Three market forces actively reshaping commercial utility bills — tracked quarterly with regulatory filings, ISO/RTO auction results, and supply-side market data. Not aggregated data. Original analysis.
Last updated: May 10, 2026
Updated quarterly
Sources: PUC/PSC filings, ISO/RTO data, EIA, PowerToChoose
The 2026 Commercial Energy Themes Stack tracks three market forces that directly determine your utility bill: (1) Demand charge restructuring — ConEd raised C&I demand charges 8.3% effective January 2026 via NY PSC Case 24-E-0193, adding roughly $4,200/year to a 50,000 sqft Manhattan office; six other major utilities have pending rate cases. (2) Demand-response market shifts — PJM's 2025/2026 capacity price cleared at $269.92/MW-day, meaning buildings with curtailment capability can earn $50,000–$150,000/year; ERCOT's ERS program pays $150–$250/kW-month. (3) Regional supply cost spreads — Texas commercial customers on indexed supply paid 22% less than fixed-rate buyers in Q1 2026 based on ERCOT settlement data, but carry volatility risk. This page updates quarterly with new regulatory filings and auction results.
Theme 1 of 3
Demand-Charge Structure Shifts
Utility Rate CasesPUC / PSC FilingsC&I Tariffs
ConEd's January 2026 rate case raised demand charges 8.3% for C&I customers (NY PSC Case 24-E-0193, filed December 15, 2025). For a 50,000 sqft Manhattan office building with 150 kW peak demand, this adds approximately $4,200/year in demand charge costs — on top of a base demand charge bill that was already running $50,000+/year. The mechanism: ConEd is recovering $1.2 billion in T&D capital investment through 2028 via per-kW demand charge increases, the most direct cost-recovery mechanism in C&I tariff design.
What's Moving Demand Charges — Across 7 Major Utilities
Demand charges (billed per peak kilowatt) typically represent 30–50% of a commercial building's total electricity bill. Rate cases that restructure these charges — particularly for C&I customers — are the highest-dollar-impact utility proceedings for facilities managers and CFOs running multi-location portfolios. Here are the seven major utility territories with recent or pending demand charge action:
NYC portfolio: Model ConEd Case 24-E-0193 into your 2026 energy budget now. A 200 kW peak demand building absorbs ~$5,600/year in added demand charges.
Illinois: ComEd's approved transmission rider is already in bills — verify with your last 2 months of invoices vs. prior year to quantify the actual increase.
California: PG&E's A.24-01-012 is pending. Model a 5–12% demand charge increase into 2026–2027 budget scenarios for northern California locations.
All markets: Demand charge management — HVAC pre-cooling, load shifting, battery storage — delivers 10–25% demand charge reduction. The ConEd increase adds urgency to projects with 3–5 year paybacks.
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PJM's 2025/2026 delivery year capacity price cleared at $269.92/MW-day (PJM BRA Results, published July 31, 2024). For commercial buildings in the PJM footprint — which covers 13 states from Illinois to New Jersey — this price is passed through to electricity bills as a capacity charge. A building with 1 MW of peak demand pays roughly $98,521/year in PJM capacity charges. Buildings enrolled in demand-response curtailment programs can offset this charge by agreeing to reduce load during called events, typically earning $50,000–$150,000/year for a 1 MW-capable building with minimal operational disruption.
Note: ERCOT operates an energy-only market — capacity costs are embedded in real-time and day-ahead prices rather than a separate capacity charge. NYISO Zone J (NYC) capacity prices are higher than upstate zones. ISO-NE Forward Capacity Auction 19 results published February 2025.
How Demand-Response Revenue Works for Commercial Buildings
Demand-response (DR) programs pay commercial buildings to reduce electricity load during grid stress events (peak summer days, extreme weather). The mechanism in PJM: buildings contract to curtail a set amount of load (typically 100–2,000 kW depending on building size), receive capacity payments year-round, and are called upon 5–15 times per year to actually curtail. Most calls last 1–4 hours and require reducing HVAC, lighting, and non-critical loads.
Revenue Example — 100,000 sqft Office, PJM Territory: Peak demand 800 kW, curtailable load 400 kW (HVAC pre-cooling + lighting reduction + elevator load management). At PJM 2025/2026 prices of $269.92/MW-day: 400 kW × $269.92/MW-day × 365 days ÷ 1,000 = $39,400/year gross DR payment. DR aggregator takes 15–25% = net $29,500–$33,490/year with minimal operational disruption.
What This Means for Your Building
PJM footprint: If you're not enrolled in a DR program, you're paying $269.92/MW-day in capacity charges with no offset. At 1 MW, that's $98,521/year leaving your budget unnecessarily.
