Market Views

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

Market View: Grid Emergency or Political Maneuver? DOE Blocks Coal Exit

Hours after brownouts hit parts of MISO, the US federal government intervened in longstanding corporate plans to shut down a coal plant in the RTO, but the move will barely shift pricing fundamentals in the region’s tight capacity market.

On May 24, the Department of Energy (DOE) issued an emergency order requiring Consumers Energy to delay the planned retirement of its 1,560 MW J.H. Campbell coal plant in Michigan.

Karbone Research modeled a preliminary review of MISO’s summer capacity outlook following the order and found that the region’s reserve margins (and price forecasts) are hardly impacted by the delayed Campbell retirement. While important as a commitment to dispatchable power, the move appears to have limited material effect on MISO’s system-wide reliability metrics.

The plant, originally set to shut down on May 31, is supposed to operate through at least August 21 to address what the DOE calls a “critical grid security issue” in the Midcontinent Independent System Operator (MISO) region.

The DOE invoked its rarely used Section 202(c) emergency authority under the Federal Power Act, citing elevated blackout risks during periods of peak summer demand. In justifying the order, Energy Secretary Chris Wright referenced recent NERC and MISO assessments highlighting tight reserve margins and late-summer solar production declines.

This action marks a departure from standard protocol. Emergency orders are typically reactive, following requests from affected grid operators or utilities. In this case, MISO, the grid operator responsible for reliability across 15 states, confirmed it did not initiate or request the DOE’s intervention. Consumers Energy also maintained earlier this month that it had sufficient capacity to meet summer demand, citing the upcoming expansion of its Zeeland gas plant and ongoing investments in renewables and storage.

Critics, including environmental and consumer advocacy groups such as Public Citizen and the Sierra Club, argue the DOE order is a politically motivated overreach. They accuse the administration of "manufacturing an emergency" to justify prolonging coal operations, despite long-standing retirement plans developed in coordination with state regulators and MISO. The Campbell plant’s closure was part of a broader decarbonization strategy aiming for 100% carbon-free electricity in Michigan by 2040 - one projected to save ratepayers $600 million through 2040.

On the other hand, proponents of the decision point to the ongoing challenge of ensuring adequate dispatchable capacity as thermal retirements accelerate and renewables increasingly dominate interconnection queues. MISO’s own capacity auction this spring highlighted a tightening summer reserve margin, especially during late-day net peak hours when solar production drops off.

Importantly, the DOE directed that the Campbell plant be dispatched only as needed to minimize costs to ratepayers, though cost recovery mechanisms remain to be determined and could face scrutiny at the Federal Energy Regulatory Commission (FERC).

We continue to monitor evolving federal-state dynamics and their potential implications for coal phaseouts, reliability protocols, and capacity market reforms across organized U.S. power markets.

Market View: PJM RECs Struggle after New Jersey BPU Meeting

On May 21, the New Jersey Board of Public Utilities (BPU) announced in a meeting that they intend to break precedent and alter the percentage of load that state utilities must offset with Class 1 RECs in 2026.

Under New Jersey's current Renewable Portfolio Standard, the percentage for Class I RECs in the state is mandated to rise from 35% in 2025 to 38% in 2026. At the BPU meeting yesterday, it was stated that the percentage will instead remain at 35% for 2026.  In the same meeting, the BPU also stated that they will investigate the rule-making procedures for energy years 2027 through 2031.

The BPU cited PJM's lagging supply of new build RPS-eligible assets coming online as the main reason for the decision. New supply has been hampered for years by interconnection queue backlog, and the sector has faced a number of new unwelcomed headwinds this year, including potential tariffs and curtailment of renewable energy tax credits under recent Congressional budget proposals.

An official order from the BPU is expected to be announced next week, though it remains unclear if the BPU has the legal authority to change the RPS percentage for existing legislation that was originally ratified by the state legislature.

PJM Tri-Qualified RECs, the bellwether REC product for the PJM region, have experienced a notable price decrease since the BPU’s announcement. As of this afternoon, 2026 PJM Tri-Qualified prices are 5% lower than yesterday’s close, and are now down 32% since the start of the year.

With 2026 pricing currently around $26.50 / REC, the market continues to inch closer towards a critical support level – the 2025 Alternative Compliance Payment (ACP) rate for both Maryland and Delaware ($25.00 / MWh). Karbone is tracking whether pricing will stabilize around this support level.

Through Base, Low, and High scenario modelling, Karbone's methodology cuts through near term uncertainty to forecast PJM Tri-Qualified REC prices out to 2050.

