Market Views

Market View: Rebalanced Ambitions – Scarcity, Structure, and the Maturation of REC Markets

Noreva’s Q4 2025 REC modeling captures a market moving from growth to governance, one where ambition gives way to realism and scarcity yields to structure.

Across PJM, NEPOOL, and California, the latest refresh shows tighter fundamentals, smoother long-run equilibria, and a clear signal that environmental markets are entering a more disciplined phase.

After years of exuberant renewable buildout forecasts, the data now tells a more grounded story shaped by permitting complexity, capital discipline, and the return of coordinated resource planning.

Noreva’s cross-commodity modeling captures this shift from momentum to management.

The New Shape of Equilibrium

The One Big Beautiful Bill Act (O3BA) continues to cast a long shadow on renewable deployment. Rising project costs, slower permitting, and constrained interconnection pipelines have delayed capacity additions, tightening near-term certificate supply even as long-term fundamentals begin to balance out.

This transition has produced a market that is less about volatility and more about verification. Fewer speculative projects and more deliverable volumes now define the new normal. Noreva’s merchant curves reflect this stabilization through flatter amplitude and steadier price trajectories, signaling maturity rather than weakness.

PJM: Compression with Conviction

In PJM, updated modeling highlights diverging trends across the footprint. Virginia’s data-center corridor remains the engine of near-term load growth, with incremental spillover into neighboring Maryland zones. Pennsylvania, by contrast, anchors the system through its scale, with large, diversified load pockets such as PPL, PENELEC, and APS continuing to set the tone for regional equilibrium.

On the supply side, realism prevails. Offshore wind remains sidelined amid PPA and permitting uncertainty, while novel technologies in Virginia provide modest near-term relief. Solar momentum continues, particularly across Dominion and AEP zones, though the O3BA framework introduces modest delays in project realization.

The result is a market finding its balance after recalibrating to new conditions. Across major Tier I markets, prices now peak in the early 2030s before easing as renewable buildout catches up with compliance demand. Virginia maintains its in-state premium due to sourcing constraints, while Pennsylvania’s depth of supply helps absorb volatility and anchor long-run stability. The broader region reflects a shift toward equilibrium, a market that is steadier and increasingly defined by structure rather than scarcity.

NEPOOL: Policy Fatigue Meets Gradual Balance

New England’s REC outlook is increasingly governed by policy fatigue and affordability pressure. Following Connecticut’s RPS freeze, Noreva’s low-case scenario assumes flat targets across Massachusetts, Maine, and Connecticut, reflecting a broader shift toward policy caution.

Offshore wind remains largely excluded from our assumptions due to ongoing permitting and cost uncertainty, with the exception of Vineyard Wind, which provides modest relief at the front of the curve. Incremental imports and stronger build rates across major Class I markets post O3BA permitting complexities ease compliance pressure, resulting in softer base-case trajectories through the 2030s. The high case, however, remains firm as stronger policy enforcement and slower renewable build sustain tighter balances, while the low case, which assumes flat RPS targets, shows more pronounced price declines.

The result is a region moving from scarcity to balance. Easing fundamentals now define the base and low cases, while the high case remains shaped by policy ambition and persistent supply friction.

California PCC1: The Era of Realism

California’s 25-year PCC1 forecast reflects a recalibration in development expectations. The CAISO interconnection queue has shrunk substantially, with active solar volumes down to about 22 gigawatts and wind now contributing less than one. The cancellation of Idaho’s Lava Ridge project and continued permitting delays underscore a constrained supply outlook.

Merchant PCC1 prices remain elevated through the 2030s before gradually easing as new capacity comes online. As RPS obligations level off, compliance growth slows, tempering demand expansion and contributing to the flattening seen toward the back of the curve. The result is a market that remains short and increasingly shaped by realism rather than ambition.

Market View: Recalibrated Realities – Dispatchable Dominance in SPP and MISO

Across both SPP and MISO, Noreva’s updated merchant curve modeling reveals the fastest thermal buildout in over a decade. 

Noreva’s latest capacity model refresh signals a decisive rebalancing across the Midcontinent and Southwest Power Pool (SPP), one that redefines scarcity, reshapes investor risk, and reestablishes dispatchable generation as the anchor of regional reliability.

Following months of headline optimism around renewable growth, the Q4 2025 update underscores a deeper structural truth: the next decade of capacity pricing will be defined not by constraint, but by coordination.

A Market in Recalibration

Natural gas queue volumes have expanded fivefold - from roughly 6 GW to 30 GW in SPP and 8 GW to 25 GW in MISO - while battery realization rates have been revised upward to 30%, reflecting the emergence of standardized, increasingly financeable storage assets.

