The Facilities Manager's Guide to Commercial Energy Procurement (2026)

For most commercial buildings, electricity is the largest or second-largest operating expense after labor — yet many facilities managers still treat energy as a fixed cost to be paid rather than a variable to be actively managed. In deregulated electricity markets, which cover a substantial portion of U.S. commercial load, that passivity is expensive. The difference between a well-procured energy contract and the default utility rate can amount to $20,000–$100,000 per location per year for a mid-size commercial building.

This guide walks you through the complete commercial energy procurement process: how deregulated markets work, how to read and navigate commodity futures cycles, what contract structures mean in practice, how to run a competitive RFP, and how to negotiate the contract terms that will define your energy costs for the next one to three years. We also cover portfolio procurement for multi-location operators and green energy options that can be layered onto any procurement strategy.

1. Understanding Deregulated vs. Regulated Markets

The first question in commercial energy procurement is whether your facilities are even in a market where competitive procurement is available. In regulated states, a single investor-owned utility or public utility controls both the delivery infrastructure and the electricity supply — you have no choice of supplier, and the rate is set by the state public utility commission. In deregulated states, the delivery infrastructure (wires, substations, meters) remains the regulated utility's domain, but you can choose a competitive retail electric supplier (CRES) to provide the electricity itself.

Deregulated States (Verified as of 2026)

The following states have fully or partially deregulated commercial electricity markets, allowing commercial customers to choose competitive suppliers:

In regulated states — California, Florida, Washington, Oregon, Arizona, and most of the Southeast and Mountain West — the utility controls supply and no competitive procurement is possible for the commodity component. Your optimization levers in regulated markets are efficiency, demand management, rate tariff selection, and on-site generation rather than supplier switching.

2. When to Buy: Timing Strategy and Market Cycles

Electricity supply pricing in deregulated markets tracks natural gas commodity prices, which are traded on NYMEX futures markets. Understanding the seasonal and cyclical patterns in these markets helps procurement managers time contracts to avoid locking in at peak pricing.

Seasonal Price Patterns

Natural gas prices — and therefore power prices in gas-dependent grid regions — follow predictable seasonal patterns driven by heating and cooling demand:

• Winter peaks (November–February): Heating demand for natural gas drives commodity prices higher. Power prices in ISO-NE (New England), NYISO, and PJM follow. Locking in a new long-term contract during peak winter is generally disadvantageous.
• Summer peaks (July–August): Cooling demand drives power prices higher, particularly in ERCOT (Texas) and PJM. Day-Ahead prices can spike significantly during heat events.
• Spring shoulder season (March–May): Historically the lowest-volatility and often lowest-priced window for locking in 12–24 month supply contracts. Heating demand has faded; cooling demand has not yet arrived. Forward curves for summer delivery are often priced at a discount relative to winter delivery.
• Fall shoulder season (September–October): Second-best window for procurement; cooling demand has faded but winter premium has not yet fully materialized in the forward curve.

Monitoring Forward Curves

The NYMEX Henry Hub natural gas futures curve and regional power forward curves (ERCOT Hub, PJM West Hub, ISO-NE Mass Hub) are public data that your energy broker or procurement advisor should be monitoring on your behalf. When the forward curve is in "backwardation" — meaning near-term prices are higher than prices 12–18 months out — locking in a longer-term contract captures future price softness. When the curve is in "contango" — near-term prices lower than future delivery prices — shorter-term or index-based contracts may be preferable.

3. Contract Structures: Fixed, Index, Block-and-Index, and Green

Not all commercial electricity contracts are structured the same way. Understanding the four primary contract types helps you choose the structure that matches your organization's risk tolerance, budget certainty requirements, and sustainability goals.

• 1

  Fixed-Price Supply Contract

  A fixed-price contract locks in a single cents-per-kWh supply rate for the entire contract term — commonly 12, 24, or 36 months. Your supply cost is completely predictable regardless of how the commodity market moves during the term. Fixed contracts are priced at a premium over the current spot market to compensate the supplier for taking on the price risk. They are the right choice when forward curves are rising, when you have tight budget constraints that cannot accommodate volatility, or when the spread between current fixed prices and current spot prices is historically narrow. Fixed prices typically include all capacity, transmission, and ancillary service pass-through charges in a single bundled rate, or may pass those components through at actual cost — verify which structure applies before signing.

• 2

  Index / Floating-Price Contract

  Index contracts price electricity supply at a market reference price — commonly the Day-Ahead or Real-Time Locational Marginal Price (LMP) at a regional hub, such as ERCOT Houston Hub, PJM West Hub, or ISO-NE Mass Hub — plus a fixed adder (in cents per kWh) that covers the supplier's margin and service fees. Your cost rises and falls with the wholesale market on a monthly or even daily basis. Index contracts have no price premium for certainty, and in soft markets they can deliver meaningfully lower costs than available fixed-price alternatives. The risk is exposure to price spikes — particularly in extreme weather events where Day-Ahead prices in deregulated markets can spike dramatically, as they did during Winter Storm Uri in Texas in February 2021.