Market View: The Meaning of Empire Wind

A clean energy reversal by the Trump administration offers insights on successful project execution as the battered sector prepares for fights ahead.

Two years ago, a group of union labor leaders joined a handful of private capital infrastructure investors, corporate VPs, and New York State power regulators at lunch at the Yale Club in New York City.

Regulators working to operationalize the state’s newest climate and energy laws had changed the planning parameters for corporate strategists watching power demand grow in New York even as retirements of fossil fuel and nuclear units cut available supply.

Private capital groups with historic fundraising hauls swarmed over the multitude of projects that would form the backbone of new supply chains and enabling infrastructure for large corporate energy projects.  Infrastructure investors, seeking access to above-trend but stable returns, were a crucial balancing force between regulators with mandates to maintain competitive pricing for consumers and companies that needed capital certainty to invest.

But the most catalytic presence at the Yale Club lunch was the handful of union leaders. Equinor’s Empire Wind project would require extensive union worker hiring to qualify for the highest band of available tax credits under federal policy, but that was only the beginning.

Everything from new offshore servicing ports to needed upgrades to interconnections and transmission across the entire region would require union labor at a time when unions were struggling to maintain membership and younger members advocated for upgraded and modernized skillsets.

Within hours of the Trump administration’s “stop work” order for the massive offshore wind project, unions swung into action, advocating for the thousands of union jobs associated with the project and its supply chains. Union work never stopped at the marine terminal intended to ship pylons, turbines and blades to the Empire Wind site from South Brooklyn, and the AFL-CIO rushed out praise for Governor Hochul after the stop work order was lifted.

The role of unions as politically-savvy enablers of long-term capital investment in infrastructure was an explicit part of the Biden administration’s bet on including labor provisions in the Inflation Reduction Act. The outsized role that unions play in New York State infrastructure also presented an innate challenge to federal efforts to unwind one of the state’s biggest energy projects in decades.

The energy transition makes for strange partnerships and strange politics, but careful navigation and cultivation of both are the best insurance for investors as they plan across long development and financing horizons.

Market View: Ratepayers vs the Solar Industry

Who is to blame for higher power prices in New Jersey? 

A local question with national consequences, the state’s lawmakers are conducting a high-profile debate over the role one of the longest-standing US renewable power financial support programs has played in higher customer bills.

Last week the New Jersey Assembly held a closely watched Committee hearing on A5460, a bill that would reduce the Solar Alternative Compliance Payment for NJ SRECs from $198.00/MWh in 2026 to $50.00/MWh starting next year.

The bill was introduced as a broader set of measures to reduce electricity bills for New Jersey ratepayers, whose residential electric bills are expected to rise between 17% and 20% this year. For instance, legislators in the Senate also introduced a separate bill (S4300) to eliminate the Solar RPS entirely, directing the Board of Public Utilities to replace SRECs with a fixed annual payment of $95.00/MWh.

The Assembly legislation, introduced by New Jersey Democrats in March, would set the ACP rate on a $10.00 annual decline, until reaching $10.00/MWh in 2030. The NJ SREC market has since seen considerable volatility, with 2026 vintages falling at times as low as 30% from pre-bill levels. Pricing has since partially recovered to the $165.00 - $175.00 range in recent weeks. 

Thursday’s hearing set the stage for a standoff between the U.S. solar industry and the Rate Counsel of New Jersey. State ratepayer advocates testified in favor of the bill, arguing that New Jersey’s solar program has inflated SREC prices substantially higher than the mid-Atlantic average and increased utility costs for customers. 

But trade groups representing solar developers and IPPs rejected the bill on the basis that its language contradicts the regulatory agreements underpinning long-term capital investments that have enabled solar growth in the state, harming project economics at a time of federal policy uncertainty and discouraging further investment in the sector. 

The debate over the contribution of solar incentives to utility bill increases coincides with a surge in PJM capacity prices in the 2025/26 Base Residual Auction. Karbone trade data indicates that regional capacity prices could continue to move higher, even as regulators act to put a cap on capacity auctions.

This debate has emerged against the background of a contentious gubernatorial race, in which political pressure for lower electricity prices has been a defining feature. Market participants do not expect the bill to be reported to the Assembly floor for consideration before the legislature enters summer recess.

Karbone’s 25-year PJM REC modelling captures over more than 130 separate pricing scenarios across policy outcomes.

Market View: IRECs Prices Launch Amid Volatility

Small regulatory adjustments continue to create new opportunities for participants in cross-border markets for environmental attributes. 

