatched storage knowing the day’s load in advance, at 83 percent round-trip efficiency and a three-hour duration.¹⁰ Its authors call the results an upper bound on storage performance.¹⁰ A real controller has to guess, so expect less.
• Look-backs. Where a schedule remembers the highest interval, one missed peak can set the billed demand for months. Dominion’s GS-3 reads the highest 30-minute average across the current and previous 11 billing months.⁷

Do you need solar panels to use a battery for peak shaving?

No. A battery can cut demand peaks without panels, charging from the grid when demand is low. Pooled across the Berkeley Lab study’s commercial simulations, with storage dispatched with perfect foresight, the median cut was 8 percent for solar, 23 percent for storage and 42 percent for both.² Combined, they beat the two cuts added up in almost all cases.

A 2015 report from the National Renewable Energy Laboratory (NREL) asked a different question, so the two don’t conflict.

The first tells you how far the peak falls; the second, what a battery adds to the bill. Whether panels belong in the project also depends on the energy savings, not only the peak.

Why does a demand line rarely reach zero?

Even solar plus storage, the strongest case in the 2020 study, had a median cut of 42 percent, not 100.² One missed interval sets the month’s peak, some schedules carry a peak forward, and several bill lines never depend on your peak.

Four things keep a demand line on the bill:

• Supply-side kilowatt lines. BGE’s standard offer service includes generation and transmission demand and energy charges.¹⁴ Dominion’s GS-2 adds generation and transmission demand charges to the distribution charge.⁶
• Floors and look-backs. GS-2 holds billed demand at the highest of the past 12 billing months once a customer has reached 500 kW.⁶ GS-3 uses the highest of the current and previous 11 months, or 500 kW.⁷ On GS-3, on-peak supply demand can’t fall below 75 percent of the highest on-peak demand in June through September of the preceding 11 billing months.⁷
• Fixed charges. BGE’s Schedule GL sets a minimum charge equal to the net delivery customer charge.⁵
• Net metering. Pepco’s rider leaves the demand charge alone.¹¹

A worked example: one 250 kW peak on three tariffs

This example shows what a given percentage cut is worth on each tariff. It forecasts no building. The percentages are the study’s pooled medians, which are upper bounds, borrowed as scenarios; your own interval data decides the real number. Use the dollar figures to compare tariffs, not to predict a bill.

The same percentage cut is worth more on a higher kilowatt charge, so the tariff matters as much as the equipment. Weigh the savings against installed cost, operating cost and tax treatment before you decide. The guide to modeling a commercial solar return walks through that fuller comparison.

What should you gather before you ask for proposals?

Start with your schedule name, 12 months of interval data and your supply contract. All three come from your bills and your utility, and they let every bidder model your real peak instead of an average building. Then work through the list below in order.

1. Find the schedule name on a recent bill and read its billing-demand paragraph. The word “demand” alone isn’t enough, because the interval, window and look-back differ.
2. Request 12 months of interval data from your utility or supplier. The schedules covered here measure 30-minute demand, so monthly totals hide the peaks.
3. Mark the interval that set each month’s peak: the hour, the weekday and the season. Compare each with the solar window and any peak period in the schedule.
4. List the kilowatt lines separately: the distribution line, any supply and transmission kilowatt lines, and any capacity tag (next section).
5. Look for a floor or look-back, and note whether one high interval carries into later months.
6. Have each bidder show its interval-data simulation, including the case where the peak doesn’t fall, and say which charges it counted.
7. Talk to a qualified tax professional about which credits apply before you count any of them.

Your schedule can also change under you, and the answer changes with it. Pepco’s MGT LV III applies to accounts with a capacity peak load contribution of 600 kW or more, measured by PJM Interconnection (PJM), the regional grid operator.⁴ Dominion moves a customer to GS-3 once demand has reached 500 kW in three billing months.⁷ A new tariff out of the open BGE case could reset the numbers too.⁸

How is a capacity tag different from a demand charge?

