Most of the conversation about Xcel Energy's updated Time-of-Use rates has focused on what customers will pay more — evening television, charging EVs after dinner, running the dishwasher at 6 p.m. That's the wrong frame. The real story is what becomes dramatically cheaper: everything outside a narrow four-hour weekday window. For commercial facility managers, that framing changes everything about how you approach energy costs.
But before any strategy can be designed, deployed, or evaluated, one thing comes first: understanding your facility's actual load profile. Without knowing how much electricity you consume during on-peak hours — and what's driving it — you're optimizing blind.
"Every kilowatt-hour you shift out of the 5–9 p.m. window saves you 13.4 cents in summer. That's a 63% reduction in your electricity price for that unit of energy. The question is: how much of your load actually falls in that window?"
— Dan Frey, CEM · St. Elmo LLCThe Rates, In Plain Terms
Effective November 1, 2025, Xcel Energy's residential and small commercial customers in Colorado operate under a simplified two-tier TOU structure. The old mid-peak tier is gone. There are now just two prices: on-peak and off-peak.
| Period | Hours | Summer (Jun–Sep) | Winter (Oct–May) |
|---|---|---|---|
| On-Peak | 5:00–9:00 p.m. · non-holiday weekdays only | 21.3¢/kWh | 18.3¢/kWh |
| Off-Peak | All other hours + weekends + holidays | 7.9¢/kWh | 6.8¢/kWh |
| Flat Rate (opt-out) | All hours, flat | ~10.0¢/kWh | ~9.0¢/kWh |
Source: Colorado PUC, 9News, CPR News, Xcel Energy rate schedules. Base rates; riders and adjustments apply.
Your 24-Hour Price Map
The chart below shows exactly what you pay — hour by hour — on a typical non-holiday weekday. Toggle between summer and winter rates. The four red bars are the danger zone; every green bar is an opportunity.
The 20-for-4 Trade
Step back and look at the arithmetic of a single weekday. There are 24 hours. On-peak hours — the window that costs 2.7 times more — occupy exactly four of them, on non-holiday weekdays only. The other 20 hours run at the low off-peak rate. Weekends and holidays are entirely off-peak. Over the course of a full year, on-peak hours represent only about 8% of all available hours.
5–9 p.m.
For many facilities, this asymmetry is genuinely manageable. A school building largely vacated by 4 p.m. A light manufacturing plant that runs day shifts. An office where the HVAC and lighting load drops sharply as employees leave. A warehouse on a morning-to-afternoon schedule. These facilities may already be well-positioned — or just a few scheduling adjustments away from capturing most of the off-peak advantage naturally.
The key question is not whether the rate structure is complex. It isn't. The key question is: what percentage of your electricity actually falls in those four hours? That number — and the nature of the loads driving it — determines everything about your strategy.
Start Here: Understanding Your Load Profile
No load management strategy can be designed, prioritized, or properly evaluated without a clear picture of your facility's actual consumption pattern. A load profile — drawn from 15-minute interval data — tells you exactly when your electricity is being used, how much, and by implication, what equipment is responsible. This is the foundation of every dollar of TOU savings.
The questions your load profile must answer are specific:
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What is your total kWh consumption during on-peak hours each month? Pull the prior three summer months and calculate the sum of all 15-minute intervals between 5:00 and 9:00 p.m. on non-holiday weekdays. This is your direct TOU energy exposure — the dollars at stake.
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What percentage of your total monthly consumption falls in peak hours? Divide on-peak kWh by total monthly kWh. For a typical office building, this is often 15–25%. A restaurant or retail operation with evening hours may see 30–40%. A manufacturing plant on day shifts may see under 10%. That percentage determines the size of the prize.
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What is your peak demand — and when does it occur? Identify your single highest 15-minute kW reading each month. Does it fall in the 5–9 p.m. window? If yes, your TOU management actions will simultaneously reduce your demand charge — compounding the savings from a single set of interventions.
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What loads are driving your on-peak consumption? HVAC is typically the largest component, followed by lighting, plug loads, and specialty equipment. Is the on-peak spike driven by occupancy, solar heat gain, equipment startups, or something else? The cause determines the remedy.
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Which on-peak loads are flexible, and which are fixed? Some loads — cooking in a restaurant, clinical operations in a healthcare facility — cannot be shifted. Others — EV charging, water heating, irrigation, laundry, pre-cooling setpoint recovery — can be easily rescheduled with zero operational impact. Separating flexible from fixed loads defines the ceiling of your achievable savings.
Xcel Energy provides 15-minute interval data through the My Account portal for customers with smart meters. This data can be downloaded as a CSV and analyzed in a spreadsheet in a matter of hours. For larger or more complex facilities, a brief professional energy audit can map the load profile against building systems and quickly identify where the highest-value interventions lie.