The result is a structural shift toward dispatchable dominance, where firm resources are once again driving marginal capacity pricing. The supply stack is growing deeper and more deliverable, producing tangible downward pressure on forward curves.

This recalibration is not a sign of weakening fundamentals, but of maturing market logic. After years of scarcity-induced price inflation, capacity markets are rediscovering equilibrium.

Thermal Reawakening and Financing Realism

The return of gas-backed capacity is not simply a technology story; it’s a financing one. Over the past 18 months, developer pipelines have translated into bankable projects, aided by more liquid debt markets and widening lender comfort with merchant exposure.

Noreva’s model reflects this financing normalization, adjusting realization rates to mirror the shift from speculative queue volumes to actionable construction schedules. The revised supply outlook now incorporates a higher share of projects expected to achieve commercial operation.

At the same time, the growing track record of operational battery projects have transformed the storage sector from a “proof-of-concept” to a creditworthy capacity resource. Batteries are now increasingly financed on the strength of multi-revenue models - energy arbitrage, capacity payments, and ancillary services - flattening the cost of capital and reinforcing grid flexibility.

Diminishing Scarcity and the Compression of Returns

The higher-than-expected supply credibility has led to pronounced downward repricing of capacity curves across both ISOs. In SPP, summer equilibrium prices are now modeled at nearly 50% below prior expectations, before easing back to high single digits through the 2030s.

In MISO, forward trajectories have flattened as well, with the north summer curve down approximately $10/MW-day relative to Q2, while south and shoulder seasons exhibit tighter dispersion and reduced volatility.

For investors, this represents a critical pivot. Projects financed under assumptions of persistently high capacity prices may face contracting margins. While this compression narrows speculative upside, it also lowers volatility and potentially enhances credit quality.

Regulatory Friction and Long-Horizon Risk

Policy remains both an enabler and a constraint. The Noreva-devised 21.6% deployment reduction for selected renewables under the One Big Beautiful Bill Act (O3BA) introduces moderate tightening to capacity availability, but not nearly enough to offset the broader easing driven by thermal and storage supply growth.

Meanwhile, interconnection bottlenecks and permitting friction continue to delay project timelines, even under accelerated market constructs. Much of the capacity now entering the queue will not be online until late in the decade, underscoring the temporal disconnect between near-term demand and long-term infrastructure realization. Markets will need to navigate several more years of localized tightness before the full benefits of this rebalancing are felt.

Price Discovery in a Transitional Market

Taken together, the Q4 update captures a market in transition from scarcity to structure. As dispatchable buildout accelerates and financing frameworks mature, forward curves are stabilizing, a development that will reshape both trading strategies and long-term investment decisions.

The implications are significant. Players gain clearer visibility on downside protection. Developers face less uncertain project economics. And lenders can underwrite with greater confidence in asset durability and price stability.

For Noreva’s clients, these dynamics reinforce the importance of trade-aligned, model-driven price discovery. Noreva’s capacity modeling integrates real-time queue data, refined realization mechanics, and accreditation harmonization across ISOs, providing an analytical advantage ahead of broader market consensus.

Karbone Research - now Noreva - continues to deliver the market’s most forward-leaning view of capacity pricing and investment risk across North America.

Market View: Whiplash Refresh – A Groundbreaking Path for US Energy

Noreva's AI-enabled price forecasting models are signaling a significant shift in energy markets. 

This month's "Whiplash Refresh" report unveils a groundbreaking path for US energy, pointing to substantial changes in the coming months, years, and decades. 

Early indications from Noreva's proprietary modeling suggest that a yearlong boom in natural gas power projects and related infrastructure is moving beyond mere headline announcements and into physical and financial markets.

Noreva's fully updated models for Capacity, Fuels, and Renewable Energy Credits offer critical insights:

Relief May Be in Sight for Electricity Ratepayers and Stressed Power Markets: Power markets in the US have faced successive years of price inflation and upside volatility, in recent years increasingly due to surging capacity costs. 

Noreva's latest SPP and MISO capacity merchant curve updates reveal that the addition of significant new natural gas generation could trigger a sweeping reversal of this trend. 

This influx of gas-backed capacity is projected to stabilize price outlooks through 2050 across multiple scenarios, offering relief to electricity ratepayers and power markets. With high capacity prices baked into many financing assumptions, market participants may need to recalibrate their capital planning.

Better Battery Financing Means Better Baseload Generation: Utility-scale batteries are no longer a nascent technology in the US power mix; they are increasingly buffering the impact of demand swings and intermittent supply from solar and wind growth across every market. 

Historically, the limited operational history of batteries has posed challenges for infrastructure financing. 

However, Noreva's unique insights into battery financing economics, now incorporated into the latest merchant curve model updates, contribute to a counter-consensus forecast for a less volatile capacity market future. 

