Energy Procurement for Commercial Buildings: Rates, Contracts, and Market Strategy

Energy procurement for commercial buildings is the process of sourcing electricity and natural gas supply at the lowest possible cost while managing price risk, contract terms, and regulatory complexity. In deregulated markets — which cover approximately 60% of U.S. commercial electricity load according to the EIA — property managers can choose their energy supplier, negotiate contract terms, and employ sophisticated hedging strategies to control costs. In regulated markets, procurement options are more limited, but rate schedule optimization, demand management, and on-site generation still offer significant savings opportunities.

This guide covers the full spectrum of energy procurement for commercial real estate: how electricity and gas markets work, the key components of a commercial energy bill, contract structures and negotiation strategies, capacity market dynamics, and the emerging role of renewable energy in procurement decisions. Whether you manage five buildings in a single market or five hundred across multiple states, a structured procurement strategy can reduce your energy costs by 10-25% compared to passive default-service pricing. According to industry benchmarks, commercial portfolios with active procurement programs pay an average of $0.02-$0.04 per kWh less than portfolios on utility default rates.

How Do Deregulated Energy Markets Work?

In a deregulated energy market, the generation (supply) of electricity is separated from the transmission and distribution (delivery). The local utility — Con Edison, ComEd, PECO, Eversource — continues to own and operate the wires that deliver electricity to your building, but the electricity flowing through those wires can be purchased from any licensed retail energy provider (REP). This separation creates a competitive supply market where dozens of REPs compete for commercial accounts by offering different pricing structures, contract lengths, and value-added services.

Deregulated states include Texas, Pennsylvania, New York, New Jersey, Connecticut, Massachusetts, Ohio, Illinois, Maryland, and the District of Columbia, among others. In these markets, your commercial electricity bill has two distinct components: supply charges (which you can shop) and delivery charges (which remain regulated and set by the utility commission). Supply charges typically represent 40-55% of the total bill, meaning that the opportunity for savings through procurement is significant but not unlimited — you cannot negotiate away the delivery portion of your bill.

Understanding Every Line Item on a Commercial Energy Bill

A commercial electricity bill in a deregulated market contains six major cost components, each driven by different factors and offering different optimization opportunities. Understanding these components is the foundation of effective procurement. The energy charge is the commodity cost of electricity, measured in dollars per kilowatt-hour ($/kWh). This is the line item that procurement directly affects. In 2025, average commercial energy charges ranged from $0.06/kWh in Texas to $0.14/kWh in New England, reflecting regional differences in fuel mix, generation capacity, and transmission constraints.

Capacity charges are the second-largest supply component and one of the most frequently misunderstood. Capacity charges fund the maintenance and availability of power plants that stand ready to generate electricity during peak demand periods, even if those plants run only a few hundred hours per year. In the PJM Interconnection (which covers the mid-Atlantic and Midwest), capacity auction results directly determine the capacity charge for commercial customers. The 2025/2026 PJM capacity auction cleared at $269.92/MW-day — nearly 10x the prior year — adding approximately $0.015-$0.025/kWh to commercial electricity costs across the PJM footprint.

Demand Charges: The 15-Minute Penalty

Demand charges are based on the highest 15-minute average power draw (measured in kilowatts) during the billing period. A single spike — caused by simultaneous HVAC startup, elevator operation, or equipment testing — sets the demand charge for the entire month. According to NREL research, demand charges represent 30-50% of the total electric bill for commercial buildings, yet many property managers overlook them because they appear as a single line item rather than a per-kWh charge. The commercial electricity rate increases projected for 2026 include demand charge escalation of 5-8% in most major markets, making demand management an increasingly important complement to supply procurement.

Contract Structures: Fixed, Index, Blend, and Block

The contract structure you choose determines your exposure to electricity market volatility. Fixed-rate contracts lock in a per-kWh price for a specified term (typically 12-36 months), providing budget certainty but eliminating the ability to benefit from market price declines. Index contracts pass through the real-time or day-ahead wholesale market price, providing the lowest average cost over time but exposing you to price spikes during heat waves, cold snaps, or grid emergencies. The average commercial electricity customer on an index contract paid 8-12% less than fixed-rate customers over the 2020-2025 period, but experienced monthly bill volatility of 25-40%.

Blended structures combine fixed and index elements — for example, fixing the base energy charge while indexing capacity and ancillary charges, or fixing 70% of expected volume at a set price and floating the remaining 30% at market. Block-and-index structures fix a specified volume at a locked price and charge market rates for consumption above that block. This approach works well for buildings with predictable baseload consumption and variable peak demand. For portfolio operators, layered purchasing — where you fix portions of your expected load at different times throughout the year — reduces the risk of locking in your entire portfolio at a market peak.

