Maryland and DC business energy: BGE and Pepco

A corridor of separate territories, each in its own PJM zone

The Baltimore-Washington corridor is not one market. It is four Maryland distribution territories plus the District, and each maps to its own wholesale zone inside PJM, the regional transmission organisation. BGE serves Baltimore City and much of central Maryland; Pepco serves Montgomery and Prince George's counties and the District of Columbia; Delmarva Power covers the Eastern Shore; and Potomac Edison serves western Maryland as the PED sub-zone of PJM's Allegheny Power System zone. PJM identifies the BGE zone as lying entirely within Maryland and the Pepco zone as covering its Maryland territory and the District, while the Delmarva and APS zones cross state lines. That matters because PJM prices capacity by locational deliverability area, so the constraint that sets a capacity price can differ between the BGE zone and the Delmarva system even though both are in the same state. A supplier pricing a Baltimore warehouse and an Eastern Shore cold-storage site is pricing two different grid paths, and the offers should reflect it. Delivery stays tariff-set and identical whichever supplier serves the meter; only the supply half of the bill changes.

• Four Maryland electric territories plus Pepco in the District.
• Each maps to a PJM load zone: BGE, Pepco, DPL, and PED within APS.
• Capacity deliverability areas such as BGE and DPL-South are not the same as retail territories.
• Delivery charges are tariff-set and identical whichever supplier you choose.

Default supply is a market product here too

A business that never chose a supplier receives the utility's Standard Offer Service, and in Maryland that is a procured market product rather than a penalty rate. The utility takes bids through competitive solicitations regulated by the Public Service Commission, with bids taken twice a year for residential and small commercial customers and quarterly for large commercial accounts, and with contracts laddered across delivery periods so the default price reflects a portfolio of purchases over time rather than one annual buy. The largest industrial accounts pay a variable rate tied to hourly market prices instead of a fixed procurement period. Commission materials describe the supply cost as passed through without an additional utility markup on the commodity itself, because the utility earns on delivery, not on the energy it resells. The practical consequence is that the default is a legitimate benchmark: a competitive offer that is not clearly better than the current Standard Offer Service price, on the same usage and term, is not obviously worth taking, and the default price moves on a published calendar rather than at a supplier's discretion.

• Capture your current default or contract price before comparing offers.
• Maryland takes small-customer Standard Offer Service bids twice a year and large commercial bids quarterly.
• The largest industrial accounts pay a variable hourly Standard Offer Service rate.
• Default service is also an option - choose it deliberately rather than by default.

The same wires, two regulators

Pepco serves both sides of the line, but the District of Columbia and Maryland are separate jurisdictions with separate commissions and separate rulebooks. A District address falls under the DC Public Service Commission and the District's Title 15 DCMR utility rules; a Maryland address falls under the Maryland Public Service Commission and Maryland law. Pepco's District tariffs set out commercial schedules by class and state that a customer without an alternative supplier receives generation and transmission through the Standard Offer Service. The split is not cosmetic. The licensing regime, the disclosure requirements, the aggregation rules and the default-service procurement calendar all differ, and a multi-site organisation with offices in Bethesda and downtown Washington is buying in two jurisdictions even though one utility delivers to both. Blending them into a single regional pricing request produces a number that cannot be priced accurately, because the two halves answer to different regulators.

• A District address answers to the DC PSC; a Maryland address to the Maryland PSC.
• Pepco still delivers on both sides; only the supply arrangement changes.
• The District's utility rules sit in Title 15 DCMR.
• Do not blend District and Maryland sites into one pricing request.

Licensing: what the Commission authorises, and what it does not

Maryland licenses electricity suppliers under Title 20, Subtitle 53 of the Code of Maryland Regulations. A supplier files an application identifying its ownership, officers and affiliates; demonstrates the financial and operational capability to serve Maryland load; maintains customer-protection procedures covering billing, deposits, complaints, contract disclosure and termination; and posts financial security where the Commission requires it. The licence is a state retail-supply authorisation. It permits the supplier to solicit and enrol Maryland customers, but it does not by itself guarantee access to a utility's distribution system or to PJM transmission service, so a supplier that serves load directly must also register for PJM market participation and meet the transmission, capacity, scheduling and settlement requirements that go with it. For a buyer the licence number is the first thing to check, because an offer from an unlicensed marketer is not one the Commission's complaint process can reach.

