Sizing the Power Rating: What the Megawatts Are Actually For
Ask what size a battery is and you will often get one number in megawatts. That number describes the rate at which it can charge or discharge, but it is only half the specification. The economic value of an incremental MW depends on the market products, interconnection rights, energy capacity and state-of-charge constraints behind it.
On the worked assumptions below, a simple attribution exercise moves from 72% “power-linked” revenue at one hour to 61% “energy-linked” revenue at six hours. Those percentages are scenario outputs, not market benchmarks.
The more important point is that MW and MWh affect different parts of the feasible operating set. MW caps instantaneous charge / discharge; MWh determines how long that power can be sustained. Capacity, ancillary-service and energy-market value can depend on both.
That matters for sizing because the two dimensions respond differently to interconnection, product rules, price shape and equipment cost. Decomposing them is useful for diagnosis; the final configuration should still be checked jointly.
ℹ️ Note: The price shape used throughout is a single representative volatile day, used to demonstrate method. Real analysis requires the full 8,760-hour price and market series for the node in question; a representative volatile day is only a worked illustration.
Power and energy answer different commercial questions:
flowchart TD
A[Battery configuration] --> B[Power rating: MW]
A --> C[Energy capacity: MWh]
B --> D[Interconnection use]
B --> E[Ancillary-service capacity]
B --> F[Maximum instantaneous revenue]
C --> G[Duration]
C --> H[Arbitrage window]
C --> I[Energy reserved for later hours]
What Does the Megawatt Actually Sell?
Three things, and only one of them cares about duration.
| Revenue / service | MW sensitivity | MWh / SOC sensitivity |
|---|---|---|
| Capacity / accreditation | accredited deliverable MW matters | duration and reliability methodology can change accredited value |
| Ancillary services | award is commonly in MW | duration / SOC must be sufficient for the product and market constraints |
| Energy arbitrage | MW sets how fast energy can move | MWh and SOC determine how long / how much can be shifted |
For arbitrage, additional MW can increase value by concentrating a fixed MWh inventory into narrower high-price intervals, but only until another constraint binds — stored energy, interconnection, charge time, SOC, market interval or price shape. There is no universal E / D point beyond which the extra MW has zero value across all days.
The Three Power-Linked Revenues
Assumptions, labelled as such:
Capacity, 4-hour at 55% ELCC × $118,625/accredited MW-yr = $65,244/MW/yr
Ancillary services, ERCOT index at the AS share = $15,840/MW/yr
----------
Power-linked revenue = $81,084/MW/yr
Capacity can be duration-sensitive through the market’s accreditation methodology. PJM, for example, publishes separate ELCC class ratings for 4-, 6-, 8- and 10-hour storage and updates those ratings as system conditions change. Use the current applicable class rating rather than a fixed ladder embedded in the model.
Ancillary services are often quoted in MW, but storage still needs enough SOC and duration to make the award deliverable. CAISO explicitly enforces ancillary-service SOC constraints, and ERCOT’s RTC+B implementation models battery SOC when co-optimizing energy and ancillary services.
The rate contribution to arbitrage is real but bounded, and the bound is the subject of the next section.
Energy-Linked Revenue, and Where the Mix Flips
Arbitrage on the same representative day, one cycle per day:
| Duration | Per cycle | Per year | Power-linked | Energy-linked |
|---|---|---|---|---|
| 1 hour | $85.91/MW | $31,357/MW | 72% | 28% |
| 2 hours | $163.68/MW | $59,744/MW | 58% | 42% |
| 4 hours | $281.82/MW | $102,864/MW | 44% | 56% |
| 6 hours | $340.73/MW | $124,365/MW | 39% | 61% |
Two things to take from that table.
The worked example crosses between two and four hours. That is a scenario result, not a structural market break. Change capacity accreditation, ancillary-service prices, node spreads, cycling or degradation assumptions and the crossover moves.
In this simplified table, the power-linked component is held mostly constant. Real markets can make both components duration-sensitive: capacity accreditation changes with duration, ancillary products have SOC / duration requirements, and energy value depends on both MW and MWh.
The Rate That Is Enough
Here is the bound that decides how much power is actually useful for arbitrage.
To discharge E megawatt-hours into the D most valuable hours of the day, the required rate is E / D. Megawatts beyond that cannot be used, because there is no more stored energy to move and no more valuable hours to move it into.
