The Cost Curve: Why Dollars per Kilowatt-Hour Is a Misleading Way to Compare Batteries
Two battery projects. The same cells at the same price, the same inverters from the same supplier, the same installation contractor.
One-hour system $560/kWh
Eight-hour system $228/kWh
The eight-hour system looks 59% cheaper. It is not cheaper at all. Every component costs exactly what it costs in the one-hour system — the only thing that changed is the denominator.
Dollars per kilowatt-hour is a ratio of two independent costs, and duration moves only one of them. That makes it a reasonable way to describe a system and a misleading way to compare systems of different lengths, which is most of what it gets used for.
This post takes the cost structure apart: the two components, the curve they produce, why the marginal hour costs the same every time, and how to compare vendors without the duration artefact getting in the way.
ℹ️ Note: Cost figures are labelled assumptions calibrated to published US ranges. Actual pricing varies enormously by geography, chemistry, scale and procurement timing.
The Cost Equation
Battery cost has two components that scale on different things.
Total cost ($/kW) = Pack cost ($/kWh) × duration (hours) + BOS cost ($/kW)
The pack — cells, modules, racks, battery management — scales with energy. Twice the megawatt-hours means twice the cells.
Balance of system — inverters, transformers, switchgear, controls, HVAC, civil works, grid connection, installation and engineering — scales with power. A 100 MW system needs 100 MW of power conversion whether it runs for one hour or ten.
That is the whole structure, and every result in this post follows from it.
Assumptions used throughout:
Pack cost $180/kWh
BOS cost $380/kW
Sanity check against the market: at four hours those produce $275/kWh, which sits in the middle of published US EPC ranges for four-hour LFP systems of roughly $230–320/kWh installed. The split is illustrative; the total is realistic.
The Curve
| Duration | $/kW | $/kWh | Marginal $/kWh | Pack share of cost |
|---|---|---|---|---|
| 1 hour | $560 | $560 | — | 32% |
| 2 hours | $740 | $370 | $180 | 49% |
| 3 hours | $920 | $307 | $180 | 59% |
| 4 hours | $1,100 | $275 | $180 | 65% |
| 6 hours | $1,460 | $243 | $180 | 74% |
| 8 hours | $1,820 | $228 | $180 | 79% |
| 10 hours | $2,180 | $218 | $180 | 83% |
Three columns worth reading carefully.
The $/kWh column falls steeply and then flattens. Most of the decline happens by four hours. Going from one to four hours cuts it by 51%; going from four to ten cuts it by a further 21%. The curve is a hyperbola, and the interesting part is at the short end.
The marginal column is flat at $180. Every additional hour costs exactly the pack price. This is the single most important number in the previous post's duration calculation, and it is constant by construction.
The pack share rises from a third to over four-fifths. A one-hour battery is mostly power conversion equipment with some cells attached. A ten-hour battery is mostly cells. They are physically different objects, and comparing their unit costs is comparing different things.
Why $/kWh Fails as a Comparison
Because the BOS cost is being spread over a denominator that duration alone controls.
Take the eight-hour system's $228/kWh. Decompose it:
Pack, per kWh of the system $180
BOS, per kWh of the system ($380/kW ÷ 8 hours) = $48
----
Total $228
Now the one-hour system's $560/kWh:
Pack, per kWh of the system $180
BOS, per kWh of the system ($380/kW ÷ 1 hour) = $380
----
Total $560
The pack costs $180/kWh in both. The entire difference is the BOS term divided by a different number of hours. Nothing about the eight-hour system's procurement was better.
The consequence for anyone reading a quote, a benchmark or a competitor comparison: a lower $/kWh figure is evidence of longer duration before it is evidence of anything else. Two vendors quoting $275/kWh and $228/kWh for four-hour and eight-hour systems respectively have quoted identical prices.
How to Compare Properly
Split the quote into its two components and compare each on its own scale.
