Market View: Battery Standards Reshape Capacity Dynamics
New sector guidance for battery projects may cushion the impact of technical derates currently weighing on project development and clouding capacity supply outlooks.
Following a multi-day fire at California’s Moss Landing facility – and subsequent warnings of derates at similar battery installations supporting intermittent renewables – the American Clean Power Association (ACP) released a comprehensive safety framework on March 28.
The guidance spans the entire lifecycle of battery projects. It emphasizes the need for robust design elements such as improved containment architecture, advanced fire suppression systems, and thermal runaway mitigation. Complementary measures include enhanced operations and maintenance protocols, more frequent health audits, and mandates for real-time performance monitoring.
Collectively, the recommendations aim to equip project owners, operators, regulators, and first responders for the accelerating pace of energy storage deployment – a cornerstone of renewable integration and grid stability.
The most financially consequential aspects of the new framework, however, are the operational constraints it introduces. In certain conditions, battery operators may be required to limit their systems’ state-of-charge or restrict charge and discharge rates. These safety-driven derates can reduce a project’s effective capacity, creating a tension between safety compliance and market viability.
In parallel, regulators and grid operators are reevaluating how energy-limited resources – particularly lithium-ion batteries – are accredited in capacity markets. Given that these systems can typically discharge for only a few hours and may now face additional safety-based operating limits, the duration and magnitude of their capacity contributions could decline. For developers whose financial models rely on predictable capacity revenues, this introduces a new layer of revenue risk.
The implications for capacity markets are twofold: over the longer term, the new standards could incentivize innovation, favoring chemistries and technologies that enable safer, more flexible performance. In the near term, however, these same standards could reduce accredited capacity across the board, tightening supply and driving capacity prices higher.
By directly linking operational limits to safety protocols, the ACP’s March 28 framework signals a potential inflection point. The valuation of battery resources in capacity markets is evolving – one shaped increasingly by performance risk, regulatory scrutiny, and investor expectation.
Market View: SPP Grows to Survive
Power markets are expanding their footprint as they chase increased access to reliable generation under the pressure of tightening capacity fundamentals.
Last week FERC has approved Southwest Power Pool’s (SPP) proposal to incorporate nine entities, primarily cooperatives and members of the Western Area Power Administration, into its RTO, marking the first instance of a grid operator offering full market services across both the Eastern and Western Interconnections.
This expansion introduces 510 MW of new capacity and is projected to generate over $200 million annually in benefits, primarily through improved transmission efficiency.
Karbone Research expects these efficiencies to result in reduced costs and enhanced market liquidity, positively impacting capacity pricing and long-term market stability.
The new members, already involved in the Western Energy Imbalance Service market, will integrate into SPP’s Integrated Marketplace by April 2026. This integration is intended to improve resource balancing and allow more efficient dispatch as it expands SPP’s geographic reach. The improved market performance could bolster longer-term investments in generation as capacity pricing volatility is quelled.
FERC’s approval also includes charges for DC tie access, deemed necessary to cover the costs associated with connecting the two interconnections. The integration of these DC ties is intended to lead to more predictable capacity pricing, benefiting long-term investors and contributing to more robust market participation.
This expansion is a key component of SPP’s five-year strategic plan, Aspire 2026, and will extend its service area to 17 states. With this broader reach, SPP will further strengthen its capacity utilization and reliability, making it a more attractive investment opportunity for market participants.
Additionally, SPP’s development of Markets+ and management of the Western Power Pool’s Resource Adequacy Program further solidify its role as a central player in the Western market, presenting additional capacity investment prospects.
Market View: PJM RECs roiled by new state actions
Price structure for some of the most actively traded PJM renewable energy credits could shift as changes to local renewable portfolio standard programs take hold in Virginia, potentially compounded by proposed changes to a different program in New Jersey.
Virginia’s governor has until the end of the day on March 24 to sign HB 1883 ER, which has been passed by the state’s House of Delegates. The law moves a provision to the 2027 compliance year that 75% of the state’s RPS must be met by generation located in the Commonwealth. That change means Virginia’s leading generator, Dominion Energy, can purchase cheaper RECs generated in other parts of PJM, underpinning a fundamental bid for cross-qualified contracts even as Virginia REC generators face additional competition for the next two years.