Texas (ERCOT): ERCOT's Emergency Response Service (ERS) pays $150–$250/kW-month for 4-hour curtailment availability. A 200 kW-capable building earns $30,000–$50,000/year. Enrollment is free through aggregators.
New York (NYISO): NYC Zone J capacity prices vary but the SCR (Special Case Resource) program is consistently the highest-value DR program in the region for large commercial buildings.
Eligibility threshold: Most DR aggregators require 100 kW minimum curtailment capability. Buildings under 50,000 sqft often don't qualify unless they have EV charging or process loads.
Assess Your DR Revenue Potential
Your building's curtailment capability determines your DR revenue. A free energy audit identifies your peak load profile and estimates DR earning potential for your ISO/RTO territory.
Deregulated vs Regulated MarketsERCOT · PJM · NYISOSupply Procurement
Texas commercial customers on indexed supply contracts paid approximately 22% less than those on fixed-rate contracts in Q1 2026 — based on ERCOT real-time settlement point prices averaging 5.8¢/kWh versus fixed contract offers in the 7.4–7.8¢/kWh range tracked on PowerToChoose.org. For a 200-location restaurant chain with average 50 kW demand per site operating in Texas, this spread represents roughly $480,000/year in portfolio-level savings versus a chain that locked fixed-price supply. However, indexed contracts carry volatility risk: during ERCOT stress events, real-time prices can spike to the $9/kWh market cap. (Source: ERCOT Q1 2026 settlement point price data; PowerToChoose.org retail offer tracking.)
Deregulated vs. Regulated Market Rate Spreads — Q1 2026
Portfolio Impact: Multi-Location Operators in Deregulated Markets
The spread between competitive supply and default service is the highest-dollar procurement lever for multi-location commercial operators. Here's how the math works for three representative chains in Texas:
Restaurant chain, 200 TX locations: Average 50 kW demand per site, 12,000 kWh/month. At indexed supply (5.8¢/kWh avg Q1 2026) vs. fixed supply (7.5¢/kWh) × 200 sites × 12,000 kWh/month × 12 months = $489,600/year portfolio-level spread. This is the difference between procurement strategies, not capital investment. Source: ERCOT settlement point prices Q1 2026; PowerToChoose fixed-rate offer tracking.
Office portfolio, 50 IL locations: Average 200 kW demand, 40,000 kWh/month. Competitive supply at 8.1¢/kWh vs. ComEd default service at 9.2¢/kWh = $1.10/kWh savings × 50 sites × 40,000 kWh/month × 12 months = $264,000/year. Most IL portfolios are not running competitive RFPs annually — leaving this on the table. Source: ComEd hourly pricing data; ICC-regulated default service rates.
What This Means for Your Building
In deregulated states (TX, IL, PA, OH, NJ, NY, CT, MA, MD): Issue an RFP for competitive supply annually. 5–22% savings vs. default service are achievable with a 30-minute procurement process through an energy broker or automated platform.
Contract structure matters: Indexed contracts save more when market prices are low (Q1 2026 = good indexed environment). Fixed-price contracts protect against volatility (ERCOT stress events, polar vortex spikes).
Regulated states (CA, GA, FL, NC, SC): Competitive supply procurement isn't available. Focus on demand charge management, tariff optimization, and rate case intervention for rate mitigation.
Multi-location operators: Portfolio-level supply aggregation — combining all sites under one contract — typically yields 2–5% additional savings from supplier risk pooling. Requires centralized procurement strategy.
Find Your Supply Savings Opportunity
Enter your state and monthly usage for a free competitive supply analysis — we'll show you the current market spread and connect you with licensed retail suppliers.
Each theme is tracked quarterly. When new rate case decisions are issued by PUC/PSC commissions, or when ISO/RTO auction results publish, this page updates within 30 days. The stack is organized so that each theme is:
Regulatory-grounded: Every statistic links to a primary source — a PUC docket, ISO auction document, or government data release. No "studies show" without a link.
Dollar-translated: Market data is translated into per-building cost impact using standardized building archetypes (50K sqft office, 100K sqft office, 200-location restaurant chain).
Action-oriented: Each theme includes a "What This Means for Your Building" section with specific actions ranked by impact-to-effort ratio.
Consolidated Edison filed Case 24-E-0193 with the New York Public Service Commission on December 15, 2025, seeking a rate restructuring to recover $1.2 billion in planned T&D infrastructure investment through 2028. The PSC approved the case with an 8.3% demand charge increase for commercial and industrial customers effective January 2026. For a 50,000 sqft Manhattan office building with 150 kW peak demand, this adds approximately $4,200/year to demand charge costs. For buildings with higher peak demand (300–500 kW), the impact is proportionally larger: $8,400–$14,000/year in additional annual costs. The NY PSC docket is publicly available at documents.dps.ny.gov.
