[GUEST ACCESS MODE: Data is scrambled or limited to provide examples. Make requests using your API key to unlock full data. Check https://lunarcrush.ai/auth for authentication information.]  TheValueist [@TheValueist](/creator/twitter/TheValueist) on x 1567 followers Created: 2025-07-22 20:34:44 UTC $CEG $VST $TLN $NRG The 2026/2027 PJM Base Residual Auction cleared XXXXXXX MW UCAP at the FERC‑approved cap of $329.17/MW‑day across every zone, versus $269.92/MW‑day RTO‑wide in the prior auction and well below the prior‑year zonal highs of $466.35/MW‑day and $444.26/MW‑day in BGE and Dominion. The uniform clearing at the cap implies that marginal supply is now system‑wide rather than local, confirming that the upward step change in the administrative cap implemented this cycle instantly became binding. Aggregate capacity revenues for the delivery year will rise approximately XX % for RTO‑wide resources, decline about XX % in BGE and XX % in Dominion, and lift total PJM capacity cash flows by roughly $XXX B despite mixed zonal effects. That incremental value feeds directly into merchant free cash flow and raises discounted valuations for at‑risk thermal fleets by an estimated $65–$75 k/MW of net summer capacity, depending on leverage assumptions. Auction fundamentals show a system running almost friction‑tight: cleared supply exceeded the reliability requirement by only XXX MW UCAP, equivalent to XXXX % of the target, while peak‑load growth of XXXXX MW yr‑on‑yr outpaced the net build rate. Cleared resource composition—45 % gas, XX % coal, XX % nuclear, X % hydro, X % wind, X % solar—underscores that conventional thermal remains indispensable after a decade of renewable build‑out. Deactivation withdrawals totaling XXXXX MW and XXXXX MW of new UCAP represent the first positive net supply response in X auctions yet still leave reserve margin headroom razor‑thin. PJM’s own Reliability Resource Initiative attracted XXXXXX MW ICAP of future project interest, but none is commercially operational before 2027/2028, implying structurally tight conditions through at least the next auction cycle. For merchant generation owners the cap‑clearing outcome materially extends the economic runway of mid‑merit combined‑cycle gas and even coal assets that were previously poised for retirement. EBITDA uplift from capacity alone is sufficient to cover as much as XX % of fixed O&M for older coal units and XX % for flexible gas peakers, improving optionality around energy‑market participation and ancillary products. Nuclear operators gain the highest absolute dollar uplift per MW given their large, largely unhedgeable fixed cost base, strengthening thesis support for uprate investment and second‑license renewal financing. Conversely, vertically integrated utilities with large retail footprints but limited merchant exposure will experience modest retail cost pressure, but regulated cost‑recovery frameworks blunt earnings impact, limiting investment committee trade opportunities on that side of the ledger. Developers of new renewables and storage face a more nuanced signal. Expanded must‑offer rules eliminate the ability to withhold intermittent or battery resources, increasing realized capacity penetration, but the new floor of $177.24/MW‑day sets a downside bound that improves revenue certainty needed for non‑recourse financing. Nonetheless, the fact that wind and solar combined captured only X % of cleared UCAP despite comprising XX % of the interconnection queue highlights enduring capacity accreditation discounts and interconnection bottlenecks. PJM has processed XX % of its transition backlog and targets full clearance within XX months, yet external hurdles—permits, supply chain, tax equity timing—mean that only a fraction of the XXXXXX MW ICAP of approved resources will reach commercial operations before 2030. Near‑term project delay risk therefore supports a structurally undersupplied capacity market and favors developers positioned with late‑stage, shovel‑ready projects and balance‑sheet resilience. Regulatory risk remains the principal counterbalance to a medium‑term bullish view. FERC’s price‑formulation docket and PJM’s capacity performance reforms could reopen debate on the cap, non‑performance penalties, and resource classification. State‑subsidized resources and offshore wind carve‑outs continue to exert political pressure for carve‑outs or downward cost allocation, while consumer advocates already point to retail bill impacts despite the modest projected 1.5–5 % increase. Any move to re‑impose a three‑year forward auction schedule could change offer behavior and the demand curve shape, but such changes will be incremental to, not