Interview: practitioners on Infrastructure finance (transmission, storage, water) — what they wish they knew earlier

The United States requires an estimated $2.6 trillion in infrastructure investment through 2030 to meet its clean energy targets, yet the interconnection queue backlog alone has swelled to over 2,600 GW of pending projects—twice the current installed capacity of the entire US grid. Behind these staggering figures are practitioners navigating the complex intersection of transmission buildouts, energy storage deployments, and water infrastructure modernization. We spoke with project finance veterans, grid operators, and infrastructure fund managers to distill what they wish they had known before entering this rapidly evolving sector.

Why It Matters

Infrastructure finance for transmission, storage, and water represents the foundational layer upon which the entire clean energy transition depends. Without adequate transmission capacity, renewable generation remains stranded. Without storage solutions, grid reliability becomes increasingly precarious as variable resources grow. Without resilient water infrastructure, both conventional and alternative power generation face operational constraints.

The scale of the challenge has intensified dramatically. According to the Department of Energy's 2024 National Transmission Needs Study, the US requires a 57% expansion of transmission capacity by 2035 to accommodate planned renewable deployments. Battery energy storage system (BESS) installations reached 16.5 GW of new capacity in 2024, a 62% increase over the previous year, yet this represents only a fraction of the 680 GW the National Renewable Energy Laboratory projects will be needed by 2050. Meanwhile, the American Society of Civil Engineers estimates that the nation's drinking water infrastructure faces a $434 billion funding gap over the next 20 years.

The practitioners we interviewed emphasized that understanding duration requirements, asset degradation curves, revenue stacking opportunities, and grid integration complexities separates successful projects from expensive failures. "The financing structures that worked for conventional infrastructure simply don't translate," noted one project finance director at a major utility-scale developer. "You're dealing with technology that degrades in ways we didn't fully appreciate, revenue streams that require constant optimization, and interconnection timelines that can make or break your entire investment thesis."

Key Concepts

Infrastructure Finance refers to the specialized discipline of structuring capital for large-scale, long-lived physical assets. In the context of transmission, storage, and water, this typically involves project finance structures where debt and equity are secured against project cash flows rather than sponsor balance sheets. The capital-intensive nature of these projects—often exceeding $500 million for utility-scale deployments—requires sophisticated modeling of construction risk, operational performance, and revenue certainty over 20-30 year horizons.

Risk Transfer mechanisms are essential in infrastructure finance, distributing various project risks among parties best positioned to manage them. Engineering, procurement, and construction (EPC) contractors typically assume construction risk through fixed-price contracts, while offtakers absorb market price risk through long-term power purchase agreements (PPAs). In storage and transmission projects, practitioners increasingly utilize availability-based payment structures that transfer technology performance risk to equipment suppliers through warranty and performance guarantee arrangements.

Scenario Analysis has become indispensable given the uncertainties surrounding regulatory evolution, technology cost trajectories, and electricity market design. Practitioners run Monte Carlo simulations across hundreds of variables—capacity factors, degradation rates, ancillary service pricing, and interconnection delay probabilities—to stress-test project economics. The 2025 vintage of infrastructure funds now routinely models scenarios where the Inflation Reduction Act's tax credits phase down earlier than scheduled or where wholesale market prices diverge significantly from forward curves.

CAPEX (Capital Expenditure) represents the upfront investment required to construct infrastructure assets. For battery storage projects, CAPEX has declined approximately 77% since 2015, reaching roughly $286/kWh for 4-hour duration systems in 2024. Transmission projects face different dynamics, with per-mile costs ranging from $1.5 million for single-circuit lines to over $10 million for high-voltage direct current (HVDC) installations. Understanding CAPEX allocation across equipment, labor, land, and interconnection costs proves critical for accurate project budgeting.

OPEX (Operating Expenditure) encompasses ongoing costs throughout an asset's operational life. For storage systems, OPEX includes augmentation costs to maintain capacity as cells degrade, typically requiring 15-20% capacity additions over a 20-year project life. Water infrastructure OPEX increasingly reflects energy costs for pumping and treatment, which can constitute 30-40% of a municipal water utility's operating budget. Practitioners emphasize that OPEX underestimation remains one of the most common causes of project underperformance.