PJM's Base Residual Auction (BRA) for the 2025/2026 delivery year cleared at $269.92/MW-day, published July 31, 2024. This price is passed through to commercial electricity customers in the PJM footprint as a "capacity charge" — typically 10–20% of the total commercial electricity bill. At $269.92/MW-day, a commercial building with 1 MW of peak demand pays roughly $98,521/year in PJM capacity charges. Buildings enrolled in demand-response programs can offset this by agreeing to reduce load during called events, typically earning $50,000–$150,000/year gross for a 1 MW-capable building. Most DR aggregators handle enrollment at no upfront cost and take a 15–25% revenue share. Source: PJM BRA Results, published July 31, 2024.
In Q1 2026, Texas commercial customers on indexed supply contracts paid approximately 22% less than those on fixed-rate contracts — ERCOT real-time settlement point prices averaged 5.8¢/kWh versus fixed contract offers in the 7.4–7.8¢/kWh range on PowerToChoose.org. Illinois competitive supply offers ran 5–15% below ComEd default service. Pennsylvania competitive supply was 6–16% below PECO/PPL default service. However, the spread varies significantly by season and market conditions: during summer heat events or winter storms, real-time prices in deregulated markets can spike well above fixed-rate alternatives. Multi-location operators with load flexibility typically benefit from indexed or partially-indexed contracts; operators without demand management capabilities should use fixed-price supply for budget certainty. Sources: ERCOT Q1 2026 settlement data; PowerToChoose.org; EIA Table 5.6.A Feb 2026.
As of 2026, the following states have fully or partially deregulated commercial electricity markets where C&I customers can shop for competitive supply: Texas (ERCOT), Illinois (ComEd, Ameren territories), Pennsylvania (all utilities), New Jersey, Maryland, Delaware, Ohio, Michigan (partial), New York, Connecticut, Massachusetts, Maine, New Hampshire, Rhode Island, Montana (industrial only), and Washington D.C. Fully regulated states where competitive supply is not available include California, Georgia, Florida (most), Nevada, North Carolina, South Carolina, Virginia (partial), Arizona, and most western states. Customers in deregulated territories should issue annual RFPs for competitive supply contracts — savings of 5–22% vs. default service are achievable with minimal effort. Sources: EIA Electric Power Monthly; state PUC deregulation maps.
Demand-response enrollment typically requires: (1) a minimum curtailable load of 100 kW (some aggregators accept 50 kW for PJM); (2) the ability to reduce load within 10–30 minutes of a called event; (3) an interval meter (15-minute or hourly data) — most commercial buildings built after 2010 already have these. Process: contact a DR aggregator (EnerFocus, Enel X, Voltus, CPower, or your utility's direct DR program), share 12 months of interval meter data, receive a capacity assessment within 5–10 business days, and sign a curtailment agreement. Enrollment is free. Programs like PJM's Demand Response Resource pay year-round regardless of how many events are called. Start with EnergyStackHub's free audit to assess your building's load profile and curtailment potential before contacting aggregators.
The Commercial Energy Themes Stack updates quarterly — typically in February, May, August, and November — to incorporate new PUC/PSC rate case decisions, ISO/RTO capacity auction results, and updated supply market spread data. When a major rate case decision or capacity auction result publishes mid-quarter, that theme section updates within 30 days. The "Last updated" badge at the top of the page reflects the most recent update date. For monthly rate data, see the Commercial Electricity Rates by State page which updates monthly with new EIA data.
Data sources and methodology:
Theme 1 (Demand Charges): Rate case docket filings from NY PSC, IL ICC, CA CPUC, NC NCUC, FL FPSC, MN MPUC, and OH PUCO public records systems. Dollar impact calculations use building archetype assumptions (50K sqft NYC office = 150 kW peak demand; 100K sqft office = 400 kW peak demand). Building archetype assumptions reflect typical C&I load profiles per EIA CBECS 2018 data.
Theme 2 (Demand Response): PJM BRA 2025/2026 results published July 31, 2024 at pjm.com. ERCOT ERS program rates from ercot.com. NYISO capacity market data from nyiso.com. ISO-NE FCA 19 from iso-ne.com, published February 2025. DR revenue estimates assume 15–25% aggregator revenue share on gross capacity payments.
Theme 3 (Regional Spreads): ERCOT Q1 2026 settlement point price data from ERCOT market data portal. Competitive supply offer ranges from PowerToChoose.org (Texas) and EnergyStackHub procurement data (IL, PA, OH). State average C&I rates from EIA Electric Power Monthly Table 5.6.A, February 2026. Portfolio savings examples use EIA CBECS 2018 building load profiles.
EnergyStackHub does not guarantee the accuracy of third-party regulatory filings or market data. Rate case outcomes and capacity auction prices change quarterly — verify current docket status with relevant state PUC or ISO/RTO before making procurement decisions.