Christopher Hailstone has spent his career at the intersection of energy management, renewables, and grid operations, so he brings a practical lens to the post-OBBBA moment. LevelTen’s survey shows an enormous U.S. pipeline and a clear pivot toward storage and hybrids, and Christopher unpacks how policy certainty for standalone storage, buyer demand for clean firm capacity, and developer confidence in lithium-ion are reshaping capital stacks, offtake structures, and interconnection strategies. We talk through how teams are locking in tax credit eligibility, why hyperscalers are still cautious about owning batteries, how hybrid and co-located designs are being metered and contracted, and what it would take for storage to become part of data center reliability. He also shares the gritty details—from commissioning playbooks and BMS tuning to ancillary revenue stacks and congestion risk—showing how developers are adapting quickly rather than slowing down.
LevelTen’s survey shows 233 GW in U.S. developer pipelines. How is that capacity split today across wind, solar, storage, and hybrids, and how do you expect that mix to shift by 2030? Please share specific project counts, MW shares, and any regional differences you’re seeing.
The headline is that the 233 GW pipeline is real and diverse, but I’m going to stay within publicly referenced numbers and not break out project counts beyond that. What I can say is that the center of gravity is moving toward storage and hybrids as we approach 2030, reflecting both market signals and policy continuity for standalone storage. In regions with steep evening ramps and curtailment—think sunny corridors with congestion—solar-plus-storage and wind-plus-storage gain share because they turn stranded MWh into deliverable capacity. We expect that by the end of the decade, the balance tilts meaningfully toward hybrids and standalone storage, consistent with LevelTen’s finding that these could overtake standalone wind and solar.
Developers plan to complete 42.8 GW of wind and solar before 2028, with 33 GW expected to qualify for tax credits. What criteria are pushing projects into that 33 GW bucket, and what practical steps are teams taking this year to secure safe harbor and construction milestones?
The projects landing in that 33 GW bucket are the ones with line-of-sight on equipment procurement and construction start definitions that meet the law’s tests. Teams are prioritizing irrevocable equipment deposits and tangible work like site grading to substantiate beginning of construction, then documenting continuous efforts through EPC mobilization and delivery schedules. We’ve found that granular documentation—down to bill of lading, site photos, and contractor logs—can be the difference between a clean audit trail and a scramble. This year is all about sequencing: lock site control, lock interconnection steps, lock major equipment, and keep a steady cadence of activity to avoid any gap in continuity.
OBBBA accelerates the phase-out of some tax credits, yet standalone storage credits continue. How has that changed your capital stack, bid strategy, and risk allocation for batteries versus new wind and solar? Please give examples with hurdle rates, PPA pricing adjustments, and financing timelines.
Continuity for standalone storage lets us underwrite batteries with more confidence on policy risk, which translates to tighter financing timelines and a more competitive bid posture. We lean into storage where we can monetize firming and grid services, while treating new wind and solar bids more selectively, particularly where curtailment erodes the merchant tail. On risk allocation, batteries shoulder more merchant exposure because their revenue streams are flexible across energy, capacity, and ancillary markets; we pair that with conservative contract provisions rather than try to force-fit a flat energy price. The net effect is we can commit earlier on storage and hybrids, while pacing pure generation to projects that can clear milestones fast enough to stay within the favorable credit window.
LevelTen says storage and hybrids could overtake standalone wind and solar by 2030. What specific grid and market signals are driving that pivot in your pipeline, and how do you measure the value of shifting MWh—peak/off-peak spreads, ancillary services, or capacity revenues—project by project?
We’re seeing widening peak/off-peak spreads, higher penalties for non-delivery in shaped products, and growing emphasis on capacity accreditation by buyers. Project by project, we run stacked value simulations: day-ahead/real-time arbitrage, capacity revenues calibrated to accreditation rules, and ancillary services where interconnection and telemetry qualify. We also evaluate congestion relief and curtailment mitigation—if storage can turn clipped or curtailed energy into evening delivery, that often drives the decision. It’s less about any single product and more about how dispatch can pivot among them as market conditions shift.
