Missing Money and Scarcity Pricing — ORDC, VOLL, Capacity vs Energy-Only, ELCC, RA Accreditation

Missing Money and Scarcity Pricing

1. At a glance

The missing money problem is the structural shortfall in wholesale electricity revenue that prevents generators from recovering their fixed (annuitised) capital costs in pure energy-only markets with capped prices. It is the central market-design question of the modern restructured electricity sector: should regulators tolerate (and engineer) high scarcity prices in the energy market to incentivise capacity investment, or should they procure capacity in parallel forward auctions while keeping energy prices bounded? The answer divides the world.

ERCOT (Texas) is the canonical energy-only market — no capacity market, scarcity pricing via the Operating Reserve Demand Curve (ORDC), system-wide offer cap currently $5,000/MWh. PJM + MISO + NYISO + ISO-NE + the UK Capacity Market + most of continental Europe + Australia (capacity investment scheme overlay) are capacity-market or hybrid designs. CAISO uses a bilateral Resource Adequacy obligation with no centralised auction. The debate has run for thirty years across academic + regulatory + political arenas, and the 2021 Texas Uri event + the 2024 PJM 2025/26 BRA price explosion have reignited it on both sides.

This note is the focused reference combining what would otherwise be two thin notes — missing money + price caps, and scarcity pricing theory. It covers: the theoretical missing-money problem (Cramton-Stoft-Joskow framing); price caps and bid caps and their interaction with capacity adequacy; ORDC mechanics (Hogan-Pope design, ERCOT 2014 + 2019 + 2022 implementations); Winter Storm Uri 2021 + PCAP (peak cap action plan) + post-Uri reforms; energy-only vs capacity-market vs hybrid architectures (with PJM RPM + Reliability Pricing Model as the capacity benchmark); shortage pricing mechanisms (Hogan formulation); VOLL (Value of Lost Load) estimation methodologies; RA accreditation methods (CAISO RAAIM); capacity accreditation reforms (PJM ELCC, MISO seasonal SAC).

See electricity-markets-and-grids for the broader market structure context; capacity-and-ancillary-services-markets for product-by-product capacity + AS detail; ferc-and-grid-policy for the federal regulatory layer + MOPR debate.

2. The missing money problem

2.1 Theoretical statement

Consider a price-taking competitive generator with annual fixed cost F ($/kW-year)andvariablecostMC($/MWh). In a frictionless competitive energy market, the generator should recover F through infra-marginal rents plus scarcity rents:

Annual revenue per kW  =  Σ_h max(0, P_h − MC) · 1{unit running}
                       =  Σ_h (P_h − MC) · 1{P_h > MC}

Under a sufficiently high price cap (above VOLL during scarcity hours), the integral equals F at the optimal entry rate — entry continues until annual revenue equals annual fixed cost.

The missing money problem arises when (a) the offer cap is set below VOLL — say, $1,000/MWhor$5,000/MWh rather than $20,000-$50,000/MWh — or (b) administrative scarcity adders are too small to deliver the full implicit capacity rent, or (c) out-of-market reliability actions (RMR contracts, emergency operating procedures, strategic reserves) suppress scarcity prices, or (d) regulator + ISO operational interventions prevent scarcity prices from clearing the market during truly tight hours.

Under any of these conditions, the marginal generator cannot recover fixed costs from energy + AS market revenue alone, even at the social-reliability-optimal entry rate. Investment dries up. Reliability deteriorates absent intervention. The “missing” revenue is the gap between the cap-bounded actual revenue and the unconstrained scarcity rent that would have prevailed in a frictionless market.

2.2 Cramton-Stoft-Joskow framing

Stoft 2002 Power System Economics is the canonical textbook treatment. Stoft’s framing: missing money is a regulatory artefact, not a fundamental property of electricity markets. Remove price caps + permit scarcity pricing + allow load-side participation, and the missing money disappears.