• 3

  Block-and-Index (Hybrid) Contract

  Block-and-index contracts allow procurement managers to fix a defined "block" of power (often 50–75% of forecast load) at a locked-in price, while leaving the remaining portion to float with the market index. This hybrid approach provides partial budget certainty while retaining some upside if markets soften. Block-and-index structures are well-suited to customers with relatively stable baseload consumption who want to hedge their core load while not fully giving up the option of benefiting from falling prices. They are also used to manage the timing risk of locking in 100% of load at a single point in time — blocks can be purchased in tranches across different market dates.

• 4

  Green Energy Products

  Most competitive retail suppliers in deregulated markets offer green product options alongside standard supply contracts. The most common mechanism is Renewable Energy Certificates (RECs) — tradeable instruments representing one megawatt-hour of electricity generated from a renewable source (wind, solar, hydro, geothermal). Bundled REC supply contracts typically cost a modest premium of $0.001–$0.003 per kWh above an otherwise identical conventional supply contract. Community solar subscriptions — where your account subscribes to output from a local solar farm and receives a bill credit — are available in several deregulated states as an alternative path. Larger commercial accounts may pursue Virtual Power Purchase Agreements (VPPAs), financial contracts that allow organizations to claim renewable attributes from a specific project while purchasing commodity power separately in the market. See our guide on commercial building decarbonization for a full treatment of green procurement options.

4. Running a Commercial Energy Procurement RFP

A competitive Request for Proposals (RFP) process is the most reliable way to ensure you are getting market-competitive pricing and terms. Even if you ultimately do not switch suppliers, an RFP gives you verified market pricing that strengthens your negotiating position with your current supplier. Here is the step-by-step process:

Step 1: Prepare Your Load Data

Suppliers price commercial energy contracts based on your historical consumption profile. You will need to provide 12 months of interval data — ideally 15-minute or hourly meter reads — for every account included in the RFP. This data is available from your utility, either through your online account portal, a written request to the utility's commercial services department, or through a third-party utility data aggregator like Urjanet or UtilityAPI. The more complete and accurate your load data, the more precisely suppliers can price your account and the less risk premium they will build into their offers.

For each meter, you should also collect: the current contract or tariff details (supplier, rate schedule, expiration date), the service address, the utility account number, and any demand profile characteristics (e.g., peak demand month, load factor). The load factor — monthly consumption divided by (peak demand × hours in the month) — is a key pricing input; accounts with higher load factors are generally priced more favorably because they represent more predictable, baseload-like demand.

Step 2: Identify Qualified Suppliers

Competitive retail electric suppliers must be licensed in each state where they operate by the state public utility commission. Supplier lists are public documents — your state PUC website will have a current list of licensed CRES providers for commercial customers. Common national suppliers active across multiple deregulated markets include companies such as Direct Energy Business, NRG Business, Constellation Energy, and TotalEnergies, as well as regional and local suppliers. Consider including both national suppliers (which offer broader product suites and credit flexibility) and regional specialists (which may offer sharper pricing in their home markets).

If running a large portfolio RFP or if your organization lacks internal procurement expertise, engaging a licensed energy broker or consultant is worth considering. Brokers are typically compensated by the winning supplier rather than by you — they are paid an adder of fractions of a cent per kWh built into the contract price — but they provide market access, comparative analytics, and contract negotiation support. Verify any broker's licensing status and ask for disclosure of their compensation structure before engaging.

Step 3: Issue the RFP

A commercial energy RFP should specify: the list of meters included (service addresses, account numbers, utilities, current contract expiration dates); the desired product types you are requesting bids for (fixed 12-month, fixed 24-month, index with adder, block-and-index, green bundled); the desired start date; any requirements for pass-through vs. all-inclusive pricing; your credit profile and any constraints on security deposits; the bid due date and evaluation timeline; and your preferred contract terms.

Step 4: Evaluate Bids on an Apples-to-Apples Basis

Commercial electricity supply bids frequently differ in structure in ways that make direct price comparison misleading. Ensure every bid specifies whether capacity charges, transmission charges, ancillary service charges, and renewable portfolio standard (RPS) compliance costs are included in the quoted rate (all-inclusive or fully bundled) or passed through at actual cost (adder-based or index with pass-throughs). An all-inclusive fixed rate of 9.5 cents per kWh is not directly comparable to an index contract quoted at Day-Ahead Hub price plus a $0.008/kWh adder if the index contract also passes through capacity and transmission at actual cost.

Use your cost estimator tool to model total annual cost under each bid scenario using your historical load data, so you are comparing projected total annual spend rather than quoted rate structures.

Step 5: Negotiate Contract Terms

Price is only one dimension of a commercial energy contract. The following terms warrant careful negotiation before execution:

5. Portfolio Procurement: Multi-Location Strategy

For organizations with electricity accounts across multiple locations — whether 5 or 500 — coordinated portfolio procurement consistently outperforms site-by-site procurement. The reasons are straightforward: volume drives pricing, aggregated load profiles smooth demand variability, and coordinated procurement eliminates the administrative cost of managing dozens of separate contract renewal cycles.