Participants in New Jersey’s solar renewable energy credits program are also eyeing proposed adjustments to the state’s alternative compliance payment level.
New Jersey assembly bill A5460 would alter the outlook for the state’s SRECs program by moving the ACP orders-of-magnitude lower than the levels proposed in the original 1999 legislation. The bill, introduced this week by a trio of Democratic assembly members, would move the ACP price ceiling for NJ SRECs from $198/MWh in 2026 to $50/MWh next year.
The ACP would maintain a declining price cap structure, falling to $10/MWh before flattening at that level through the remainder of the program, which ends in 2033. The program originally allowed for a 2033 ACP of $128/MWh.
The New Jersey SRECs program has already been tightly restricted over the years. Only in-state solar qualifies, limiting the impact for the rest of the PJM RECs markets, in which many other state RECs cross-qualify and are able to retire in the highest-priced program.
The proposed changes to the ACP will also be accompanied by a bill that would require the state Board of Public Utilities to take the resulting savings for utilities buying SRECs to “reflect” those savings in electricity rate approvals.
The changes would have a significant financial impact on the remaining qualifying solar facilities delivering into New Jersey’s program through 2033. The Karbone Research merchant curve for NJ SRECs forecasts prices would never reach the current ACP but still hold more than $100/MWh over the proposed ACP over almost the entire remaining life of the program.
In 2026 alone, the financial impact of the proposed ACP adjustment could be as high as $360.5 million, as the $114.79/MWh discount to the current Karbone Research base case hits the state’s anticipated SRECs available supply. Based on recent trade for 2026 NJ SRECs, the discount could be even larger, stretching to $140/MWh for the prompt year.
Market View: BYOG, say regulators
A “bring your own generation” trend is sweeping U.S. power markets, as regulators acknowledge that current market structures won’t allow for sufficiently speedy additions of power to serve certain kinds of new load growth.
Karbone Research forecasts indicate, however, that BYOG matchmaking may do little to balance capacity market fundamentals.
A rebound in US load growth forecasts after decades of near-zero expansion in power demand has caught market coordinators by surprise and brought overloaded generation interconnection queues into the public spotlight.
On the other side of the fundamental equation, however, load interconnection queues are proving equally hard for market coordinators to forecast, both because they do not require public reporting and because power regulators have become unaccustomed to handicapping large scale load additions.
As capacity prices have become highly volatile in the interplay between less-than-credible generation forecasts and opaque load growth, regulators are increasingly telling planned large load additions in their regional markets that they must BYOG if they expect to connect: “Bring your own generation.”
By obligating large load, whether from data centers or from resurgent manufacturing demand to pre-contract for matching generation capacity in order to qualify for interconnection, power market participants say regulators hope to circumvent the trend for behind the meter backup generation that relies on the grid without contributing to it.
The processes by which large load is being matched to generation in capacity planning by ISOs remain on a case-by-case basis for now and is spread across individual utility commission and ISO and RTO filings.
Independent power producers are benefiting from the resulting premium-priced power purchase agreements, especially where they can reallocate existing assets to the higher-urgency demand and put incoming planned generation back into the broader power pool.
Those high-priced PPAs are in turn creating turmoil across other markets, where the premium for speedy “matching” generation is not available for other power assets that are contracting for new power sales.
The extent to which regulatory matchmaking between specific large load additions and specific available generation fends off higher capacity prices remains uncertain. Karbone Research modeling of forward merchant capacity pricing indicates that methodologies for awarding accreditation generally have a much higher weighting in capacity price formation than sheer generation availability.
Absent a responsive methodology that accounts for the right kind of capacity added to match with the particular characteristics of new load contracted in BYOG PPAs, imbalances may persist and the drive to add behind the meter gas may continue.
Market View: Behind the meter gas boom
Behind the meter natural gas generation is in danger of becoming the most “overbought” play in U.S. energy markets today.
At the CERAWeek conference in Houston, Texas last week, CEOs and their advisers had two things on their minds: AI dominance and the electrons and molecules required to achieve it.
With data center financing cresting after months of successively larger deals in both private and public markets, the question of how to power this infrastructure has shifted from price discovery to contractual urgency.
With renewable power intermittency and uncertain access to sufficient battery power coinciding with lengthy and overcrowded interconnection queues for both large load and the generation to serve it, the sector has all landed on the same solution at the same time: behind the meter natural gas.