Given a quoted total for a known configuration:
Pack_$/kWh = (Total_$ − BOS_$/kW × MW × 1,000) ÷ (MWh × 1,000)
BOS_$/kW = (Total_$ − Pack_$/kWh × MWh × 1,000) ÷ (MW × 1,000)
With two quotes for different durations from the same vendor, both components can be solved directly:
Quote A: 100 MW / 200 MWh = $74,000,000
Quote B: 100 MW / 400 MWh = $110,000,000
Difference = $36,000,000 for 200 MWh
→ Pack = 36,000,000 ÷ 200,000 kWh = $180/kWh
→ BOS = (74,000,000 − 180 × 200,000) ÷ 100,000 kW = $380/kW
That is a genuinely useful procurement technique and it takes one extra quote. Asking a vendor to price two durations reveals its cost structure, which a single quote conceals — and the structure is what you actually need, because it tells you the marginal cost of duration at that vendor's pricing.
Two vendors can be compared on the two numbers rather than on one ratio, and the comparison then survives a change in configuration.
What About the 40% That Is Not the Battery?
A useful reality check on where the money goes.
Published analysis of long-duration projects outside China and the US puts an all-in figure of roughly $125/kWh as approximately $75 of core equipment and $50 of installation, engineering and grid connection — so nearly 40% of the spend has nothing to do with the battery itself.
That has three implications.
Cell price declines pass through partially. A 30% fall in cell prices is not a 30% fall in project cost. On a 60/40 split it is an 18% fall, and less than that on a short-duration system where the pack is a smaller share.
The non-battery share is duration-dependent too. On the table above, BOS is 68% of a one-hour system and 17% of a ten-hour one. So the same cell price decline moves a long-duration project's cost far more than a short one's — which is another mechanism pushing optimal duration longer over time.
Grid connection sits inside that 40%. Which links directly back to the constraint stack: a site with an expensive connection carries a cost that behaves like BOS — incurred once, per megawatt, indifferent to duration — and therefore pushes the same way, toward longer durations to spread it.
The Geography Test
There is a striking piece of evidence for how little of the cost is actually the battery, and it comes from comparing markets rather than durations.
China EPC, 4-hour LFP, installed ~$90–130/kWh
US EPC, 4-hour LFP, installed ~$230–320/kWh
Roughly a 2.5× gap for the same chemistry at the same duration. Cells are a globally traded commodity and do not cost two and a half times more in one market than another. Essentially the entire gap is the non-cell component: labour, engineering, permitting, interconnection, land, contractor margin, and the cost of the regulatory and safety requirements each market imposes.
Two things follow.
The pack/BOS split is market-specific, not universal. The $180/$380 assumption used here is a US-shaped split. A Chinese project has a much higher pack share, which means its optimal duration calculation looks different — the marginal hour is a larger fraction of a smaller total, and the BOS term being spread is smaller.
Cell price declines matter less where BOS dominates. A market where the battery is 30% of project cost sees a third of any cell price move. One where it is 70% sees most of it. So the same global cell price decline lengthens optimal durations faster in low-BOS markets than in high-BOS ones — and the convergence people expect between markets is slower than cell pricing alone suggests.
What Falls Over Time, and What Does Not
The two components have behaved very differently, and the divergence is the main long-run driver of configuration.
Pack costs have fallen substantially and continue to. Cell chemistry improvements, manufacturing scale and competition have driven the energy component down persistently.
BOS costs have been far stickier. Inverters, transformers, civil works, labour and grid connection are not subject to the same learning curve, and several of them — interconnection in particular, as Series C documented at length — have been rising.
The consequence is a steady shift in the mix, and it changes the answer to every question in this series:
If pack falls 33% and BOS is flat:
Pack share at 4 hours 65% → 56%
Marginal hour cost $180 → $120
4-hour system $/kWh $275 → $215
The marginal cost falls by the full 33% while the system cost falls by 22%. Duration decisions therefore move faster than project economics, which is why a configuration standard ages badly even when the overall business case looks stable.
It also means the two components should be forecast separately. A model escalating "battery cost" as a single line at a single rate has assumed the pack and the BOS move together, and they demonstrably do not.
Augmentation Is Priced on the Pack Curve
A consequence that is routinely mispriced, and it matters for the reserve funding the waterfall post described.
When a battery is augmented — cells added to restore capacity lost to degradation — the purchase is pack only. No new inverters, no new transformers, no new civil works, no new connection. So augmentation should be costed at the pack price, not at the system's blended $/kWh.
The error is material:
System cost at 4 hours $275/kWh
Pack cost $180/kWh
Overstatement if augmentation is priced at system cost 53%
And it compounds with the timing. Augmentation happens years after commercial operation, at the pack price prevailing then, not at today's. On the declining trend above, an augmentation modelled at today's pack cost is itself conservative — while one modelled at today's system cost is wrong by half.