immediate substitutes for, physical capacity scarcity. Gas infrastructure optionality strengthens under a XX % gas‑dominated capacity stack. Data‑center and electrification‑driven load growth occurs disproportionately in Dominion, PEPCO, and DPL South, areas constrained by pipeline takeaway and compressor station permitting. Basis widening in Transco Z5 North and Dominion South hubs is probable, benefiting midstream owners with latent expansion capacity and compression rights. Coal dispatch hours will rise on the margin during winter reliability events, pulling CSX‑served NAPP coal demand higher but still within existing logistics capacity; upside is capped by ESG policy durability and aging unit heat‑rate economics. Relative value positioning favors going long PJM merchant generation equities and capacity strips while shorting ERCOT‑only merchant peers where reserve margins are expanding. Within PJM, leverage to the price cap is greatest for independent generators with high UCAP‑to‑ICAP ratios and minimal hedging—Vistra, Talen, and LS Power generation portfolios screen best. A paired trade of long PJM‑centric gas peaker tolls versus short Midwest ISO capacity forwards captures divergent reserve trajectories. For credit investors, the auction result materially improves interest coverage metrics, supporting spread tightening of 25–40 bp on subordinated tranches of merchant IPP debt. Looking ahead, the December 2025 auction for 2027/2028 is highly likely to clear at or near the cap given that net load growth outstrips visible supply additions through 2028 by roughly XXXXX MW UCAP under base‑case assumptions. Downside to capacity pricing would require an 8,000‑MW UCAP surprise build or a regulatory cap cut, each less than XX % probability. The investment committee should therefore expect a multiyear window in which PJM capacity provides above‑mid‑cycle returns, warranting incremental capital deployment into flexible gas assets, distressed coal optionality plays, and late‑stage renewable projects capable of monetizing both energy and capacity stacks. Maintain vigilance on FERC rulemaking, state policy shifts, and interconnection project attrition rates, but base‑case portfolio positioning should remain pro‑capacity through at least the 2028/2029 delivery year. XXXXX engagements  **Related Topics** [nrg](/topic/nrg) [$44426mwday](/topic/$44426mwday) [$46635mwday](/topic/$46635mwday) [$26992mwday](/topic/$26992mwday) [$32917mwday](/topic/$32917mwday) [auction](/topic/auction) [$nrg](/topic/$nrg) [$vst](/topic/$vst) [Post Link](https://x.com/TheValueist/status/1947757225956581800)
[GUEST ACCESS MODE: Data is scrambled or limited to provide examples. Make requests using your API key to unlock full data. Check https://lunarcrush.ai/auth for authentication information.]
TheValueist @TheValueist on x 1567 followers
Created: 2025-07-22 20:34:44 UTC
$CEG $VST $TLN $NRG The 2026/2027 PJM Base Residual Auction cleared XXXXXXX MW UCAP at the FERC‑approved cap of $329.17/MW‑day across every zone, versus $269.92/MW‑day RTO‑wide in the prior auction and well below the prior‑year zonal highs of $466.35/MW‑day and $444.26/MW‑day in BGE and Dominion. The uniform clearing at the cap implies that marginal supply is now system‑wide rather than local, confirming that the upward step change in the administrative cap implemented this cycle instantly became binding. Aggregate capacity revenues for the delivery year will rise approximately XX % for RTO‑wide resources, decline about XX % in BGE and XX % in Dominion, and lift total PJM capacity cash flows by roughly $XXX B despite mixed zonal effects. That incremental value feeds directly into merchant free cash flow and raises discounted valuations for at‑risk thermal fleets by an estimated $65–$75 k/MW of net summer capacity, depending on leverage assumptions.
Auction fundamentals show a system running almost friction‑tight: cleared supply exceeded the reliability requirement by only XXX MW UCAP, equivalent to XXXX % of the target, while peak‑load growth of XXXXX MW yr‑on‑yr outpaced the net build rate. Cleared resource composition—45 % gas, XX % coal, XX % nuclear, X % hydro, X % wind, X % solar—underscores that conventional thermal remains indispensable after a decade of renewable build‑out. Deactivation withdrawals totaling XXXXX MW and XXXXX MW of new UCAP represent the first positive net supply response in X auctions yet still leave reserve margin headroom razor‑thin. PJM’s own Reliability Resource Initiative attracted XXXXXX MW ICAP of future project interest, but none is commercially operational before 2027/2028, implying structurally tight conditions through at least the next auction cycle.