• Maryland suppliers are licensed under COMAR Title 20, Subtitle 53.
• The licence authorises retail supply; it does not itself grant distribution or PJM transmission access.
• A supplier serving load directly must also register for PJM market participation.
• Verify the licence number before treating an offer as actionable.

PJM capacity costs sit inside the supply price

Maryland and the District sit in PJM, whose capacity market pays for generation availability ahead of the delivery year, and those costs are recovered through the supply portion of a commercial bill rather than through delivery. That makes capacity behave like a market input: an offer embeds an assumption about future capacity costs, and any component written as a pass-through instead moves with the auction result. PJM's capacity market also prices locational deliverability areas, so the constraint that sets a capacity price can differ between the BGE zone and the Delmarva system, and a supplier pricing two Maryland sites may be carrying two different capacity assumptions. The practical test on any quote is to establish, in writing, which components are fixed for the term and which are passed through. A fixed energy price with a floating capacity adder is not the fixed-cost contract it may appear to be.

• Capacity sits in supply; delivery charges are separate and tariff-set.
• Auction results move every supplier's input cost at the same time.
• Locational deliverability areas can differ within one region.
• Identify fixed and pass-through components in writing.

The rate class sets the demand charge, and the demand charge sets the peak

For both BGE and Pepco the delivery tariff classifies a commercial account by how much it uses, how much it peaks and at what voltage it takes service. BGE's commercial schedules include General Service, a time-of-use General Service, Primary Service, and Large General Service with its own time-of-use variant; Pepco's include General Service Non-Demand, General Service Demand, Large General Service, a time-metered General Service and Primary Service. The names matter less than the structure. Once an account is demand-metered the bill carries a demand charge separate from the energy charge, and that charge is computed from the highest integrated demand in the billing interval - commonly a fifteen-minute interval - during the month. Tariffs may add a ratchet or minimum-demand provision, a seasonally differentiated demand rate, or an on-peak and off-peak split, so a site that trims kilowatt-hours but keeps the same monthly peak does not reduce the demand component at all. Cutting cost means moving load off the interval that sets the peak, which is an operating decision rather than a procurement one.

• BGE commercial classes: General Service, time-of-use General Service, Primary Service, Large General Service.
• Pepco commercial classes: General Service Non-Demand, General Service Demand, Large General Service, Time Metered General Service, Primary Service.
• Demand is billed on the highest integrated interval, commonly fifteen minutes.
• A ratchet, seasonal rate or on-peak split can carry a past peak forward.

What the corridor's buildings consume

The region's commercial density is unusual: federal and contractor offices, life-sciences campuses, hospitals, universities, hotels and distribution centres sit within a short drive of each other, and each has a distinct energy signature. Laboratories and hospitals run continuous, ventilation-heavy loads at a high load factor; offices peak during the working day and fall sharply outside it; hotels never fully empty; refrigerated distribution centres carry a baseload that is both high and flat. Load factor - energy used over the period divided by peak demand times the hours in the period - is what a supplier prices from, so two sites with identical annual consumption and different peaks are not the same account. A corridor buyer should expect an offer to be computed on the site's own interval data, and should check any power-factor provision where heavy motor loads are present.

• Identify what sets the monthly peak for each building type.
• Laboratories and hospitals run high-load-factor, always-on profiles.
• Compute your own load factor; it is what the offer is priced from.
• Check power-factor provisions where heavy motor loads are present.

What to prepare before requesting offers

Corridor pricing is underwritten per account, so the quality of the request sets the quality of the response. Because the region crosses four Maryland territories and two regulatory jurisdictions, a multi-site organisation should provide a per-site inventory rather than a blended summary - blending usage across utilities produces a number nobody can price. Bring twelve months of consumption per site in the unit each contract is priced in, the demand readings where the meter records them, the account and meter numbers, the service address and delivery utility, the current contract end dates and the notice period attached to each, and the entity and credit details a supplier will underwrite. Confirm separately whether gas and any district services are in scope, because they run on their own contracts and their own clocks.

