CHP plants generate value through two products simultaneously, but the revenue they earn from each product fluctuates on completely different timescales. Heat demand follows a seasonal and daily pattern driven by weather and occupancy, while electricity prices can swing by a factor of five or more within a single trading day based on grid conditions, renewable generation, and demand peaks. Running a CHP plant on a fixed schedule that ignores electricity market price signals is equivalent to a farmer who harvests regardless of market prices, then wonders why profitability is inconsistent. The plants that capture the most value from their cogeneration capacity are the ones that treat the electricity market price curve as a primary input to their dispatch decision, adjusting their heat-to-power ratio and operating hours to sell electricity when prices are high and throttle back when prices collapse. Book a dispatch optimization review to see how much revenue your CHP schedule is leaving on the table.
Your CHP Plant Is Selling Electricity at the Wrong Price Every Day
Fixed-schedule CHP dispatch ignores the electricity market price curve, which means the plant is almost certainly exporting power during low-price hours and throttling back during high-price hours. Market-responsive dispatch aligns CHP output with price signals while respecting heat demand constraints, capturing revenue that fixed schedules cannot reach.
The Revenue Gap Between Fixed Dispatch and Market-Responsive Dispatch
A CHP plant that runs the same schedule every day produces the same total electrical output, but the revenue it earns from that output varies dramatically depending on when that output is delivered to the grid. The electricity market rewards generation delivered during peak price periods with prices that can be three to eight times higher than off-peak prices, and penalizes generation that adds supply during periods of already-low prices. Fixed dispatch schedules, which are typically set based on heat demand alone, have no mechanism to capture this price differential.
The market-responsive dispatch delivers 48 percent more electricity revenue from the same plant by shifting two operating hours from low-price periods to high-price periods, with a two percent reduction in heat demand satisfaction that is bridged by a modest thermal storage buffer. Over a heating season, this pattern compounds into a six-figure revenue difference for even a mid-size CHP installation.
Three Competing Forces That Every Dispatch Decision Must Balance
CHP dispatch is not a single-variable optimization problem. Every hour, the plant operator must balance three forces that pull the dispatch decision in different directions. Ignoring any one of them produces a schedule that appears optimal from one perspective but is suboptimal from the system perspective. The art and economics of dispatch optimization lie in finding the operating point that maximizes total system value, not just one component of that value.
The spot price for electricity at the plant grid connection point, updated on whatever granularity the market provides, typically 15-minute to 1-hour intervals. Higher prices incentivize maximum electrical output from the CHP plant, which in most engine-based CHP systems means running at full electrical load with the heat-to-power ratio determined by the engine operating point. When electricity prices drop below the plant marginal fuel cost, the economic signal reverses and the plant should throttle back or shut down, unless heat demand requires continued operation. The challenge is that price signals arrive with limited lead time, requiring a dispatch system that can respond to price changes faster than the CHP plant ramp rate allows.
The thermal energy demand from the district heating network or industrial process that the CHP plant serves, modified by the available thermal storage capacity. Heat demand is less volatile than electricity prices but still varies with weather, time of day, and production schedules. Thermal storage decouples heat production from heat consumption in time, allowing the CHP plant to produce heat during high-electricity-price hours and release it during low-price hours when the plant throttles back. The size of the thermal buffer determines how much dispatch flexibility the plant has: a plant with two hours of storage can shift its operating window by roughly two hours, while a plant with eight hours of storage has far more latitude to chase electricity price peaks.
The cost of natural gas or other fuel input, combined with the CHP plant efficiency at each operating point. The marginal cost of generating one additional MWh of electricity from the CHP plant is the fuel cost divided by the electrical efficiency at that operating point. When the electricity market price exceeds this marginal cost, each MWh of additional electrical generation creates positive margin. When the market price falls below marginal cost, each additional MWh destroys value. The marginal cost curve is not flat across the CHP operating range because electrical efficiency changes with load, typically peaking at 75 to 90 percent of rated load and declining at both lower and higher outputs. Dispatch optimization must use the actual efficiency curve, not the nameplate efficiency rating.
Electricity Market Signals and How Each One Drives Dispatch Behavior
Not all electricity market price signals carry the same information or drive the same dispatch response. Understanding the distinction between day-ahead prices, real-time prices, and capacity payments is essential because each signal operates on a different timescale and requires a different dispatch response. Plants that respond to only one of these signals are leaving value from the others uncollected.
A dispatch optimization system that only reads day-ahead prices will miss intraday price improvements and real-time spikes. A system that only responds to real-time prices cannot plan thermal storage charging and discharging cycles with enough lead time. Effective dispatch requires integrating all available price signals with appropriate lead times, using day-ahead prices for the base schedule and intraday and real-time prices for incremental adjustments within the ramp-rate constraints of the CHP equipment.
