Battery energy storage systems, or BESS, have become essential infrastructure for data center development. The data center industry’s global electricity consumption is set to surge by more than 300 percent by the end of this decade according to several industry forecasts, and the grid cannot absorb that demand without dispatchable, flexible capacity at scale. Battery storage is no longer simply backup equipment at the edge of a data center’s power strategy. It is instead a primary tool for securing grid connections, managing the extreme power demands of artificial intelligence (AI) workloads, providing resilience, and meeting the clean energy commitments that operators have made to their boards, their customers, and their investors.
The numbers reflect the urgency. The U.S. Energy Information Administration (EIA) projects that developers will add 24 GW of utility-scale battery capacity to the grid in 2026, up from the record 15 GW installed in 2025, with more than 40 GW deployed over the past five years. That growth is heavily concentrated: Texas, California, and Arizona together account for roughly 80 percent of planned 2026 additions. Texas leads with approximately 12.9 GW (over half the national total), driven by wind and solar balancing needs on the ERCOT grid and surging data center demand near Dallas and Houston. California, which has used batteries for years to manage peak evening loads and reduce reliance on natural gas peakers, is expected to add 3.4 GW. Arizona is projected to add 3.2 GW.
While this alert focuses primarily on federal regulatory developments and the ERCOT market, where recent project activity provides useful illustration, the financing, compliance, and structuring considerations discussed here apply across all major interconnection markets, including PJM, where data center load concentration is highest and a December 2025 capacity auction revealed a 6,623 MW deficit at a record clearing price.
The legal and commercial landscape governing these assets has grown to match their strategic importance, and it shifted materially in 2025 and is shifting again in 2026. New federal rules under the One Big Beautiful Bill Act (OBBBA) have made supply chain compliance a condition of tax credit eligibility. A live Federal Energy Regulatory Commission (FERC) proceeding is poised to reshape the economics of co-located storage. Import tariffs have raised equipment costs by more than 50 percent since January 2025. Each of these developments creates obligations, opportunities, and risks that data center developers and operators, battery storage companies, project lenders, and energy transition investors will want to understand before their next transaction.
I. What BESS Does for a Data Center
The function a BESS performs in a data center context determines its contract structure, its financing treatment, and its regulatory classification. That function matters enormously, and establishing it clearly at the outset of a project is not a technicality. It determines which revenue streams are monetizable, what performance warranties are commercially appropriate, and how the asset is underwritten by lenders and equity investors.
Battery storage now performs four distinct functions for data centers: (1) regulating the massive power shifts common in AI training loads by enabling facilities to ramp from 10 percent to 90 percent capacity in milliseconds; (2) securing faster grid connections for data centers that install storage to guarantee demand response when requested by utilities; (3) providing resilience coverage for shorter grid outages; and (4) supporting long-term 24/7 carbon-free energy commitments for operators with clean energy goals. The fourth function, supporting 24/7 carbon-free energy commitments, has particular structural implications. Operators pursuing hourly matching rather than annual matching require storage sized and dispatched to cover every hour of load with verified clean energy, which produces fundamentally different cycling profiles, capacity requirements, and verification protocols from those of an annual renewable energy credit retirement. Agreements for hourly-matched storage need to address time-granular delivery obligations, measurement and verification standards, and the interaction between the BESS dispatch schedule and grid services revenue. An asset dispatched to fill hourly gaps in renewable generation may not be available for the ancillary services markets that support its merchant revenue, and agreements that do not account for that tension will underperform on one side or the other.
A BESS procured primarily to accelerate interconnection is a different asset legally, commercially, and financially from one procured for resilience, and both differ from one procured to monetize revenue for grid services. Lenders underwriting these assets benefit from that clarity before pricing the deal, and operators are well-served by establishing it before entering procurement.
The interconnection use case deserves particular attention given where the market is moving. Aligned Data Centers recently agreed to pay to build a 31-megawatt battery as an explicit strategy to accelerate grid interconnection, making it one of the first data center operators to use storage as an interconnection tool rather than a power backup. That model is replicable across constrained markets nationally, and operators facing long interconnection queues may find it worth evaluating seriously before accepting delay as the only option.