Who Is On TOU — And Who Controls the Switch?
Before designing any load management strategy, it's important to understand exactly which accounts are subject to TOU rates, what the switching rules are, and — critically for commercial customers — which rate schedules carry demand charges. The answers are more nuanced than most utility customers realize.
TOU Eligibility by Customer Class
Residential customers (Schedule RE-TOU) are the primary target of the November 2025 rate restructuring. All residential customers with a smart meter (AMI meter) installed are automatically enrolled in TOU rates. Smart meter installation typically triggers TOU enrollment 4–10 months after the meter is in place. Customers without smart meters remain on the legacy flat rate but may incur a $13–$26 per month manual meter-reading fee if they decline installation.
Small commercial customers with smart meters are also enrolled in the new TOU structure under the updated tariff. The Colorado PUC's language specifically covers "residential and small commercial customers" as the primary impacted class under Proceeding No. 24AL-0377E. Larger commercial and industrial customers operate under separate rate schedules — Schedule SG (Secondary General), Schedule PG (Primary General), Schedule TG (Transmission General), and their TOU and Critical Peak Pricing variants — which have their own demand charge structures and are not part of the residential TOU case.
Medical exception customers may qualify for a modified flat rate. Customers with a verified medical condition that necessitates high, time-inflexible electricity use should contact Xcel at 1-800-895-4999 to discuss the Medical Exemption Program (Schedule R MEP).
Notification and Timing: Switching On and Off TOU
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30-day advance notice required to transition to TOU. Customers are notified 30 days before their account is switched to the TOU rate following smart meter installation. This notice period is mandated so customers can understand the rate structure before it affects their bill.
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Opt-out is available anytime, at no charge. Any customer can opt out of TOU rates and elect the flat-rate opt-out (Schedule R-OO) by calling 1-800-895-4999 or through Xcel's My Account portal online. There is no fee for switching to the flat rate. The flat rate is set above the TOU off-peak rate and below the TOU on-peak rate — designed so the average customer pays roughly the same annual total under either plan.
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Switching back to TOU carries a 12-month minimum stay requirement. If a customer opts out to the flat rate and later wishes to return to TOU, they must remain on TOU for at least one full year before being permitted to opt out again. This lock-in provision is intended to prevent customers from gaming the system by selectively switching seasonally.
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Flat rate is also seasonal. The flat-rate opt-out is not a single fixed price — it carries a higher rate during the summer season (June–September, approximately 10¢/kWh) and a lower rate during winter (October–May, approximately 9¢/kWh). Customers on the flat rate are still subject to seasonal pricing, just without the on-peak/off-peak differentiation.
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Use Xcel's calculator before switching. The PUC directed Xcel to develop and maintain an online bill comparison tool. Customers should use this calculator — available at co.my.xcelenergy.com — with their actual interval data before opting out. For customers with manageable peak-hour loads, TOU is almost always the better choice once modest load shifting is implemented.
Which Customer Classes Face Demand Charges?
Demand charges are a commercial and industrial billing feature. Standard residential customers on Schedule RE-TOU or the flat-rate R-OO do not pay explicit demand charges — their entire bill is energy-based (¢/kWh). The one residential exception is Schedule RD (Residential Demand), a legacy rate available to a small number of larger residential customers, which does include a demand component.
For commercial and industrial customers, demand charges are a core billing element across all major rate schedules:
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Schedule C — Commercial Service. Small commercial customers served at secondary voltage. Includes a demand charge component; applies to businesses with loads typically in the range of 10–100 kW. This is the entry point for most small businesses into demand-billed territory.
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Schedule SG — Secondary General. The most common schedule for mid-size commercial and institutional customers (offices, schools, retail, light industrial). Served at secondary voltage. Carries both a demand charge and energy charges, with seasonal differentiation. The SG demand charge runs approximately $27.65/kW in summer and $20.31/kW in non-summer months (inclusive of all riders and adjustments), making it one of the most impactful line items on a commercial bill.
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Schedule PG — Primary General. Larger commercial and industrial customers served at primary voltage (typically 100 kW and above). Higher demand charges and energy charges than SG, with greater rate complexity. TOU and Critical Peak Pricing variants (Schedule PG-TOU, PG-CPP) are available and often advantageous for customers with manageable peak loads.
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Schedule TG — Transmission General. Very large industrial and institutional customers served at transmission voltage. The highest-demand-charge tier, with correspondingly higher per-kW rates and the greatest potential savings from demand management strategies.
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SG-TOU, PG-TOU, SG-CPP, PG-CPP — TOU and Critical Peak variants. Optional TOU and Critical Peak Pricing versions of the SG and PG schedules are available for commercial customers who want to combine time-differentiated energy pricing with their existing demand charge structure. These can offer additional savings for customers who have invested in load management and can reliably suppress on-peak consumption.