This indicates that improved financing mechanisms will enable batteries to play a more robust role in providing stable baseload generation even where they only shave the peaks and valleys..

Moving Electrons and Fuels Matters Most Across the US: While distributed energy often captures significant attention, addressing energy shortfalls at scale still necessitates the development of large infrastructure. 

The "revenge” of the hub and spoke model in 2025 underscores the need for more wires to carry electrons and more pipelines for carrying fuels, primarily natural gas. 

In regions heavily reliant on power or fuel imports, Noreva's models demonstrate a high correlation between energy attribute price inflation and import dependency over the coming decades. Regions with high import dependency like NEPool can expect higher prices for longer.

Price stability remains a function of infrastructure availability, a lesson US energy markets are learning all over again. 

Reversion Play: ESG Product Rebound Could Be in Sight: Clean energy attributes, such as voluntary renewable energy credits (RECs) - widely utilized by businesses to achieve their net-zero and sustainability goals - have undeniably experienced a challenging year. 

Prices have been battered amid a perceived breakdown of the "climate consensus" that was prevalent in the US corporate sector just a few years ago. 

However, Noreva's modeling indicates that these markets are now poised for a rebound. Fundamental demand linked to long-term outlooks and cross-cycle buying behavior suggests a reversion back into these products. 

Despite being sometimes tarred as "ESG," these attributes ultimately play a central role in long-term resource planning across decades, indicating a strong potential for recovery..

Karbone Research is now Noreva. Please continue to find all your data and pricing insight at karbone-hub.com 

Market View: The Three Big Risks at NAEMA

As the North American power industry prepares for the future, three interlocking risks – Timing Risk, System Risk, and Planning Risk – are emerging as decisive forces, reshaping price formation and market behavior outlooks for the coming decade.

The stakes are high for attendees at the North American Energy Marketers Association (NAEMA) meeting in Kansas City this week, where the mismatch between apparent and proven new demand for electrons across time horizons, geographies, and regulatory regimes is generating uncertainty in otherwise booming market conditions.

Noreva’s trade-aligned capacity models demonstrate the potential for material outcome dispersion as these risks take hold, with significant variance between once tightly-correlated low, base and high scenario runs.

Timing Risk in the North American energy markets, long associated with slow generation buildout, is increasingly defined by the pace at which new load demand – largely from data centers – comes online.

Generators rushing projects to completion and investors backing transmission development are leaning on novel contracting mechanisms to get projects financed, including asking hyperscalers to commit both cash and credit upfront.

For regulators, timing risk materializes when massive investment programs are cleared, only to have the spend distributed across a smaller-than-expected retail base already facing rising power bills.

This creates structural tension: the industry must accelerate infrastructure to meet projected needs yet avoid over-capitalizing capacity that may never be fully utilized.

System Risk is equally pressing, particularly around transmission infrastructure.

The rapid rise of intermittent, non-dispatchable resources such as wind and solar complicates real-time balancing, heightening reserve reliance, and making renewable integration more complex.

System operators with increasingly renewable-heavy portfolios must add new wires to balance the new fuel mix but finding transmission projects still challenging to build are clearing dispatchable gas units quickly instead.

These units, however, increasingly collide with pipeline constraints, compounding system risk as multiple overlapping interconnection requests from hyperscale load (to cover the same amount of anticipated compute end-use) muddy the planning process across both wires and pipes.

At the heart of the evolving risk profile for high-growth energy markets lies Planning Risk.

Power market regulation has never been fully settled, but the extent of uncertainty is underscored by state commissioners now openly questioning the viability of the federal oversight framework established more than 25 years ago.

At NAEMA, regulators actively discussed moving away from the traditional “trustee” model, where states and utilities coordinate via independent system operators, toward a “delegate” model. Such a shift would put states back in the driver’s seat on resource development and management, but also likely necessitate new mechanisms for managing interaction among large, often unaligned market actors.

This questioning of the basic market structures comes against a backdrop of widespread, often ad hoc regulatory re-writes at the ISO level as demand growth and renewable penetration stress legacy mechanisms. Developers – whether regulated utilities or independent power producers – are already recalibrating anticipated revenue stacks with each rule change. A structural retreat from the ISO model would only intensify planning risk.

With all three risks – Timing, System, and Planning – amplifying each other under surging demand, traders, investors, and strategic planners are converging around the need for more responsive market intelligence and forecasts for power markets.

Legacy forecasting is under pressure to deliver dynamic, risk-aligned modeling that reflects fundamental supply realities. Noreva’s AI-enabled, trade-calibrated forecasting framework is purpose-built to meet this need.

Market View: Sizewell C Signals Return of Nuclear – But at What Cost?

The UK’s final investment decision on the Sizewell C nuclear project sends a strong directional message: clean baseload is now strategic infrastructure. But strategic does not mean fast, nor free.