When to Buy: Market Timing and Procurement Cycles

Energy market timing affects procurement costs more than most property managers realize. Wholesale electricity futures markets exhibit strong seasonal patterns: forward prices for summer delivery peak in March-April as weather forecasts become available, and forward prices for winter delivery peak in September-October. Buying a 12-month fixed contract in August (when summer has already priced in and winter premium is still building) versus January (when winter premium is at its peak) can result in a 3-8% cost difference on the same contract term, according to data from ICE (Intercontinental Exchange) futures markets.

For portfolio operators, the procurement cycle should begin 60-90 days before contract expiration. This window provides enough time to solicit competitive quotes from 3-5 REPs, evaluate contract terms, negotiate pricing, and execute agreements without the pressure of an imminent expiration. Allowing contracts to expire without renewal typically results in automatic enrollment in the utility's default service rate, which carries a 10-20% premium over competitively procured supply in most deregulated markets.

Capacity Markets: The Hidden Cost Driver

Capacity markets are wholesale electricity markets that procure commitments from power plants to be available during peak demand periods. The PJM capacity auction, which serves 65 million customers across 13 states and D.C., is the most impactful capacity market for commercial real estate. The 2025/2026 PJM auction clearance at $269.92/MW-day — compared to $28.92/MW-day in the prior year — sent shockwaves through the commercial real estate industry, adding an estimated $3-5 billion in annualized capacity costs across the PJM footprint.

Capacity costs are allocated to individual customers based on their peak load contribution (PLC) — the building's electricity consumption during the top five peak demand hours on the grid during the prior summer. Buildings that consumed heavily during those specific hours receive a disproportionately high capacity cost allocation. The strategic implication is clear: reducing consumption during grid peaks — through demand response, thermal storage, or load shifting — directly reduces your capacity cost allocation for the following delivery year. A building that reduces its PLC by 20% saves 20% on capacity charges, which at current PJM rates represents $0.004-$0.006/kWh in annual savings.

Regional Market Conditions: Where Procurement Matters Most

Procurement opportunity and strategy vary significantly by region. In Texas (ERCOT), the fully deregulated market and high wholesale price volatility create both the greatest savings opportunity and the greatest risk. Texas commercial customers who locked in fixed rates before the February 2021 winter storm paid $0.07/kWh while spot prices exceeded $9/kWh during the event. The lesson: in volatile markets, some degree of price certainty is essential for risk management.

The Northeast is experiencing a rate shock in 2026 driven by the convergence of three factors: PJM capacity auction increases, natural gas pipeline constraints that elevate winter electricity prices, and transmission upgrade costs being passed through to ratepayers. New York City commercial electricity rates have increased approximately 38% since 2022. Connecticut has seen similar escalation. For Northeast portfolio operators, procurement is not optional — the spread between default service rates and competitively procured supply can exceed $0.04/kWh, representing $20,000-$40,000 in annual savings for a typical 100,000-square-foot office building.

Natural Gas Procurement

Natural gas procurement follows similar principles but operates through a separate market structure. In deregulated gas markets, commercial customers can choose their gas supplier independently of the local distribution company (LDC). Fixed-price gas contracts provide budget certainty but have historically carried a 10-15% premium over market-index pricing. The Henry Hub natural gas benchmark averaged $2.50-$3.50/MMBtu during 2023-2025, but regional delivered prices — which include pipeline transportation and LDC delivery charges — range from $6-$14/MMBtu depending on location and season. Winter-peaking markets in New England can see delivered gas prices spike to $20+/MMBtu during cold snaps due to pipeline capacity constraints.

Green Energy Procurement and Renewable Options

Green energy procurement — purchasing electricity from renewable sources — is increasingly driven by both economic and regulatory factors. Corporate renewable energy purchases exceeded 46 GW in cumulative contracted capacity by 2025, according to the Clean Energy Buyers Alliance. For commercial real estate, green procurement options include retail green supply contracts (where the REP sources electricity from renewable generators), virtual power purchase agreements (VPPAs), community solar subscriptions, and on-site solar installations.

The economics of green procurement have shifted dramatically. In many markets, renewable supply contracts now price at parity with or below conventional fixed-rate contracts. A 2025 analysis by Lazard found that the levelized cost of utility-scale solar ($24-$96/MWh) and onshore wind ($24-$75/MWh) is competitive with or below the marginal cost of natural gas generation ($39-$101/MWh) in most U.S. regions. For property managers seeking to meet building performance standard requirements or ESG commitments, green procurement offers a compliance pathway that may also reduce costs. The key is evaluating the additionality and locational attributes of the renewable energy certificates — not all green procurement contracts deliver equivalent emissions reduction benefits.

