Myths vs. realities: Grid-scale energy storage economics & procurement — what the evidence actually supports

Global grid-scale battery storage installations reached 120 GWh of new capacity deployed in 2025, a 74% increase over 2024, yet cumulative financial losses across the sector exceeded $4.2 billion as projects underperformed revenue projections by an average of 31%, according to BloombergNEF's 2026 Global Energy Storage Outlook. This gap between deployment momentum and economic reality has created fertile ground for persistent myths that misguide procurement decisions, inflate investor expectations, and distort policy design. For investors evaluating grid storage opportunities across the Asia-Pacific region, where 58% of 2025's new installations were concentrated, separating evidence-backed economics from promotional narratives is essential for capital allocation.

Why It Matters

Grid-scale energy storage is the single largest infrastructure investment category in the clean energy transition after generation assets themselves. The International Energy Agency projects cumulative global storage investment of $620 billion through 2030, with the Asia-Pacific region accounting for $380 billion of that total (IEA, 2025). China deployed 48 GWh of grid storage in 2025 alone, Australia commissioned 14 GWh, and India's pipeline exceeds 40 GWh of contracted capacity through 2028.

These deployment volumes mean procurement decisions are being made at unprecedented scale and speed. State-owned utilities in China, merchant developers in Australia, and public-private partnerships in India are all navigating a market where vendor claims, consultant projections, and policy assumptions frequently diverge from operational evidence. The financial stakes are enormous: a single 400 MWh battery energy storage system (BESS) represents $120 million to $180 million in capital expenditure, and the difference between a well-structured and poorly structured procurement can determine whether that investment generates 8 to 12% internal rate of return or becomes a stranded asset within five years.

Understanding where the myths cluster, and what the operational data actually shows, is the difference between deploying capital effectively and repeating the mistakes of early movers.

Key Concepts

Levelized Cost of Storage (LCOS): The total lifecycle cost of storing and discharging one megawatt-hour of energy, encompassing capital costs, operations and maintenance, degradation-related capacity replacement, and end-of-life costs. LCOS varies dramatically based on duty cycle, depth of discharge, and project duration assumptions.

Revenue stacking: The practice of earning revenue from multiple grid services simultaneously or sequentially, including energy arbitrage, frequency regulation, capacity payments, and ancillary services. Revenue stacking is frequently cited as the mechanism that makes storage economics work, but its real-world execution is far more complex than financial models suggest.

Capacity market: A market mechanism where grid operators compensate resources for being available to generate or discharge electricity during peak demand periods. Capacity payments provide a fixed revenue floor that improves storage project bankability.

Augmentation: The process of adding additional battery cells to a storage system over its operating life to compensate for capacity degradation and maintain contracted performance levels. Augmentation costs are frequently underestimated in initial project economics.

Myth 1: Battery Storage LCOS Has Fallen Below Gas Peakers

The myth: Numerous industry reports and vendor presentations claim that battery storage LCOS has fallen below the cost of natural gas peaker plants, making gas peakers economically obsolete for all applications.

The reality: This comparison is valid only for a narrow set of use cases. Lazard's 2025 Levelized Cost of Storage Analysis shows lithium iron phosphate (LFP) four-hour BESS achieving LCOS of $115 to $165 per MWh for daily cycling applications, compared to $150 to $210 per MWh for gas peaker plants (Lazard, 2025). However, this comparison assumes a 4-hour duration at 350 or more annual cycles. For peaking applications requiring 6 to 8 hours of discharge duration, or for facilities that cycle only 50 to 100 times per year, gas peakers retain a significant cost advantage because battery LCOS is highly sensitive to utilization rate. Australia's Hornsdale Power Reserve, one of the most commercially successful BESS projects globally, achieves its economics primarily through frequency regulation revenue with a duty cycle that rarely requires full 4-hour discharge, a profile that does not translate to capacity-replacement applications. The Waratah Super Battery (850 MWh) in New South Wales reported LCOS 22% higher than its pre-financial-close projections in its first full year of operation due to lower-than-expected arbitrage spreads and curtailment during high renewable generation periods (AEMO, 2025).

Myth 2: Revenue Stacking Makes Any Storage Project Viable

The myth: By stacking revenues from energy arbitrage, frequency regulation, capacity payments, and ancillary services, storage projects can achieve attractive returns regardless of individual revenue stream weakness.

The reality: Revenue stacking works in theory but faces severe practical constraints. First, many revenue streams are mutually exclusive in real time: a battery providing frequency regulation cannot simultaneously capture arbitrage spreads because its state of charge must remain at the midpoint for regulation service. Second, ancillary service markets saturate quickly as storage penetration increases. The PJM Interconnection frequency regulation market in the US, once the most lucrative revenue stream for storage, saw clearing prices decline 62% between 2020 and 2025 as installed storage capacity grew from 300 MW to 4,800 MW (PJM, 2025). Australia's National Electricity Market shows similar saturation: FCAS (Frequency Control Ancillary Services) revenue per MW of installed storage declined from A$85,000 per MW per year in 2022 to A$34,000 per MW per year in 2025 as storage capacity tripled (AEMO, 2025). Third, contract structures for capacity payments often impose availability requirements that restrict participation in other markets. Projects that model aggressive revenue stacking during development frequently discover during operations that achievable stacked revenue is 25 to 40% below projections.