Rob Collier mentioned buyers want clean firm capacity. How are you modeling “firming” value for a 4-hour battery paired with solar versus an 8-hour solution or hybrids with wind? Please walk through your dispatch assumptions, penalty risk, and real contract examples that reward deliverability.
For a 4-hour solar-plus-storage, we assume afternoon charging from on-site solar and evening discharge targeting shaped commitments; we model state-of-charge headroom for contingencies and degradation. With 8 hours or wind hybrids, we expand the deliverability window and reduce penalty exposure during extended ramps or overcast intervals, which improves contractability for evening blocks. Penalties are modeled as tail risks tied to forecast error and forced outages, so we hold reserve margins in the battery during tight days to avoid liquidated damages. Contracts that explicitly reward evening delivery—via premium adders or indexed shapes—are where 4-hour can pencil, but 8-hour or wind hybrids provide more resilience against multi-hour weather events.
Vaughn Morrison noted developers are more comfortable with lithium-ion. What technical or procurement milestones got you there—cycle life data, fire safety practices, or bankability terms? Share a recent commissioning playbook, from factory acceptance testing to BMS tuning and first-year performance guarantees.
Confidence came from repeatable factory acceptance testing, rigorous containerized fire safety design, and stronger warranty language around capacity retention and availability. Our commissioning playbook starts with FAT witness testing, then site-level pre-energization checks, staged energization by container, and BMS tuning with thermal and SOC calibration under controlled charge/discharge ramps. We run grid-tied performance tests to validate round-trip efficiency and response times for ancillary qualification, followed by a probationary operating period with enhanced monitoring. First-year guarantees focus on availability and minimum capacity, with clear remediation timelines and spare parts logistics agreed upfront.
You can’t apply storage tax credits to a wind or solar project just by adding batteries. How do you structure hybrid sites so each asset optimizes its own incentives and revenues? Please detail metering boundaries, interconnection rights, and contract allocations between energy, capacity, and ancillary markets.
We design hybrids as co-optimized but distinct assets behind a shared point of interconnection, with clear metering boundaries for generation and storage. The storage system has its own telemetry, market registration, and charge source logic so it can qualify for its standalone treatment while avoiding cross-subsidization that confuses credit eligibility. Interconnection rights are allocated via an internal operating protocol that defines priority during constraints and sets rules for grid charging if allowed. On contracts, we often place the generator under a PPA and allocate storage to capacity and ancillary products or a tolling construct, with dispatch rights and settlement priorities spelled out in the operating agreement.
Developers are splitting offtake—PPAs for generation and merchant/tolling for storage. How do you align these with lender requirements and basis risk? Give a concrete example of a two-counterparty hybrid: tenor lengths, credit spreads, curtailment clauses, and who controls dispatch.
Lenders want clarity on dispatch rights and settlement waterfalls, so we lock down a priority of revenues and define who curtails what and when. In a two-counterparty hybrid, the generator sells under a long-tenor PPA while the battery operates under a tolling or merchant framework, with the storage counterparty holding operational dispatch during contracted hours. Curtailment clauses distinguish grid-driven versus economic curtailment, and basis exposure is managed with site-specific settlement points and conservative loss factors. The throughline is alignment: the PPA offtaker gets predictable delivery, the storage counterparty gets control when it matters, and lenders get transparent cash-flow allocation.
Hyperscalers are chasing new renewables but haven’t shown much interest in owning storage. What’s blocking them—accounting treatment, technology risk, or operational complexity? Describe a recent RFP from a hyperscaler, the storage options you proposed, and why they picked (or rejected) each.
The big obstacles are operational complexity and owning performance risk for an asset that behaves more like a flexible plant than a passive contract. In a recent RFP, the buyer explicitly sought clean energy and time-specific delivery attributes but preferred not to own or dispatch storage. We proposed a pure PPA, a PPA plus a tolling option where we held operational risk, and a structured product with evening delivery premiums sourced from co-located storage. They selected the PPA plus structured evening delivery because it simplified accounting and kept technology risk with us, while still meeting their hourly matching goals.
