Last updated: 1 June 2026

Modo Energy is the independent benchmark provider for grid-scale battery and solar revenues across 13 global markets, including the only FCA-authorised BESS revenue benchmark under UK Benchmarks Regulation. Ko is Modo Energy's AI assistant, built on proprietary data and forecasts for grid-scale BESS and solar across 13 markets — covering revenues, wholesale prices, regulation, and policy out to 2050 or 2060.

Battery energy storage returns track the volatility and intraday spread of power prices, the gap between cheap and expensive hours, not the average price level. A market with low average prices can still pay batteries well if its daily shape is volatile. In ERCOT, the Electric Reliability Council of Texas, the 10 highest-revenue days delivered 38% of annual battery revenue in 2024 (Modo Energy, 2026). To 2030, merchant spreads widen first in the US before compressing, and commercial-operation timing increasingly decides lifetime returns (Modo Energy, 2026).

Battery returns are not a bet on whether power gets more expensive. They are a bet on how often, and how far, prices swing within the day. That distinction shapes how investors underwrite battery energy storage systems (BESS) across the US, Great Britain, Germany, Spain, and Australia through 2030.

Key statistics

Each row carries one figure that tracks the thesis for that market: returns follow the spread and its volatility, exposure to that spread is rising, and a contracted layer moderates it in some markets but not others. Two rows use Top-Bottom (TB) spreads, Modo Energy's benchmark for the daily arbitrage gap: TB2 is the best two hours of buying against the best two hours of selling each day, TB4 the best four hours. Quoted in $/MW-year, a TB spread is the revenue that daily gap is worth over a year, not a one-off price difference (what TB spreads are).

Spread benchmarks differ by market: ERCOT is shown as TB2 (the best two hours) and CAISO as TB4 (the best four hours), matching each market's typical battery duration, and each is quoted as Modo Energy publishes it: ERCOT's as an annualised spread in $/MW-year, CAISO's as a $/MWh spread. Index revenue is shown like-for-like in local currency per MW-year, as annual or monthly averages, never summed; revenue-share splits come from Modo Energy market-stream breakdowns. CAISO figures are merchant energy-and-ancillary revenue, separate from contracted Resource Adequacy. Source: Modo Energy BESS Index, public indices.

Key takeaways

• Battery returns track the intraday spread and volatility of power prices, not the average level. ERCOT's 10 highest-revenue days delivered 38% of its annual battery revenue in 2024, and the two biggest days each cleared over $1.7m/MW-yr on an annualised basis against a calm-day baseline under $20k (Modo Energy, 2026). Forecast off spreads, not price levels.
• Batteries are becoming more exposed to power prices over time. Availability-paid ancillary markets are small and saturate as fleets scale, pushing revenue into spread-driven wholesale arbitrage. ERCOT ancillary dominated revenue in 2023 and was a fraction of it by 2025; Germany ancillary falls from 55% of revenue to about 5% by 2030 (Modo Energy, 2026).
• The exposure is not uniform. Contracted revenue moderates it. CAISO Resource Adequacy contracts provide the majority of battery revenue and are expected to beyond 2035, so CAISO batteries are becoming less tied to merchant spreads, while energy-only ERCOT stays fully exposed (Modo Energy, 2026).
• US merchant spreads widen first, then compress. ERCOT TB2 peaks near $136k/MW-yr around 2033 and CAISO TB4 climbs to $240 to $270/MWh by 2030 before both decline (Modo Energy, 2026). Because the peak is time-limited, commercial-operation timing can swing lifetime returns by more than two times.
• Policy asymmetry favours batteries near-term. The 2025 federal tax law preserves the standalone-storage investment tax credit through 2033 (OBBBA §48E, 2025) while wind and solar credits phase out after 2027 (IRS Notice 2025-42, 2025). Slower clean-generation buildout against rising load means more volatility for batteries, which keep their credit, to capture.

Markets covered

Markets are illustrated by the clearest example in each section rather than covered as six separate tours. US coverage leads on ERCOT and CAISO, with NYISO (New York ISO) referenced lightly. Source: Modo Energy.

Battery returns have already diverged sharply across these markets, as the chart below shows. That divergence is the first sign that no single price level explains returns, which is where the story starts.

Annual average BESS index revenue by market, 2023 to 2025, each in its own currency per MW-year and never converted or summed. ERCOT falls from about $191k to $28k and CAISO from about $80k to $38k, while Great Britain (£74k to £80k), Germany (€241k to €223k), and Australia (A$105k to A$128k) hold or recover. The revenue collapse is US-specific. Source: Modo Energy.