Myth 3: Battery Degradation Is a Solved Problem

The myth: Modern LFP batteries are warranted for 15 to 20 years and will maintain performance throughout their warranted life with minimal additional investment.

The reality: While LFP chemistry represents a significant improvement over nickel manganese cobalt (NMC) in cycle life and thermal stability, degradation remains a material economic factor. Manufacturer warranties typically guarantee 60 to 70% of nameplate capacity at the 15-year mark, meaning a 200 MWh system may deliver only 120 to 140 MWh by year 15 without augmentation. Maintaining contracted capacity requires augmentation investments, the addition of new cells to replace lost capacity, typically starting in years 6 to 8 of operation. Wood Mackenzie estimates that augmentation adds $8 to $15 per MWh to lifecycle costs, a factor frequently excluded from headline LCOS figures used in procurement evaluations (Wood Mackenzie, 2025). China's State Grid reported that its early utility-scale LFP installations (2019 to 2021 vintage) showed capacity fade rates of 2.5 to 3.5% per year at daily cycling, faster than the 1.5 to 2.0% per year that manufacturers had projected, driven by operating temperature extremes and deeper-than-modeled discharge patterns (State Grid Corporation of China, 2025). The financial impact is substantial: for a 500 MWh project with a 15-year power purchase agreement, underestimating degradation by 1% per year translates to approximately $12 million in unbudgeted augmentation costs over the project life.

Myth 4: Procurement Should Focus Primarily on CapEx per kWh

The myth: The most important metric for BESS procurement is the installed cost per kilowatt-hour, and the lowest-price bid represents the best value.

The reality: Capital cost per kWh is necessary but grossly insufficient as a procurement metric. The total cost of ownership is driven equally by round-trip efficiency (which determines how much energy is lost per cycle), degradation rates (which determine augmentation costs), thermal management effectiveness (which affects both degradation and safety), and integration costs including grid connection, control systems, and balance of plant. A procurement comparison of two BESS bids for a 200 MW/800 MWh project in Queensland, Australia revealed that the lowest CapEx bid ($148/kWh installed) had a round-trip efficiency of 83%, while the second-lowest bid ($162/kWh) achieved 89% round-trip efficiency. Over a 15-year operating life at 300 annual cycles, the efficiency difference alone was worth $18 million in avoided energy purchase costs, more than offsetting the $11.2 million higher initial capital cost (Clean Energy Council, 2025). Smart procurement frameworks evaluate total LCOS across multiple scenarios, warranty terms and the financial strength of the warrantor, demonstrated operating performance at reference installations, and supply chain risk including cell sourcing concentration and shipping logistics.

What's Working

Performance-based procurement frameworks that evaluate total lifecycle cost rather than upfront price are producing superior outcomes. South Korea's KEPCO has implemented a scoring system that weights CapEx at only 30%, with remaining evaluation points allocated to demonstrated degradation performance, round-trip efficiency, safety certification, and local service infrastructure. This approach has reduced warranty claims by 45% compared to projects procured under earlier price-only frameworks.

Co-located storage paired with renewable generation assets consistently outperforms standalone merchant storage on risk-adjusted returns. In Australia, solar-plus-storage projects with shared grid connections achieve 15 to 25% lower total connection costs and benefit from generation-following charging that extends battery life by reducing grid-charged cycling. The 300 MW/1,200 MWh Western Downs Battery in Queensland, co-located with a 400 MW solar farm, achieved 94% availability and revenue within 5% of P50 projections in its first year.

Long-duration capacity contracts (10 to 15 years) with creditworthy offtakers provide the revenue certainty necessary for debt financing. Projects with contracted capacity payments covering 60 to 70% of projected revenue can secure project finance at 70 to 80% leverage ratios, significantly improving equity returns compared to merchant-exposed structures.

What's Not Working

Merchant-only revenue models in markets with rapidly growing storage penetration are delivering returns well below investment-grade thresholds. Australian merchant BESS projects commissioned in 2024 achieved average returns of 4 to 6% in their first year, compared to 10 to 14% projected at financial close, as arbitrage spreads compressed and ancillary service prices declined with each new installation.

Single-source cell procurement from a single Chinese manufacturer creates concentrated supply chain risk. Several projects in the Asia-Pacific region experienced 6 to 12 month commissioning delays in 2024 and 2025 when cell manufacturers prioritized domestic Chinese projects over export orders. Developers that sole-sourced from a single supplier had no fallback options.

Fixed-price EPC contracts with inadequate performance guarantees allow integration risk to transfer to asset owners. Several early BESS projects in India experienced 12 to 18 months of underperformance after commissioning due to control system integration issues, inverter firmware deficiencies, and thermal management inadequacies that were not covered by EPC warranties focused on construction completion rather than operational performance.