Building a Portfolio-Wide Procurement Program

A structured procurement program for a commercial portfolio should include four elements: market monitoring (tracking wholesale prices, capacity auction results, and regulatory changes across every market in your portfolio), contract management (centralizing expiration dates, renewal terms, and pricing data for every supply account), supplier relationship management (maintaining competitive tension by soliciting quotes from 3-5 REPs at every renewal), and performance measurement (comparing actual costs to market benchmarks and alternative contract structures to quantify procurement value).

For portfolios spanning multiple deregulated markets, aggregation is a powerful tool. Combining the load from ten buildings into a single procurement event creates volume leverage that smaller individual accounts cannot achieve. REPs will typically offer 2-5% better pricing for aggregated portfolios of 10+ accounts compared to individual account pricing. However, aggregation also concentrates contract renewal risk — if all accounts renew simultaneously and market conditions are unfavorable, the entire portfolio is locked into higher-than-necessary pricing. Staggering contract expirations across the portfolio mitigates this concentration risk.

How to Evaluate Retail Energy Providers

Not all REPs are created equal, and the lowest price quote is not always the best value. Beyond price, evaluate REPs on: credit quality (can the supplier fulfill a 36-month contract without financial distress?), billing accuracy (REPs with poor billing systems create reconciliation nightmares for property accounting teams), customer service responsiveness (when a billing dispute arises, how quickly does the REP resolve it?), and contract flexibility (does the contract allow you to add or remove meters without penalty as your portfolio changes?).

Contract terms to scrutinize include: early termination fees (typically 2-4 cents/kWh on remaining volume), bandwidth clauses (which penalize you if actual consumption deviates more than 10-15% from contracted volume), tax and regulatory pass-through language (which can add unbudgeted costs if regulations change during the contract term), and renewal provisions (some contracts auto-renew at potentially unfavorable rates if you do not provide written notice 60-90 days before expiration). A 2024 survey by the Commercial Real Estate Finance Council found that 23% of property managers were not aware of their contracts' auto-renewal provisions.

Frequently Asked Questions

What is energy procurement for commercial buildings?

Energy procurement is the process of sourcing electricity and natural gas supply at competitive prices through contract negotiation with retail energy providers (REPs) in deregulated markets. It involves selecting contract structures, timing market entry, managing price risk, and optimizing demand charges to reduce total energy costs across a portfolio.

What is the difference between deregulated and regulated energy markets?

In deregulated markets, you can choose your electricity supplier from competing REPs while the local utility handles delivery. In regulated markets, the utility provides both supply and delivery as a bundled service with rates set by the state public utility commission. Approximately 60% of U.S. commercial electricity load is in deregulated markets. See our full guide on deregulated vs. regulated markets.

How much can I save through active energy procurement?

Commercial portfolios with active procurement programs typically pay $0.02-$0.04/kWh less than portfolios on default utility rates, representing 10-25% savings on the supply portion of the bill. For a portfolio spending $5 million annually on electricity, that translates to $500,000-$1,250,000 in annual savings.

What is a capacity charge and why did it increase so much?

Capacity charges fund the availability of power plants during peak demand periods. The PJM capacity auction for 2025/2026 cleared at $269.92/MW-day, nearly 10x the prior year, due to plant retirements and growing demand from data centers and electrification. This increase adds approximately $0.015-$0.025/kWh to commercial bills across the PJM footprint.

Should I choose a fixed-rate or index-price contract?

Fixed rates provide budget certainty and protect against price spikes. Index rates offer lower average costs over time but expose you to monthly volatility. Blended approaches — fixing 60-70% of volume and floating the rest — provide a middle path. The right choice depends on your organization's risk tolerance, budget cycle requirements, and market outlook.

How far in advance should I start my procurement process?

Begin the procurement process 60-90 days before contract expiration. This allows time to gather competitive quotes, negotiate terms, and execute contracts without the pressure of an imminent switch to default service rates. Monitor wholesale market prices year-round to identify favorable buying windows.

Can I aggregate multiple properties into a single procurement?

Yes. Aggregating the load from multiple accounts (10+) into a single procurement event typically yields 2-5% better pricing due to volume leverage. However, stagger contract expirations across the portfolio to avoid concentration risk — locking in your entire portfolio at a single market price point.

What are renewable energy procurement options for commercial buildings?

Options include retail green supply contracts, virtual power purchase agreements (VPPAs), community solar subscriptions, on-site solar installations, and renewable energy certificate (REC) purchases. In many markets, renewable supply contracts now price at parity with or below conventional fixed-rate contracts, making green procurement both an environmental and economic decision.