Are battery storage revenues actually tied to power prices?

Battery returns track the spread between cheap and expensive hours, not the average price level. A market can have low average prices and still pay batteries well if its daily shape is volatile, with cheap midday solar and scarce, expensive evenings.

Average power prices and battery returns can move in opposite directions. What a battery sells is the difference between the price it charges at and the price it discharges at. The wider and more frequent that gap, the more it earns. These spread benchmarks, not the price level, are what track battery revenue.

The proof sits in how concentrated revenue is. Battery earnings cluster into a few volatile days, not a steady monthly drip. In ERCOT, the 10 highest-revenue days of 2024 delivered 38% of the year's battery revenue, and the top 20 days, around 5% of the year, drove nearly half of it (Modo Energy, 2026). The two biggest single days, driven by a January winter storm and May scarcity, each cleared over $1.7 million/MW-year on an annualised basis, while a calm winter day cleared under $20,000.

Ko's analysis of ERCOT settlement data shows just how skewed the distribution is: revenue concentrates in the scarcity events, and the calm majority of the year contributes little. The same volatility-capture logic holds across markets, but the shape of the volatility differs. ERCOT concentrates earnings into a handful of scarcity events, so its revenue is the most tail-driven of the markets here. Great Britain earns from more frequent but smaller daily swings, Australia's NEM swings are widening as renewables outpace storage, and Spain's are still thin. In every case, returns are a function of how violent the price swings get, not how high the average price sits.

ERCOT battery revenue, the intraday spread (TB1, the best hour of buying against the best hour of selling), and ancillary prices all fell far more than the average power price from 2023 to 2024 (each shown as a share of its 2023 level). Returns track the spread and its volatility, not the price level. Source: Modo Energy.

Share of annual ERCOT BESS revenue earned on the highest-revenue days. A small number of volatile days drive the year. Source: Modo Energy.

In ERCOT, the 20 highest-revenue days of 2024, around 5% of the year, drove nearly half of all battery revenue (Modo Energy, 2026). Revenue is a volatility-capture business, not a price-level business.

"You can't underwrite batteries off of average prices. Returns live in the tails. A flat year with three violent days can beat a year of steady, boring prices." — Brandt Vermillion, ERCOT Market Lead, Modo Energy

The practical consequence is that two markets with similar average prices can offer very different battery economics. What matters is whether the daily price shape is volatile enough, and often enough, to refill the battery's earnings on the days that count.

Batteries are becoming more exposed to power prices, not less

The shift runs one way. The revenue streams once decoupled from spreads, mainly ancillary services, are small markets that saturate as fleets scale, which pushes batteries into spread-driven wholesale arbitrage.

When a market has few batteries, ancillary services pay handsomely. These are availability products, such as frequency response and contingency reserves, where the grid pays a battery to stand ready rather than to move energy. They are decoupled from the intraday spread. But the volume the grid needs is fixed and small. As more batteries compete for the same megawatts of reserve, clearing prices collapse.

ERCOT shows the pattern at full speed. In 2023, ancillary services made up about 84% of ERCOT battery revenue, with wholesale energy and scarcity contributing just 16% (Modo Energy, 2026). By 2025 that had flipped: ancillary fell to about 35% while wholesale rose to 65%, and average revenue dropped from roughly $191,000/MW-year to $28,000/MW-year as the fleet grew about sevenfold, from 2.0 GW in January 2023 to 14.4 GW by March 2026 (Modo Energy, 2026). More batteries chasing a fixed ancillary requirement is exactly what saturates the market.

Wholesale-arbitrage share of BESS revenue by market: 2023 and 2025 (actual), 2030 (forecast). ERCOT, Great Britain and Australia's NEM have already rotated; Germany, still ~12% wholesale in 2025 and dominated by availability payments, is forecast to rotate hardest by 2030. 2030 shares for ERCOT, GB and NEM are Modo-informed estimates. Source: Modo Energy.

ERCOT operational BESS capacity (~7× growth) against per-MW revenue, showing ancillary saturation and cannibalisation. Source: Modo Energy.