400 MWh discharged over the top 4 hours requires 100 MW
400 MWh discharged over the top 2 hours requires 200 MW
The second line is not obviously worse. Discharging the same energy into the best two hours rather than the best four captures a higher average price — on the representative day, the top two hours average $91.50 against $81.25 for the top four. So doubling the power rating to concentrate delivery into fewer, better hours raises arbitrage revenue by about 12.6%.
Whether that is worth doubling the power rating depends on what the extra megawatts cost, and on whether the point of interconnection permits them at all. On a power-constrained site the question does not arise. On a land-constrained site with a large connection, it is the central decision.
For a fixed energy inventory and a fixed set of discharge hours, power above E / D no longer improves that specific dispatch schedule. In a full annual model, extra MW can still change value through different charge windows, additional cycles, ancillary participation, scarcity events or product eligibility.
What Actually Sets the Power Rating?
Four recurring drivers, with no universal ordering.
The interconnection envelope, as the previous post established. Injection and charging limits can cap usable power, but the exact limit and the ability to modify it are project-specific.
The power conversion cost. The inverters, transformers and balance of plant scale with megawatts and are the fixed component of the cost structure — roughly $380/kW on the assumptions this series uses. Unlike cells, this cost does not fall with duration; it is incurred once per megawatt.
The products available. A market with a deep ancillary services requirement and a capacity construct rewards megawatts. An energy-only market with thin ancillary procurement does not, and the rate that is enough becomes the rate to build.
Capacity accreditation. Where capacity revenue matters, duration can change accredited MW materially. PJM's 2028/29 BRA ratings, for example, were 59% for 4-hour storage, 68% for 6-hour, 71% for 8-hour and 78% for 10-hour storage. Those are delivery-year-specific ratings, not a permanent ladder.
Those four interact in a way worth stating explicitly, because the interaction is where sizing errors come from.
The interconnection sets a ceiling. The power conversion cost sets a price for approaching it. The available products decide whether approaching it is worth paying for. And capacity accreditation can make additional duration economically valuable, which may require more energy capacity and site area than a short-duration design.
So a site can fail in a way that looks contradictory: a large interconnection, adequate land for a short-duration asset, a deep capacity market, and no viable project — because the accreditation floor requires four hours, four hours requires more land than the parcel has after setbacks, and without accreditation the megawatts do not clear their cost.
That is not an exotic case. It is the ordinary shape of an urban or constrained site, and it is invisible to any analysis that treats the four factors as a checklist rather than as a system. The constraint-stack post's instruction applies directly: identify which one binds, then test whether the others are still satisfiable at that point.
When a Power-Heavy Strategy Stops Fitting the Market
Worth testing because a configuration optimized for one product mix may be a poor fit after prices, procurement quantities or market rules change.
When ancillary services paid well, the optimal configuration was obvious: maximise power, minimise energy. Ancillary products pay per megawatt held available, have short maximum delivery periods, and rarely call for sustained output. A one-hour battery could hold the same award as a four-hour one at a quarter of the cell cost.
That produced a generation of short-duration assets whose economics were almost entirely power-linked — the 72% row in the table above, and often higher.
Then the economics changed. As the battery revenue-stack post documents, ERCOT ancillary-service value compressed sharply as storage participation increased and the market design evolved. The lesson is not that ancillary demand is literally fixed; ERCOT can and does change procurement quantities and product design. The lesson is that a power-heavy configuration is exposed to saturation and rule change in the products that pay for MW.
A short-duration asset can remain valuable after ancillary-service economics weaken, but its alternative revenue options are shaped by the MWh inventory it was built with. The worked table illustrates how less energy capacity limits time-shifting depth.
Three lessons for sizing that generalise beyond this episode.
A configuration optimised for one revenue regime can age badly. Ancillary procurement quantities, eligibility rules and prices can change while the physical MW/MWh ratio cannot be changed cheaply.
Power is the harder dimension to change later. Adding energy to an existing site is an augmentation project. Adding power means new inverters, a larger connection and possibly a new interconnection study. A configuration decision that errs toward more power is harder to unwind than one that errs toward more energy.
The revenue mix at the time of sizing is not the mix over the asset's life. A fifteen-year asset sized on a two-year-old revenue split has assumed away exactly the change that has already happened once in this market.