A fifth configuration is emerging among operators that pair data centers with dedicated on-site generation rather than relying primarily on grid interconnection. In that model, storage stabilizes the output of co-located generation assets, manages load variability without grid dispatch, and provides ride-through capability during fuel supply or generation interruptions. The contract structures for these configurations differ materially from grid-connected models: the BESS is typically integrated into the generation facility’s operating agreement rather than procured separately, and the performance guarantees are tied to generation availability rather than grid service metrics. As more operators explore on-site power solutions to avoid interconnection delays, this configuration is likely to grow in commercial significance. Developers deploying behind-the-meter generation to power data centers while waiting two to four years for grid connections are finding that battery storage is not optional: without it, the mix of solar, gas, and diesel generation cannot deliver the power quality that data center loads require. Regardless of configuration, co-located BESS installations raise fire safety and thermal management considerations, including compliance with NFPA 855 and local fire code requirements, that affect siting, insurance, and the physical separation requirements between storage and computing infrastructure. These requirements are increasingly finding their way into offtake and site lease agreements as conditions of operation.
II. The Financing Environment
Energy storage remains central to grid reliability, renewable integration, and data center growth, and while capital deployment became more selective in 2025, investor interest in battery storage assets remained strong, particularly for late-stage and operational projects positioned for near-term execution. The market has matured in a healthy direction: it now rewards well-structured, de-risked transactions and prices speculative ones accordingly.
Three financing dynamics define the current environment and warrant attention from every party to a BESS transaction.
The first is that storage benefits materially from documentation as a distinct asset rather than an afterthought to a larger financing arrangement. Storage investment is increasingly embedded within broader energy and infrastructure transactions, and publicly reported M&A and financing data often does not distinguish between projects that include storage and those that do not. In practice, BESS assets are frequently under-documented: collateral descriptions are vague, insurance requirements do not specifically address storage risks, and lender consent provisions treat storage as ancillary equipment rather than a material project component. Transactions structured with storage explicitly identified, valued, and ring-fenced within the financing arrangement close with fewer surprises at the table.
That documentation challenge extends to the revenue structure. Lenders and equity sponsors increasingly distinguish between contracted and merchant revenue when sizing debt and pricing equity. A BESS with a tolling agreement or capacity contract supporting 60 to 70 percent of projected revenue is a fundamentally different financing proposition from one relying primarily on energy arbitrage and ancillary services. Where a project stacks multiple revenue streams, the complexity compounds: dispatch optimization must balance competing obligations across energy arbitrage, ancillary services, and capacity commitments, and the financing documents must define priority among those streams, allocate dispatch authority between the operator and the offtaker, and address the risk that regulatory changes to one market product may affect the economics of the others.
The second dynamic is that project-level acquisitions have roughly doubled. Approximately 45 reported energy storage project M&A transactions occurred during the first nine months of 2025, compared to roughly 22 during the same period in 2024, driven by buyers’ preference for de-risked assets with confirmed interconnection, permitting, and offtake. The exit market for storage platforms is liquid, and the debt markets are following. In January 2026, BlackRock’s Jupiter Power closed a $500 million senior secured green revolving loan to accelerate a 12,000 MW U.S. development pipeline. Construction began in March 2026 on a 203 MW project in the high-demand corridor between Dallas and Houston, with completion targeted for May 2027. Separately, in 2025, Lydian Energy closed a $233 million tax credit bridge facility backed by ING and KeyBank to support three battery projects, including two 200 MW / 400 MWh systems in Texas representing a combined investment of approximately $139 million. Battery companies building data center market presence may wish to structure for eventual monetization from the first project, because institutional buyers have historically paid full value for confirmed interconnection, documented Foreign Entity of Concern (FEOC) compliance, and contracted revenue.
The third is that tariffs have raised costs materially and created potential contract exposure that parties to existing agreements may not have anticipated. Since January 2025, battery storage costs have risen an estimated 56 to 69 percent due to the Trump administration’s tariff policies, depending on configuration and sourcing. Those cost increases compound the capital intensity of an already infrastructure-heavy segment: Enbridge’s 600 MW Clear Fork Creek Solar and BESS project in Wilson, Texas, for example, represents an estimated $800 million combined capital investment for the full facility, and several standalone battery projects now under development in ERCOT exceed 400 MW apiece. Fixed-price supply agreements executed before this escalation may no longer reflect current economics, and force majeure, material adverse change, and price-adjustment provisions in those contracts are worth reviewing. New agreements that include explicit tariff pass-through mechanisms with defined limits are designed to address this exposure prospectively.
III. The FERC Large-Load Interconnection Proceeding
The most consequential active regulatory proceeding for everyone in this space warrants close attention, not because it is abstract policy, but because its outcome will directly affect the economics of BESS assets that are being procured and financed right now.