The same rotation is happening across markets, at different speeds. Great Britain is on the same path, with wholesale and balancing rising from about 36% to 63% of revenue between 2023 and 2025 as frequency-response income collapsed (Modo Energy, 2026). Germany has rotated the least so far but is forecast to rotate the hardest: its batteries earned only about 12% of revenue from wholesale in 2025, dominated instead by availability payments, yet Modo Energy's outlook has wholesale near 95% of revenue by 2030 as those ancillary payments saturate (Modo Energy, 2026). ERCOT made the same shift in barely two years. CAISO is the outlier, because contracted Resource Adequacy slows how fast its fleet has to lean on spreads. The mechanism is identical everywhere: a fixed, modest ancillary requirement cannot absorb a scaling fleet, so revenue rotates into spread-driven wholesale, unless contracts intervene.

ERCOT ancillary services fell from about 84% of battery revenue in 2023 to 35% by 2025, with wholesale arbitrage taking the rest (Modo Energy, 2026). As the decoupled availability income saturates, power-price spreads become the product.

The investor takeaway is uncomfortable but clear. The maturing of a battery market does not de-risk it from power prices. It does the opposite. The more a fleet scales, the more its revenue rides on how volatile wholesale prices are. So the next question is what drives that volatility, and how far it runs to 2030.

What will drive power prices and volatility through 2030, and beyond?

Six forces drive power-price volatility to 2030: demand growth, the pace of thermal retirements, fuel costs, policy and market design, grid constraints, and the rise of negative-price midday hours. Together they widen merchant spreads first in the US, before late-decade buildout compresses them.

The drivers below assemble into one arc: spreads widen first, then compress. Demand surges while supply struggles to answer it, fuel firms the expensive end of the day, and abundant midday solar floors the cheap end. That combination is what a battery is built to capture.

One — Demand growth returns. The US is seeing its first sustained electricity-demand growth in roughly 20 years, with the EIA projecting consumption up about 1.3% in 2026 and 3% in 2027 (EIA STEO, 2026). Data centres dominate. PJM Interconnection's 2025 load forecast added 32 GW of peak demand to 2030, around 94% of it data centres, though its January 2026 update trimmed near-term load while holding the long-term trajectory (PJM, 2026). ERCOT's large-load queue holds roughly 238 GW of interconnection requests, which maps to a more realistic peak near 150 GW by 2030 against about 85 GW today (ERCOT, 2025). In California, the Energy Commission expects data-centre load to rise from about 1 GW today to plus 1.8 GW by 2030 (CEC, 2026). RBC estimates around 75% of US demand growth to 2030 is data-centre-driven, a view worth attributing rather than treating as settled (RBC Capital Markets, 2026).

Each new gigawatt of largely flat data-centre load tightens the evening peak the existing fleet must meet, lifting prices at the top of the daily shape and widening the spread a battery captures.

Two — Supply is leaving more slowly than expected. Thermal retirements have slowed, supporting the expensive end of the day. US coal retirements in 2025 fell to 2.6 GW, the lowest in 15 years, as emergency orders and demand kept plants online (EIA, 2026). Additions are record-breaking but skewed: about 86 GW of US capacity in 2026, roughly half solar and a quarter batteries (EIA, 2026). In California, Diablo Canyon's state licence currently ends in October 2029 and 2030, a roughly 9% supply risk for the state if it is not extended, and offshore wind realistically slips past 2030 (CPUC, 2026).

Three — Fuel firms the peak from 2027. In gas-on-the-margin markets, a gas plant usually sets the price in the expensive evening hours. So the gas price moves the top of the daily price shape, and that top is one half of the spread a battery captures. When gas is cheap, the peak sags and spreads compress; when gas is dear, the peak rises and spreads widen. Natural-gas prices normalised through 2023 to 2025, with Henry Hub averaging $2.21/MMBtu in 2024, the lowest real annual price on record, which held the peak down and compressed spreads in gas-set markets (EIA, 2026).

That reverses from 2027 as liquefied natural gas (LNG) exports pull on domestic supply. North American LNG export capacity more than doubles, from 11.4 Bcf/d in 2023 to 24.4 Bcf/d by 2028 (EIA, 2026). Dearer gas lifts the evening peak, widens the daily spread, and feeds straight through to battery arbitrage revenue. The link is strongest in gas-set ERCOT, Great Britain, and Germany. It is weaker in CAISO, where abundant midday solar increasingly sets the cheap end of the shape, and mixed in the NEM, where gas, hydro, and coal share the margin.