Key Players

Established companies: CATL (cell manufacturer supplying over 40% of global grid storage cells), Fluence Energy (systems integrator with 12 GWh deployed globally), Tesla Energy (Megapack platform with vertically integrated manufacturing), Wartsila (energy storage systems and optimization software), Samsung SDI (NMC and LFP cell manufacturer with significant Asia-Pacific market share)

Startups: Powin Energy (modular BESS systems with integrated controls), ESS Inc. (iron flow battery technology for long-duration applications), EnerVenue (nickel-hydrogen battery chemistry targeting 30-year life), Invinity Energy Systems (vanadium redox flow batteries for 4 to 12 hour duration)

Investors: Macquarie Green Investment Group (over $3 billion deployed in storage assets across Asia-Pacific), BlackRock Climate Infrastructure (targeting 15 GWh storage portfolio by 2028), Brookfield Renewable Partners (4.2 GWh operating storage portfolio), AES Corporation (integrated development and operation of 6 GWh storage globally)

Action Checklist

• Evaluate BESS bids on total LCOS across at least three operating scenarios (base case, low utilization, high degradation) rather than upfront CapEx alone
• Require demonstrated degradation data from at least three reference installations operating for 3+ years under comparable duty cycles
• Model revenue projections with storage saturation effects: reduce ancillary service revenue assumptions by 40 to 60% from current clearing prices for projects commissioning in 2027 or later
• Structure procurement with performance guarantees covering round-trip efficiency, capacity degradation, and availability, backed by liquidated damages
• Include augmentation cost estimates and timing in financial models, budgeting $8 to $15 per MWh of lifecycle storage throughput
• Diversify cell supply across at least two manufacturers to reduce commissioning delay risk
• Secure contracted revenue covering at least 50 to 60% of projected total revenue before reaching financial close

FAQ

Q: What is a realistic return expectation for a grid-scale BESS project in the Asia-Pacific region? A: Contracted projects with 10 to 15 year capacity agreements and creditworthy offtakers are achieving levered equity returns of 9 to 13%, depending on market and currency risk. Merchant-exposed projects in competitive markets like Australia's NEM should model returns of 6 to 9%, with significant downside risk as storage penetration grows. Projects relying on revenue stacking across multiple merchant services should stress-test returns assuming 40 to 50% revenue haircuts on ancillary services from current levels.

Q: How should investors evaluate battery degradation risk in procurement? A: Request independent engineer review of manufacturer degradation warranties, including the financial backing behind the warranty (manufacturer credit rating and warranty reserve provisions). Compare warranted degradation curves against independently verified operational data from reference plants. Model the cost of augmentation at current cell prices plus 10 to 20% as a conservative hedge, and include augmentation capital in your LCOS calculation. LFP systems typically require first augmentation at years 6 to 8 for daily-cycling duty profiles.

Q: Is long-duration storage (8 to 12 hours) investable today? A: Lithium-ion BESS at 8 to 12 hour durations is technically feasible but economically challenging, with LCOS of $200 to $300 per MWh. Alternative technologies (iron-air, vanadium redox flow, compressed air) are approaching cost parity for long-duration applications but lack the operational track record of lithium-ion at scale. Form Energy's iron-air pilot in Minnesota and ESS Inc.'s iron flow installations in Oregon represent early commercial deployments, but investors should treat long-duration storage as a 2028 to 2030 opportunity for scaled deployment, with current investments positioned as strategic or demonstration-stage capital.

Q: What is the biggest procurement mistake in grid storage today? A: Evaluating bids primarily on installed CapEx per kWh without adequate weighting for round-trip efficiency, degradation warranty terms, thermal management design, and integration track record. The lowest CapEx bid frequently produces the highest LCOS over the project life. Procurement teams should allocate no more than 30% of evaluation weighting to upfront cost, with remaining scoring distributed across performance, reliability, and lifecycle cost factors.

Sources

• BloombergNEF. (2026). Global Energy Storage Outlook 2026: Deployment, Economics, and Market Dynamics. London: BNEF.
• International Energy Agency. (2025). World Energy Investment 2025: Energy Storage Chapter. Paris: IEA.
• Lazard. (2025). Lazard's Levelized Cost of Storage Analysis, Version 9.0. New York: Lazard Ltd.
• Australian Energy Market Operator. (2025). Battery Energy Storage System Performance Review 2024-25. Melbourne: AEMO.
• PJM Interconnection. (2025). State of the Market Report: Ancillary Services and Energy Storage Performance. Norristown, PA: Monitoring Analytics.
• Wood Mackenzie. (2025). Global Battery Storage Augmentation Cost Outlook. Edinburgh: Wood Mackenzie.
• State Grid Corporation of China. (2025). Utility-Scale Battery Storage Operational Performance: Five-Year Review 2020-2025. Beijing: SGCC.
• Clean Energy Council. (2025). Battery Energy Storage Procurement Best Practice Guide. Melbourne: CEC.