Deep dive: Grid-scale energy storage economics & procurement — what's working, what's not, and what's next

Grid-scale energy storage has shifted from a niche technology into a foundational pillar of electricity system planning. Global installed capacity reached 120 GW/340 GWh by end of 2025, with lithium-ion batteries accounting for roughly 85% of new deployments. Yet behind the headline growth figures lies a more nuanced picture: procurement mechanisms remain fragmented across jurisdictions, revenue stacking is still inconsistent, and the economics of long-duration storage technologies have not yet reached the inflection point many anticipated. This deep dive examines the current state of grid-scale storage economics and procurement, identifies what is delivering value today, what continues to underperform, and where the most consequential developments will emerge over the next three to five years.

Why It Matters

Electricity systems worldwide face a structural mismatch between variable renewable generation and demand patterns. The International Energy Agency projects that solar and wind will supply over 50% of global electricity by 2030, up from approximately 14% in 2024. Without storage, curtailment rates in high-penetration markets already exceed 10% in regions like California's CAISO, South Australia, and parts of northern Germany. Each percentage point of curtailment represents wasted capital investment and foregone emissions reductions.

Storage procurement decisions made today will shape grid architecture for decades. Battery installations typically carry 15 to 20 year operational lifetimes, while pumped hydro and compressed air assets operate for 40 to 60 years. The procurement frameworks, contract structures, and revenue mechanisms being established in 2025 and 2026 will determine whether storage assets are deployed efficiently or whether misaligned incentives lead to stranded assets, underutilized capacity, and unnecessarily high electricity costs for ratepayers.

The financial stakes are enormous. BloombergNEF estimates cumulative global investment in grid-scale storage will reach $452 billion between 2024 and 2030. For sustainability leaders, understanding the economics of storage procurement is no longer optional: it directly affects corporate renewable energy strategies, power purchase agreement structures, and Scope 2 emissions accounting.

Key Concepts

Levelized Cost of Storage (LCOS) measures the total cost per unit of energy discharged over a storage asset's lifetime, incorporating capital expenditure, operating costs, degradation, financing, and round-trip efficiency losses. Unlike the levelized cost of energy (LCOE) for generation assets, LCOS depends heavily on the number of annual charge-discharge cycles and the revenue generated from those cycles. A four-hour lithium-ion system cycling once daily has a fundamentally different LCOS than the same system cycling 300 times per year for frequency regulation. As of early 2026, LCOS for four-hour lithium-ion systems ranges from $120 to $180 per MWh in most markets, down from $350 per MWh in 2020.

Revenue Stacking refers to the practice of earning income from multiple grid services simultaneously or sequentially. A single storage asset might provide energy arbitrage (buying low, selling high), frequency regulation, spinning reserves, capacity payments, and transmission deferral value. The viability of a storage project often hinges on the ability to stack three or more revenue streams. Markets that allow robust stacking, such as PJM, ERCOT, and the Australian National Electricity Market, see faster deployment than markets where participation rules restrict multi-service operation.

Capacity Markets and Resource Adequacy frameworks provide fixed payments to generators and storage assets that commit to being available during peak demand periods. Storage assets increasingly qualify as capacity resources, but accreditation methodologies vary significantly. FERC Order 841 requires US wholesale markets to allow storage participation on equal footing, yet effective load carrying capability (ELCC) valuations differ across ISOs, creating uncertainty for developers. In PJM, a four-hour battery receives approximately 80 to 90% of a thermal generator's capacity credit; in CAISO, the value depends on net demand peak characteristics that shift as solar penetration increases.

Tolling Agreements are procurement contracts in which an offtaker pays a fixed fee for the right to dispatch a storage asset, similar to capacity payments but with the added right to determine charge and discharge schedules. Tolling structures have become the dominant procurement model for utility-scale storage in the United States, accounting for over 60% of contracted capacity in 2024 and 2025. These agreements typically run 10 to 15 years and provide developers with the revenue certainty needed to secure project financing.