At ~£38–40 billion and targeting a 2034 online date, Sizewell is more decarbonization signal than solution. For the next decade, it won’t displace a single molecule of gas or add a kilowatt to the grid. The emissions, reliability, and affordability challenges Britain faces this decade – especially as coal exits and demand rises – will require complementary answers. And none of those will come from a nuclear facility that won’t deliver electrons until well into the 2030s.

The Regulated Asset Base (RAB) model, used to finance Sizewell, is designed to hedge long-duration construction risk. But it shifts risk (and cost) onto ratepayers. A projected IRR of 10–12% sounds compelling, but Karbone analysis shows that just a 20% overrun can wipe out that upside, especially if commissioning delays shift returns years into the future. Meanwhile, UK ratepayers are on the hook from day one, paying into a project that won’t generate electricity for over a decade.

This isn’t theory, it’s blueprint. Comparable megaprojects like Hinkley Point C, Sizewell’s sister project, and the Thames Tideway Tunnel have seen 30–50% cost overruns and 5–10 year delays, outcomes that trigger automatic RAB levies. If Sizewell C follows suit, taxpayers and ratepayers will foot the bill for costs well beyond the original £40 billion. To put this in perspective: the UK’s annual defense budget is ~£55 bn.

Energy Now vs. Energy Later

This is where the stakes get more complex. While Sizewell C could power six million homes by the mid-2030s, it does nothing to solve short- and medium-term energy reliability. The coming decade’s tight capacity margins, particularly in winter, will be met with imports, renewables, and fossil assets still on life support. The nuclear bet is long-term; but the energy crunch is very much now. For ratepayers, this means not just a higher monthly bill, but a quieter risk: structural cost embedded in long-term tariffs for power they won’t use for another decade.

Karbone Brokerage sees no immediate impact on European environmental attribute markets. Guarantees of Origin (GOs), UK REGOs, and other products are priced on existing generation and near-term expectations. Sizewell C is not yet priced into any forward curve, and rightly so.

A Transatlantic Echo

The message resonates across the Atlantic: U.S. federal backing of nuclear, ranging from tax incentives, bipartisan support, debt financing, to recent DOE and NRC reforms, paints a familiar picture. From the Palisades SMR plans to revival of Three Mile Island via a Microsoft-backed deal, power regulators are converging on nuclear as a keystone of energy strategy.

What Comes Next

Ultimately, Sizewell is a hedge, not a fix. It insures against the long-term risk of gas price volatility and firm capacity shortfalls. But the risk being hedged is ten years away. The near-term risk is underbuilding today – and leaving consumers exposed to price spikes and constrained grids in the 2020s.

Understanding Sizewell C demands integrated modeling across electricity prices, capex curves, financing frameworks, and geopolitical shocks. Karbone Research helps capital allocators quantify nuclear’s strategic value, simulate overruns against legacy assets, and benchmark returns across U.S.–UK infrastructure models.

Market View: Ceiling Shock: PJM Capacity Prices Reveal Structural Grid Stress

The 2026/2027 PJM Base Residual Auction cleared at the administrative price ceiling of $329.17/MW-day – a result that is as surprising as it is logical.

This result reflects a combination of tightening supply fundamentals, increasing reliability concerns, and evolving market rules that have not yet produced meaningful constraints on price increases.

The auction secured 134,311 MW UCAP, plus another 11,933 MW UCAP from FRR entities, totaling 146,244 MW UCAP.

That’s just 139 MW above PJM’s reliability requirement, a margin so slim that it underscores how precarious regional supply is.

All zones, including previously capped ones like BGE and Dominion, cleared uniformly at $329.17. In other words the ceiling didn’t suppress prices in select areas; it became the clearing price for the entire footprint.

Politically, this outcome intensifies existing fault lines. Last week, New Jersey threatened to leave PJM, citing structural unfairness in pricing. That warning followed a joint letter from seven governors, who bluntly flagged the auction’s misalignment with real-world constraints. Their message was clear: market design is failing in practice – and the ceiling result only bolsters their argument.

That outcome reflects inaction on multiple fronts: stalled Reliability Resource Initiative volumes, slow progress on FERC Order 2023’s interconnection reforms, and regional constraints in zones like EMAAC and ATSI.

Notably, proposed exits like the threatened New Jersey shift take this to a tipping point: states are now considering moving assets to state-run or dual markets, threatening PJM’s core functioning.

For asset owners and investors, the takeaway is stark: the right location pays premium returns, but the likelihood of further political intervention and regulatory risk has jumped. A ceiling clearing increases project IRRs – but also magnifies volatility in contract negotiations and credit agreements.

The ceiling result may catalyze reform – but it may also spark fragmentation and further improvisation in price discovery.