A capacity tag, called a peak load contribution (PLC), is set from your load during the grid’s highest system hours, not from your own monthly peak. BGE publishes the method. Because the tag follows system hours rather than your building’s peak, the two can call for different battery timing.¹⁶

BGE’s supplier page describes two tags. The capacity tag comes from the five highest weather-normalized PJM system hours between June 1 and September 30, averaged after the summer ends. A separate network transmission tag comes from the five highest unrestricted load hours in the 12 months ending October 31 of the prior year.¹⁶ You won’t know which hours counted until the period is over. Your supply contract spells out how the tag reaches your bill, so read that clause. For the market behind the tag, see the guide to PJM capacity prices and your electric bill.

Which incentives and rules touch a commercial battery in Maryland?

Two programs matter most: the federal investment credit in section 48E of the tax code, and the Maryland Energy Administration (MEA) storage rebate. Have a tax professional check any tax credit before you count it as money in hand. Virginia and DC storage incentives are outside this page.

The rebate’s eligibility rules are in the MEA announcement, so read them before you plan around the money. The federal credit for the solar side has its own cutoffs, covered in the commercial solar tax credit deadline guide. For the wider cost picture, see the guide to commercial battery storage in Maryland.

When won’t these numbers fit your account?

The examples break down in several situations: the account has no demand line, a schedule carries a peak forward, the demand design differs from the study’s, a competitive supplier changes the supply-side lines, or a different utility applies. Find your situation below.

Will a peak-shaving battery keep the lights on?

Not by default. A standard grid-tied solar system shuts down when the grid goes down, to protect line workers. To run on its own it has to island, meaning isolate itself from the grid safely with extra power-management electronics. The U.S. Department of Energy (DOE) adds that it needs a properly configured inverter and a storage system.^21,22

A battery bought for peak shaving may not be wired to any backup circuit, so ask the designer which circuits it would carry. Energy held back for outages can’t also cut peaks, so the design has to split the two jobs. Permits are part of any installation. Montgomery County’s Department of Permitting Services, for example, says rooftop solar projects need a building permit and an electrical permit.²³ Your own authority may differ.

Next step for a commercial project

Soleil Energy’s solar engineering, procurement and construction page describes an assessment step that starts with the site and the load.²⁴ The battery storage page covers storage for homes and businesses and retrofits to existing solar. If your project also needs a utility connection, the commercial solar interconnection guide walks through the process. To start a conversation, tell Soleil Energy about the site and the load: Request a proposal or call (301) 953-4140.

Solar savings and incentive eligibility depend on your roof, your usage, your utility, and your tax situation. Incentive programs change and some have limited funding. We are not tax advisors — we will review your bill with you and tell you what you may qualify for. Confirm any tax credit with a qualified tax professional.

Program rules decide who qualifies. Ask any installer whether it is on the program’s contractor list.

Sources (24)

1. Same source as ¹⁰, results for standalone solar; read October 25, 2026. ↩ ↩² ↩³ ↩⁴ ↩⁵ ↩⁶ ↩⁷ ↩⁸

2. Same source as ¹⁰, results for solar plus storage, commercial simulations pooled across building types, cities and system sizes, perfect-foresight storage; read October 25, 2026. ↩ ↩² ↩³ ↩⁴ ↩⁵ ↩⁶

3. U.S. Energy Information Administration, Glossary: demand charge, undated page; current page, read October 24, 2026. ↩ ↩²

4. Pepco, Maryland electric tariff, P.S.C. Md. No. 1, current update effective October 1, 2026; Schedules MGT LV II (pages 7 to 7.2) and MGT LV III (page 7.3), pages issued August 14, 2026, rate columns listed through October 31, 2026; read October 25, 2026. ↩ ↩² ↩³ ↩⁴ ↩⁵ ↩⁶ ↩⁷ ↩⁸ ↩⁹ ↩¹⁰ ↩¹¹ ↩¹² ↩¹³ ↩¹⁴

5. Baltimore Gas and Electric Company, Retail electric service tariff, Schedule GL, pages 47 to 48-A, P.S.C. Md. E-6; rate table filed January 12, 2024 with Rate Year 3 effective January 1, 2026; page 48-A filed April 30, 2026, effective May 1, 2026; read October 25, 2026. ↩ ↩² ↩³ ↩⁴ ↩⁵ ↩⁶ ↩⁷ ↩⁸ ↩⁹ ↩¹⁰ ↩¹¹