Grid Storage Economics: Benchmark Ranges

Metric	Below Average	Average	Above Average	Top Quartile
LCOS (4-hour Li-ion, $/MWh)	>180	140-180	120-140	<120
All-in Capex ($/kWh installed)	>280	220-280	180-220	<180
Round-trip Efficiency	<82%	82-86%	86-90%	>90%
Annual Revenue per MW	<$60K	$60-100K	$100-150K	>$150K
Capacity Factor (cycling)	<15%	15-25%	25-35%	>35%
Degradation Rate (annual)	>3%	2-3%	1.5-2%	<1.5%
Project IRR (unlevered)	<6%	6-9%	9-12%	>12%

What's Working

Lithium-Ion Cost Reductions Continue to Outpace Forecasts

Lithium iron phosphate (LFP) battery cell prices fell to approximately $55 per kWh by late 2025, a 35% decline from 2023 levels. This reduction has been driven by Chinese manufacturing overcapacity, with CATL, BYD, and EVE Energy collectively adding over 500 GWh of annual production capacity between 2023 and 2025. System-level installed costs for four-hour grid storage projects in the United States declined to $200 to $250 per kWh, including balance of system, inverters, and engineering. In China and parts of Southeast Asia, fully installed costs have reached $140 to $170 per kWh. These cost trajectories have made storage cost-competitive with natural gas peaker plants in most US and European markets. Lazard's 2025 analysis found that a new four-hour battery system now has a lower annualized cost than a new gas peaker in 28 of 30 modeled scenarios.

Revenue Stacking in Mature Wholesale Markets

Storage operators in well-designed wholesale markets are generating attractive returns by stacking multiple revenue streams. In ERCOT, where energy prices exhibit extreme volatility due to the energy-only market design, storage assets earned average revenues of $130,000 to $180,000 per MW in 2025. Top-performing operators employing sophisticated algorithmic trading captured over $220,000 per MW. In the Australian National Electricity Market, Neoen's 300 MW/450 MWh Victorian Big Battery generated approximately AUD $40 million in its first full year of operation through a combination of frequency control ancillary services, energy arbitrage, and system strength payments. The key differentiator across markets is trading capability: operators using machine learning for price forecasting and dispatch optimization consistently outperform those relying on static scheduling by 30 to 50%.

Utility Procurement Through Competitive Solicitations

Competitive procurement processes have driven storage costs well below bilateral negotiation benchmarks. The California Public Utilities Commission's storage procurement mandates, initiated under AB 2514 and expanded through subsequent decisions, have resulted in over 15 GW of contracted storage capacity. Average contract prices declined from approximately $180 per kW-year in 2020 to $110 to $130 per kW-year in 2025 procurement rounds. Hawaiian Electric's 2025 solicitation attracted bids for solar-plus-storage at combined prices below $45 per MWh, demonstrating that paired configurations can provide firm renewable energy at costs below new gas generation in island and remote grid contexts.

What's Not Working

Interconnection Queue Backlogs

The single most significant barrier to storage deployment is not technology or economics but interconnection process delays. In the United States, the average time from interconnection application to commercial operation exceeded 5 years by 2025, according to Lawrence Berkeley National Laboratory's annual queue analysis. Over 680 GW of storage capacity sits in US interconnection queues, but completion rates remain below 20%. FERC Order 2023, which reformed interconnection procedures to a first-ready, first-served cluster study approach, has not yet meaningfully reduced timelines. Developers report spending $2 to $5 million on interconnection studies and deposits before receiving cost certainty, with network upgrade allocations frequently making otherwise economic projects unviable.

Long-Duration Storage Economics Remain Challenging

Technologies designed for durations beyond eight hours, including iron-air batteries, flow batteries, compressed air energy storage, and green hydrogen, have not achieved the cost reductions necessary for widespread commercial deployment. Form Energy's iron-air battery, targeting a system cost of $20 per kWh for 100-hour duration, has yet to demonstrate performance at scale; its first commercial project in Weirton, West Virginia, remains under construction with an expected completion in 2026. Vanadium redox flow batteries from manufacturers like Invinity and Rongke Power have achieved system costs of $350 to $500 per kWh, still two to three times the threshold needed for broad market competitiveness. The fundamental challenge is that long-duration storage assets cycle infrequently (perhaps 20 to 50 times per year), spreading high capital costs across relatively few discharge events and yielding LCOS values that exceed $250 per MWh in most scenarios.