Transition Plan refers to the strategic roadmap by which asset owners and financiers navigate the shift from fossil fuel-based systems to clean energy infrastructure. Effective transition plans address workforce retraining, community engagement, stranded asset risks, and the sequencing of capital deployment across complementary technologies.

What's Working and What Isn't

What's Working

Merchant storage paired with contracted revenue floors has emerged as a viable financing structure. Projects securing 40-60% of projected revenues through tolling agreements or capacity contracts while retaining upside exposure to volatile ancillary services markets have attracted institutional capital. "We closed a 400 MWh project in Texas last year with a 15-year tolling agreement covering 55% of nameplate capacity," shared a senior vice president at an infrastructure-focused private equity firm. "The contracted floor gave our debt providers comfort, while the merchant tail gives us IRR enhancement potential."

Standardized interconnection study processes implemented by certain Independent System Operators (ISOs) have reduced queue attrition rates. MISO's revised interconnection procedures, effective since 2024, introduced cluster study windows and increased study deposits, resulting in a 35% reduction in speculative project submissions and faster progression for shovel-ready developments.

Municipal green bonds for water infrastructure have achieved spreads competitive with general obligation issuances while attracting ESG-mandated investors. The Los Angeles Department of Water and Power's $500 million green bond issuance in 2024 priced at just 8 basis points above comparable municipal credits, demonstrating that the sustainable finance premium has effectively compressed to near-zero for high-quality issuers.

Hybrid renewable-plus-storage configurations have simplified offtake negotiations by delivering shaped power products that more closely match load profiles. Utilities increasingly prefer these bundled contracts, which reduce basis risk and provide dispatchable capacity value without requiring separate procurement processes.

What Isn't Working

Duration uncertainty in long-duration storage continues to challenge financing. Projects proposing 8-hour or longer discharge durations struggle to secure project finance debt because performance track records remain limited. "Lenders want five years of operating data from comparable installations before they'll underwrite 15-year debt," explained a managing director at a development finance institution. "For technologies like iron-air or flow batteries, that data simply doesn't exist yet."

Transmission cost allocation disputes between states have stalled regional backbone projects. The absence of federal siting authority and the complexity of allocating costs among multiple benefiting regions have delayed high-priority lines by 5-7 years. The Grain Belt Express, first proposed in 2010, only secured its final state approval in 2024 after protracted regulatory proceedings across four states.

Degradation modeling gaps have resulted in storage asset underperformance. Early-vintage lithium-ion projects underestimated calendar aging effects, particularly in high-ambient-temperature environments. Several projects in Arizona and Nevada have required augmentation capex 3-4 years ahead of schedule, eroding sponsor returns and straining reserve accounts.

Revenue stacking complexity in wholesale markets creates operational and contractual challenges. Storage assets seeking to capture value across energy arbitrage, frequency regulation, spinning reserves, and capacity markets face participation rules that vary by ISO and change frequently. "We spent 18 months negotiating contract provisions for a 200 MW project only to have FERC Order 2222 implementation fundamentally alter the value proposition," noted an asset manager.

Key Players

Established Leaders

NextEra Energy operates the largest portfolio of renewables and storage in North America, with over 31 GW of operating capacity and a development pipeline exceeding 60 GW. Their infrastructure financing arm has pioneered yieldco structures and maintains investment-grade credit ratings that enable sub-5% cost of debt.

Berkshire Hathaway Energy owns extensive transmission assets across the western United States through PacifiCorp and NV Energy, with ongoing investments exceeding $3 billion annually in grid modernization and renewable integration infrastructure.

American Water Works Company serves as the largest publicly traded water and wastewater utility in the United States, providing regulated services to approximately 14 million people across 14 states. Their capital deployment of $2.8 billion in 2024 focused heavily on infrastructure replacement and resiliency improvements.

Fluence Energy emerged from a joint venture between Siemens and AES to become a leading storage technology provider, with over 14 GWh of deployed or contracted capacity globally. Their service agreements and digital applications support the operational optimization that lenders require.

Pattern Energy specializes in transmission development through its subsidiary Pattern Transmission, having successfully completed the 350-mile Western Spirit transmission line in New Mexico that enabled 1,050 MW of wind capacity to reach load centers.

Emerging Startups

Form Energy has secured over $800 million in venture and project capital for its iron-air battery technology, which promises 100-hour duration storage at costs <$20/kWh capacity—potentially transforming the economics of multi-day reliability solutions.