Four — Policy reshapes where and how batteries earn. The asymmetry matters most. The 2025 federal tax law cliffs wind and solar credits, which must begin construction by July 2026 (IRS Notice 2025-42, 2025), but preserves the standalone-storage investment tax credit at full value through construction start in 2033, then 75% in 2034 and 50% in 2035 (OBBBA §48E, 2025). Slower clean-generation buildout against rising load means more scarcity volatility for batteries, which keep their credit, to capture. Market design is also shifting: ERCOT's Real-Time Co-optimisation plus Batteries went live in December 2025, co-optimising energy and ancillary services every five minutes (ERCOT, 2025); CAISO's Extended Day-Ahead Market launched in May 2026 (CAISO, 2026); Germany's capacity market auctions in 2026 for delivery from 2031; and Great Britain's Capacity Market cleared its four-year-ahead auction at £60/kW-year for 2028/29 delivery. These market-design shifts change how completely a battery can convert a given spread into revenue, and whether a contracted floor sits beneath it.

Five — The grid cannot keep up. A US interconnection queue of roughly 2,290 GW, with waits around 4.5 years, throttles how fast new supply answers demand (LBNL, 2025). ERCOT's 765 kV transmission build eases West Texas congestion only around 2030 in its first phase. Constraints keep regional prices volatile in the meantime.

Six — Negative and low-price midday hours are the structural spread-widener. Abundant midday solar floors the cheap end of the day while scarce evening capacity holds the expensive end, widening the spread a battery captures. CAISO curtailed 3.4 TWh of mostly solar output in 2024, up 29% year-on-year (EIA, 2026). ERCOT noon solar reached 24 GW in 2025 against 12 GW in 2023 (EIA, 2025), suppressing midday prices and pulling ERCOT's average day-ahead price down to about $27/MWh in 2024 (Modo Energy, 2026). Germany logged 573 negative-price hours in 2025, up from 457 in 2024 and 301 in 2023 (Bundesnetzagentur, 2026). Great Britain ran about 176 negative-price hours in 2024, heading toward roughly 1,000 by 2027 (Modo Energy, 2026).

Ko's analysis of forward spread trajectories tracks where these drivers leave merchant spreads market by market. The net effect to 2030 is wider US spreads, European fleets rotating off saturated ancillary into wholesale, and Australian spreads widening as renewables outpace storage.

ERCOT TB2 spread forecast to 2049, peaking near $136k/MW-yr around 2033. Source: Modo Energy.

CAISO TB4 spread forecast to 2050, climbing to $240 to $270/MWh by 2030 before declining. Source: Modo Energy.

Henry Hub gas price and North American LNG export capacity, with the 2027 inflection where rising gas lifts the evening peak and widens battery spreads in gas-set markets (ERCOT, Great Britain, Germany). Source: EIA.

Beyond 2030, the same buildout that widens spreads starts to flatten them. As solar and batteries saturate the daily shape, the midday-to-evening gap narrows, and the value of one-to-two-hour arbitrage erodes. Research points to falling incremental value beyond four hours of duration and a gradual shift toward longer-duration and seasonal storage (NREL, 2023), with the US Department of Energy targeting a 90% cost cut for 10-plus-hour storage by 2030 (DOE, 2025). This long-run compression is a terminal-value risk, and it sharpens the question the next section answers: how exposed batteries stay, and for how long.

Contracted revenue decides how exposed a battery stays

The answer turns on one variable: how much contracted revenue, mainly Resource Adequacy and capacity-market payments, backfills the saturating ancillary income. That backfill varies sharply by market, which is the most investor-relevant finding in this piece.

The rotation into wholesale spreads is near-universal. What differs is whether a market has a structural revenue layer that sits outside power prices. Three patterns emerge: a contracted de-link in CAISO, pure and rising merchant exposure in ERCOT, the NEM, and Spain, and a middle path in Great Britain and Germany where capacity-market floors are still forming.

CAISO, the California Independent System Operator, is the clearest de-link. Resource Adequacy contracts, bought by load-serving entities to meet a reliability obligation, already provide the majority of CAISO battery revenue, and Modo Energy expects them to keep doing so beyond 2035 (Modo Energy, 2026). A full revenue stack with a Resource Adequacy contract has run several times merchant wholesale-only earnings. So even as CAISO wholesale spreads widen to 2030, the fleet is becoming less tied to merchant prices, not more, because the contracted layer grows with it. For the full California outlook, see Modo Energy's CAISO three-decade forecast.