In October 2025, the U.S. Department of Energy (DOE) formally requested that FERC assert jurisdiction over the interconnection of large electrical loads to the U.S. bulk electric transmission grid and to establish standardized interconnection procedures. DOE proposed April 30, 2026, as the target date for FERC’s final action. This proceeding builds on a series of FERC orders, including FERC’s conditional treatment of the Talen Energy-Amazon co-location structure and subsequent directives to PJM and SPP to develop formal frameworks for co-located loads, that have progressively defined how federal regulators approach the intersection of large load growth and transmission system access. DOE’s April 30 deadline is close, and its outcome will be operative for projects whose agreements are being negotiated today.
The central contested question is how transmission costs are allocated when generation or storage is co-located with large load. Several hyperscalers have described co-location as a bridge solution until regulatory certainty improves. The specific positions vary: some have focused on willingness to pay for transmission services conditioned on unused capacity being excluded from cost allocations, while others have emphasized broader grid investment commitments tied to their clean energy procurement frameworks. How FERC reconciles these positions will determine the economics of BESS assets co-located with data center facilities, because transmission cost allocation directly affects grid services revenue, a primary component of return on invested capital for many storage projects. Agreements currently being negotiated with commercial operation dates in 2026 through 2028 will be operative under whatever rules FERC issues, and parties to those agreements may wish to consider provisions that contemplate a range of transmission cost allocation outcomes rather than assuming today’s rules will continue to persist.
IV. FEOC Compliance: The Issue That Now Governs Tax Credit Eligibility
The Prohibited Foreign Entity (PFE) rules under the OBBBA, operationalized by Internal Revenue Service (IRS) Notice 2026-15, issued February 12, 2026, are the single most consequential legal development in battery storage in 2026. They are in effect now, and every BESS beginning construction this year is subject to them.
The framework. A Prohibited Foreign Entity is generally an individual or entity with significant ties to China, Russia, North Korea, or Iran, or listed on certain U.S. government watch lists. A PFE cannot claim, sell, or purchase certain clean energy tax credits, and an energy storage facility that contains an excessive proportion of components produced by PFEs is ineligible for the Section 48E Investment Tax Credit (ITC) or Section 45Y Production Tax Credit (PTC).
The MACR test. Developers must calculate a Material Assistance Cost Ratio (MACR) for each energy storage technology for which they seek the ITC. For storage facilities beginning construction in 2026, the minimum threshold is 55 percent, meaning at least 55 percent of direct equipment costs must come from non-PFE sources. That threshold increases five percentage points annually, reaching 75 percent by 2030, which means that a supply chain configuration that clears the threshold in 2026 may fall short by 2028 without active management. The trajectory matters as much as the current number.
The cell problem. IRS safe harbor tables assign 52 percent of total direct cost to battery cells in certain grid-scale BESS configurations, and Chinese manufacturers control over 80 percent of the global battery cell and module supply chain. Most cells currently come from covered foreign nations, making MACR compliance the central procurement challenge for any developer seeking federal tax credits on a new BESS beginning construction in 2026. This is the commercial reality for every BESS transaction, and it requires active supply chain strategy rather than passive compliance.
The recapture exposure. If disqualifying payments to a specified foreign entity are made within 10 years after a facility is placed into service, the taxpayer must repay the entire value of the previously claimed tax credit. On a large BESS project claiming a 30 percent ITC with bonus adders, that can be a nine-figure contingent liability sitting in the capital structure for a decade. Lenders will want to model it as a contingent obligation, and some are already requiring reserves, escrows, or insurance wraps as conditions of financing. On the commercial side, offtake and supply agreements benefit from explicit allocation of this exposure between parties, with indemnification provisions that reflect the full recapture risk rather than just the incremental cost of a future supply chain swap.
The monetization path for the ITC itself also warrants attention. Internal Revenue Code (IRC) Section 6418 transfer elections allow project owners to sell tax credits directly to unrelated buyers, which has become a preferred structure for many sponsors. Where the project owner retains the credits instead, the combination of the ITC with Modified Accelerated Cost Recovery System (MACRS) depreciation remains a central component of the equity return. The PFE recapture framework applies directly to the tax credits, but a recapture event can also disrupt the broader tax structure in ways that affect the depreciation assumptions underlying the equity model. Transferability, moreover, does not eliminate recapture risk for the transferee, and credit purchase agreements that do not allocate PFE-related recapture exposure with the same specificity as the underlying supply agreements may leave the credit buyer holding a contingent liability that it did not price at closing.