How Xcel Calculates Your Demand Charge: The Formula
Understanding the demand charge formula is essential because it explains both why demand charges are so significant and exactly what you need to do to reduce them. Xcel's tariff defines the billing demand formula as follows:
The Demand Charge Formula
kW demand recorded during the billing month
Billed in full kilowatt increments
× $/kW Rate
Summer: ~$27.65/kW
Winter: ~$20.31/kW
(Schedule SG, all-in)
The practical implication is stark: demand charge management is not about reducing overall consumption — it is specifically about controlling the shape of your load curve at its peak. A facility that runs 100 kW steadily all day and briefly touches 160 kW for 15 minutes at 5:15 p.m. on one Tuesday in August is billed on 160 kW for the entire month. Shaving that one spike to 120 kW saves $1,106 at Schedule SG summer rates — from a single 15-minute intervention.
The Bill You're Not Paying Attention To
Energy charges — the per-kWh cost that TOU rates directly affect — are only part of your bill. For most commercial and industrial facilities on Xcel's larger rate schedules, demand charges account for 40% or more of total electricity costs, yet they receive a fraction of the attention that energy charges do.
Demand charges are billed on your single highest 15-minute or 30-minute peak demand interval in the billing month. One spike — a momentary convergence of HVAC startup, plug loads, and EV chargers during a warm Tuesday evening in August — sets your demand charge for the entire 30-day billing period. A facility that runs at 100 kW all day and briefly touches 180 kW at 5:30 p.m. on one day gets billed on that 180 kW all month long.
The compounding insight: the 5–9 p.m. on-peak window and monthly demand spikes frequently coincide. HVAC at full capacity as employees return for evening operations, simultaneous equipment startups at shift end, EV chargers all activating at once — these events both drive up your TOU energy charge per kWh and set the demand peak that follows you for 30 days. Load management actions that suppress on-peak consumption attack both line items from a single effort.
Strategies to Shift and Shed Peak Load
Once you've quantified your on-peak exposure and identified the loads driving it, the strategy menu becomes clear. The best approaches combine immediate no-cost scheduling changes with modest investments in controls, and — for facilities with the right profile — a more transformative step into battery storage.
BAS reprogramming cost: often zero. On-peak HVAC energy reduction: 40–65% routinely achieved. Simultaneously cuts TOU energy charges and suppresses the demand spike that sets your monthly demand charge.
Staggered equipment startups — preventing HVAC compressors, air handlers, and other high-draw equipment from energizing simultaneously at 5 p.m. — are among the highest-ROI, lowest-cost interventions available. A 15-minute stagger across equipment groups can cut demand spikes by 20–40 kW with no operational disruption.
Other targets: commercial dishwashers, laundry cycles, irrigation systems, and ice machine harvest schedules. Smart outlet timers and programmable plugs cost under $20 each. The savings begin the first billing cycle with no contractor required.
Networked lighting controls (Lutron, Enlighted, Acuity) can be programmed with TOU-aware schedules that dim or extinguish fixtures in unoccupied spaces precisely at the 5 p.m. threshold, providing both TOU energy savings and demand charge reduction.
When the Numbers Justify a Bigger Step: Battery Storage
The strategies above — pre-cooling, demand controls, load scheduling — are available to virtually every commercial facility, often with minimal investment. But for facilities where on-peak exposure is significant, where demand charges are high, or where critical operations require standby backup power anyway, there is a more powerful solution that deserves serious evaluation: battery energy storage.
The Peak-Cost Case for Battery Storage
The 13.4¢/kWh summer spread between on-peak and off-peak rates creates a compelling economic engine for battery storage: charge at 7.9¢ during off-peak hours, discharge at 5 p.m. to displace electricity that would otherwise cost 21.3¢. Every kWh cycled through the battery captures that full spread as savings — every single day of the summer season.
But the energy arbitrage alone understates the value. A battery programmed to cap facility demand at a target threshold will suppress the monthly peak kW that sets your demand charge. A 200 kWh commercial battery can eliminate $800–1,500 per month in demand charges for a mid-size commercial facility — often exceeding the value of the TOU energy savings themselves.
The case becomes even more compelling for facilities that already require or are considering standby backup generation for critical operations. Consider: a diesel or natural gas generator provides backup power during outages but contributes nothing to daily energy cost management. A battery storage system does both simultaneously — it dispatches daily during peak hours to reduce costs, and it stands ready as backup power when the grid goes down. For facilities with data centers, medical equipment, cold storage, or other critical loads, this dual function fundamentally changes the investment calculation. The battery is no longer just an energy management tool; it is infrastructure that pays for itself through daily operation while providing the resilience backup your operation requires.