• Twelve months of consumption and demand per site, not a blended annual figure.
• Account and meter numbers, service address and delivery utility for each location.
• Current contract end dates and the notice period attached to each.
• Business entity, credit details and any tax or exemption status.
• Whether gas, and any district services, are also in scope.

Aggregation's ceiling, and who it leaves out

Maryland authorises community choice aggregation, but the statute draws the line at the small commercial class. The aggregation route covers residential and small commercial electric customers, which the Public Utilities Article defines by a peak electric load of not more than 25 kilowatts; the aggregator itself is defined separately in the same article. A county may negotiate generation supply on an opt-out basis for that class, and an eligible customer is enrolled unless it declines or chooses another supplier. A business whose peak sits above the threshold is outside the county programme and shops on its own, which in practice is most mid-size commercial sites. The test is arithmetic on the meter: if the site's highest monthly demand exceeds 25 kilowatts, the aggregation programme is not an option and the real choice is between the default and a competitive supplier.

• Aggregation covers residential and small commercial accounts at 25 kW of peak load or less.
• A site above that peak is outside the county programme and shops on its own.
• The aggregator is defined in the Public Utilities Article; the Commission oversees the process.
• For most mid-size commercial sites the choice is the default or a certified supplier.

The renewable obligation, tier by tier

Maryland's Renewable Portfolio Standard obliges retail suppliers to retire certified renewable energy credits, or make an alternative compliance payment, for a rising share of retail sales, and the obligation is embedded in the supply price rather than shown as a supplier line item. The Clean Energy Jobs Act lifted the Tier 1 requirement to 50 per cent by 2030, with the separate Tier 2 requirement held at 2.5 per cent, a combined 52.5 per cent by 2030. Within Tier 1 sits a solar carve-out that rises to 14.5 per cent of retail sales by 2030 and must be satisfied with Maryland-eligible solar credits; a supplier that meets Tier 1 with wind or biomass still has to satisfy the solar percentage separately. Offshore wind is handled as its own Tier 1 carve-out through offshore renewable energy credits, with statutory milestones of at least 400 megawatts of Round 2 capacity in 2026-2027, 800 megawatts in 2028-2029 and 1,200 megawatts by 2030. Because the compliance cost sits inside the commodity price, two suppliers quoting the same energy can differ by their credit strategy alone.

• Tier 1 rises to 50 per cent by 2030; Tier 2 holds at 2.5 per cent.
• The solar carve-out within Tier 1 rises to 14.5 per cent by 2030.
• Offshore wind is a Tier 1 carve-out met with offshore renewable energy credits.
• Round 2 offshore milestones: 400 MW (2026-27), 800 MW (2028-29), 1,200 MW (2030).
• Compliance cost sits inside the supply price, not on a separate supplier line.

EmPOWER is a delivery charge, not a supply one

The EmPOWER Maryland surcharge finances energy-efficiency and demand-response programmes, and it is recovered as a regulated, non-bypassable charge on the distribution side of the bill. The utility files programme budgets and cost-recovery proposals with the Commission; the Commission approves the costs and any performance incentive; and the approved amount is recovered through a separate bill line or tariff charge that varies by utility, customer class and rate schedule. Because the surcharge supports regulated programmes rather than a supplier's commodity, a business continues to pay it after switching suppliers - it is not a cost the competitive market can bid away. For a commercial account the charge may be based on monthly kilowatt-hours, on peak demand, or on both, depending on the tariff, which is one more reason to compare an offer against the total delivered bill rather than against the commodity line alone.

• EmPOWER is a regulated, non-bypassable distribution charge.
• It varies by utility, customer class and rate schedule.
• It remains payable on delivery even after a switch.
• Its billing determinant may be usage, demand, or both.

How HighGround works in this market

HighGround sources energy supply through the Broker Online Exchange supplier network and compares proposed scope and term per site, rather than quoting one blended figure. Whether a site can choose a competitive supplier at all depends on the service address, the meter and the utility that serves it - municipal systems, cooperatives and some jurisdictions offer no retail choice - and gas eligibility is confirmed separately from electricity. HighGround may receive provider compensation when a purchase completes, and an inquiry places no order and switches no supplier.

• Electricity and gas are quoted separately, as are sites in different territories.
• Nothing is ordered and no supplier is switched by submitting an inquiry.
• The comparison shows proposed scope and term before anything is signed.

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