New analysis of the International Renewable Energy Credit market (IREC) shows how rapidly market pricing can respond to technical adjustments. Historical and daily pricing for major  international Renewable Energy Credit (IREC) markets, including Brazil, Chile, India, Mexico, Thailand, and Vietnam, are currently available on the Karbone Data Hub.

Volatility in Mexico's IREC market has recently stood out due to a significant price spike, with values more than doubling since December 2024, surpassing $3.00/MWh by March 2025.

This surge followed regulatory adjustments by NORMEX in early 2024, which reduced registration fees to €100 for renewable production devices under 1 MW. The policy aimed to encourage participation from small and medium-sized enterprises (SMEs), yet small-scale generators still represent under 1% of Mexico's total IREC capacity. Consequently, despite regulatory incentives, supply has remained relatively stagnant compared to expectations and prices jumped.

Further influencing the supply dynamics, the Mexican Clean Energy Certificate (CEL) market competes directly with the IREC market. Projects aiming for CELs must meet specific commercial operation date (COD) requirements, generally leading to higher standards and costs. Consequently, CELs typically trade at a premium compared to IRECs, intensifying competition for renewable energy generation certificates and limiting the available supply for the IREC market.

Simultaneously, demand for renewable energy certificates rose dramatically. In February 2025, IREC retirements increased approximately 55% year-over-year, reaching 2.1 TWh. This imbalance between rapidly growing demand and limited supply significantly elevated IREC prices, with wind and solar IRECs hitting $3.25/MWh by the end of March, and some trades even reaching $4.15/MWh.

This scenario mirrors the volatility seen in compliance markets like U.S. REC markets, where regulatory shifts and supply-demand imbalances similarly contribute to rapid price fluctuations. Karbone's tracking of NJ SRECs, for instance, shows pricing for RY 27 dropping from $183 on March 14 down to $113 on March 28 before jumping back up to $171.50 on April 16.

Market View: Capacity bill comes due in MISO

Market View: Everyone’s Chasing Capacity

The center of gravity in power markets is shifting – away from energy, and toward capacity.

At last week’s S&P Global (Platts) Global Power Markets conference, one theme cut through the noise: energy prices, in most markets, are no longer sufficient to underwrite the infrastructure the grid needs.

As energy markets trend toward structural oversupply – driven by renewables, mild demand growth, and policy pressure – developers and investors are turning their focus to capacity markets as the new engine of revenue.

The distinction is more than semantic. In the old paradigm, energy arbitrage and merchant pricing volatility were enough to support new assets. But in today’s landscape, peakers (fast-ramping, capacity-heavy assets) are commanding valuation premiums.

The forward curves are no longer shaped by energy price expectations alone. Instead, capacity accreditations, auction outcomes, and reliability requirements are forming a new price signal – and a new value stack.

The implications are far-reaching. Project financing, risk management, and asset optimization are all being quietly retooled to reflect this shift. From combined-cycle plants struggling to secure merchant revenue, to storage developers banking on multi-year capacity payments, the power sector is beginning to recognize that the ground has moved. Capacity, not energy, is what moves capital today.

Karbone Research expects this trend to deepen. As demand volatility increases and policy support for firming resources expands, capacity revenue will increasingly define project viability. Many market participants may still be thematically chasing energy – but they are pricing, financing, and operating around capacity.

The value stack has already changed. The market is only now beginning to realize by how much.

Market View: Can Gas save SPP?

The rapid evolution of U.S. power markets is increasingly defined by the role of natural gas, and new forecasts from Karbone Research show why.

No other fuel so effectively aligns with the capacity accreditation methodologies adopted by market operators. By mirroring historic waves of gas additions into price forecasts through 2050 this scenario shows that gas may be the only effective way to limit long-term price inflation for capacity in the SPP power market.

This starkly different scenario from the other forecasts run by Karbone as part of our capacity merchant curve modeling shows the divergent reality for energy investors. Gas additions quell capacity price inflation, even as limited capacity upside may dissuade developers from building the needed gas.

Against a backdrop of heightened focus on gas-fired generation, Karbone Research’s Gas Scenario presents a forward-looking view of how capacity markets could reshape in response to a prolonged gas buildout. This scenario mirrors the late-1990s and early-2000s dash to gas, capturing a potential future where gas infrastructure dominates the supply stack, influencing volatility, price trajectories, and investment strategies.

Near-term capacity markets in this SPP gas forecast reflect familiar volatility, shaped by existing infrastructure constraints, policy uncertainty, and shifting demand patterns. However, from the early 2030s onward, an accelerated wave of gas-fired generation enters the stack, tightening reserve margins and driving a sustained price increase until the early 2040s.