The Dispatch Strategy Matrix: When Each Mode Wins
CHP dispatch strategies fall along a spectrum from fully heat-led to fully power-led, with market-responsive dispatch occupying the middle ground where both heat and electricity values inform the decision. No single strategy is optimal across all market conditions and heat demand levels. The optimal approach switches between modes as conditions change, sometimes within a single day.
The CHP plant runs whenever heat is needed, and electricity generation is treated as a byproduct whose revenue is collected but does not influence the operating schedule. This is the default mode for most CHP plants and it is genuinely optimal when electricity prices are relatively flat across the day, because there is no price signal worth chasing. The limitation appears when electricity prices become volatile and the plant continues exporting power during low-price hours simply because heat demand requires operation. Heat-led dispatch also cannot evaluate whether it would be cheaper to meet heat demand from a backup boiler and shut down the CHP plant during negative or very low electricity price periods.
The CHP plant runs when electricity prices are high, and thermal output is stored or dumped if it exceeds immediate heat demand. This mode maximizes electricity revenue but requires sufficient thermal storage to buffer the mismatch between when the plant generates heat and when the heating network needs it. Power-led dispatch becomes risky when thermal storage is insufficient because the plant may be forced to reject heat, which is thermodynamically wasteful and can stress the CHP heat rejection system. It also requires careful monitoring of backup fuel costs if supplemental boilers must fire to cover heat demand during periods when the CHP plant is shut down for low electricity prices.
The dispatch engine evaluates both heat demand and electricity price for each upcoming time interval and selects the operating point that maximizes total margin, which is electricity revenue minus fuel cost minus any supplemental heating cost. This mode automatically transitions between heat-led and power-led behavior as conditions change: it runs heat-led when prices are flat, power-led when prices spike, and may choose to shut down the CHP plant entirely if electricity prices are below marginal fuel cost and backup boiler fuel cost is lower than the cost of running the CHP plant to produce heat. Market-responsive dispatch requires real-time data feeds for both electricity prices and heat demand, plus a model of the CHP plant efficiency curve and thermal storage state.
Turn Electricity Price Volatility Into Dispatch Revenue
iFactory connects to your electricity market data feed and CHP plant controls, calculates the marginal cost of generation at each operating point, and produces an hourly dispatch schedule that maximizes total margin while respecting heat demand and equipment constraints.
Five Dispatch Optimization Strategies Ranked by Complexity and Return
Not every plant needs the most sophisticated dispatch system on day one. The strategies below are ordered from simplest to most complex, with each building on the capabilities of the previous level. The goal is to implement them in sequence, capturing value at each stage while building toward a fully market-responsive dispatch capability.
Day-Ahead Price-Aware Scheduling
The simplest form of market-responsive dispatch. The plant operator reviews the day-ahead electricity price curve published by the market and manually adjusts the CHP operating schedule to shift as much generation as possible into high-price hours, within the constraint of meeting heat demand. This requires no software beyond access to the price curve and the ability to adjust the plant schedule, but it captures a significant portion of the available price differential because day-ahead prices typically explain 60 to 70 percent of the variation in real-time prices. Plants that implement only this level typically capture 40 to 55 percent of the total dispatch optimization value available, because they miss intraday adjustments and cannot optimize within hourly blocks.
Marginal Cost Curve Integration
Level one treats the CHP plant as having a constant cost per MWh, which is incorrect because electrical efficiency varies with load. Level two introduces the actual marginal cost curve, which is the fuel cost divided by the electrical efficiency at each operating point. With this curve, the dispatch engine can determine not just when to run but at what load level to run. For example, if electricity prices are moderate but above marginal cost only at partial load, the plant may generate more total margin by running at 70 percent load than at 100 percent load, even though 100 percent load produces more total electricity. This level requires a reasonable efficiency model of the CHP plant, which can be derived from operating data without detailed manufacturer performance maps.
Thermal Storage-Coordinated Dispatch
Level three adds thermal storage to the dispatch model, treating it as a time-shifting buffer that allows the CHP plant to decouple heat production from heat consumption. The dispatch engine now evaluates not just the current hour but a rolling window of 4 to 12 hours, deciding when to charge storage, when to discharge it, and when to bypass it. This is where the largest single-step improvement in dispatch value typically appears, because thermal storage converts a plant that can only shift its schedule by 30 to 60 minutes within ramp-rate constraints into a plant that can shift its effective heat delivery by the full storage duration. The optimization must respect storage capacity limits, charge and discharge rate limits, and thermal losses from the storage vessel during the holding period.