What compliance involves in practice. Each containerized BESS combines battery modules, enclosures, thermal systems, inverter assemblies, and electronic controls, each of which can introduce PFE exposure at different points in the supply chain, and top-level entity certifications from manufacturers are generally not sufficient to establish compliance. Supply agreements that require component-level sourcing disclosure, per-product MACR calculations tied to the cost tables in IRS Notice 2026-15, and manufacturer certification obligations that survive ownership changes and supply chain restructurings provide meaningfully stronger protection. Until the safe harbor tables promised by the OBBBA are published (due December 31, 2026), taxpayers may rely on IRS Notice 2025-08 tables and supplier certifications, provided they do not have actual knowledge that a certification is inaccurate. That carve-out requires active supply chain management and real traceability protocols, not passive reliance on a folder of manufacturer paperwork that no one has verified against the actual component list. The market’s response to these rules has been telling: industry analysts tracked at least 10 GW of storage projects that began construction before year-end 2025 specifically to safe-harbor under the prior regime and avoid FEOC compliance entirely. That volume underscores both the difficulty of meeting the new thresholds and the competitive advantage available to developers who can.
V. The Data Center Market: What Battery Companies Should Consider
Most battery storage companies have built their businesses around utility-scale grid applications. The data center segment is structurally different and presents both genuine opportunity for companies willing to develop the right capabilities and real commercial risk for those that apply utility-market assumptions without adjustment.
A threshold point is worth stating clearly: the utility-scale BESS projects now proliferating across ERCOT and other markets are grid assets, not data center assets. They are dispatched into wholesale energy and ancillary services markets, and the data centers driving regional load growth are, for now, indirect beneficiaries rather than direct offtakers. But the trajectory is toward convergence. Battery storage has emerged as a critical tool for managing congestion and reliability challenges associated with data center development and rapid load growth, particularly in constrained interconnection markets. Several of the largest standalone battery projects advancing toward commercial operation in 2026 and 2027 are sited in ERCOT, where proximity to rapidly expanding data center clusters near Dallas and Houston creates both merchant revenue opportunities and potential behind-the-meter offtake structures for co-located facilities. The revenue dynamics differ by market: ERCOT’s energy-only design rewards price volatility; California’s Resource Adequacy framework provides a contracted capacity floor that can represent 30 to 40 percent of a storage project’s annual revenue; and PJM’s recent capacity price spike signals acute need for new dispatchable resources. As interconnection constraints intensify and co-location frameworks take shape under the FERC proceeding discussed in Section III above, the line between grid-serving and load-serving storage is likely to blur, and battery companies positioned on the utility-scale side of that line today will want to be ready when it does.
That said, data center customers are not utility procurement teams. The largest AI infrastructure operators are sophisticated counterparties with experienced in-house counsel and procurement staff who have structured large, complex infrastructure transactions before. Standard utility offtake agreements will not serve either party well in that context, and battery companies that arrive at the table with utility-market templates will find themselves renegotiating from the start.
What this market rewards, and what utility storage does not, includes discharge profiles and cycling tolerances tuned to AI training load ramps, performance guarantees expressed in terms that align with data center uptime standards rather than grid dispatch metrics, Foreign Entity of Concern (FEOC)-compliant supply chain documentation ready at signing (because tax credit eligibility is a closing condition, not a post-closing diligence item), and financing structures that treat storage as long-term infrastructure rather than commodity equipment with a short replacement cycle. New battery cell chemistries resilient to the cycling demands of AI training loads are being developed specifically to target this use case, and companies developing or deploying those chemistries with clean supply chains to match are well-positioned to establish preferred vendor relationships before the segment consolidates around a smaller number of proven counterparties.
Companies with proven unit economics and operational track records are accessing debt markets and specialized industrial financing, marking the transition from startup funding to heavy industry capital structures. Battery companies entering the data center segment with a view toward eventual monetization are well-served by building institutional financing track records beginning with their first deal in this market. The buyers who pay full value for storage platforms want operating history, documented compliance, and contracted revenue. The time to build that foundation is at the beginning of the platform, not after several transactions have closed without it.
VII. Technology Trends That Affect Agreement Structure
The battery technology stack is evolving fast enough that agreements drafted without flexibility may be commercially disadvantaged well before their expiration dates, and the technology choices being made today have direct implications for FEOC compliance and long-term contract performance.