GridUnity provides interconnection management software that automates study processes and reduces interconnection timelines by 30-40%, addressing a critical bottleneck that practitioners consistently cite as their primary frustration.

Crusoe Energy converts stranded natural gas and flared resources into computational power, demonstrating innovative infrastructure finance approaches that monetize otherwise wasted energy assets.

Xylem Inc.'s emerging digital business develops AI-powered water network optimization tools, reducing non-revenue water losses by 15-25% and enabling utilities to defer capital-intensive pipe replacement projects.

LineVision deploys dynamic line rating sensors that increase transmission capacity on existing infrastructure by 10-40%, offering a cost-effective bridge while new transmission lines navigate permitting processes.

Key Investors & Funders

BlackRock's Global Infrastructure Partners manages over $100 billion in infrastructure assets, with significant allocations to energy transition investments including transmission development companies and storage platforms.

Brookfield Asset Management has deployed over $40 billion into renewable power and transition assets globally, maintaining dedicated funds for battery storage development and transmission co-investment.

Generate Capital focuses exclusively on sustainable infrastructure, having deployed over $8 billion in capital to projects including water treatment, distributed energy, and industrial decarbonization assets.

The DOE Loan Programs Office provides critical financing for first-of-kind infrastructure, with over $40 billion in active lending authority following the Inflation Reduction Act's expansion. Their recent $9.2 billion conditional commitment to BlueOval SK's battery manufacturing facilities exemplifies their catalytic role.

Clean Energy Infrastructure (CEIA) is a consortium backed by JPMorgan, Bank of America, Citi, Morgan Stanley, and Wells Fargo, committing to facilitate $1 trillion in clean energy financing by 2030 with specific allocations for transmission and storage.

Examples

1. Sunrise Wind Transmission Interconnection (New York): This 924 MW offshore wind project required a $700 million transmission investment to connect generation to the Long Island grid. The financing structure combined New York Green Bank subordinated debt with senior project finance from international development banks. Notably, the project secured a 25-year offtake agreement with LIPA that included escalators linked to both inflation indices and transmission delivery performance metrics. The 84-mile submarine cable route achieved regulatory approval in 28 months—faster than comparable Atlantic coast projects—by front-loading stakeholder engagement and conducting voluntary environmental assessments beyond regulatory requirements.

2. Edwards Aquifer Habitat Conservation Plan (Texas): This $478 million water infrastructure program, implemented across 15 years, demonstrates integrated infrastructure financing for combined conservation and supply purposes. The program utilized Environmental Impact Bond structures where investor returns are partially contingent on measurable improvements in endangered species populations and aquifer levels. Municipal participants reduced per-capita water consumption by 42% through infrastructure investments in leak detection, smart meters, and demand management, ultimately deferring $1.2 billion in alternative supply development costs. The innovative risk-sharing structure attracted ESG-focused institutional investors who previously avoided water sector exposure.

3. Moss Landing Battery Energy Storage (California): Vistra Energy's 750 MW/3,000 MWh facility in Monterey County represents the world's largest battery storage installation. The $1.1 billion project secured a 10-year resource adequacy contract with PG&E providing revenue certainty for approximately 70% of capacity, while the remaining capacity participates in CAISO's ancillary services markets. Despite experiencing thermal events requiring safety modifications, the project demonstrated successful revenue stacking: in Q3 2024, the facility generated $38 million in revenue across capacity payments ($22 million), energy arbitrage ($11 million), and ancillary services ($5 million). The project's degradation curve has tracked better than P50 projections, requiring only 8% capacity augmentation in year four versus the initially modeled 12%.