Intraday and Real-Time Price Response
Level four extends the dispatch optimization beyond the day-ahead schedule into intraday and real-time price adjustments. As updated price forecasts arrive through the day, the dispatch engine recalculates the optimal schedule for the remaining hours and adjusts the CHP plant operating point accordingly. This level captures the additional value from intraday price movements that the day-ahead schedule could not anticipate, such as unexpected wind generation drops, demand spikes from weather changes, or transmission constraints that create localized price spikes. The practical limit on real-time response is the CHP plant ramp rate, which for gas engines is typically 20 to 40 percent of rated load per minute, meaning the plant can adjust output significantly within a single 15-minute market interval.
Multi-Revenue Stack Optimization
The most comprehensive dispatch approach integrates electricity energy prices with capacity payments, ancillary service revenues, and any demand response program payments into a single optimization that evaluates all revenue streams simultaneously. At this level, the dispatch engine might choose to hold 10 percent of CHP capacity in reserve for frequency regulation if the ancillary service price makes that more valuable than exporting the full electrical output, or it might modulate output to follow a demand response signal if the demand response payment exceeds the net margin from electricity sales at the current price. This level requires integration with multiple market interfaces and a decision engine that can evaluate competing revenue opportunities on a common marginal cost basis. It represents the full potential of market-responsive CHP dispatch.
Revenue Impact by Dispatch Optimization Level
Figures from CHP plants that implemented dispatch optimization progressively, measured as the increase in annual electricity revenue relative to the fixed-schedule baseline that was in place before optimization began.
Peak Shaving vs Price Chasing: Why the Distinction Matters
Peak shaving and price chasing are often used interchangeably in CHP dispatch discussions, but they describe fundamentally different strategies with different value propositions, different implementation requirements, and different risk profiles. Confusing the two leads to dispatch strategies that appear rational but fail to capture the available value because they target the wrong objective.
Peak shaving targets the demand charge component of the electricity bill, which is based on the facility maximum power draw during the billing period, typically measured as the highest 15-minute average demand. The CHP plant runs during periods of high facility electrical demand to reduce the net import from the grid, lowering the demand charge. This strategy has predictable value because demand charges are known in advance and do not vary day to day, but the value is capped at the total demand charge amount. Peak shaving does not respond to wholesale electricity prices because its objective is to reduce measured peak demand, not to optimize the timing of electricity exports to the grid. It is most valuable for facilities with high demand charges relative to energy charges, which is common in commercial and institutional CHP applications.
Price chasing targets the energy component of electricity revenue, which varies with the wholesale market price at the plant grid connection point. The CHP plant adjusts its electrical output to export more power when prices are high and less when prices are low, regardless of the facility internal demand pattern. This strategy has variable value because it depends on market price volatility, which changes from day to day and season to season, but the upside is uncapped because the plant can capture extreme price spikes that occur during supply shortages or transmission constraints. Price chasing requires access to real-time or near-real-time price data and the ability to adjust CHP output within market interval timeframes. It is most valuable for plants that export a significant fraction of their electrical output to the grid rather than serving only behind-the-meter load.
A CHP Plant Manager on the First Month of Market-Responsive Dispatch
We had been running our two-megawatt CHP plant on a fixed schedule for six years, starting up at six in the morning and shutting down at ten at night because that was when our heat demand window fell. When we finally connected to the day-ahead price feed and started shifting our start time to match the morning price ramp, we picked up eleven percent more electricity revenue in the first month without changing our total operating hours. The real wake-up call came three weeks in, when a late-afternoon price spike hit 180 per megawatt-hour and our old schedule would have had us shutting down right as the price peaked. The new schedule kept us running through the spike, and that single afternoon was worth more revenue than the entire previous week of fixed-schedule operation. We left thousands of euros on the table every time that pattern repeated, and it repeated constantly.
Frequently Asked Questions
How quickly can a CHP plant respond to electricity price changes?
Gas engine CHP plants typically ramp at 20 to 40 percent of rated load per minute, meaning a 5 MW plant can adjust its output by 1 to 2 MW within a single minute. This is fast enough to respond to 15-minute market intervals and to participate in many frequency regulation programs, though not fast enough for the fastest sub-second regulation services that battery systems provide. Steam turbine CHP plants ramp more slowly, typically at 5 to 15 percent of rated load per minute, which limits their ability to chase intraday price movements but does not prevent day-ahead schedule optimization. The practical dispatch response time also includes the time required for the control system to receive the price signal, run the optimization calculation, and send the setpoint change to the CHP controller, which typically adds 30 seconds to 2 minutes depending on the system architecture. Book a demo to see how real-time price response works with your CHP ramp rate.