The practical instruction: model augmentation as MWh_to_restore × Pack_$kWh(year of augmentation), with a stated view on the pack price trajectory. It is one of the few places in a storage model where the honest answer is likely to be cheaper than the naive one.
What the Split Means for a Constrained Site
The cost structure interacts with the binding constraint in a way that is worth stating explicitly.
On a power-constrained site, the BOS cost is already committed. The connection is what it is, the inverters are sized to it, and those dollars are spent regardless. The marginal decision is purely pack cost against marginal revenue — the clean version of the duration calculation, with no complications.
On an energy-constrained site, the pack is capped by land and fire code. Additional spend can only buy power, at $380/kW, earning capacity and ancillary revenue. The duration question does not arise; the power question does.
On a budget-constrained site, the trade-off is live in both directions and the frontier from the constraint-stack post applies:
Budget = MW × $380,000 + MWh × $180,000
Every dollar moved from power to energy buys 380/180 = 2.11 MWh per MW given up. That exchange rate is the entire configuration decision on a budget-constrained project, and it is computable before any revenue modelling.
What the Curve Says About Long-Duration Storage
A useful implication falls out of the pack-share column, and it explains why long-duration storage is a different investment proposition rather than simply a longer one.
At ten hours the pack is 83% of system cost. At one hour it is 32%. So as duration extends, the project converges on being a pure cell purchase — the inverters, the connection and the civil works become a rounding error against the cells.
Three things follow.
Long-duration economics are almost entirely a cell-cost story. Interconnection cost, labour rates and contractor margin — the things that make US projects 2.5× Chinese ones at four hours — matter progressively less as duration rises. The geography gap narrows at the long end.
The learning curve applies more directly. Because the pack dominates, a given percentage fall in cell prices passes through to a ten-hour project almost one-for-one, against roughly a third for a one-hour one. Long-duration storage benefits disproportionately from exactly the cost trend that has been running.
It also explains why alternative chemistries target long duration first. A technology with a lower energy cost and a worse power cost — flow batteries being the obvious example — is uncompetitive at one hour, where BOS dominates, and can be competitive at ten, where it does not. The crossover is a function of the same two-component structure this post has been describing, with different coefficients.
None of that makes long duration economic on its own; the previous post's marginal-hour calculation still governs, and the marginal hour's revenue falls faster than its cost does at most nodes. But it does mean the two ends of the duration range respond to different variables, and a view on long-duration storage is mostly a view on cell prices rather than on anything else in the project.
Does Chemistry Change the Split?
Yes, and it moves both components in ways that do not cancel.
LFP — lithium iron phosphate — has become the default for stationary storage. Lower energy density means more volume and more containers for the same megawatt-hours, which raises the footprint and some of the civil and installation cost. Against that, it is cheaper per kilowatt-hour, more thermally stable, and generally offers longer cycle life. The thermal stability also reduces fire suppression requirements relative to the alternative, which shows up in BOS.
NMC — nickel manganese cobalt — is denser, so it fits more energy into less space, which matters on a land-constrained site where the previous post's fire-code arithmetic binds. It costs more per kilowatt-hour and carries a more demanding safety profile.
The practical effect on the two components:
| Pack $/kWh | BOS $/kW | Footprint per MWh | |
|---|---|---|---|
| LFP | Lower | Lower (less suppression) | Higher |
| NMC | Higher | Higher | Lower |
So the chemistry decision is genuinely a constraint-stack decision rather than a pure cost one. On a site with abundant land, LFP's lower cost on both components wins comfortably. On a land-constrained site, NMC's density may be the only way to fit the required energy inside the available footprint after setbacks — and the premium is then the price of the site rather than the price of the chemistry.
That is the right way to frame it in a model: chemistry is a lever on the energy constraint, and it should be tested when land binds rather than defaulted to on cost.
How Do You Build the Cost Curve in Excel?
As two inputs and a function, never as a single $/kWh assumption.
The core
Cost_per_kW(d) = Pack_$kWh × d + BOS_$kW
Cost_per_kWh(d) = Cost_per_kW(d) / d
Marginal_$kWh = Pack_$kWh (constant)
Total_Capex = Cost_per_kW(d) × MW × 1,000
The two outputs to publish
PF_PackCost_$kWh $180
PF_BOSCost_$kW $380
Those two numbers describe the project's cost structure completely. A model carrying a single blended $/kWh assumption cannot answer what an extra hour costs, which is the question the duration analysis needs.