Where existing pipelines can provide rapid delivery of the molecule and data center developers are able to secure modular turbines and power equipment, the redeployment of existing sites into power production facilities for data centers is already underway. These projects are underpinned by premium power purchase agreements that have warped the contracting environment for all other forms of power sales, as developers chase the fastest money from the biggest AI hyperscalers.
But the sheer volume of money and dealmakers chasing the same solution set is running up against fundamental deployment limitations. Equipment manufacturers and suppliers at CERAWeek were quoting the end of the decade as the soonest likely availability for new turbines, while electrical equipment suppliers were quoting 2028. Price quotes were up across the board as C-suite representatives from suppliers like Siemens and Caterpillar cited a “supercycle” in demand for turbines and expressed resistance to building out manufacturing capacity on spec.
In the power markets, regulators and their stakeholder utilities are pressing developers of behind-the-meter gas to guarantee they can serve front-of-the-meter markets as capacity tightens in power markets increasingly shaped by intermittent renewables. Data centers with behind the meter gas are customarily not entirely “islanded,” and their continued reliance on the grid means they could be subject to load-shifting requirements by regulators concerned about volatility.
Capacity models from Karbone Research demonstrate the unique role that natural gas generation can play in limiting upside volatility in power markets, when it can come online and bid into capacity provision. Merchant pricing forecasts for the SPP power market underline the fundamental logic behind natural gas additions, but where that gas capacity is soaked up by behind the meter demand its impact on capacity pricing is muted.
Market View: The Scene from CERAWeek
CERAWeek is underway in Houston and this year’s event underscored a rapidly evolving energy narrative.
The dominant theme to kick off CERAWeek 2025? Energy dominance through natural gas. From panel discussions to dealmaking in the side meeting rooms, the focus is squarely on securing long-term access to "molecules and midstream" infrastructure.
Market participants appear convinced that natural gas will remain the backbone of US energy security and global trade for years to come. Conversations about new gas infrastructure, expansion of LNG capacity, and strategic partnerships were constant. A revival in gas-fired power generation – driven by capacity market signals and data center growth – was a key talking point, reinforcing the sense that gas is back in a big way.
Even the tech sector is taking notice. Speculation about a major tie-up between a big tech company and a major energy player dominated late-night bar conversations. Everyone had their preferred scenario: “Microsoft could buy Exxon” was a phrase heard more than once, as industry veterans debated whether such a merger would be the only way both sectors could grow meaningfully at this point. The idea may sound far-fetched, but the underlying logic reflects the growing intersection of energy and data infrastructure.
Nuclear remains stuck in neutral. While small modular reactors (SMRs) continue to surface in panel discussions, there’s little confidence that nuclear power will scale meaningfully without an "all-of-government" policy push. The licensing process remains slow, and the infrastructure costs are massive. Most market participants remain focused on gas rather than betting heavily on nuclear, even as decarbonization goals remain in play.
On the geopolitical front, CERAWeek is delivering its share of eyebrow-raising moments, with Canada-US relations in focus. Trade tensions and cross-border disputes have heightened in recent months a new level of friction in US-Canada energy relations is apparent. Ontario Premier Doug Ford added fuel to the fire on Monday by imposing a 25% surcharge on electricity exports to the U.S. in retaliation for Trump’s latest round of tariffs, a move that could cost American consumers and businesses nearly CA$400,000 ($277,000) per day.
Meanwhile, crisis advisors are having a field day. Sessions on tariffs have been packed, and advisory firms are running back-to-back meetings with CEOs navigating the shifting trade landscape.
The signal from the opening sessions of CERAWeek 2025 is clear: natural gas is ruling the day, tech and energy could soon converge in unexpected ways, and geopolitical uncertainty is adding new layers of complexity to the energy outlook.
Market View: RA poised for a rebound
Prices for Cal 26 resource adequacy (RA) provision in CAISO may have overcorrected to the downside. The Cal 26 prices traced the Cal 25 prices sharply down over the last seven months.
Prompt-year RA collapsed lower in the second half of 2024 as load growth forecasts were revised downward and expectations of natural gas plant retirements were overturned. This one-two punch to pricing soon weighed on the forward curve, sending Cal 26 prices tumbling as 2024 ended, before meeting resistance around $15.00/kw-mo.
