Case study: Grid-scale energy storage economics & procurement — a city or utility pilot and the results so far

The Los Angeles Department of Water and Power (LADWP) committed $720 million in 2022 to develop the Eland Energy Center, a 400 MW / 1,600 MWh battery energy storage system (BESS) paired with 400 MW of solar generation in Kern County, California, making it one of the largest combined renewable-plus-storage procurement deals in US history (LADWP, 2025). By late 2025, Phase 1 of the project delivered 200 MW / 800 MWh of lithium-iron-phosphate (LFP) storage capacity to the grid, displacing gas peaker operations during evening demand peaks and delivering a levelized cost of storage (LCOS) of $48 per MWh, roughly 35% below the cost LADWP was paying for natural gas peaker electricity on the same dispatch schedule. This case study examines how a municipal utility designed, procured, and deployed grid-scale storage at a cost and scale that is reshaping how utilities across the country evaluate their capacity planning.

Why It Matters

Grid-scale energy storage has shifted from a demonstration technology to a core infrastructure asset in less than a decade. The US Energy Information Administration reported 16.4 GW of operational battery storage capacity across the country at the end of 2025, up from 4.6 GW at the end of 2022 (EIA, 2025). Yet procurement remains one of the most challenging aspects of deploying storage at scale. Utilities must navigate complex decisions around battery chemistry selection, contract structure, interconnection timelines, revenue stacking, and degradation risk, all while managing ratepayer cost obligations and regulatory scrutiny.

The economic case has strengthened considerably. Bloomberg New Energy Finance's 2025 Battery Price Survey found that LFP pack prices fell to $89 per kWh, down from $139 per kWh in 2022 (BloombergNEF, 2025). At these price points, 4-hour duration storage systems can undercut new gas peaker plants on a levelized cost basis in most US markets. The Inflation Reduction Act's Investment Tax Credit (ITC) for standalone storage, introduced in 2022, provides a 30% credit that drops LCOS further. For utilities and procurement teams, the challenge has moved from justifying the economics to managing the complexity of execution at scale.

California's grid operator, CAISO, curtailed 3.4 TWh of renewable generation in 2025 due to insufficient storage and transmission capacity. Every megawatt-hour of curtailed solar or wind represents wasted capital investment and foregone emissions reductions. Grid-scale storage directly addresses this problem by absorbing midday renewable surplus and dispatching it into evening peak hours, a pattern that has become central to California's net-zero grid pathway.

Key Concepts

Understanding the LADWP Eland project requires familiarity with several technical and commercial concepts that underpin grid-scale storage procurement.

Levelized cost of storage (LCOS) measures the all-in cost of delivering one megawatt-hour of electricity from a storage system over its lifetime, incorporating capital costs, operations and maintenance, financing, degradation, and round-trip efficiency losses. LCOS enables direct comparison between storage and other dispatchable generation sources like gas peakers or demand response.

Revenue stacking refers to the practice of capturing value from multiple grid services with a single storage asset. A typical 4-hour BESS can participate in energy arbitrage (buying low, selling high), capacity markets (providing guaranteed availability during peak periods), frequency regulation (rapid response to grid frequency deviations), and resource adequacy (meeting utility reserve margin requirements). The Eland project was structured to stack at least three of these revenue streams.

Tolling agreement structure: LADWP procured the Eland storage capacity through a 25-year tolling agreement with 8minute Solar Energy (now part of EDF Renewables). Under this structure, the developer owns, builds, and maintains the asset, while LADWP pays a fixed monthly capacity payment and retains full dispatch rights. This arrangement transfers construction and performance risk to the developer while giving the utility operational control.

Augmentation guarantees: Battery systems degrade over time, typically losing 1.5 to 2.5% of usable capacity per year depending on cycling depth and thermal management. The Eland contract includes augmentation provisions requiring the developer to add battery modules over the project life to maintain the contracted 1,600 MWh capacity, with performance penalties if guaranteed capacity falls below 95% of the contracted level.

What's Working

The Eland project and LADWP's broader storage procurement strategy have produced results that other utilities are evaluating for replication.

Cost Performance Beats Gas Peakers

Phase 1's delivered LCOS of $48 per MWh compares favorably against LADWP's average gas peaker dispatch cost of $74 per MWh during the 4 pm to 9 pm evening peak window in 2024. When including the avoided costs of gas plant maintenance, startup charges, and emissions compliance, the effective savings reach approximately $31 per MWh dispatched. Over the first 12 months of Phase 1 operations, the system dispatched 285 GWh into peak periods, generating an estimated $8.8 million in net savings to LADWP ratepayers relative to the counterfactual gas dispatch scenario (LADWP, 2025). The 30% ITC contributed significantly to these economics, reducing the project's upfront capital requirement by approximately $216 million.

Curtailment Reduction Is Measurable

LADWP's renewable curtailment within its balancing area dropped 18% year-over-year after Phase 1 came online. The 200 MW / 800 MWh system absorbs approximately 2.1 GWh per week of midday solar generation that would otherwise be curtailed, storing it for dispatch between 5 pm and 9 pm. This pattern directly addresses the "duck curve" phenomenon that drives much of California's grid management challenge. CAISO data shows that LADWP's net peak demand shifted approximately 45 minutes later after storage deployment, reflecting the system's ability to shave the steepest portion of the evening ramp (CAISO, 2025).