Cramton + Stoft 2005 A Capacity Market that Makes Sense + Cramton + Stoft 2008 Forward Reliability Markets. Counter-view: capacity markets are the institutional accommodation to a political reality of price-cap regulation. Without capacity markets, regulators eventually impose Reliability Must-Run (RMR) contracts + bilateral procurement + Integrated Resource Plan requirements that achieve the same outcome with less transparency. The choice is between explicit capacity markets and implicit ones; explicit wins on transparency + investor signal clarity.

Joskow 2007 Competitive Electricity Markets: Have they been worked out? (Yale Journal on Regulation) + Joskow 2008 Capacity Payments in Imperfect Electricity Markets: detailed empirical + theoretical case for capacity markets given price-cap regulation realities. Joskow points to political unwillingness to tolerate sustained $9,000/MWh price spikes, plus the operational interventions ISOs make during scarcity (capacity emergency steps, voltage reductions, load shedding) that suppress true clearing prices.

Hogan 2005 On an “Energy Only” Electricity Market Design for Resource Adequacy + multiple subsequent papers by Hogan + Pope: defends the energy-only design with an explicit Operating Reserve Demand Curve (ORDC) that lifts the energy clearing price toward VOLL as reserves tighten. Hogan + Pope designed the ERCOT ORDC implemented in 2014 and refined post-Uri. Hogan’s position: capacity markets distort entry by paying for nameplate capacity rather than for delivered scarcity-hour energy; if scarcity pricing is properly engineered + permitted, the missing money disappears.

The Stoft-Hogan vs Cramton-Joskow debate has run for 20+ years. The empirical answer is messy. ERCOT pre-Uri (2014-2020) seemed to vindicate Hogan: scarcity pricing delivered the reliability target without a capacity market, despite low reserve margins. ERCOT 2021 Uri + 2023-24 reserve tightness shifted the empirical balance toward capacity markets. PJM 2024 BRA price explosion + MISO 2024 PRA CONE-cap simultaneously shifted toward the other side — capacity markets are not delivering investment + reliability either when stress hits.

2.3 Why the gap exists

Several intersecting reasons price caps + administrative interventions create missing money:

• Political tolerance for high prices is low. \$9,000/MWhx100hours=$900/MWh average retail-supply impact for those hours; spread over a month it’s a noticeable bill increase; spread over a year via REP pass-through it’s a politically explosive rate-shock event. Even sophisticated regulators (PUCT, FERC) face strong constituent pressure to cap.
• Market power concerns — when scarcity prices clear, the marginal supplier often has significant local market power; cleared price reflects power + scarcity together. Independent market monitors apply bid mitigation (Conduct + Impact tests) that effectively cap bids during constrained conditions.
• Demand elasticity is thin. True real-time load response below 1-2% of peak in most ISOs as of 2024-26. Without elastic demand, scarcity prices have no “natural” ceiling other than supply cost + administrative cap.
• Operator reliability interventions — capacity emergency steps + voltage reduction + load shedding clip scarcity pricing because clearing happens before the load is actually shed. The Hogan critique: shedding load involuntarily at $1,000/MWhisequivalenttovoluntaryload-shedat$1,000/MWh, which understates VOLL.
• VOLL estimation is highly uncertain — credible estimates range from $5,000/MWhto$50,000/MWh depending on sector + outage duration + study methodology. Setting administrative cap at any specific level is contestable.
• Risk aversion of investors — even with high expected scarcity revenue, investors discount variable revenue streams heavily; fixed capacity payments are preferred (lower risk premium, easier debt financing).

3. Operating Reserve Demand Curve (ORDC)

3.1 Hogan-Pope design

Hogan + Pope 2014 Demand-Side Reserve Pricing in the Texas ERCOT Wholesale Electricity Market — design proposal commissioned by ERCOT. Subsequently implemented + iteratively refined.

The core idea: real-time energy prices should reflect the probabilistic value of available operating reserves. When reserves are abundant, the marginal value of an additional MW of reserves is near zero. As reserves tighten toward minimum-contingency levels, the marginal value rises sharply — both because the probability of activating the next contingency rises + because the consequence of activation (rolling outages) is severe.