The pricing shift forecasted in this period is defined by market participants recalibrating expectations in response to a gas-centric buildout, replacing a decade of stalled renewable growth.

This transition pushes capacity prices into a structurally higher range compared to historical norms, with markets repricing risk as gas secures a greater share of marginal capacity. While this deployment alleviates short-term reliability concerns, the long-term implications remain nuanced.

Compared to the Core Scenario, the Gas Scenario exhibits the most dramatic shifts in price formation. The market experiences sustained upward pressure for a decade before a rebalancing period emerges, underscoring the cyclical nature of infrastructure deployment and market equilibrium.

This reinforces the strategic importance of forward-looking capacity procurement strategies, as market participants seek to optimize risk exposure across this pronounced cycle.

Market View: Nuclear cannot save the day in SPP

The addition of large-scale nuclear capacity has long been positioned as a stabilizing force in power markets, but Karbone Research’s capacity pricing forecasts indicate that even sizable nuclear investments will provide only moderate relief to structurally tight conditions.

Under a nuclear additions scenario in the SPP power market, two 4GW nuclear units come online in 2035 and 2040, introducing additional baseload capacity.

While this dampens prices in the mid-term, overall trends remain consistent with the core scenario of steadily rising prices, reinforcing the structural shortfall that defines capacity markets into the 2040s and beyond.

This scenario underscores a key reality: capacity markets remain fundamentally tight, even with nuclear additions.

The expected price trajectory still trends higher, albeit with mid-term dips driven by new nuclear capacity coming online. However, these additions primarily affect the low-case price scenario from Karbone, which experiences deeper declines post-2040.

The base and high-case price projections, in contrast, see only marginal adjustments, demonstrating that nuclear’s impact on overall market structure is limited in the face of ongoing supply constraints and increasing peak demand.

Nuclear remains a long-cycle asset with complex permitting and high capital expenditure requirements, which, in turn, shape the degree to which these additions can alter market outcomes.

Even with significant new nuclear capacity, forward pricing remains structurally elevated, highlighting the persistent value of capacity-backed assets and reinforcing the importance of market entry timing for investors looking to capitalize on volatility and potential price floors.

Karbone Research expects the addition of large-scale nuclear would provide moderate downward pressure on capacity pricing in the medium-term but leave broader price dynamics largely intact. The divergence across low, base, and high cases grows more pronounced, with the low case showing material dips post-2040 while the base and high cases remain near core scenario trajectories.

This scenario highlights that, while nuclear investment can smooth volatility, it does not fundamentally disrupt the upward trajectory of capacity prices – a critical insight for asset developers, investors, and market participants navigating long-term commitments in an evolving regulatory and economic landscape.

Market View: Wind delays hit SPP capacity outlook

Prices for capacity in SPP will be higher for longer if current restraints on wind energy additions continue, Karbone Research forecasts indicate.

Capacity markets are poised for sustained price appreciation, but policy-driven constraints on wind deployment introduce a new dynamic to the forward outlook in Karbone’s merchant curve models.

Under this scenario, a politically driven halt to new wind projects over the next six years amplifies near-term tightness, reinforcing upward price pressure across all timeframes. The absence of incremental wind power additions removes a key deflationary force from the market, resulting in a supply-side squeeze that reshapes merchant risk and alters the competitive landscape for existing generators.

The implications of this policy-induced constraint are stark: removing wind capacity does not ease market pressure – it exacerbates it.

Capacity remains a function of supply and demand fundamentals, and with demand growth continuing, stripping out a major source of new build only intensifies scarcity pricing. In the absence of additional wind resources, fossil-fuel generators, particularly gas-fired assets, gain greater pricing power, while battery deployments accelerate to partially fill the gap.

However, storage alone does not mitigate the tightening reserve margin, leading to structurally higher clearing prices.

In contrast to the core scenario, where supply diversification introduces greater variance between low, base, and high cases, this wind-restricted trajectory exhibits significantly less divergence across forecast bands.

The removal of wind as a competitive force compresses price dispersion, producing a more predictable – yet structurally elevated – capacity price environment. This dynamic presents both risks and opportunities: while higher price certainty may facilitate financing, the absence of a key hedge against future price shocks elevates the risk of prolonged tightness in the 2030s and beyond.

Karbone Research expects that, under this scenario, capacity prices will experience a more pronounced and sustained increase, reaching levels in the low double digits ($10-$15/kW-month) more rapidly than in the core case.