Meanwhile, pricing for future CAISO power delivery to SP15 has shifted higher in recent weeks, creating an energy-to-RA spread that indicates tighter fundamentals for the RA market – particularly among closely-watched “must-offer” units.
The Karbone forward curve for Cal 26 system RA prices has stabilized in recent weeks as the pace of current-year RA price declines has slowed, and concerns about rebalancing fundamentals – following the 2024 load growth shortfall – have reemerged among market participants.
Cal 26 RA retains a sharp premium over the forward curve through 2033, though Karbone price indications hold above a $10/kw-mo resistance level until 2029. CAISO system RA prices began moving above that level across the complex in mid-2022 as forward power availability appeared to tighten significantly, before surging higher in mid-2023.
History could repeat itself in coming sessions. The multi-month correction lower has brought RA pricing for forward years back within early 2022 bounds, creating a scenario where any resurgent concern about tightening markets could trigger a raft of higher-priced bids.
Market View: Surprising Allies for U.S. Hydrogen
An unlikely consortium of energy lobbyists and companies have joined forces to defend one of the least-utilized but potentially most generous IRA tax credits.
Institutions like the American Petroleum Institute have added their name to a letter to the U.S. Congressional leadership just as Congress begins a budgeting process explicitly targeting many of the Biden-era clean energy provisions.
Regulatory guidance on the 45V tax credit, issued in the closing weeks of the Biden administration, is designed to support rollout of low-carbon hydrogen, and was broadly seen by energy market participants as at-risk from this year’s budget cutting fever on Capitol Hill.
In recent days, industrial gas producer Air Products exited two hydrogen projects in New York and California and scrapped plans to build a carbon monoxide plant in Texas, taking a $3.1 billion hit – a reflection of fading developer confidence.
But the February 18 letter sent to US congressional leaders on behalf of the American hydrogen industry pushed back, emphasizing the significance of 45V and urging lawmakers to keep the tax credit in place.
The American Petroleum Institute previously released a statement on January 3 arguing that 45V ‘offers an opportunity for natural gas, when paired with carbon capture and storage, to compete more fairly in new markets.’ The new letter aligns the tax credit with the Trump administration’s “energy dominance” executive order, arguing that expanding hydrogen production would allow the US to compete with China and serve increased energy demand from data centers.
When first announced as part of the IRA’s passage in 2022, the hydrogen production incentives appeared to lay the groundwork for a boom in production, and several infrastructure funds raised billions of dollars in new capital to serve the industry. The roughly two-year process of refining the tax credit guidance and the focus on fossil fuels from the new presidential administration kept projects from moving ahead, and the Air Products cancellations are only the latest in a string of delays and pullbacks.
Given the profile of oil and gas in the current Trump administration, the support of API and other fossil fuel advocates and companies for 45V could prove vital in keeping the tax credits in place and finally unleashing allocated but unspent hydrogen capital.
Market View: The Paper Gas phenomenon
Energy investors often cohere around a single data point that can anchor analysis as turbulence persists the norm across market outlooks. In recent weeks, that number has been 80 gigawatts.
U.S. generators have announced tens of gigawatts of new gas-fired capacity entering interconnection queues in recent months, with a headline total of 80GW catching the attention of strategic planners and investors.
Part of the excitement around new gas generation lies in the suddenness of the reversal of fortune for the fuel. After a few years in which future gas fired generation appeared arguably de minimus in the US interconnection queue, a blend of AI data center need and capacity market pricing signals have reawakened the U.S. domestic gas-to-power story.
Many of these announced projects are leveraging underutilized legacy fossil fuel infrastructure, often taking advantage of existing but underused grid interconnections, to add meaningful amounts of new gas-fueled electrons into the US energy mix. While these units are frequently labeled as “behind the meter,” complicating power market forecasting, the overall impact is clear: gas is set to play a larger role in the future U.S. power mix.
However, banks, investors, and energy market participants may be overestimating the viability of greenfield natural gas development. The recent surge in announcements comes at a moment when a tech-fueled bid for firm power and a fossil fuel-friendly administration appear to be resetting U.S. energy policy.