Action Checklist

• Conduct detailed degradation curve analysis using manufacturer data, independent engineering assessments, and comparable operating project performance—assume conservative scenarios in base case financial models
• Secure interconnection queue positions early and budget 18-36 months longer than ISO-published timelines for study completion and system upgrade construction
• Structure revenue contracts to ensure 50-60% contracted cash flows while preserving merchant upside through capacity set-asides or revenue sharing mechanisms
• Engage specialized insurance providers for technology performance wrap coverage that can substitute for limited track record data in lender credit analysis
• Build augmentation reserves sufficient for 20-25% capacity additions over the project life, funding these reserves from operating cash flow rather than relying on refinancing
• Develop multiple grid services revenue streams—avoid over-reliance on any single market product given regulatory uncertainty around market design evolution
• Commission independent transmission studies that identify curtailment risks and basis differentials before finalizing site selection for generation or storage assets
• Establish community benefit agreements and local hiring commitments early in development to build political support and reduce permitting timeline risks
• Model scenario sensitivity across at least five key variables: interest rates, equipment costs, degradation rates, capacity factor, and wholesale price forecasts
• Engage with utility offtakers 18-24 months before commercial operation to align on metering protocols, dispatch procedures, and performance testing standards

FAQ

Q: How do practitioners approach the trade-off between longer-duration storage and financing availability? A: Experienced practitioners recommend a staged approach. Initial project phases utilize 4-hour lithium-ion systems with established financing pathways, while reserving interconnection capacity and land rights for longer-duration additions once technology matures. Several developers are structuring "accordion" facilities where foundations, switchgear, and grid connections are sized for ultimate buildout but initial deployment uses bankable technology. This preserves optionality while maintaining sponsor returns on committed capital.

Q: What revenue stacking strategies are proving most effective in current wholesale markets? A: The most successful projects combine a capacity contract (providing 40-50% of revenue with high certainty), energy arbitrage participation (contributing 25-35% with moderate variability), and ancillary services optimization (adding 15-25% with higher volatility but meaningful upside). Critical success factors include sophisticated bidding algorithms that forecast day-ahead and real-time price spreads, the ability to switch between market products quickly, and maintenance scheduling that maximizes availability during high-value periods. Projects in ERCOT have benefited particularly from scarcity pricing events, though practitioners caution against building business cases around tail-risk revenue outcomes.

Q: How are water infrastructure projects accessing climate-focused capital pools? A: Municipal water utilities increasingly issue green bonds with use-of-proceeds restrictions tied to climate resilience and resource efficiency objectives. Rating agencies now incorporate climate risk assessments into credit analysis, creating incentive alignment between sustainability performance and borrowing costs. Private activity bonds for investor-owned water utilities have also expanded, with the IRS increasing the national volume cap in 2024. Environmental Impact Bonds with pay-for-success structures remain relatively nascent but are gaining traction for projects where outcomes can be clearly measured, such as stormwater management and non-revenue water reduction.

Q: What insurance and risk transfer mechanisms address technology performance concerns in storage projects? A: Technology performance insurance has matured significantly since 2022. Specialized insurers now offer production guarantee wraps that backstop manufacturer warranties, covering capacity degradation beyond specified curves and round-trip efficiency declines. Captive insurance structures allow developers to retain predictable degradation risk while transferring catastrophic performance failure to the insurance market. Lenders typically require sponsors to maintain degradation insurance for at least 80% of the warranty period, with coverage limits equal to augmentation capex requirements. Premium costs have declined from 2-3% of project value in 2020 to 0.8-1.2% for well-structured transactions with tier-one equipment suppliers.

Q: How do transmission development timelines compare across different regulatory jurisdictions in the US? A: Regional variation remains substantial. Projects within single ISO footprints and single-state jurisdictions typically achieve energization within 5-7 years from initial development activities. Multi-state projects requiring coordinated approvals routinely exceed 10 years. FERC's proposed backstop siting authority under Order 1920 may eventually reduce interstate coordination challenges, though implementation remains uncertain. Practitioners recommend securing state-level permits in parallel rather than sequentially, utilizing existing rights-of-way wherever possible, and engaging affected communities through formal benefit-sharing mechanisms rather than relying solely on regulatory proceedings.

Sources

• U.S. Department of Energy. "National Transmission Needs Study." October 2024.
• Lawrence Berkeley National Laboratory. "Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection." April 2025.
• National Renewable Energy Laboratory. "Storage Futures Study: Key Learnings for the Coming Decades." 2024 Update.
• American Society of Civil Engineers. "2025 Report Card for America's Infrastructure: Drinking Water."
• BloombergNEF. "Energy Storage System Costs Survey 2024."
• Federal Energy Regulatory Commission. "Order No. 1920: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation." May 2024.
• Wood Mackenzie. "US Energy Storage Monitor Q4 2024."
• S&P Global Ratings. "ESG Industry Report Card: Water Utilities." November 2024.