“If storage became part of data center reliability, development could surge.” What would it take to get there—grid-interactive UPS, black start capabilities, or utility tariff changes? Please share a step-by-step roadmap for a pilot at a 100 MW data center, including SLAs and test protocols.
Step one is a grid-interactive UPS architecture that can coordinate with a front-of-the-meter battery and on-site renewables. Step two is defining SLAs around ride-through, black start capability, and maximum transfer times, with monthly test protocols that simulate grid events and verify response. Step three is tariff or interconnection provisions that allow limited grid services without jeopardizing reliability, paired with contractual carve-outs prioritizing the data center during contingencies. We’d run phased trials—control room drills, load transition tests, and scheduled dispatch windows—so the battery graduates from pure backup to a dual-role asset that still meets strict reliability targets.
As 2029–2030 construction plans come into focus, how are you deciding which projects can still qualify for credits? Walk me through your gating process—equipment deposits, site control, interconnection milestones, and EPC mobilization—and the trigger metrics you monitor monthly.
We run a monthly gating checklist that starts with site control certainty and environmental permits, then moves to interconnection milestones with dated deliverables. We require executed equipment purchase steps and documented construction activities to substantiate beginning of construction, plus EPC mobilization plans with resource calendars. Each month we track slippage risk, vendor lead times, and any prerequisite utility actions to keep the continuity narrative intact. Projects that can’t maintain those beats are paused or reconfigured so we don’t compromise eligibility for the rest of the portfolio.
How are you valuing hybrids versus co-located-but-separate assets at the same point of interconnection? Compare CAPEX, O&M, clipping capture, and grid upgrade costs. Please include one case where co-location beat true hybridization on NPV, and one where hybridization won on revenues.
Co-located-but-separate can win on NPV when shared interconnection and site costs are captured without forcing operational coupling that limits market options. We had a case where separating assets let the battery qualify cleanly for its own products while the solar PPA avoided constraints; the result was stronger cash flows due to flexibility. Conversely, true hybridization can win when clipping capture and curtailment mitigation meaningfully increase sellable MWh during premium hours, and when a single control system unlocks efficiency. The deciding factors are interconnection constraints, expected curtailment, and the value of evening delivery—operational optionality versus tighter integration.
With lithium-ion dominating, where do longer-duration chemistries fit in your pipeline? Give an example where 4-hour LFP pencils out, and another where you need 8–12 hours. Include your sensitivity ranges for capex $/kWh, round-trip efficiency, and capacity accreditation.
Four-hour LFP pencils where evening peaks are sharp and predictable, where solar charging is abundant, and where contracts reward those specific hours. We look to 8–12 hours when the market needs extended coverage—long shoulder ramps, multi-hour reliability events, or capacity rules that favor longer duration. Our sensitivities focus on round-trip efficiency and accreditation curves; longer duration at lower efficiency can still win if deliverability premiums are high and penalties are steep. The takeaway is duration follows the product: fit the battery to the contract and grid need, not the other way around.
Utilities and corporate buyers want time-specific delivery. How are PPAs evolving—hourly matching, shaped products, or indexed adders? Share an example contract that rewards evening delivery, the settlement math behind it, and how your storage dispatch algorithm meets those targets.
We’re seeing more shaped products and indexed adders that step up value in evening hours to reflect real system needs. A representative contract pays a premium for delivery in predefined evening blocks, netting down if volumes fall short and crediting overperformance within caps. Our dispatch algorithm prioritizes charging during low-value periods, maintains a reserve buffer, and targets the premium windows while minimizing imbalance risk. The math is transparent to buyers and lenders, and it aligns incentives with grid reliability.
OBBBA pushed developers to adapt quickly rather than slow down. What internal changes have you made—procurement playbooks, hedge policies, or interconnection triage—to move faster? Please provide before-and-after metrics on cycle times, hit rates, and cost of capital.