ORDC adder formula (simplified):

ORDC_adder_t  =  LOLP(R_t)  ×  (VOLL − P_energy_t)
                  ─────────       ─────────────────
                  loss-of-load    expected economic
                  probability      damage at marginal
                  given current   shortfall
                  reserves R_t

• LOLP(R_t) — Loss-of-Load Probability as a function of current operating reserves R_t. Approaches 1 as R_t falls toward zero; near zero when R_t is comfortably above the largest single contingency.
• VOLL — Value of Lost Load (the economic damage per MWh of involuntary load shed). ERCOT VOLL set at $9,000/MWhoriginally;post-Uri2022reductionto$5,000/MWh.
• P_energy_t — the energy clearing price absent the ORDC adder.

The ORDC effectively lifts the real-time clearing price by the expected economic damage of shortage, even when explicit shedding has not occurred. Generators offering operating reserves are compensated for the option value of being available, which is highest precisely when reserves are scarcest.

3.2 ERCOT implementation: 2014 + 2019 + 2022

2014: ERCOT implemented the original Hogan-Pope ORDC alongside SCED with the operating reserve demand curve calibrated against a Brattle Group + Hogan study. VOLL set at $9,000/MWh.

2019 refinements: ERCOT introduced Reliability Deployment Price Adder (RDPA) + adjusted ORDC parameters to address dispatch behaviour + scarcity-revenue distribution issues.

Post-Uri 2022 reforms: After Winter Storm Uri (Feb 2021), the Texas legislature (SB 3 + SB 2 + HB 17) and PUCT issued multiple orders:

• VOLL lowered from $9,000to$5,000/MWh as part of the System-Wide Offer Cap reduction.
• ORDC curve recalibrated against post-Uri load + outage data.
• Operating Reserve floor (X) raised from 2,000 MW to 3,000 MW (the reserve level at which ORDC adder becomes substantial).
• Performance Credit Mechanism (PCM) proposed by PUCT 2023 — administrative credit for energy generated during specified scarcity hours, complementing the energy-market revenue stream. PCM under design 2024-26 amid political + legal pushback; as of mid-2026, ERCOT remains a pure energy-only market in practice.
• New ancillary product ECRS (Contingency Reserve Service) added 2023 for 10-minute response, providing additional scarcity revenue stream for resources able to ramp quickly.

The 2022 lowered offer cap (from $9,000to$5,000/MWh) and the slowdown in scarcity-pricing accumulation post-Uri have triggered fresh missing-money concerns. ERCOT reserve margins remain tight; investment in dispatchable thermal slow; storage + solar leading new entry but ELCC discounts reducing scarcity revenue attribution.

3.3 ORDC adoption beyond ERCOT

The Hogan-Pope ORDC concept has been partially adopted elsewhere:

• CAISO introduced a Scarcity Reserve Demand Curve (SRDC) in 2023 — analogous mechanism for spinning + non-spinning reserves.
• MISO introduced Emergency Demand Response Resource (EDRR) + administrative scarcity adders during emergency conditions.
• PJM introduced Reserve Pricing Reform under FERC Order 825 directives — adds scarcity-pricing-like adders for synchronised + non-synchronised reserves under operating-reserve shortages.
• Australia NEM uses a high cap product + co-optimised AS clearing that delivers scarcity revenue, though without an explicit ORDC formulation.

4. VOLL — Value of Lost Load

4.1 What VOLL is + why it matters

VOLL (Value of Lost Load) = the economic damage per megawatt-hour of involuntary electricity service interruption. It is the price ceiling on energy in a frictionless market — the willingness-to-pay of the marginal user who would otherwise be cut off. In missing-money-and-scarcity-pricing contexts, VOLL is the parameter against which scarcity prices and capacity market clearing should be benchmarked, and the value to which ORDC adders push energy prices during near-shortage hours.