The Power-to-Energy Ratio Is Also a Degradation Decision
The link that sizing conversations usually miss, because power is discussed with the commercial team and degradation with the engineering team.
The ratio of power to energy is the C-rate — the rate at which the battery charges or discharges relative to its capacity. A 100 MW / 100 MWh system runs at 1C. A 100 MW / 400 MWh system runs at 0.25C.
C-rate matters because it drives heat, and heat drives degradation. A cell cycled hard at a high C-rate loses capacity faster than the same cell cycled gently, for the same energy throughput. So two batteries delivering identical megawatt-hours over their lives can reach end of warranty at different times purely because of their power-to-energy ratio.
Three consequences for sizing.
Shorter duration raises C-rate for the same MW, but the degradation consequence is chemistry- and operating-condition-specific. NREL lifetime models treat charge/discharge rate, temperature, SOC history and cycling pattern as interacting drivers rather than reducing battery life to C-rate alone.
OEM warranties and operating envelopes can constrain rate, throughput and operating conditions. Check the actual C-rate, depth-of-discharge, temperature, throughput and availability conditions rather than assuming every warranty uses the same maximum-C-rate structure.
The auxiliary load rises with C-rate. Thermal management consumes energy, and it consumes more of it at high rates. That is a direct deduction from round-trip efficiency, which the next posts in this series treat as a fixed parameter and which is in fact partly a consequence of how the asset was configured.
The practical instruction is to carry the C-rate as an explicit output of the sizing calculation rather than as an implied consequence of two numbers chosen separately — and to check it against the warranty before the configuration is fixed rather than after.
The C-Rate Rises Over the Asset's Life
A second-order effect that follows directly, and which is genuinely under-modelled.
Capacity fade often reduces usable energy before the inverter nameplate changes, so effective duration and C-rate can rise if power capability is held constant. But usable MW can also be derated by cell resistance, thermal limits, PCS limits or OEM controls. Model both energy and power capability rather than assuming only MWh degrades.
Year 1 100 MW / 400 MWh = 4.00 hours 0.250C
Year 10 100 MW / 340 MWh = 3.40 hours 0.294C
Year 15 100 MW / 320 MWh = 3.20 hours 0.313C
The asset becomes shorter in duration and higher in C-rate every year, at constant power. Three things follow that a flat-configuration model will miss entirely.
The revenue mix can drift. Capacity fade changes effective duration, but the accreditation consequence depends on the market methodology and whether augmentation maintains the qualified configuration. Do not convert an energy-retention curve directly into a capacity-revenue cliff without the applicable accreditation rules.
The operating point changes as usable energy falls. If MW is held constant while MWh declines, the implied C-rate rises. Whether that materially accelerates degradation depends on the OEM degradation model and operating conditions.
Augmentation can restore usable energy and therefore duration, subject to the electrical design, inverter limits and integration strategy. Its timing should be based on the contractual performance / warranty case and the degradation model rather than a generic throughput-only rule.
Modelling the configuration as fixed at its year-one specification can misstate late-life revenue, duration and degradation. The direction depends on augmentation, derating and the market’s accreditation methodology.
How Do You Size the Power Rating in Excel?
By attributing revenue to the variable that pays it, then testing megawatts against the marginal cost of adding them.
The revenue attribution
Power_Linked_Revenue = Capacity_MW × ELCC% × $/acc.MW-yr
+ AS_MW × AS_$/MW-yr
Energy_Linked_Revenue = Σ over cycles of (Σ sell prices − Σ buy prices / RTE)
PF_PowerLinkedShare = Power_Linked / (Power_Linked + Energy_Linked)
Publish that share. It tells a reader in one number which kind of asset this is, and therefore which sizing question is worth spending time on.
The marginal megawatt test
Marginal revenue of +1 MW:
if MW < Energy_MWh / Discharge_Hours → capacity + AS + arbitrage uplift
if MW ≥ Energy_MWh / Discharge_Hours → capacity + AS only
Marginal cost of +1 MW = BOS_$/kW × 1,000 ÷ annuity factor
= 380,000 ÷ 6.8109 = $55,793/MW/yr
Against $81,084 of power-linked revenue per megawatt-year, an additional megawatt clears its cost on capacity and ancillary alone — provided those products are actually available and the accreditation holds. Strip out the capacity revenue and the same megawatt earns $15,840 against a $55,793 cost, and fails badly.