This auction was supposed to offer clarity; instead, it has amplified uncertainty. Karbone’s research team can help market participants navigate these dynamics, uncover hidden risks, and model forward capacity pricing under a range of evolving assumptions.

Market View: PJM’s Load Forecast Rewrites the Auction Math

PJM’s newly released load forecast for the 2026/2027 Base Residual Auction marks one of the sharpest year-over-year adjustments in the market’s history – and it’s changing everything from auction volume to zonal dynamics.

After a decade of stagnant or slowly climbing peak demand projections, PJM now anticipates a meaningful surge.

The biggest drivers? Data centers, electrification, and methodological course corrections.

Revised summer peak demand expectations are up across the board, but most notably in Dominion (DOM) and EMAAC service areas, where local policy support and hyperscaler infrastructure buildouts are colliding with EV adoption and building electrification.

The sheer magnitude of the shift is what’s drawing market attention. Year-over-year forecasted capacity demand increases of this scale are virtually unprecedented. Some zones are seeing peak forecasts rise by thousands of megawatts. That raises immediate implications for auction size, UCAP demand curves, and price formation – especially in areas already facing siting, transmission, or interconnection constraints.

But while the numbers are big, the uncertainty is bigger. Is this new demand actually going to show up? Or is PJM over-correcting for years of flat growth and under-forecasted winter load?

 Forecasting error has historically been a key driver of BRA volatility, and if the demand doesn’t materialize, we could see unnecessary procurement and inefficient price formation.

Still, the macro trend is undeniable: the structural load story is shifting, and PJM’s forecast is finally beginning to reflect it. AI, EVs, and behind-the-fence industrial load are all rewriting the long-term trajectory of electricity consumption, and resource adequacy constructs need to evolve accordingly.

The revised demand forecast could mark a turning point for PJM capacity markets, where tight zones become tighter, previously oversupplied areas firm up, and load-side uncertainty becomes the new price signal.

Karbone Research is actively tracking zonal load forecast revisions and their implications for auction dynamics and bilateral pricing. Contact us for custom analysis across DOM, EMAAC, and the rest of PJM.

Market View: New PJM Price Collar Faces First Test

As PJM heads into the 2026/2027 Base Residual Auction (BRA), a quiet but consequential change is coming into play: a redesigned Variable Resource Requirement (VRR) curve and an updated set of price collar mechanics.

While attention has swirled around demand growth, ELCC revisions, and supply stack reshuffling, it’s the new floor and ceiling constraints that could prove to be the decisive force shaping price outcomes this summer.

At a glance, the mechanics appear technocratic – tweaks to the formulaic price limits in response to updated Net Cost of New Entry (Net CONE) and inflation. But the market impact is far from marginal.

The new collar sets firmer boundaries for how high prices can spike in tight years and how far they can fall in surplus years. And with PJM projecting healthy reserve margins in many zones, the lower bound of that collar may be doing more price setting than anyone initially expected.

Bilateral trading behavior over the past quarter reflects that uncertainty. Bid-ask spreads have widened, and transaction volumes have slowed. Buyers believe the auction will bottom out at the price floor; sellers are pricing in a ceiling-driven upside. Both are likely to be disappointed.

Historically, PJM’s BRA prices have mostly cleared well within collar bounds. But this year’s setup introduces a real possibility that the collar becomes a price setter rather than just a guardrail. The newly flattened VRR curve, combined with rising capacity accreditations for DR and falling ELCC values for gas and storage, only heightens the chance that the collar, not scarcity, will define the clearing price.

The collar is intended to reflect economic fundamentals, yet it also imposes a form of price choreography in what was once a more free-moving market. In theory, it’s a stabilizing tool, protecting both buyers and sellers from extreme swings. In practice, it introduces the risk of artificial pricing outcomes, especially in a year where technical capacity may be abundant but economic capacity (after derates) is tight.

The larger question isn’t whether the collar prevents a crash or surge this year. It’s whether its presence sends a broader signal about risk-adjusted value in the PJM market. When clearing prices reflect regulatory design more than market scarcity, bilateral deals become harder to price – and harder to justify for capital allocators.

Karbone Research is modeling collar impacts across likely supply-demand scenarios for the 2026/2027 BRA and beyond. Reach out to understand where fundamentals end and policy signals begin and how that line might move over time.

Market View: From Installed to Accredited: PJM ELCC Shift Upends Capacity Math

PJM’s latest recalibration of Effective Load Carrying Capability (ELCC) values is no longer just a solar and wind story – it’s a sweeping restructuring of accredited capacity across nearly every major asset class.

The revised framework, released June 18, reflects a more granular, probabilistic methodology, and the implications are immediate: capacity market supply will fall, prices will rise, and revenue models across the asset stack must be re-evaluated.