4.2 Estimation methodologies

Three methodological families:

1. Stated preference / survey-based:

• Willingness-to-pay surveys to residential + commercial + industrial customers asking what they would pay to avoid outages of various durations + frequencies. Standard surveys: London Economics (UK NESO), Stoft + Mansur (US), Lawton + Sullivan + Vojdani + Eto (LBNL studies).
• Willingness-to-accept the converse — compensation required to accept outages. WTA-WTP gaps are typically 2-3x consistent with loss aversion (see behavioral-economics + microeconomics §9.1 prospect theory).
• Generally yields VOLL in the $5-15/kWhrange($5,000-$15,000/MWh) for residential; higher for commercial + industrial.

2. Revealed preference / market-based:

• Backup generation costs — what businesses pay for diesel gensets + UPS systems + microgrids reveals lower-bound VOLL for the segment of load that voluntarily protects itself.
• Interruptible-load tariff discounts — what customers accept in discounted rates to permit utility interruption reveals upper-bound VOLL for that load.
• Curtailment-service-provider compensation — what aggregated demand-response programs pay reveals market-clearing willingness to be interrupted, conditional on terms.

3. Production function / counterfactual:

• Lawrence Berkeley National Laboratory (LBNL) studies (Sullivan + Eto et al. 2009 + updates) — production-function estimates of value-added losses during outages by industry sector + outage duration. Industry-specific VOLL estimates from $1/kWhforlow-value-addedsectorsto>$1,000/kWh for data centres + semiconductor fabs.
• Texas Uri damage estimate (\$50-130B+intotaleconomicdamageover4daysx30GWx50$9,000/MWh cap by orders of magnitude during the cold-weather emergency.
• Macroeconomic estimates — Sullivan et al. 2018 LBNL synthesis: US national VOLL average around $5,000-$10,000/MWh weighted by sector.

4.3 ERCOT VOLL parameter

ERCOT VOLL set at:

• $9,000/MWh from 2014 (ORDC introduction) through Feb 2022.
• $5,000/MWh from Feb 2022 onward (post-Uri PUCT mandate aligned with System-Wide Offer Cap reduction).

The 2022 reduction was politically motivated by post-Uri rate-shock concerns rather than by updated economic analysis; the underlying empirical Uri damages suggest VOLL substantially exceeded $9,000/MWhduringtheevent.Severalacademic+industrycritiques(Cramton,Hogan,Brattle,ERCOTIMM)havequestionedthe$5,000 cap as inconsistent with credible VOLL estimates.

4.4 European + UK + Australia VOLL

• GB NESO: VOLL set at £6,000/MWh in capacity-market calibration (raised from earlier £5,000 in 2023).
• EU ACER: published guidance on VOLL estimation methodology (Regulation 2019/943 + ACER guidance 2023); member-state VOLL ranges from €5,000 to €15,000/MWh.
• AEMO Australia NEM: $16,600/AUD/MWh cap; effective VOLL embedded in cap + cumulative-price-threshold mechanism.
• NZ NEMS: scarcity price floor at NZ$10,000/MWh during shortage.
• Ireland SEM: €3,000/MWh administrative reference VOLL for capacity-market calibration; cap-and-floor mechanism for ancillary scarcity.

5. Capacity markets vs energy-only vs hybrid

5.1 Energy-only design

Defining features:

• No centralised capacity construct.
• Energy market clears with scarcity pricing (high offer caps + ORDC + administrative scarcity adders) intended to deliver the full annualised fixed-cost recovery during scarcity hours.
• Resource adequacy is implicit — investors enter when expected scarcity-rent revenue exceeds fixed cost.
• Demand-response + behind-the-meter resources + storage compete in the energy market on a level basis.

Examples: ERCOT (Texas), Australia NEM (with capacity-investment-scheme overlay 2023+), New Zealand NEMS (with Reserve Market for capacity supplement), parts of EU (until 2024 market design reform).

Strengths:

• Transparent investment signal — scarcity revenue is observable + predictable from historical patterns.
• Resource-neutral — demand-response + storage + thermal + renewable all compete on the same basis.
• Avoids “lumpy” capacity-procurement decisions that may over- or under-procure.
• Lower regulatory overhead — no separate capacity auction + accreditation administration.