Furthermore, the absence of wind additions locks in a more rigid supply curve, reducing the responsiveness of capacity markets to future demand fluctuations. While battery adoption will accelerate as a partial offset, the lack of complementary renewables weakens the long-term price effects of storage expansion.

As election cycles introduce policy uncertainty, investors and asset managers must recalibrate risk models to account for regulatory-driven constraints on new capacity development. While wind remains a politically charged issue, the market’s structural need for new supply remains unchanged.

In the wind-adjusted scenario for SPP capacity forward pricing, the absence of wind additions fundamentally alters the risk-reward balance in capacity market strategies, favoring incumbents while increasing forward market volatility in a landscape where scarcity remains the dominant pricing force.

Market View: A new price regime in SPP

Summer capacity prices in the central US are heading into double digits for the coming decades, breaking through resistance higher on persistent undersupply.

The evolving dynamics of power markets indicate a decisive shift in capacity pricing, marking the beginning of a sustained move into higher price levels.

Karbone Research’s Core Scenario for SPP peak summer capacity outlines a market trajectory shaped by a gas-driven buildout, tempered onshore wind expansion, and an eventual acceleration of battery deployment.

These underlying trends set the stage for capacity prices to rise steadily through 2050, with near-term volatility acting as the precursor to a fundamental repricing of risk and reliability.

A confluence of factors is redefining capacity valuations. The rapid expansion of gas generation in the 2020s, coupled with a more measured pace of onshore wind deployment in the latter half of the 2030s, recalibrates supply expectations.

Battery storage gains traction in the 2040s, reinforcing reliability but also introducing new arbitrage dynamics. These shifts collectively drive a structural uplift in clearing prices, moving from the mid-to-high single digits into a sustained low double-digit range ($10–15/kw-month) across key markets.

Despite a steady upward trajectory, the market is entering a period of near-term uncertainty. Fluctuations in fuel prices, evolving regulatory frameworks, and the complex interplay between intermittent and firm capacity will shape price formation in the coming years. These transient dislocations, however, are laying the groundwork for a prolonged repricing cycle.

Toward the latter half of the horizon, the divergence between the base and high price case forecasts widens, reflecting increased uncertainty around technology costs, policy shifts, and the pace of investment.

While structural trends point to a higher equilibrium, scenario-specific factors – such as the depth of gas reliance, the speed of storage adoption, and potential regulatory interventions – create an expanding range of outcomes.

The Core Scenario of the Karbone Research SPP merchant curve, however, envisions little relief from upward pressure. Left to the current trajectory, prices are headed higher.

Market View: Capacity Markets: The Next Frontier in Power Trading

Capacity pricing has shifted from a peripheral concern to a central force in power markets, influencing project finance, asset optimization, and long-term investment strategies.

As volatility and structural changes reshape the energy landscape, decisions made today will define cost differentials worth millions of dollars per MWh at peak demand.

Karbone Research's new Capacity Merchant Curves provide the critical insights needed to navigate this evolving market, offering a strategic advantage for investors, asset owners, and traders alike.

Access to capacity markets is now fundamental to project viability, requiring a sophisticated understanding of both price formation and trading dynamics. Unlike energy markets, where fundamentals often dictate pricing, capacity is a "professionals' market," where market structure, procurement mechanisms, and policy interventions create wide price spreads and unique risks.

Identifying these distortions and leveraging trading strategies accordingly will define successful participation in the capacity market.

Karbone Research’s proprietary capacity modeling framework integrates fundamental supply-demand dynamics with market behavior, regulatory considerations, and trade activity.

Our approach offers a differentiated perspective on capacity pricing, moving beyond simple forecasts to deliver actionable intelligence.

Look for our new curves at the Global Power Markets conference in Las Vegas on April 14-16, 2025, providing a structured, scenario-driven outlook that aligns with real-world investment and trading needs.

The launch will include four distinct capacity price trajectories – our Core Scenario, alongside Wind, Nuclear, and Gas scenarios – each reflecting a different pathway for grid reliability, policy intervention, and resource deployment.

This week’s market views will lay out our arguments for each case, allowing participants to assess how structural shifts in generation and interconnection capacity impact forward pricing, procurement costs, and investment decisions.

With capacity no longer a marginal consideration in power markets, understanding trade dynamics is as critical as grasping fundamental supply and demand.

Karbone Research's insights bridge this gap, equipping market participants with the strategic intelligence needed to anticipate risks, seize opportunities, and optimize portfolio decisions in an increasingly complex capacity landscape.