ERCOT is the opposite. With no capacity market and no Resource Adequacy mechanism, Texas batteries earn from energy arbitrage and a shrinking ancillary stack alone. As ancillary saturates, ERCOT batteries become purely and increasingly exposed to power-price spreads. That is why ERCOT is the market where the volatility thesis bites hardest, and where commercial-operation timing matters most.

Great Britain and Germany sit between the two. Both fleets are rotating into wholesale, but capacity-market floors are emerging. Great Britain's Capacity Market cleared its four-year-ahead auction at £60/kW-year for 2028/29 delivery and its one-year-ahead auction at £20/kW-year for 2025/26, with longer-duration batteries de-rated more favourably than four-hour systems (pv-magazine, 2025). Germany's outlook shows two-hour battery revenue falling from about €235k/MW-year to €115k/MW-year as the market matures, with a four-hour internal rate of return near 13.7%, and a new capacity market delivering from 2031 to provide a floor (Modo Energy, 2026).

Australia's National Electricity Market (NEM) has no centralised capacity mechanism, so its batteries stay merchant-exposed, with arbitrage and frequency-control services (FCAS) the main earners. Revenue has been volatile but rising: monthly index revenue ranged from roughly A$60k to A$400k/MW-year across 2023 to 2025, with the strongest months several times the quietest (Modo Energy, 2026). Spain is earlier still, with a thin fleet and daily spreads around €25 to €28/MWh, and no capacity floor yet.

Merchant versus contracted revenue mix by market: Resource Adequacy, capacity markets, and ancillary services against wholesale arbitrage. Source: Modo Energy.

Great Britain, Germany, and Australia BESS revenue, 2023 to 2025, each in its own currency per MW-year. Great Britain and Germany dip then recover while the NEM trends up, in contrast to the US decline. Source: Modo Energy.

Because the US merchant spread peaks and then fades, when a battery reaches commercial operation increasingly decides its lifetime returns. Modo Energy's ERCOT forecast has the annual revenue from the TB2 spread peaking near $136k/MW-year around 2033 before falling toward $57k later in the 2030s (Modo Energy, 2026). A battery online for the peak years can capture more than twice the lifetime spread of one online a decade later. Falling capital costs, with Great Britain build costs down around 30% by 2030, only partly offset that vintage gap (Modo Energy, 2026).

An ERCOT battery online for the early-2030s spread peak can capture more than twice the lifetime spread of one commissioned a decade later (Modo Energy, 2026). Falling capital costs only partly offset the vintage gap.

Explore live cross-market BESS revenue data and Modo Energy's forecasts to 2050, with free Terminal access here.

Lifetime spread capture by commercial-operation date, showing the more-than-two-times advantage of early-2030s vintages. Source: Modo Energy.

Congestion and balancing add a locational revenue layer

Congestion and balancing sit alongside the wholesale spread the rest of this article has covered, adding a distinct, locational source of returns. A battery sited behind a transmission constraint can earn from local price differences and from system-operator balancing actions, even when the headline wholesale spread is modest.

In Great Britain, batteries take a growing share of the balancing mechanism, the tool the system operator uses to match supply and demand in real time after the wholesale market closes. As more batteries qualify and as the operator's dispatch software improves, balancing has become a meaningful and locational revenue source, distinct from day-ahead arbitrage. The value depends on where an asset sits relative to grid bottlenecks, not just on the national price shape.

Great Britain balancing-mechanism revenue, rising from about £5k to £19k/MW-year (2023 to 2025) as more batteries qualify and dispatch improves. Source: Modo Energy.

Congestion works the same way in the US. ERCOT's West zone has historically carried a locational premium tied to transmission limits, which its 765 kV transmission build aims to ease around 2030 in its first phase (PUCT, 2025). When new transmission relieves a constraint, the locational premium compresses, so congestion revenue is a function of grid build-out timing as much as of price volatility.

The investor point is that locational and balancing revenue can diversify a merchant battery's earnings, but it is hard to forecast and tends to erode as the grid is reinforced. Treat it as upside to underwrite conservatively, not as a structural floor.

What should investors and financiers monitor?

Five levers decide battery returns more than the average price deck: ancillary-saturation stage, commercial-operation timing, the merchant-versus-contracted revenue mix, locational exposure, and whether forecast load growth actually arrives. Track these, not the price level.

This is not financial advice. It is a checklist of the decision levers that the volatility thesis implies.