Weaknesses:

• Politically sensitive scarcity prices (Uri 2021 + post-Uri Texas backlash + REP-pass-through legal cases).
• Investment risk concentrated on a small number of scarcity hours per year — high variance + skewness in revenue.
• Demand response thin → cannot reliably clear scarcity at consumer willingness-to-pay; involuntary shed risk persists.
• Operator interventions (capacity emergency steps + voltage reduction) suppress scarcity prices below VOLL.

5.2 Capacity-market design

Defining features:

• Forward auction (1-4 years ahead of delivery year) procures capacity in MW units at a clearing $/MW-day price.
• Variable Resource Requirement (VRR) demand curve calibrated against Cost-of-New-Entry (CONE) anchors auction.
• Energy market with offer cap below VOLL (e.g. $1,000-$2,000/MWh historic; now $5,000/MWh in some markets); energy + AS revenue plus capacity payment together cover fixed cost.
• Capacity Performance (or analogous) penalty regime ties capacity payment to delivery during scarcity hours.
• Capacity accreditation (ELCC, ICAP, or other methodologies) determines how much credit each resource receives.

Examples: PJM RPM, MISO PRA, NYISO ICAP, ISO-NE FCM, UK Capacity Market, Italian + Polish + French + Belgian + Irish CRMs.

Strengths:

• Reduced revenue variance for capacity owners → lower required risk premium → lower financing cost → lower CONE.
• Explicit reliability target via clearing against VRR demand curve calibrated to LOLE 0.1.
• Reduced reliance on scarcity-pricing tolerance + clearing-mechanism integrity.
• Transparent forward signal of capacity-need 3-4 years ahead.

Weaknesses:

• Capacity-market clearing depends on calibrated parameters (CONE, VRR shape, ELCC) that are inherently contested.
• Pays for nameplate capacity rather than delivered scarcity-hour energy — distorts entry signals between resource types.
• State-policy interactions (MOPR debate, state ZECs, RPS) create chronic political friction.
• Lumpy procurement → boom-and-bust cycles in cleared prices (PJM 2024 BRA $269.92/MW-dayafter$28.92/MW-day prior auction).
• Administration cost + complexity.

5.3 Hybrid design

Defining features:

• Capacity market or bilateral RA obligation overlay on energy market.
• Energy market may have moderate scarcity pricing (CAISO RA + EDAM SRDC; NYISO ICAP + RT scarcity adders).
• Multiple capacity products targeted at distinct attributes (flexible RA, local RA, system RA in CAISO; locational ICAP in NYISO; LDA-zonal RPM in PJM).

Examples: CAISO (bilateral RA + SRDC scarcity adder), PJM + MISO + NYISO + ISO-NE (capacity market + RT scarcity reserve pricing under Order 825 reforms), UK Capacity Market + CfD + balancing-mechanism scarcity.

The hybrid is the dominant modern architecture. Pure energy-only (ERCOT) is the outlier; pure capacity-market-without-scarcity-adder is rare since FERC Order 825 directives + the 2010s scarcity-pricing reforms.

6. PJM RPM as the capacity-market benchmark

The PJM Reliability Pricing Model (RPM) is the largest centralised capacity market in the world by cleared volume (~150 GW). It is the empirical benchmark for capacity-market design + the focal point of the 2024-26 capacity-market debate.

Core auction: Base Residual Auction (BRA) held annually, three years forward, for a single delivery year. The 2025/26 BRA in July 2024 cleared capacity for June 2025 - May 2026.

Auction mechanics:

• Uniform-price sealed-bid auction against a Variable Resource Requirement (VRR) demand curve.
• VRR curve anchored on CONE (Cost of New Entry, calibrated reference combined-cycle gas turbine fixed-cost figure in $/MW-year).
• For 2025/26 delivery year: gross CONE ~115,000/MW-yr (varies by LDA); net CONE (after deducting expected energy-and-AS margin "E&AS offset") ~80,000/MW-yr.
• VRR curve from 1.0× net CONE at reliability requirement minus 1% to 0.5× net CONE at requirement plus several percent.
• Locational Deliverability Areas (LDAs) — zonal price separation when transmission constraints bind. Major LDAs: RTO, MAAC, EMAAC, SWMAAC, DOM, ATSI, BGE, PEPCO, Mid-Atlantic, others.
• Incremental Auctions (IAs) — held at intervals through delivery year for buy-back + top-up.