That contrast is the whole power-sizing decision in two lines, and it explains why battery power ratings differ so sharply between markets with a capacity construct and markets without one.
The concentration test
Discharge over top 4 hours: average captured price $81.25/MWh
Discharge over top 2 hours: average captured price $91.50/MWh
Uplift from concentrating 12.6%
Extra MW required to concentrate 400 MWh into 2 hours +100 MW
Extra cost 100 × $55,793 = $5,579,300/yr
Arbitrage uplift 400 × 10.25 × 365 = $1,496,500/yr
On these assumptions, concentrating is not worth it on arbitrage alone — the extra megawatts cost nearly four times what they add. They would only clear if the additional 100 MW also earned capacity and ancillary revenue, which returns the decision to whether those products exist at this node.
ℹ️ Note: Use the MW/MWh decomposition to understand marginal value, but run the final configuration jointly. A joint optimization captures the interaction; the decomposition makes the result auditable.
To build the revenue attribution, the marginal megawatt test and the concentration comparison, prompt Dezzmond with your price series, product prices and interconnection limit.
What Do Developers Actually Check?
- What share of revenue is power-linked versus energy-linked?
- Is there a capacity construct at this node, and what does it accredit?
- What is
E / D— the rate that is enough for the arbitrage strategy? - Does a marginal megawatt clear its cost on capacity and ancillary alone?
- How sensitive is the ancillary-service value to storage penetration and market-rule changes?
- How does the current accreditation methodology change with duration for the delivery year being modeled?
- Is the power rating the interconnection limit, or a choice? Both are common; they are different situations.
Frequently Asked Questions
What does the megawatt rating of a battery sell?
Capacity accreditation and ancillary services, both paid per megawatt, plus the rate at which stored energy can be moved. Arbitrage itself is paid per megawatt-hour, so power contributes to it only up to the rate needed to discharge the available energy.
When does more power stop adding arbitrage revenue?
In a fixed single-cycle schedule, once the stored energy can already be delivered into the selected high-value hours. In an annual co-optimised model, the answer depends on charge windows, multiple cycles, price shape, ancillary participation and interconnection limits.
Why does the revenue mix flip with duration?
In the worked assumptions, the MW-attributed component is held relatively stable while time-shifting value grows with MWh, so the crossover falls between two and four hours. In a real market both sides can be duration-sensitive.
Should power and energy be sized together or separately?
Decompose them first for diagnosis, then test the final configuration jointly. The diagnostic split shows what pays for MW versus MWh; the joint optimisation captures their interaction.
What is the C-rate and why does it matter for sizing?
The ratio of power to energy — 100 MW / 400 MWh is 0.25C. C-rate affects heat and degradation, but the magnitude is chemistry- and operating-condition-specific. Check the OEM warranty and lifetime model rather than applying a universal penalty.
Does the C-rate change over the asset's life?
It can rise if usable energy fades while available MW is held constant. Augmentation, thermal derating or OEM power limits can change that path, so model effective C-rate from the actual annual MW and MWh capability.
Does a bigger power rating let you capture better prices?
Yes, by concentrating discharge into fewer, better hours — on the worked day, the top two hours average 12.6% more than the top four. Whether that pays depends on the cost of the extra megawatts, which on these assumptions it does not on arbitrage alone.
Closing: The Rate, Not the Size
"How big is the battery" is a question with two answers, and the megawatt figure that usually gets quoted is the one describing how fast rather than how much.
That distinction has a practical consequence. Capacity and ancillary products may settle in MW, but storage still needs enough duration and SOC to qualify and perform. Energy markets settle MWh, but MW determines how quickly that inventory can be moved. The two dimensions are commercially distinct and physically coupled.
The most useful thing a sizing analysis can produce at this stage is therefore not a megawatt figure. It is the power-linked revenue share: one number that says whether this project is a capacity asset with storage attached or a storage asset with a power rating, because the answer determines whether the next post's question is the important one or a footnote.
the next post asks how many hours to build, and why a familiar four-hour configuration may or may not be the economic answer.
Sources: PJM — 2028/29 BRA ELCC class ratings, including 4-/6-/8-/10-hour storage · ERCOT — RTC+B go-live and SOC-aware real-time co-optimization · ERCOT current Nodal Protocols · NREL Battery Lifespan — lifetime-aware battery controls and design · Dezzmond analysis; revenue-attribution and cost examples are illustrative.