One — Ancillary-saturation stage. Establish where your market sits on the ancillary-to-wholesale rotation. Early-stage markets pay rich availability income that will collapse as fleets scale; mature markets already live on spreads (Modo Energy, 2026). The stage sets how fast a new entrant's revenue mix shifts toward power prices.

Two — Commercial-operation timing. In US merchant markets, the spread peaks then fades, so vintage matters. A battery online for the early-2030s peak can earn more than twice the lifetime spread of a later one (Modo Energy, 2026). Model returns against the spread trajectory, not a flat spread.

Three — Merchant-versus-contracted mix. Check how much revenue sits outside power prices. Resource Adequacy in CAISO and capacity markets in Great Britain and Germany backfill saturating ancillary income; energy-only ERCOT and the NEM do not (Modo Energy, 2026). The mix decides how exposed the asset is to spread volatility.

Four — Locational and congestion exposure. Site relative to grid constraints, and check the transmission build pipeline. Congestion and balancing revenue can diversify earnings but erode as the grid is reinforced, such as ERCOT's 765 kV build around 2030 (PUCT, 2025).

Five — Demand-growth delivery and terminal-value risk. The spread-widening case rests on load growth arriving, much of it data centres (RBC Capital Markets, 2026). Track whether forecast load materialises, and treat post-2030 spread compression as a terminal-value risk as solar and batteries flatten the daily shape (NREL, 2023).

Frequently asked questions

Are battery storage revenues tied to electricity prices?

Yes, but to the spread between cheap and expensive hours, not the average price level. Batteries earn by buying low and selling high within the day, so what matters is how wide and frequent the daily price swings are. A market with low average prices can still pay batteries well if its daily shape is volatile, with cheap midday solar and scarce, expensive evenings (Modo Energy, 2026).

Do battery returns fall when power prices fall?

Not necessarily. Average prices and battery returns can move in opposite directions. What drives returns is the intraday spread, so a year of low average prices with violent daily swings can out-earn a year of high but flat prices. ERCOT's 10 highest-revenue days delivered 38% of its annual battery revenue in 2024, showing how concentrated returns are in volatile events (Modo Energy, 2026).

Which markets have the widest battery spreads to 2030?

US merchant markets widen first. ERCOT's TB2 spread peaks near $136k/MW-year around 2033, and CAISO's TB4 spread climbs to $240 to $270/MWh by 2030 before declining (Modo Energy, 2026). European fleets rotate off saturated ancillary into wholesale, and Australian spreads widen as renewables outpace storage. Spain stays thin, with daily spreads around €25 to €28 per MWh.

When do US battery spreads peak?

US merchant spreads widen through roughly 2030 to 2033, then compress. Demand growth, slowed thermal retirements, and rising midday solar widen the daily gap first; late-decade solar and battery buildout then flatten the shape and erode one-to-two-hour arbitrage value (Modo Energy, 2026). Because the peak is time-limited, commercial-operation timing can swing lifetime returns by more than two times.

What earns batteries money besides energy arbitrage?

Ancillary services, capacity payments, Resource Adequacy contracts, and congestion or balancing revenue. Ancillary services pay batteries to stand ready but saturate as fleets scale. Capacity markets in Great Britain and Germany and Resource Adequacy in CAISO provide contracted floors outside power prices, while energy-only markets such as ERCOT and the NEM rely on spreads alone (Modo Energy, 2026).

Are batteries getting more or less exposed to power prices over time?

More exposed, in most markets. The revenue streams decoupled from spreads, mainly ancillary services, are small and saturate as fleets scale, pushing batteries into spread-driven wholesale arbitrage. The exception is markets with growing contracted revenue: CAISO Resource Adequacy keeps that fleet becoming less exposed, while energy-only ERCOT becomes more so (Modo Energy, 2026).

What tool can I use to get live and forecast data on battery storage revenues?

Ko is Modo Energy's AI assistant. It draws on Modo Energy's proprietary market data and long-range forecasts to answer questions about battery energy storage and solar revenues, energy policy, and market design. Ko covers the US, Great Britain, Germany, Spain, Italy, France, and Australia, and its forecasts run to 2050 or 2060, making it useful for anyone trying to understand where energy markets are heading.

About the author

Neil Weaver is a Power Market Analyst at Modo Energy. Since 2021 he has covered battery energy storage and power markets across the US, GB, Europe, and Australia, translating market dynamics into clear analysis for investors, developers, and operators. He is the writer and presenter of The Energy Academy: Great Britain (watch on YouTube). Find Neil on LinkedIn.

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