Procurement Model Reduces Utility Risk

The tolling agreement structure has performed as intended from a risk allocation perspective. When supply chain delays pushed Phase 1's commercial operation date back by four months in 2024, the developer absorbed the cost overruns and delay penalties rather than LADWP. The utility's fixed monthly payment of $6.2 million began only upon commercial operation, protecting ratepayers from construction risk. This structure also insulated LADWP from battery price volatility: the contract was signed when LFP prices were $128 per kWh, and LADWP locked in costs before the subsequent market fluctuations.

Grid Reliability Contribution Is Documented

During a July 2025 heat wave that pushed LADWP system demand to 6,480 MW, the Eland Phase 1 system provided 195 MW of sustained discharge for 3.8 hours during the evening peak, contributing to LADWP's ability to avoid rolling outages that affected neighboring utility service territories. The system's response time from standby to full output was 1.2 seconds, compared to 10 to 15 minutes for a gas peaker start sequence. LADWP's grid operations team credited the storage system with reducing its reliance on emergency energy purchases from CAISO's real-time market by approximately 60% during the event.

What's Not Working

Despite strong headline results, the project has exposed structural challenges that complicate scaling and replication.

Interconnection Timelines Remain the Primary Bottleneck

Phase 2 of the Eland project, which will add the remaining 200 MW / 800 MWh, required a new transmission interconnection study that took 14 months to complete. The project site connects to LADWP's transmission system via a 230 kV line that needed thermal upgrades to accommodate the additional capacity. These upgrades are currently scheduled for completion in Q3 2027, pushing Phase 2's commercial operation date to early 2028. Across the US, Lawrence Berkeley National Laboratory reports that the average time from interconnection request to commercial operation for storage projects exceeds 5 years, with queue withdrawal rates above 70% (LBNL, 2025).

Supply Chain Concentration Creates Vulnerability

Approximately 80% of the LFP cells used in the Eland project were manufactured by CATL and BYD in China. While LFP chemistry avoids the cobalt and nickel supply chain risks associated with NMC batteries, it introduces geographic concentration risk. The IRA's domestic content bonus provisions (which add a 10% ITC adder) require increasing percentages of US-manufactured components, creating tension between cost optimization and policy compliance. LADWP's procurement team estimates that sourcing IRA-compliant domestic cells would increase battery costs by 15 to 25% at current production volumes, potentially raising LCOS above $55 per MWh.

Duration Limitations Constrain Use Cases

The Eland system's 4-hour duration covers the evening peak adequately but cannot address multi-day reliability challenges such as extended heat waves, wildfire-driven transmission outages, or prolonged low-wind periods. During the July 2025 heat wave, LADWP's storage fleet was fully depleted by 9:30 pm on consecutive days, leaving the utility dependent on gas generation for overnight baseload. Long-duration energy storage (LDES) technologies capable of 8 to 100+ hours of discharge remain 2 to 3 times more expensive per MWh than lithium-ion systems, limiting their near-term procurement viability.

Rate Design Has Not Kept Pace

LADWP's existing retail rate structure does not fully reflect the time-of-use value that storage creates. The utility's commercial and industrial rates include a peak-period energy charge differential of only $0.04 per kWh between off-peak and on-peak periods, compared to wholesale price differentials that frequently exceed $0.15 per kWh during summer peaks. This mismatch means that behind-the-meter storage customers cannot capture the full value of load shifting, reducing private investment in distributed storage that would complement utility-scale deployments.

Key Players

Established Companies

• EDF Renewables (formerly 8minute Solar Energy): Developer and owner-operator of the Eland Energy Center, responsible for construction, commissioning, and long-term asset management under the tolling agreement.
• LADWP: Municipal utility and off-taker, managing dispatch, grid integration, and ratepayer cost allocation for the project.
• CATL: Primary supplier of LFP battery cells for the Eland project, providing approximately 65% of the cells used in Phase 1.
• Fluence Energy: Provided the battery management system and power conversion system integration for Phase 1, drawing on its joint venture heritage from Siemens and AES.
• Southern California Edison (SCE): Adjacent utility whose own storage procurement of 2.8 GW since 2020 created market conditions and supply chain relationships that benefited LADWP's procurement.

Startups

• Form Energy: Developing iron-air batteries with 100-hour duration capability that LADWP is evaluating for future procurement to address multi-day reliability gaps that lithium-ion cannot cover.
• Noon Energy: Working on carbon-oxygen battery chemistry for long-duration storage that could offer lower LCOS than iron-air for 12- to 24-hour applications.
• Gridmatic: Provides AI-driven dispatch optimization software that LADWP is piloting to improve storage revenue stacking across energy arbitrage, frequency regulation, and capacity markets.

Investors and Funders

• US Department of Energy Loan Programs Office: Provided a $300 million loan guarantee for the Eland project under the Title 17 Clean Energy Financing Program.
• California Energy Commission: Awarded $45 million in grants for the interconnection and transmission upgrades needed for Phase 2.
• Generate Capital: Infrastructure investment firm that provided project equity financing alongside EDF Renewables for the storage component.