Merchant Risk and Revenue Volatility

Storage projects developed on a fully merchant basis (without long-term contracts) face significant revenue uncertainty. In ERCOT, revenues per MW ranged from $80,000 to over $300,000 across individual assets in 2025, depending on location, trading strategy, and market conditions. This volatility makes project financing difficult: lenders typically underwrite to P90 revenue scenarios, which can be 40 to 50% below median expectations. The result is that merchant storage projects require higher equity contributions and accept lower leverage ratios than contracted assets, increasing the cost of capital by 200 to 400 basis points. Several early ERCOT storage projects that reached financial close in 2022 and 2023 at optimistic revenue projections have underperformed, leading to covenant challenges and refinancing discussions.

Supply Chain Concentration Risks

Over 80% of global lithium-ion battery cell manufacturing is located in China, with additional concentration in raw material processing (China refines over 70% of the world's lithium, 85% of cobalt, and 95% of manganese). The US Inflation Reduction Act's domestic content requirements and FEOC (Foreign Entity of Concern) restrictions, effective for storage ITC eligibility in 2025 and beyond, have created supply chain compliance complexity. Developers must navigate evolving rules around cell and module sourcing, critical mineral provenance, and manufacturing location. Non-compliant projects forfeit the 30% investment tax credit (or 6% base rate), fundamentally altering project economics.

What's Next

Hybrid Solar-Plus-Storage as the Default Procurement Model

The integration of storage with solar generation at the point of interconnection is rapidly becoming standard practice. Over 70% of new utility-scale solar projects in the US now include co-located storage, up from less than 20% in 2021. This configuration reduces interconnection costs by sharing grid connection infrastructure, improves capacity value by providing dispatchable output, and simplifies procurement by offering a single offtake counterparty. Developers including NextEra Energy, AES, and Intersect Power have standardized their development pipelines around hybrid configurations, with storage ratios typically ranging from 25% to 100% of solar nameplate capacity.

Emergence of Storage-as-Transmission

Regulators and grid operators are increasingly recognizing that strategically sited storage can defer or avoid costly transmission upgrades. FERC's 2023 transmission planning rulemaking (Order 1920) explicitly includes storage as a transmission alternative that must be evaluated in long-range planning processes. The New York Power Authority's deployment of 316 MW of storage in constrained areas of New York City and Long Island has deferred approximately $800 million in transmission infrastructure. This use case unlocks regulated rate-of-return economics for storage, providing more predictable revenue than merchant or tolling structures and potentially accelerating deployment in transmission-constrained regions.

Standardization of Procurement Contracts

The Edison Electric Institute and the American Clean Power Association released standardized storage tolling agreement templates in 2025, reducing transaction costs and legal complexity for procurement. These templates address augmentation obligations (guaranteeing capacity maintenance as batteries degrade), performance guarantees, force majeure provisions specific to storage, and insurance requirements. Standardization is expected to reduce development timelines by three to six months and lower financing costs as lenders develop familiarity with uniform contract structures.

Domestic Manufacturing Scale-Up

US domestic battery manufacturing capacity is expanding rapidly, driven by IRA incentives. By 2027, committed factory investments from LG Energy Solution, Samsung SDI, CATL (through licensing arrangements), and domestic startups including EnerVenue and Ambri will bring approximately 200 GWh of annual US cell manufacturing capacity online. This expansion will reduce supply chain concentration risk, improve IRA domestic content compliance, and potentially lower logistics costs for US projects, though per-unit manufacturing costs are expected to remain 15 to 25% above Chinese equivalents in the near term.