Volume Discounts from Aggregated Load

Electricity suppliers price contracts based on total annual load volume. A portfolio of 10 locations with an aggregate of 500,000 kWh per month will receive materially sharper pricing than a single location buying 50,000 kWh per month, even within the same grid region. The pricing improvement from aggregation varies by market and supplier but is typically in the range of 0.3–1.5 cents per kWh — representing $18,000–$90,000 per year in savings on a 500,000 kWh/month portfolio relative to buying each location separately.

Cross-state aggregation is possible if your portfolio spans multiple deregulated states served by the same regional grid operator — for example, a portfolio spanning Pennsylvania, New Jersey, and Maryland can be aggregated into a single PJM-wide RFP with several suppliers who operate across the full PJM footprint. Portfolios that span different grid operators (e.g., PJM and ERCOT) will require separate RFPs.

Synchronized Contract Renewal Cycles

One of the most underappreciated benefits of portfolio procurement is the operational simplicity of managing all locations on synchronized contract cycles. With locations staggered across different expiration dates, your procurement team is perpetually in renewal mode — evaluating markets, issuing RFPs, and executing contracts year-round. Consolidating your portfolio onto a common renewal cycle means one market analysis, one RFP process, and one contract execution per cycle — freeing procurement bandwidth for other priorities.

For guidance on managing multi-location energy portfolios, see our guide on commercial utility bill management and the current commercial energy rates by state.

6. Green Energy Procurement: RECs, PPAs, and Community Solar

Sustainability mandates, corporate net-zero commitments, and customer expectations are driving rapid growth in commercial green energy procurement. The good news for facilities managers is that green procurement and cost-effective procurement are increasingly compatible — and in some cases, green procurement structures offer superior economics to conventional supply contracts.

Renewable Energy Certificates (RECs)

A REC represents one megawatt-hour of electricity generated by a renewable source (solar, wind, hydro, geothermal, biomass). RECs are the standard instrument used to document and claim renewable energy consumption under the Greenhouse Gas Protocol and CDP reporting frameworks. They can be purchased bundled with your electricity supply contract (from your CRES) or purchased separately in voluntary REC markets from brokers such as 3Degrees, RECommunity (now NativeEnergy), or directly from renewable energy generators.

Bundled RECs added to a competitive supply contract typically cost $1–$3 per MWh ($0.001–$0.003 per kWh) above the base supply rate — a modest premium for organizations with sustainability reporting requirements. Unbundled RECs purchased separately in spot markets are typically even cheaper but do not carry the same quality assurance as RECs from specific verified generation facilities.

Power Purchase Agreements (PPAs)

A Physical PPA is a long-term contract (often 10–25 years) where a developer finances, builds, and owns a renewable energy facility (typically solar or wind) and sells the output to you at a contracted price. Physical PPAs are most commonly used for on-site solar installations at owned facilities. A Virtual PPA (VPPA) is a financial contract — not a physical power delivery contract — where you contract to pay a developer a fixed price for renewable generation, and the developer sells the actual power into the wholesale market; you receive the difference (positive or negative) as a financial settlement, along with the associated RECs. VPPAs are used by large commercial organizations to support new renewable development without requiring physical delivery to their locations.

Community Solar Subscriptions

For commercial customers who lease rather than own their facilities, who lack suitable rooftop or ground-mount area, or whose building does not support on-site generation, community solar subscriptions offer an alternative path. Community solar programs — available in New York, Illinois, Massachusetts, New Jersey, Maryland, and several other deregulated states — allow commercial customers to subscribe to output from a nearby solar installation and receive a bill credit from their utility that reduces the delivery portion of their bill. Subscription costs are typically set below the utility's retail delivery rate, creating a direct bill savings alongside the renewable energy benefit. See our New York commercial energy guide for details on New York's ConEd Community Solar program.

7. Utility Bill Auditing as a Procurement Complement

A comprehensive energy procurement strategy is most effective when combined with a professional utility bill audit. Procurement optimizes the price you pay for electricity; an audit verifies that the bill you receive actually reflects what you should be paying under your tariff and contract. These are related but distinct functions, and neglecting the audit piece leaves money on the table even after procurement is optimized.

Professional utility bill audits systematically examine: tariff classification accuracy (whether your account is on the correct rate schedule), sales tax and utility excise tax exemptions (many commercial and industrial uses qualify for partial or full exemptions that are not automatically applied), demand ratchet charges (provisions in some utility tariffs that bill a minimum demand charge based on a percentage of your highest demand in the prior 12 months), billing calculation errors, and meter read accuracy. Studies by utility billing specialists consistently identify billing errors or suboptimal classifications in 25–35% of audited commercial accounts, with recoverable overcharges commonly ranging from $5,000 to $50,000 per location.

Schedule a free energy audit to have our team review your utility bills alongside your procurement status. We identify both billing recovery opportunities and procurement optimization actions in a single engagement. We also offer a full commercial utility bill guide covering how to read and interpret commercial utility bills line by line.

Frequently Asked Questions