The exchange rate on a budget constraint
PF_MWh_per_MW_traded = BOS_$kW × 1,000 ÷ (Pack_$kWh × 1,000)
= 380 ÷ 180 = 2.11
The sensitivity that actually matters
Pack cost −33% ($180 → $120)
4-hour $/kWh $275 → $215 (−22%)
1-hour $/kWh $560 → $500 (−11%)
Marginal hour $180 → $120 (−33%)
Note the three different percentages from one input change. The headline project cost moves least on a short-duration system, most on a long one, and the marginal cost moves by the full amount — which is why cell price declines change duration decisions more than they change project costs.
ℹ️ Note: Never carry a single blended $/kWh cost assumption into a sizing model. It cannot produce a marginal cost, so it cannot answer the duration question, and it silently embeds the duration it was derived from.
To build the cost curve, decompose vendor quotes into pack and BOS, and run the budget frontier, prompt Dezzmond with your quotes and configuration options.
What Do Developers and Lenders Actually Check?
- Is the cost model two components or one blended $/kWh? One cannot answer the marginal question.
- What are the pack and BOS figures separately, and how were they derived?
- Have vendors been asked to quote two durations so the structure can be solved?
- Is a $/kWh comparison being made across different durations? It is meaningless if so.
- What share of cost is not the battery, and how does that change the pass-through of cell price moves?
- On a budget constraint, what is the MWh-per-MW exchange rate?
- Does the grid connection cost behave like BOS? It usually does, and it pushes toward longer duration.
Frequently Asked Questions
Why does $/kWh fall as duration rises?
Because balance-of-system cost is incurred per megawatt and is then divided by more megawatt-hours. The cells cost the same per kilowatt-hour at every duration — only the BOS term per kilowatt-hour shrinks.
Is a lower $/kWh always better?
No. Across different durations it is mostly evidence of duration. A four-hour system at $275/kWh and an eight-hour at $228/kWh can have identical pack and BOS pricing.
What does an extra hour of duration cost?
The pack cost only — $180/kWh on these assumptions, constant at every duration. That constant is what the duration optimisation compares against a declining marginal revenue.
How do you find a vendor's real cost structure?
Ask for two quotes at different durations. The difference divided by the additional energy gives the pack cost, and substituting back gives the BOS cost. One quote conceals both.
How should augmentation be costed?
At the pack price, not the system $/kWh, because augmentation buys cells only. Using the blended system cost overstates it by 53% on these assumptions — and it should be priced at the pack cost prevailing in the year of augmentation, not today's.
Do pack and BOS costs fall at the same rate?
No. Pack costs have fallen persistently while BOS has been far stickier and interconnection has been rising. That divergence shifts the mix over time and is the main reason optimal duration lengthens even when project economics look stable.
How much of the cost is not the battery?
On published long-duration figures outside China and the US, roughly 40% — about $50 of a $125/kWh all-in figure being installation, engineering and grid connection. The share is higher still on short-duration systems.
Closing: Two Numbers, Not One
The single most common way to describe a battery's cost is the one that makes durations incomparable. It is not wrong as a description — a four-hour system genuinely does cost $275 per kilowatt-hour — but it collapses two independent quantities into one ratio, and the ratio moves with a variable that has nothing to do with procurement.
The fix is small. Carry the pack cost and the BOS cost separately, because they answer different questions: the pack cost is the price of an hour, and the BOS cost is the price of a megawatt. Every sizing decision in this series needs one or the other, and neither can be recovered from a blended figure.
It also makes vendor comparison honest. Two quotes at different durations solve the structure in one line of arithmetic, and once solved, the comparison holds whatever configuration the project eventually lands on — which the single ratio never does.
That completes the sizing half of this series: what limits the build, what the megawatts are for, how many hours, and what those hours cost. The second half is about operating what you built. The next post starts it with the decision the whole asset exists to make: when to charge.
Sources: NREL — Utility-Scale Battery Storage, Annual Technology Baseline · Ember — How Cheap Is Battery Storage? · How to Store Electricity — BESS Cost per MWh, Utility Scale 2026 · Timera Energy — What Battery Durations Are Investable?