Action Checklist

• Evaluate storage procurement through competitive solicitation rather than bilateral negotiation to capture market-driven pricing
• Model revenue stacking across energy arbitrage, ancillary services, and capacity markets before committing to single-revenue contract structures
• Assess interconnection queue position and realistic timeline before finalizing development schedules
• Require performance guarantees with independent measurement and verification for degradation, round-trip efficiency, and availability
• Structure tolling agreements with augmentation provisions that maintain contracted capacity throughout the agreement term
• Verify IRA domestic content and FEOC compliance for investment tax credit eligibility on all new procurement
• Consider hybrid solar-plus-storage configurations to reduce interconnection costs and improve capacity value
• Monitor long-duration storage technology milestones, particularly Form Energy and flow battery cost trajectories, for future procurement planning

FAQ

Q: What is the current all-in cost for a four-hour grid-scale lithium-ion storage system? A: Fully installed costs in the United States range from $200 to $250 per kWh for systems reaching commercial operation in 2025 and 2026, including cells, modules, inverters, balance of system, engineering, and interconnection. This translates to approximately $800 to $1,000 per kW for a four-hour system. Costs in China are 30 to 40% lower. These figures exclude land, financing costs, and any grid upgrade allocations, which can add $50 to $150 per kW depending on location.

Q: How should organizations compare storage bids from different developers? A: Normalize bids to a common LCOS basis that accounts for differences in degradation rates, round-trip efficiency, augmentation commitments, and warranty terms. A lower upfront price may yield higher lifetime costs if degradation is faster or augmentation obligations are weaker. Request 20-year financial models from bidders using standardized assumptions for cycling, degradation, and auxiliary power consumption. Engage independent technical advisors to validate performance projections against manufacturer data and comparable operating assets.

Q: When will long-duration storage become cost-competitive? A: For durations of eight to twelve hours, lithium-ion and lithium iron phosphate systems are approaching cost-competitiveness in markets with high price volatility. For durations beyond 24 hours, commercial viability requires system costs below $50 to $80 per kWh, which no technology has demonstrated at scale as of early 2026. Form Energy targets $20 per kWh for iron-air technology by 2028. Flow battery manufacturers project costs of $150 to $250 per kWh by 2028. Realistic expectations for broad long-duration deployment at competitive costs point to 2028 to 2030 for front-runner technologies.

Q: What risks should procurement teams prioritize when contracting for grid storage? A: The five primary risks are: counterparty creditworthiness (particularly for newer developers), technology performance risk (degradation exceeding projections), interconnection delay risk (projects failing to achieve commercial operation on schedule), regulatory risk (changes to market rules or incentive programs), and supply chain risk (cell delivery delays or domestic content compliance failures). Mitigate these through performance bonds, liquidated damages for delay, technology-specific insurance products, and diversified supplier sourcing.

Q: How does the Inflation Reduction Act affect storage procurement economics? A: The IRA provides a standalone investment tax credit (ITC) of 30% for energy storage systems placed in service after January 1, 2023, with potential adders of 10% for domestic content compliance and 10% for projects in energy communities. The combined 50% ITC can reduce effective system costs by nearly half. However, FEOC restrictions effective in 2025 exclude projects using battery components from designated Chinese entities, requiring careful supply chain documentation. Projects that fail to meet domestic content requirements still receive the 6% base ITC rate, a significant reduction that fundamentally alters project returns.

Sources

• BloombergNEF. (2025). Global Energy Storage Market Outlook 2026. New York: Bloomberg LP.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection, 2025 Edition. Berkeley, CA: LBNL.
• Lazard. (2025). Lazard's Levelized Cost of Storage Analysis, Version 9.0. New York: Lazard Ltd.
• International Energy Agency. (2025). World Energy Outlook 2025: Renewables and Storage Chapter. Paris: IEA Publications.
• Wood Mackenzie. (2025). US Energy Storage Monitor, Q4 2025. Edinburgh: Wood Mackenzie.
• National Renewable Energy Laboratory. (2025). Annual Technology Baseline: Storage Technologies. Golden, CO: NREL.
• Federal Energy Regulatory Commission. (2023). Order No. 2023: Improvements to Generator Interconnection Procedures. Washington, DC: FERC.
• Edison Electric Institute. (2025). Model Energy Storage Tolling Agreement, Version 1.0. Washington, DC: EEI.