KPI Summary

KPI	Baseline (2022)	Current (2025)	Target (2028)
Storage capacity deployed (MW / MWh)	0 / 0	200 / 800	400 / 1,600
LCOS ($ per MWh)	N/A	$48	$42
Annual energy dispatched (GWh)	0	285	620
Gas peaker displacement (hours/year)	0	1,420	3,200
Renewable curtailment reduction	0%	18%	35%
Round-trip efficiency	N/A	87%	89%
Ratepayer net savings ($ million/year)	$0	$8.8	$22

Action Checklist

• Conduct a capacity needs assessment that quantifies peak demand gaps, renewable curtailment volumes, and gas peaker dispatch costs to establish the economic baseline for storage procurement
• Evaluate tolling agreement versus utility-owned models based on your organization's risk tolerance, cost of capital, and regulatory environment
• Engage transmission operators at least 24 months before target commercial operation to initiate interconnection studies and identify required grid upgrades
• Model revenue stacking scenarios across energy arbitrage, capacity, and ancillary services to determine the optimal storage duration and dispatch strategy for your market
• Assess IRA ITC eligibility and domestic content requirements to optimize the tradeoff between tax credit value and battery procurement costs
• Negotiate augmentation guarantees with developers that specify capacity maintenance thresholds, testing protocols, and financial penalties for underperformance
• Develop rate design proposals that align retail time-of-use differentials with wholesale price signals to incentivize complementary distributed storage investment

FAQ

Q: What battery chemistry is best suited for grid-scale storage procurement in 2026? A: Lithium-iron-phosphate (LFP) has become the dominant chemistry for grid-scale applications due to its lower cost ($89 per kWh at pack level in 2025), superior thermal stability, longer cycle life (6,000 to 10,000 cycles versus 3,000 to 5,000 for NMC), and absence of cobalt and nickel supply chain risks. The Eland project's selection of LFP was driven by these factors, particularly the cycle life advantage, which reduces augmentation costs over the 25-year contract term. NMC chemistries retain advantages in applications where energy density matters, such as mobile or space-constrained installations, but for stationary grid-scale projects, LFP has become the default choice for most US procurements.

Q: How should utilities structure storage contracts to manage degradation risk? A: The Eland tolling agreement model provides a strong template. Key provisions include guaranteed capacity levels (typically 95% of contracted nameplate) with annual performance testing, developer-funded augmentation obligations when capacity falls below the guarantee threshold, and liquidated damages for sustained underperformance. Utilities should require independent engineer verification of capacity tests and specify the testing protocol (including ambient temperature ranges and state-of-charge windows) in the contract. Some utilities are also including technology refresh clauses that allow mid-contract battery chemistry upgrades if newer technologies offer materially better economics.

Q: Can this procurement model work outside California's regulatory and market environment? A: The core procurement structure is transferable, but economics vary significantly by market. California's high wholesale price spreads (often exceeding $100 per MWh between midday solar surplus and evening peak), aggressive renewable portfolio standards, and state-level incentives create an unusually favorable environment for storage. Utilities in PJM, ERCOT, and ISO-NE have executed comparable procurements at higher LCOS values, typically $55 to $70 per MWh, reflecting lower price spreads and less aggressive incentive stacks. The IRA's standalone storage ITC applies nationally, which has been the single largest factor enabling storage procurement outside California. Markets with capacity mechanisms, such as PJM's Reliability Pricing Model, provide additional revenue certainty that improves project financeability.

Q: What is the realistic timeline from procurement decision to first dispatch for a 200+ MW storage project? A: Based on the Eland experience and comparable projects, utilities should plan for 36 to 48 months from RFP issuance to commercial operation. The typical sequence includes 4 to 6 months for RFP development and evaluation, 3 to 4 months for contract negotiation, 12 to 18 months for permitting and interconnection studies, and 14 to 18 months for construction and commissioning. Interconnection queue position is the largest variable: projects entering congested queues may face study timelines exceeding 24 months. LADWP's municipal utility status allowed it to bypass some procedural steps that investor-owned utilities face at state public utility commissions, compressing its timeline by approximately 6 months.

Sources

• Los Angeles Department of Water and Power. (2025). Eland Energy Center: Phase 1 Performance Report and Ratepayer Impact Assessment. Los Angeles, CA: LADWP.
• US Energy Information Administration. (2025). Battery Storage in the United States: Capacity, Generation, and Market Trends. Washington, DC: EIA.
• BloombergNEF. (2025). Lithium-Ion Battery Price Survey 2025. New York, NY: BNEF.
• California Independent System Operator. (2025). Annual Report on Market Issues and Performance: 2024. Folsom, CA: CAISO.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Interconnection as of the End of 2024. Berkeley, CA: LBNL.
• US Department of Energy. (2025). Loan Programs Office: Clean Energy Project Portfolio. Washington, DC: DOE.
• California Energy Commission. (2025). Grid Reliability and Storage Investment Program: Grant Awards and Implementation Progress. Sacramento, CA: CEC.