Yet markets have seen this before. Over the past decade, “paper electrons” have become a familiar phenomenon – renewable energy projects that secure early equity commitments, shift market sentiment, and reshape pricing forecasts but never fill out their capital stack or reach commercial operation. Historically, less than a quarter of announced generation projects reach the grid on schedule, and there’s little reason to believe greenfield gas projects will fare differently.
Already, tech firms like Microsoft are pulling back from the upper range of their data center capex forecasts, undermining the bullish gas narrative for investors. Market participants are now watching for signs of “paper gas” – projects with a low likelihood of ever securing financing or breaking ground.
For project financiers and environmental credit traders, who are eyeing shifting fundamentals for environmental attributes, a peak in gas project announcements at the widely discussed 80GW figure in early 2025 could signal tightening in REC markets and rising prices. But if a significant portion of this “paper gas” fails to materialize, it could loosen REC fundamentals – even in programs designed to tighten supply over time.
Market View: FERC Confronts Co-Location Conundrum
PJM and its transmission owner members have just a few weeks to either justify current tariff structures for co-located large load or suggest reforms, FERC said.
FERC’s unanimous vote on February 20 signaled a decisive stand in a complex regulatory battlefield as it launches a consolidated review of co-located large loads in the PJM region.
By merging dockets EL25-49-000, AD24-11-000, and EL25-20-000 into a single show-cause proceeding, the Commission is zeroing in on longstanding ambiguities in PJM’s Open Access Transmission Tariff.
The action follows Constellation Energy Generation’s November 2024 complaint under Section 206 of the Federal Power Act, which challenged the tariff for failing to offer clear, equitable rules for behind-the-meter co-location – especially as digital giants and AI-enabled data centers fuel a surge in load demand.
FERCs newly appointed Chairman Mark Christie downplayed the impact of President Donald Trump's executive order asserting greater control over independent agencies and simultaneously made it clear that the time for incremental tweaks is over.
With forecasts pointing to up to 30 GW of additional peak load over the next five years – largely driven by the rapid growth of digital infrastructure – the consolidated proceeding has broad implications as regulatory frameworks struggle to keep up with evolving load growth.
In an environment where digital infrastructure growth and energy reliability are inextricably linked, a more proactive stance from FERC could catalyze a more stable regulatory environment. The objective is to balance innovation with the enduring imperatives of grid stability and consumer protection.
FERC’s decisive action could come to represent more than just a recalibration of tariff rules; as a rejection of “business as usual” it could form a bold step toward aligning market signals with the evolving realities of the energy landscape.
As stakeholders brace for a 60-day cycle of public comments and replies, investors and operators alike will be watching closely to see how these reforms shape the future of co-location.
Market View: Load growth durability
Can US load growth survive a recession?
The U.S. has gone nearly a quarter of a century without a “normal” business-cycle recession, though the long-tail “great recession” that followed the financial crisis and the short-lived COVID crisis recession both counted even if neither were textbook recessions.
The long, albeit uneven, expansion of the world’s largest economy has been accompanied by intermittently but meaningfully expanded market engagement by the federal government into both credit markets and supply-side support, masking the impact of steadily increasing corporate, financial and sovereign indebtedness.
At the same time, the U.S. has lagged in building new power sector infrastructure. Even in a modern economy increasingly driven by less energy-intensive industries, it is striking that U.S. GDP has nearly tripled to just under $29 trillion over the past 25 years, while power generation capacity has grown by only 20% in the same timeframe.
U.S. investors and companies have grown accustomed to extracting ever-greater efficiencies from an aging grid, despite recent waves of investment that, if anything, have introduced more uncertainty around grid reliability. The key question now is whether a U.S. recession could derail the long-awaited revival in dispatchable generation and energy storage investment.
Much of this investment is being driven by cash-rich balance sheets at technology firms rather than traditional ratepayer-backed utilities willing to socialize costs through rising power prices. But in a business cycle recession, as banks and credit providers tighten lending in response to rising defaults, generation plans reliant on corporate spending rather than broad-based power tariff boosts could disappear as quickly as they emerged.
Recent Karbone Research reviews of forward power and capacity pricing fundamentals highlight how net short power supply could become in many U.S. markets over the next decade. In SPP alone, while installed nameplate capacity is expected to nudge higher by 5GW through the end of the decade, actual available capacity will decline by 3GW as fossil retirements outpace the addition of batteries and renewable generation.