The industry is moving toward greater technology diversity, with longer-duration storage shifting from a niche solution to a strategic necessity as AI-driven load growth continues. Two developments in particular deserve attention from parties structuring BESS agreements for data center applications.
Silicon-anode batteries are emerging as the performance answer to AI’s specific power demand profile. The near-instantaneous power response required by AI-enabled servers overwhelms traditional lithium-ion technology, and silicon-anode cells’ extreme fast-discharge capability directly addresses this constraint. Supply agreements that lock operators into lithium-ion specifications for 10- to 15-year terms may benefit from technology substitution rights: explicit provisions allowing migration to superior chemistries as they reach commercial scale, without requiring full renegotiation of the underlying agreement. Regardless of chemistry, all BESS assets degrade over time, and agreements with long-term capacity guarantees should include augmentation provisions that specify the timing, cost allocation, and performance testing protocols for capacity replenishment, particularly where the BESS supports uptime commitments that do not tolerate degradation-driven shortfalls.
Sodium-ion alternatives address both the performance question and the FEOC compliance problem simultaneously. FEOC regulations and global mineral pressures are driving renewed interest in non-lithium, FEOC-safe chemistries, and sodium-ion batteries avoid the Chinese-dominated lithium and cobalt supply chains that make MACR compliance difficult. Chemistry-agnostic procurement specifications (rather than lithium-specific technical requirements) reduce FEOC risk, preserve access to a broader and improving supplier base, and give operators the flexibility to benefit from cost declines in alternative chemistries as they mature.
VII. Considerations for Developers, Operators, Lenders & Battery Companies
Several issues are worth addressing actively rather than allowing to accumulate.
- Existing BESS supply agreements merit review for tariff pass-through provisions, force majeure coverage, and PFE representations, particularly those executed before July 2025 when the OBBBA took effect;
- Modeling MACR exposure before signing new procurement contracts is advisable, given that the 55 percent threshold for 2026 facilities is the floor and the path to 75 percent by 2030 means today’s sourcing decisions carry consequences through the decade;
- The FERC large-load interconnection rulemaking appears to be moving forward, with final action expected as early as April 30, 2026, and agreements now being negotiated may benefit from provisions that contemplate a range of transmission cost allocation outcomes;
- Requiring component-level supply chain disclosure in procurement agreements, rather than entity-level certifications alone, provides substantially more durable FEOC compliance protection;
- Credit purchase agreements under IRC Section 6418 transfer elections warrant the same PFE-related recapture allocation as the underlying supply agreements, particularly where the credit buyer has not independently verified the project’s MACR compliance;
- BESS agreements supporting hourly carbon-free energy commitments should address the tension between time-granular delivery obligations and ancillary services availability, because dispatch profiles for hourly matching differ materially from those optimized for merchant revenue;
- Operators pairing data centers with dedicated on-site generation should expect BESS contract structures that integrate storage into the generation facility’s operating agreement rather than treating it as a standalone procurement, with performance guarantees tied to generation availability; and
- Battery companies building data center market presence are well-served by investing early in the commercial infrastructure this customer segment requires, including tailored offtake structures, AI-workload performance guarantees, and FEOC documentation protocols ready at signing, rather than adapting utility-market contracts after the customer conversation has already begun.
VIII. Conclusion
Battery storage for data centers has become a project finance, regulatory compliance, and supply chain management challenge as much as it is a procurement decision, and the FEOC rules, the FERC interconnection rulemaking, the tariff-driven cost increases, and the shifting technology stack have made this a more complex environment than it was 18 months ago. With 24 GW of new capacity expected in 2026 alone and major project financings closing at a pace that would have been difficult to imagine even two years ago, the opportunity for well-positioned developers, operators, and their advisors to establish durable competitive advantages in this segment has never been larger, or more time-sensitive.
This alert is intended to provide a general overview of the financing, regulatory, and structuring considerations relevant to battery storage for data center applications. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.
RJ Colwell is a senior associate at Davis Graham & Stubbs LLP in the Energy & Mining Group. His practice focuses on the intersection of battery storage, data center infrastructure, and energy regulatory compliance, advising data center developers, power generation companies, battery storage companies, and their investors and lenders on transaction structuring and regulatory matters. For questions about the above article or data center considerations, please contact RJ Colwell or a member of the Davis Graham Data Center Group .