Does market-responsive dispatch increase CHP plant maintenance costs?
Frequent load following and start-stop cycles do increase certain maintenance components compared to steady-state baseload operation, but the magnitude of the increase is often overestimated. Gas engine CHP plants are designed for load following and can tolerate multiple start-stop cycles per day within their maintenance interval specifications when proper warm-up and cool-down protocols are followed. The additional maintenance cost from market-responsive dispatch is typically one to three percent of the additional electricity revenue captured, which means the net economic benefit remains strongly positive. The key maintenance consideration is tracking equivalent operating hours, which account for the additional wear from start-stop cycles, and adjusting maintenance scheduling accordingly rather than relying solely on calendar time or total operating hours. Talk to a specialist about maintenance planning for market-responsive operation.
What is the minimum thermal storage needed for effective price-responsive dispatch?
The minimum useful thermal storage depends on the CHP plant thermal output and the typical duration of price peaks in the relevant electricity market. As a practical guideline, storage equivalent to 1.5 to 2 hours of CHP thermal output at full load provides enough buffer to shift the plant operating window by roughly that duration, which is sufficient to capture most single-peak daily price patterns. In markets with pronounced morning and evening price peaks separated by a midday valley, 3 to 4 hours of storage allows the plant to run through both peaks and throttle back during the valley. Storage beyond 6 to 8 hours of CHP capacity provides diminishing dispatch value because the typical price peak duration in most markets does not exceed that window, and longer storage periods incur higher thermal losses that erode the benefit. Book a demo to model the optimal storage size for your CHP and market profile.
Can dispatch optimization work if the CHP plant only operates behind the meter with no grid export?
Yes, but the value proposition shifts from electricity revenue optimization to electricity cost avoidance optimization. Behind-the-meter CHP plants reduce grid imports, so the relevant price signal is the retail electricity tariff rather than the wholesale market price. Many commercial and industrial tariffs include time-of-use pricing, demand charges, or both, which create price signals that dispatch optimization can exploit. Time-of-use tariffs with peak, shoulder, and off-peak rates create a simplified version of the wholesale price curve that still rewards shifting CHP generation into high-rate periods. Demand charge reduction through peak shaving is a separate but complementary value stream. Even flat-rate tariffs can benefit from dispatch optimization if the facility has demand response program participation or if the utility offers real-time pricing options. Talk to a specialist about optimizing dispatch for your specific tariff structure.
What data feeds does a dispatch optimization system need to operate effectively?
At minimum, a dispatch optimization system requires three data feeds: an electricity price signal updated at the granularity of the market intervals the plant participates in, a heat demand forecast for the upcoming 12 to 48 hours depending on the optimization horizon, and real-time CHP plant operating data including electrical output, thermal output, and fuel consumption to maintain an accurate marginal cost model. Additional valuable feeds include thermal storage state of charge, weather forecasts that drive heat demand prediction, backup boiler fuel cost and availability, and any demand response or ancillary service program signals the plant is enrolled in. The quality of the dispatch output is directly proportional to the quality and timeliness of these inputs, with electricity price data accuracy being the single most impactful variable because price forecast errors translate directly into suboptimal dispatch decisions. Book a demo to see what data integration is needed for your plant.
The Bottom Line on CHP Dispatch Optimization for Electricity Markets
Every CHP plant that sells electricity to the grid or reduces grid imports through behind-the-meter generation is participating in the electricity market whether it knows it or not. The only question is whether it is participating intelligently or ignorantly. A fixed-schedule plant that ignores price signals sells electricity at whatever price the market happens to offer at the hours it chose to run, which means it systematically underperforms relative to its economic potential. Market-responsive dispatch does not require the plant to run more hours or produce more electricity; it requires the plant to produce the same electricity at better-priced hours. The five levels of dispatch optimization, from simple day-ahead price awareness through full multi-revenue stack optimization, each capture additional value that the previous level leaves on the table. The marginal cost of implementing each level is modest compared to the revenue it unlocks, and the cumulative effect of moving from fixed dispatch to fully optimized dispatch can increase annual electricity revenue by 50 to 70 percent for the same CHP plant, same fuel consumption, and same total operating hours. The data required to make these decisions, specifically electricity price feeds, heat demand forecasts, and CHP plant efficiency curves, is available to every plant operator today. The gap is not in data availability but in the analytical capability to convert that data into dispatch decisions in real time.
Stop Selling Electricity at Prices You Would Never Accept
Book a 30-minute dispatch optimization assessment. Bring your CHP operating schedule and your electricity bill or market settlement data, and iFactory will quantify the revenue gap between your current dispatch and a market-responsive schedule.