The critical question is whether this widening shortfall in U.S. power and capacity markets will be enough to sustain investment in new generation and interconnection through a recession.
With corporate defaults rising and trade war disruptions ricocheting through manufacturing and consumer sectors of the U.S. economy, the risk of a long-delayed U.S. recession no longer seems like an abstract concern. Investors and traders will be closely watching first-quarter earnings in April for any signs of capital expenditure pullbacks – an early indicator of further volatility in power markets, which could remain fundamentally undersupplied even longer than current forecasts envisage.
Market View: Alternative chemistries as a defense play
A fire in California and a speech in Munich have an important, if unlikely, connection: both underscore the urgent need to commercialize alternative battery chemistries.
The explosive fire at the Moss Landing battery energy storage plant in California could have lasting repercussions as battery manufacturers reevaluate the energy ratings of their units, with underpriced fire risk likely to result in higher costs and tighter insurance underwriting standards.
More critically, a broader downgrade in how power and capacity markets assess battery unit availability could weaken the revenue economics of these systems – just as large-scale lithium-ion energy storage is poised to support extensive renewable additions to the U.S. grid.
Alternative battery chemistries have long demonstrated superior fire safety but have struggled to match lithium-ion’s energy density and grid performance. The dominance of lithium-ion packs has remained largely unchallenged, preventing alternative chemistries from reaching commercial scale.
Unexpectedly, it may be that defense applications provide a path to market for alternative battery chemistries that overturn the long-standing dominance of the lithium-ion pack in energy markets.
European stock markets surged Monday on expectations of increased military spending following the Trump administration’s abandonment of long-standing European security guarantees. The shift followed a speech by U.S. Vice President JD Vance in Munich, which signaled that traditional alliances underpinning the war in Ukraine were no longer valid as the U.S. engaged directly with Russia on a peace deal.
With drones, robotics, and distributed energy supply lines playing an increasingly dominant role, military technology trends are aligning with renewable power and battery deployment at scale. Firms like Anduril are now experimenting with alternative battery chemistries better suited for long-range battlefield operations rather than fast-start grid services.
Military technologies have a long tradition of finding industrial applications, and over the U.S. Presidents Day weekend, battery energy storage developers told Karbone Research they were fielding new inquiries as the technology landscape expanded – both due to heightened fire risk and the anticipated surge in European defense spending.
Several industry figures noted that the largest fuel market shifts in history have generally occurred as a result of military conflicts that drove large scale infrastructure spending to accommodate evolving technology. Just as the British Navy’s preparations for World War II ended coal’s dominance and ushered in the oil age, today’s emerging global conflicts may accelerate the transition to the “battery age”.
Market View: D3 RINS outlook
Fundamental price forecasts for D3 RINs prices imply that recent selloffs may be overdone.
Karbone’s newly available D3 RIN merchant curve forecast shows that 2025 prices are likely to pop higher across all three base, low and high cases. Even the low case shows fundamental support at a floor 50 cents to a dollar per RIN over the general pricing level seen during the last Trump administration.
Market participants have noted to Karbone in developing this forecast that fundamental analysis can only go so far in a market where retroactive readjustments are the rule and prices swing wildly on any indication of shifts in policy. Nonetheless, it would take targeted and deliberate action by regulators to drive prices lower under current supply and demand conditions for the underlying molecules, Karbone analysis demonstrates.
And in the flood of early action from the new Trump administration, US federal government support for biofuels via the EPA-administered RVO has stayed out of the limelight, giving investors hope that the program will stay largely intact.
Karbone’s low and base cases assume a readjustment of the 2025 RVO, while the high case reflects a scenario in which the RVO will not be readjusted. Karbone Research continues to monitor changes to make timely adjustments to our merchant curve outlook.
Investors gathered in New Orleans for the Projects and Money conference last week said they expect to see continued support for biodiesel and renewable natural gas via the EPA programs under the Trump administration.
Project developers and backers said they were pressing legislators for a renewal of the blenders tax credit to replace the new 45Z credit created by the IRA, as many operators see a step-down in value from the new policy. The new policy remains at risk from Congressional action after its finalization in the closing days of the Biden presidency.
Karbone prices for D3 RINs could hold higher over the next decade in instances where CNG trucking drives accelerated demand and supply additions remain constrained. Increased availability of larger engines that can use CNG and ongoing development of fueling infrastructure would both lift overall demand.