Most notably, ELCC values for solar, battery storage, and gas-fired units, vital resources of the PJM fleet, are being marked down significantly in the upcoming 2027/2028 Base Residual Auction (BRA). Battery ELCCs dropped 12–18% across all durations through 2030, and gas Combined Cycle units were de-rated by 6–8%, implying fewer UCAP megawatts will clear. Even storage with six-hour duration, once on par with a peaker, falls to just 35% ELCC by 2035, while combustion turbines rise to nearly 70%.

Meanwhile, demand response (DR) is the clear beneficiary. PJM has upgraded DR’s accreditation by nearly 20% for 2027/2028, recognizing its demonstrated seasonal reliability and making it a competitive alternative to new generation. Wind receives a modest short-term bump, but its ELCC declines sharply in out-years – from ~40% today to 20% by 2035. Solar, though largely unchanged in status as a marginal capacity contributor, continues to trend lower.

The pro forma impact on market supply is striking. Karbone Research expects a net 3 GW decline in cleared capacity in 2027/2028 due to these accreditation revisions alone, tightening the supply-demand balance and putting upward pressure on clearing prices. The market implications are asymmetric across asset owners:

• Nuclear-heavy portfolios stand to benefit most, maintaining near-perfect 95% accreditation while earning elevated prices.
• Mixed fleets also benefit from higher prices but will see some volume offset from gas deratings.
• Gas-reliant portfolios face greater headwinds yet still gain from the overall price uplift. Companies’ growing DR platforms could offer partial upside.

Taken together, these ELCC changes further solidify a “higher-for-longer” regime for PJM capacity pricing. While the 2026/2027 auction remains in investor focus, the structural revisions taking hold in subsequent years may matter more for forward curves and long-term project economics.

From a policy perspective, the shift introduces new pressures. Higher clearing prices may intensify regulatory scrutiny, particularly if ratepayer costs continue to escalate. Some utilities are already positioning themselves for increased ownership of regulated generation – citing both price stability and resource adequacy mandates.

For developers, the new ELCC regime reinforces a core challenge: installed capacity no longer maps neatly to accredited capacity. Financing and valuation models must now account for probabilistic derating across delivery years, with significant implications for debt sizing, contract structure, and offtake strategies.

Karbone Research is working with clients to quantify the impacts of PJM’s revised ELCC framework on forward capacity pricing, project returns, and bilateral valuation strategies. Reach out to learn how updated accreditation pathways may affect your portfolio.

Market View: OBBBA Winners – Gas and EPCs

The oil and gas industry got what it paid for in the final language of the “One Big Beautiful Bill Act” currently in the closing stages of House review before moving to the President’s desk, possibly in time to meet a self-imposed Independence Day deadline.

Early and enthusiastic supporters of rolling back most of the Inflation Reduction Act’s clean power and electrification expanded tax credits, while protecting and expanding the range of clean energy businesses that fit its molecule-first value stack, oil and gas firms got the full measure of their wish list in the final language of the OBBBA.

Karbone Research noted the intra-fuel politics in the days after the Republican sweep of November 2024 predicted that the IRA tax credits were at greater risk than consensus: That forecast has been proven correct, despite the billions of dollars of investment at risk in Republican districts from sweeping project cancellations.

Almost every existing and proposed energy project in the US will need to be re-underwritten in the wake of the OBBBA enactment.

The massive pipeline of wind and solar projects planned for the remainder of the decade are most at risk from a 2027 “cliffs’ edge” for tax credits built into the bill, but existing qualifying projects planning to refinance will also need to revisit the energy market fundamentals in a changed financing landscape.

Meanwhile natural gas and nuclear plants that expected to capture massive capacity revenues from much higher renewable energy penetration will need to reevaluate their merchant-to-contracted mix and rework their financial outlooks given predictions of much higher power prices post-OBBBA through the end of the decade.

In the energy sector, the biggest winner of the change in Washington is natural gas. Gifted with kinder tax treatment in the OBBBA and with their main competition for long-term fuel mix dominance now handicapped, gas producers, midstream companies and gas-fueled power generators have a generational opportunity to rapidly lock in market share through uprates and system expansions.

A new “fast lane” permitting process at FERC and potential for federally mandated accreditation changes only further burnish the natural gas business case.

A late-breaking element of the latest version of the Senate OBBBA bill is a “safe harbor” window on tax credits for projects that begin construction within 12 months of the bill’s enactment.

There’s little doubt that a number of engineering, procurement and construction company leaders woke up this morning to requests to fast-track renewable project construction starts.

With EPC capacity already strained by the IRA-fueled renewable energy buildout of the last few years, higher costs to jump the construction queue and renegotiated contracts are likely. How those higher costs filter through to each project’s stakeholders and how they are passed through under current regulations will trigger further rounds of project re-underwriting.