For merchant generation owners the cap‑clearing outcome materially extends the economic runway of mid‑merit combined‑cycle gas and even coal assets that were previously poised for retirement. EBITDA uplift from capacity alone is sufficient to cover as much as XX % of fixed O&M for older coal units and XX % for flexible gas peakers, improving optionality around energy‑market participation and ancillary products. Nuclear operators gain the highest absolute dollar uplift per MW given their large, largely unhedgeable fixed cost base, strengthening thesis support for uprate investment and second‑license renewal financing. Conversely, vertically integrated utilities with large retail footprints but limited merchant exposure will experience modest retail cost pressure, but regulated cost‑recovery frameworks blunt earnings impact, limiting investment committee trade opportunities on that side of the ledger.
Developers of new renewables and storage face a more nuanced signal. Expanded must‑offer rules eliminate the ability to withhold intermittent or battery resources, increasing realized capacity penetration, but the new floor of $177.24/MW‑day sets a downside bound that improves revenue certainty needed for non‑recourse financing. Nonetheless, the fact that wind and solar combined captured only X % of cleared UCAP despite comprising XX % of the interconnection queue highlights enduring capacity accreditation discounts and interconnection bottlenecks. PJM has processed XX % of its transition backlog and targets full clearance within XX months, yet external hurdles—permits, supply chain, tax equity timing—mean that only a fraction of the XXXXXX MW ICAP of approved resources will reach commercial operations before 2030. Near‑term project delay risk therefore supports a structurally undersupplied capacity market and favors developers positioned with late‑stage, shovel‑ready projects and balance‑sheet resilience.
Regulatory risk remains the principal counterbalance to a medium‑term bullish view. FERC’s price‑formulation docket and PJM’s capacity performance reforms could reopen debate on the cap, non‑performance penalties, and resource classification. State‑subsidized resources and offshore wind carve‑outs continue to exert political pressure for carve‑outs or downward cost allocation, while consumer advocates already point to retail bill impacts despite the modest projected 1.5–5 % increase. Any move to re‑impose a three‑year forward auction schedule could change offer behavior and the demand curve shape, but such changes will be incremental to, not immediate substitutes for, physical capacity scarcity.
Gas infrastructure optionality strengthens under a XX % gas‑dominated capacity stack. Data‑center and electrification‑driven load growth occurs disproportionately in Dominion, PEPCO, and DPL South, areas constrained by pipeline takeaway and compressor station permitting. Basis widening in Transco Z5 North and Dominion South hubs is probable, benefiting midstream owners with latent expansion capacity and compression rights. Coal dispatch hours will rise on the margin during winter reliability events, pulling CSX‑served NAPP coal demand higher but still within existing logistics capacity; upside is capped by ESG policy durability and aging unit heat‑rate economics.
Relative value positioning favors going long PJM merchant generation equities and capacity strips while shorting ERCOT‑only merchant peers where reserve margins are expanding. Within PJM, leverage to the price cap is greatest for independent generators with high UCAP‑to‑ICAP ratios and minimal hedging—Vistra, Talen, and LS Power generation portfolios screen best. A paired trade of long PJM‑centric gas peaker tolls versus short Midwest ISO capacity forwards captures divergent reserve trajectories. For credit investors, the auction result materially improves interest coverage metrics, supporting spread tightening of 25–40 bp on subordinated tranches of merchant IPP debt.
Looking ahead, the December 2025 auction for 2027/2028 is highly likely to clear at or near the cap given that net load growth outstrips visible supply additions through 2028 by roughly XXXXX MW UCAP under base‑case assumptions. Downside to capacity pricing would require an 8,000‑MW UCAP surprise build or a regulatory cap cut, each less than XX % probability. The investment committee should therefore expect a multiyear window in which PJM capacity provides above‑mid‑cycle returns, warranting incremental capital deployment into flexible gas assets, distressed coal optionality plays, and late‑stage renewable projects capable of monetizing both energy and capacity stacks. Maintain vigilance on FERC rulemaking, state policy shifts, and interconnection project attrition rates, but base‑case portfolio positioning should remain pro‑capacity through at least the 2028/2029 delivery year.
XXXXX engagements
Related Topics nrg $44426mwday $46635mwday $26992mwday $32917mwday auction $nrg $vst