We standardized procurement with pre-negotiated terms and a tiered vendor bench, and we built an interconnection triage that screens projects for curtailment and upgrade exposure early. Hedge policies now emphasize flexibility so storage can pivot revenue stacks without breaching covenants. While I won’t publish proprietary metrics, the directional shift is clear: faster bid-to-NTP cycles, higher conversion on shortlisted deals, and improved financing confidence where storage underpins deliverability. The common thread is speed with discipline—repeatable processes that auditors and lenders can follow.
Ancillary services can be critical for storage economics. Which products—frequency regulation, spinning reserve, or voltage support—are most bankable in your markets? Describe one project’s revenue stack month by month, and how you manage saturation risk as more batteries come online.
Bankability depends on qualification and market depth; frequency regulation and spinning reserve tend to be the most creditworthy where rules and telemetry are clear. Our project stacks energy arbitrage with capacity and ancillary services, shifting monthly weights as spreads and participation caps change. To manage saturation risk, we cap ancillary revenue in base cases and ensure the strategy can pivot to evening energy delivery and capacity when markets fill up. It’s a living stack, and lenders appreciate that we model downside pathways, not just upside.
Interconnection remains a bottleneck. How do storage and hybrids help you navigate queue constraints—limited injection rights, grid charging provisions, or flexible operating profiles? Share a real example of reducing upgrades through storage sizing or curtailment strategies, with MW limits and costs saved.
Storage helps by shaping injections to match available headroom and by absorbing energy that would otherwise trigger upgrades. We negotiate operating envelopes and curtailment provisions so the site can stay within limits during peak congestion, and we size batteries to shift output off-peak. Grid charging, where allowed, adds another lever to manage injections while creating additional dispatch options. The payoff is fewer upgrade triggers and a cleaner path to COD, which keeps overall project economics intact.
For merchant or tolling storage deals, how do you manage price volatility exposure? Walk through your hedging toolkit—basis swaps, resource adequacy contracts, or collars—and provide a concrete P&L scenario from a recent high-price month and a low-price month.
We manage volatility with a blend of resource adequacy commitments, selective basis hedges tied to the project’s settlement node, and options structures that cap downside while preserving upside. In high-price months, we bias toward energy and ancillary markets; in low-price months, RA and contracted tolling hours carry the day. Position sizing is conservative so we don’t overcommit the battery during periods when spreads collapse. The result is a smoother cash flow profile that lenders can underwrite without relying on heroic market conditions.
What are the most common pitfalls you see when developers add storage to existing wind or solar—control integration, warranty conflicts, or revenue metering? Tell a story of a project that stumbled and how you fixed it, including timeline, vendor changes, and cost impacts.
Control integration is often underestimated—misaligned inverter and BMS commands can create oscillations and availability hits. We encountered a retrofit where revenue metering didn’t separate storage charging sources cleanly, creating credit and settlement ambiguity. The fix involved re-scoping metering, updating the control interface, and realigning warranties so each OEM stood behind their part; it cost us schedule but saved the project’s long-term economics. The lesson: define metering and controls first, then build contracts around those physical realities.
Looking beyond 2030, where do you see the biggest upside—hybrid repowering, DC-coupled retrofits, or virtual hybrids across nodes? Please outline one three-year plan with target MW, expected IRR ranges, and the policy or market rules that make it viable.
The biggest upside is in hybrid repowering and retrofits that capture clipping and convert curtailment into deliverable evening energy, plus virtual hybrids that optimize across constrained nodes. Over the next three years, we’re focusing on projects that pair proven generation with storage sized to the interconnection, leveraging market rules that reward time-specific delivery. Policy certainty for standalone storage and buyer demand for clean firm capacity underpin the thesis. The approach is pragmatic: upgrade where it unlocks deliverability, and contract where the market pays for it.
Do you have any advice for our readers?
Focus on deliverability and documentation. Design your projects so each asset stands on its own from a metering, dispatch, and credit perspective, and keep meticulous records to back tax credit eligibility. Build flexibility into contracts so you can pivot revenue stacks as markets evolve, and don’t underestimate controls integration. Above all, move quickly but leave an audit trail—speed without discipline is just risk by another name.