With summer vacations for project developers and financiers officially cancelled, the frenetic reworking of project economics will likely only roil traded energy, commodity and attributes markets further. Fundamental-driven and trade-informed price discovery will be doubly important, absent the cushion of reliable tax credits, and existing volatility is only enhanced by the latest switchback in US energy policy.

Market View: RINs Rise on Release of EPA’s “RFS Set 2” Proposal

The EPA has released its proposed Renewable Volume Obligations (RVOs) for 2026 and 2027 under the Renewable Fuel Standard, delivering a notable surprise to the clean fuels market.

Clean fuels and agricultural groups had advocated for a 2026 biomass-based diesel (BBD) volume of 5.25 billion gallons. In the months leading up to the announcement, market participants expected volumes to fall short of that target, with bearish trade sentiment and wide price swings fueled by rumors of leaked drafts. However, the EPA exceeded expectations, setting the 2026 BBD requirement at 7.12 billion RINs and 7.50 billion for 2027. In response, D4 and D6 RINs rose 10-15 cents in today’s trading.

In contrast, the agency revised the 2025 cellulosic-derived biofuel volume requirement down to 1.19 billion RINs from a previously finalized 1.38 billion. In a separate proposal, the EPA also issued a partial waiver for the 2024 cellulosic requirement, enabling the use of waiver credits to assist obligated parties with compliance. These revisions underscore the ongoing infrastructure challenges in the RNG sector, particularly the limited availability of CNG fueling stations - a persistent bottleneck constraining D3 RIN generation.

Karbone’s 20-year D3 RIN pricing model anticipated a downward revision to 2025 volumes in its Base Case scenario. Looking ahead, prices could remain elevated if CNG trucking demand accelerates and supply remains tight - driven by expanded fueling infrastructure and adoption of larger CNG-compatible engines. 

However, unanswered questions remain about small refinery exemptions (SREs), which are granted to refiners with an average annual crude oil throughput of 75,000 barrels or less, demonstrating "economic hardship" as a result of RVO compliance. The EPA's proposal leaves uncertainty around the volume of gasoline and diesel that will be exempt in 2026 and 2027, with estimates ranging from zero to 18 billion gallons, and does not definitively address the backlog of 169 SRE petitions, underscoring the long-term uncertainty for projects relying on RIN revenues.

A particularly impactful component of the EPA’s proposal is its emphasis on domestic energy production. Under the new proposed rulemaking, renewable fuels produced from imported or foreign-derived feedstocks will generate only half as many RINs per gallon. This offers a clear regulatory advantage to U.S.-based feedstock suppliers; Karbone expects this shift to drive additional RIN demand and support continued price strength across the market.

Together, these regulatory shifts reinforce a growing federal commitment to domestic clean fuel production - creating tailwinds for U.S.-based biofuels investment. The proposed mandates are subject to change based on a public comment period and intake of biofuel production data over the coming months. Karbone Research continues to track these regulatory developments and their market impacts, providing forward-looking insights and long-term pricing forecasts to help clients navigate an increasingly dynamic RINs landscape.

Market View: Feds Fret, Private Markets Feast

With high prices prompting mergers and acquisitions in power, how long can the party last?

While federal regulators wring their hands over resource adequacy, capacity pricing, and runaway load growth, the private capital markets are riding high on power deals – at least for now.

At the S&P Global Power and Gas M&A Forum this week, top players from Evercore, KKR, Morgan Stanley, and Barclays painted a clear picture: deal activity is booming. Despite transaction volume holding flat year-over-year, the volume of megawatt-hours changing hands has doubled, driven overwhelmingly by tech-sector demand. The data center arms race isn’t just reshaping the grid; it’s also reordering private market priorities.

The dominant narrative? Demand is surging, but buildout remains bogged down by ambiguous federal signals, rising development costs, and an interconnection queue that resembles a waiting list for a sold-out concert. It's the same cocktail of uncertainty that dominated last week’s FERC conference – except now, the tone is more opportunistic.

Panelists repeatedly called for an “all of the above” buildout strategy: more renewables, more gas, more nuclear. But while private capital is happy to foot the bill for now, many are asking: where’s the public funding?

Especially as residential ratepayers start to feel the pinch, the absence of a coherent federal funding mechanism is glaring. One panelist pointed out that gas and nuclear are particularly appealing targets for infrastructure funds this year; hardly the full-spectrum energy transition.

Meanwhile, deals like the Calpine–Constitution pipeline transaction are setting new benchmarks for private equity spend in the sector. But even this optimism has its limits. If chip efficiency doesn't keep pace with hyperscale load growth, and if retail prices continue to climb, political intervention is only a matter of time.