6. Virginia Electric and Power Company (Dominion Energy Virginia), Schedule GS-2, Intermediate General Service, filed December 9, 2025, effective for usage on and after January 1, 2026; read October 25, 2026. ↩ ↩² ↩³ ↩⁴ ↩⁵ ↩⁶ ↩⁷ ↩⁸ ↩⁹ ↩¹⁰ ↩¹¹ ↩¹² ↩¹³

7. Virginia Electric and Power Company (Dominion Energy Virginia), Schedule GS-3, Large General Service, Secondary Voltage, filed December 9, 2025, effective for usage on and after January 1, 2026; read October 25, 2026. ↩ ↩² ↩³ ↩⁴ ↩⁵ ↩⁶ ↩⁷ ↩⁸ ↩⁹

8. Maryland Public Service Commission, news release “BGE Seeks $156 Million Electric Rate Increase”, July 6, 2026, Case No. 9888; read October 25, 2026. ↩ ↩²

9. Maryland Public Service Commission, news release “November 18 Public Comment Hearing on BGE Electric Rate Application Changed to In-Person Meeting”, October 6, 2026; read October 25, 2026. The release says the October 26 and November 4 hearings stay virtual and November 18 is in person. ↩

10. Darghouth and colleagues, “Demand charge savings from solar PV and energy storage,” Energy Policy 146 (2020) 111766, Berkeley Lab and NREL, available online August 25, 2020, methods sections; read October 25, 2026. ↩ ↩² ↩³ ↩⁴ ↩⁵ ↩⁶ ↩⁷

11. Pepco, Maryland electric tariff, Rider NEM (net energy metering), section E, page 31, issued May 1, 2026; same document as ⁴; read October 25, 2026. ↩ ↩²

12. Baltimore Gas and Electric Company, Retail electric service tariff, Rider 18, Net Energy Metering, pages 97 to 98-A, Suppl. 690 filed November 15, 2022, effective December 14, 2022; read October 25, 2026. ↩

13. Neubauer and Simpson, Deployment of Behind-The-Meter Energy Storage for Demand Charge Reduction, NREL/TP-5400-63162, January 2015; read October 24, 2026. ↩ ↩²

14. Baltimore Gas and Electric Company, Retail electric service tariff, Rider 1, Standard Offer Service, page 76, filed December 21, 2022, effective February 1, 2023; read October 25, 2026. ↩

15. Illustrative calculation, run October 2026, with the inputs sourced at ⁴, ⁵ and ⁶, and the scenario percentages sourced at ². ↩

16. Baltimore Gas and Electric Company, Peak Load Contribution (PLC) Overview, supplier site, undated page; current page, read October 25, 2026. ↩ ↩² ↩³

17. 26 U.S.C. 48E, subsections (a)(2)(B), (c)(3) and (e)(4), text as amended through Pub. L. 119-21 (July 4, 2025); current page, read October 25, 2026; and Public Law 119-21, section 70513(g)(5), read October 25, 2026. Not tax advice. ↩

18. Maryland Energy Administration, FY27 Residential and Commercial Energy Storage Program Funding Opportunity Announcement, issued September 24, 2026, sections 7 and 10 to 11; read October 25, 2026. ↩

19. Maryland Energy Administration, Residential and Commercial Energy Storage Program page, budget table headed “Total FY26 RCES Grant Program Budget” on the FY27 program page, with “Last Update to Total Budget Reserved: October 19, 2026”; current page, read October 25, 2026. ↩

20. Baltimore Gas and Electric Company, Retail electric service tariff, Schedule G, page 43, filed January 12, 2024 with Rate Year 3 effective January 1, 2026; read October 25, 2026. ↩

21. National Laboratory of the Rockies (formerly NREL), Will Solar Panels Help When the Power Goes Out?, NREL/TP-7A40-75704, March 2020; read October 24, 2026. ↩

22. U.S. Department of Energy, Solar and Resilience Basics, undated page; current page, read October 24, 2026. ↩

23. Montgomery County Department of Permitting Services, Commercial Solar Building permit process, undated page; current page, read October 25, 2026. One example of a permitting authority. ↩

24. Soleil Energy, utility-scale solar page and battery storage page, current pages, read October 25, 2026. ↩