But the wide dispersion of potential price outcomes for D3 RINs in the Karbone merchant curve forecast also show cases where prices steadily grind lower to land closer to $1.20/RIN, reflecting the continued regulatory risk to investors, operators and developers relying on RIN revenue to underpin projects.
Market View: Synthetic single asset power plays
A new asset type is becoming increasingly popular among energy financiers and investors seeking to profit from volatile intraday power prices and anticipated sustained firm capacity shortages in developed economies.
The “synthetic CCGT” concept drew heightened attention from the U.S. energy project finance community during the Projects and Money conference in New Orleans last week. The colocation of solar, batteries, and a gas peaker into a single unit, combining the reliability characteristics of a gas plant with the emissions and cost profile of solar and the rapid-start ancillary and the grid services rewards associated with batteries, can create a financing profile similar to legacy combined-cycle gas turbines.
The colocation of renewables with batteries on the same site, often behind the meter, has been an accelerating trend in recent years as federal and state incentives have accelerated cost declines in renewables while also undermining the modeled reliability of grid performance. Expanding colocation to include a natural gas peaker unit – designed to run less than 30% or even 20% of the time – goes further to match current power market conditions with price and emissions sensitivities.
Grouping seemingly dissimilar assets into a single “energy campus” that can then be project- and asset-financed as a single ringfenced unit is also a better match than a full fleet of projects or assets for many of the best-capitalized financial investors in U.S. energy in 2025.
Middle-market debt funds and private infrastructure groups prefer the check size and risk profile of financing single assets over backing larger utility- and IPP-led power supply rollouts, which can face intensified interconnection queue backlogs and other regulatory constraints.
Matching merchant power risk appetite to individual regions further drives the preference for single-asset plays over corporate lending, and with much of the sector’s capital continuing to originate from energy transition funds, pure-play fossil fuel project development absent a renewable component are still finding long-term project financing conditions choppy.
With U.S. federal support for core production and investment tax credits anticipated to remain largely intact under the Trump administration, the new “synthetic” structure integrates diverse attributes that enhance asset financeability.
Project financiers in New Orleans expected gas peakers to be the most common pairing with renewables, but said they do see deal flow for alternative structures, including combining small hydropower, SMR nuclear units, and even retirement-delayed coal units into new synthetic single-asset plays for new capitalization or refinancing.
Market View: Price caps rock U.S. power outlook
New price caps imposed on capacity in the largest U.S. power market are too low to underpin financing for new generation buildout and may “freeze” supply additions in the PJM transmission grid even as power demand rises.
Project financiers, bankers, investors and developers at the Projects and Money conference in New Orleans this week have been meeting against the background of repeated waves of turmoil across U.S. energy markets, as resurgent demand meets unsettled governance.
PJM’s decision to abandon its defense of this part of it’s capacity market structure amid objections from state governors over rising power prices marks the latest disruption in power and capacity price formation. Ongoing auction delays, shifts in accreditation methodologies, and shifting regulatory goalposts have already deterred investors.
Ultimately, politicians and regulators may be forced to choose between rising prices and what will amount to energy rationing, one leading U.S. infrastructure investor said at the conference.
Concerns about the potential for retroactive capping of prices in existing capacity agreements, which the agreement between PJM and the state governors does not directly address, has already resulted in deal cancellations.
Completed capacity deals representing hundreds of megawatts were pulled, and Calpine reversed course on PJM generation investment it had announced only six months ago, as it said this week it would divest four natural gas units in PJM ahead of its proposed merger with Constellation.
A wholesale reorganization and reregulation of power markets to a universal rate-basing environment of guaranteed profits and central planning, undoing decades of efforts to create workable investment signals in U.S. power markets, could unfold in coming years if regulators prove consistently unable to manage load growth.
With capped capacity prices undermining efforts to add generation, REC markets could also see dislocation, with the energy mix failing to add new renewables or new fossil plants even as RPS targets tighten.
Projects already being slow-walked for both renewables and fossil generation will come under even more scrutiny from lenders and investors in the wake of the PJM decision. While other RTOs are not facing the same conditions as PJM, political interventions in power sector investment are become increasingly common across the country as prices rise in response to increasing load growth and overloaded interconnection queues.