As consolidation sweeps the market and uncertainty dominates the policy landscape, Karbone Research provides valuation support, price forecasting, and strategic guidance for those navigating the new energy economy.

Market View: MISO in FERC’s Hot Seat on Day Two

MISO’s reliability gaps have become the talk of the federal energy establishment, with state regulators and market participants zeroing in on the region’s capacity shortfalls and the limits of the current residual capacity auction.

On the second day of the commissioner led technical conference hosted by FERC, panelists were clear-eyed about the challenges: a short-term reliability crunch from looming generator retirements, ballooning load forecasts driven by new industrial and data center demand, and an interconnection queue that has grown too large to ignore.

Central to MISO’s approach is its move toward seasonal accreditation, an attempt to better reflect the actual contributions of resources across different seasons – an effort that was widely discussed as a possible model for other ISOs facing similar capacity valuation dilemmas. But the panelists highlighted that even seasonal accreditation alone cannot solve the region’s capacity puzzle, especially when delays in bringing new resources online threaten to outpace load growth.

Long interconnection wait times and siting challenges were identified as key obstacles, with corporate buyers and regulators expressing frustration that project delays and uncertain timelines have become routine. MISO’s independent market monitor and other stakeholders suggested that until these bottlenecks are cleared, seasonal accreditation will remain a partial fix rather than a complete solution.

Karbone Research’s new capacity forecasts echo the concerns raised at FERC: Even under optimistic development scenarios, MISO may need to add historic amounts of new capacity annually for decades to come. In the high case for MISO Summer North, prices soar in the closing years of the 2020s before breaking higher into a new pricing regime as high as $20 per kw-mo by 2030. This mismatch between the need for capacity and the speed of delivery underscores why state-level policy interventions and regional coordination efforts have become urgent topics in the Midwest’s capacity conversation.

As states weigh alternative constructs and push for changes to MISO’s resource adequacy model, the balancing act between reliability, affordability, and policy ambitions will shape the region’s capacity outlook for years to come.

Market View: Feds Fight over Capacity Pricing Authority

The tech sector takeover of DC has rolled into the federal government’s oversight of energy markets, with access to electrons for data centers being the latest battlefield.

Set into motion by a convergence of high capacity pricing, deep-pocketed data center developer concerns about access to firm power, and President Trump’s executive order declaring a sweeping energy emergency in the US, agencies are competing with each other to become the regulator of choice for hitherto sidelined resource adequacy and capacity markets.

At a blockbuster Federal Energy Regulatory Commission conference this week, the commissioners put their stake in the ground, gathering state regulators, bulk power market operators and hyperscaler corporates to lay out a litany of professed market failures in existing capacity price discovery. Outgoing FERC chairman Mark Christie, soon to be replaced by Trump nominee Laura Swett, opened the two-day event by asking the overflowing rooms of lawyers and corporate representatives onsite why FERC shouldn’t impose a single national capacity accreditation methodology to anchor pricing in those markets.

PJM and MISO were placed in the crosshairs, with the heads of state utility commissions and representatives of large power buyers invited to critique current capacity market approaches on the record at length. The list of problems with current operators was familiar to anyone with a glancing experience of power markets in recent years, from years-long interconnection queues to disorderly retirements of fossil generation and opacity on resurgent load growth after decades of replacement-level investment across the sector.

If FERC is able to demonstrate that the disorder in state-level capacity accreditation is affecting cross-state power markets, it will become the obvious regulator of choice for a national capacity regulation effort. This would let it fend off the efforts underway across the National Mall at the Department of Energy, where Trump’s emergency order has set off a workflow to create a competing national methodology for resource adequacy in power markets. The legislative authority for a DOE effort is less clear unless it is acting under the emergency authority in section 202 of the Federal Power Act, a move repeatedly cited by speakers at the FERC conference as unneeded. 

For now, states may end up forcing the standoff between FERC and DOE to a head as they attempt to circumvent the RTOs in order not to lose data center business to the least regulated states. Across PJM, state politicians and utility regulators are pressing for revised relationships and processes that give the states more latitude to permit new building, and Governor Shapiro of Pennsylvania is expected to press for sweeping structural changes to PJM capacity markets, including “sub-annual auctions,” as soon as next week. 

Missing from the commissioners’ discussion of the crisis in capacity and the need for regulation were informed forecasts for future capacity pricing. Karbone Research was at the FERC conference to discuss exactly that: New merchant curve capacity forecasts from Karbone show the disruption coming to SPP and MISO after years of underinvestment across a 25 year horizon. Understanding the dynamic influence of accreditation on pricing over time is the only way to construct an effective methodology that both incentivizes investment and keeps prices from reaching escape velocity.

Market View: Connecticut Takes Aim at Renewable Power