- IRA Investment Tax Credit: 30% of project cost, directly reducing capital outlay
- Colorado's commercial rebate programs further reduce net cost
- Typical commercial battery payback periods: 4–7 years with IRA credits applied
- Backup-capable systems provide additional resilience value that can justify shorter payback thresholds
- Paired with solar, batteries store midday generation for peak-hour discharge — maximizing both solar ROI and TOU savings
What This Looks Like in Practice
Consider a 40,000 sq ft office building in the Denver metro on Xcel's General Service rate schedule — a representative commercial facility with moderate on-peak exposure.
Before TOU Load Management
After Pre-Cooling + Demand Controller + EV Schedule Shift
TOU + Demand: Double the Return from the Same Actions
The same load-shifting actions that reduce your TOU energy bill also reduce your demand charge — because on-peak hours are precisely when demand peaks occur. Pre-cooling that reduces HVAC runtime from 5–9 p.m. simultaneously lowers the kW peak that sets your demand charge for the month.
A facility calculating TOU savings on energy charges alone is systematically undervaluing the strategy by roughly half. For a commercial facility spending $8,000/month on electricity, a combined approach targeting both TOU energy (38% of bill) and demand (40%+ of bill) can realistically reduce total annual electricity costs by $12,000–$18,000 — often with minimal capital investment.
The Window of Opportunity Is Open Now
The Best Combination of Rate Incentives and Financial Support in a Generation
For commercial facilities in Colorado, the convergence of factors that make TOU load management attractive has never been stronger. On one side: Xcel's new rate structure creates an unusually clear and actionable price signal — a defined four-hour window where cost avoidance is direct, measurable, and immediate. On the other side: the financial support available to fund the tools that capture that savings is at a historic high.
The federal Inflation Reduction Act's Investment Tax Credit covers 30% of battery storage system costs outright — a direct reduction in capital, not a deduction. Colorado's state rebate programs, utility incentives, and PACE financing options can layer additional support on top of that. For organizations considering both load management and resilience infrastructure, the combination of daily cost savings and backup power capability makes the business case more defensible than at any prior point.
Meanwhile, Xcel's rates are not static. The utility has a pending additional rate increase request that could push summer on-peak rates higher still — widening the spread further and making today's investment economics look increasingly conservative in retrospect. The facilities that build load management capabilities now will be structurally advantaged as rates continue to evolve.
The analysis is straightforward. The tools are available. The incentives are generous. The rate signal is clear. For commercial clients across Colorado, the time to evaluate and adopt these strategies is now — not after the next rate increase, and not after the next peak-season bill arrives as an unpleasant surprise.
Your Next 30 Days: An Action Checklist
- 1Pull your 15-minute interval data. Log into your Xcel account and download interval data for the past three months. Calculate your on-peak kWh total and express it as a percentage of total consumption. This one number frames your entire opportunity.
- 2Identify your peak demand and when it occurs. Find your highest 15-minute kW reading each month. If it falls between 5–9 p.m. on a weekday, you have TOU-demand charge overlap — and a compounding savings opportunity from every load management action you take.
- 3Implement pre-cooling before June 1. Summer on-peak rates begin June 1. If you have a BAS or programmable thermostat, configure the pre-cool protocol this week — drive to 68–70°F by 4:30 p.m., raise setpoint to 76°F at 5:00 p.m. sharp, recover at 9:00 p.m. Measure and iterate.
- 4Reschedule EV charging and large discretionary loads. Program all EV chargers to start at 9:01 p.m. Review dishwasher, laundry, and irrigation schedules. These are $0-cost changes with same-month savings that compound across every summer billing cycle.
- 5Evaluate demand controller economics. If your demand charge exceeds $800/month, a demand controller or BAS upgrade typically pays back in under 18 months. Get a quote and compare against your monthly demand charge reduction potential.
- 6Request a battery storage feasibility analysis. If your on-peak energy exposure exceeds 500 kWh/month, demand charges exceed $1,500/month, or your facility has critical backup power requirements, battery storage economics deserve a serious look. Apply the 30% IRA tax credit to your cost basis before evaluating payback. The analysis may surprise you.
Dan Frey is a Certified Energy Manager (CEM) and founder of St. Elmo LLC, a Boulder-based sustainability consulting firm. With 40 years of experience and hundreds of ENERGY STAR certifications, St. Elmo specializes in demand management, TOU rate optimization, load profiling, and turning utility complexity into measurable, verified savings. For a complimentary review of your facility's load profile and TOU exposure, reach out at stelmollc.com.
Rate data sourced from Colorado PUC, CPR News, 9News, and Xcel Energy published rate schedules. Rates reflect approved 2025–2026 tariffs. Example calculations are illustrative; actual savings will vary by facility. Always verify current rates and demand charge structures with Xcel Energy directly.