2025/26 BRA outcome (July 2024):

• RTO zone: $269.92/MW-dayclearedprice($98,500/MW-year).
• MAAC + EMAAC: hit LDA cap.
• DOM (Dominion): $444.26/MW-day — driven by Northern Virginia datacenter load growth.
• ATSI (American Transmission Systems Inc, Ohio): $244.06/MW-day.
• BGE (Maryland): cleared at the LDA cap.

Total revenue paid to capacity in 2025/26: ~$14.7Bvs$2.2B in 2024/25 — a politically explosive 10x jump.

Drivers:

• ~5 GW of coal retirements concurrent with delivery year.
• Capacity accreditation reform — ELCC accreditation for renewables + storage replacing nameplate de-rating, sharply reducing accredited capacity from those resource classes.
• Interconnection-queue delays preventing new entry.
• Data centre load growth in DOM + AEP (Ohio).
• Capacity Performance penalty regime + Stop-Loss formula maintaining high option-value of firm capacity.

Aftermath + reforms:

• Pennsylvania Governor Shapiro filed FERC complaints August 2024 over BRA outcomes.
• Maryland Public Service Commission directives to consider procurement outside PJM.
• FERC-ordered cap of $325/MW-day for 2026/27 BRA — partially reins in further price escalation while preserving market signal.
• PJM capacity-market reform working group + stakeholder process 2024-26.
• Capacity-accreditation tweaks + auction-parameter adjustments under FERC filing.

6.1 PJM Capacity Performance

The Capacity Performance product, introduced post-Polar-Vortex January 2014 for the 2018/19 delivery year onward, requires resources to perform during PJM-declared Performance Assessment Hours (PAHs) under a strict obligation. Non-performance penalty:

• Non-Performance Charge = (Cleared Price × Performance Shortfall) × 1.5 (or analogous Stop-Loss formulation).
• Bonus payment for over-performance: outperforming units may receive Performance Credits from under-performing units’ penalties.

The PfP regime substantially raised the value of “deliverability” relative to “nameplate” capacity — driving up demand for storage + dispatchable thermal + reducing accredited credit for renewables in the absence of firming.

6.2 ELCC accreditation in PJM

The PJM transition to Effective Load Carrying Capability (ELCC) for renewables + storage in delivery year 2024/25 + 2025/26 is one of the principal drivers of the BRA price explosion.

Mechanics (see electricity-markets-and-grids §14):

1. PJM runs annual resource-adequacy Monte Carlo simulation with stochastic load + thermal forced outages + renewable hourly profiles.
2. Adds candidate resource class at incremental MW size, re-runs, computes load-carrying capability ratio.
3. Marginal ELCC declines with class penetration.

Approximate 2025 PJM accreditations:

• Nuclear: ~95-97% of nameplate (after EFORd-equivalent forced outage adjustment).
• Combined cycle gas: ~85-90% (after EFORd).
• 4-hour battery storage: ~50-65% (varying by LDA + penetration).
• 1-hour battery: ~15-25%.
• Solar PV: ~9-13% (down from ~38% under prior ICAP rules).
• Wind: ~14-18%.

The shift cut accredited capacity from existing renewables + storage portfolios sharply + reduced the supply of capacity available to clear at any given price — contributing to the 10x BRA price escalation. Owners of renewables under existing long-term capacity obligations face de facto stranded-cost exposure; multiple FERC complaints + state-PUC interventions filed 2022-25.

7. CAISO Resource Adequacy + RAAIM

CAISO does not operate a centralised capacity auction. Instead, Resource Adequacy (RA) is a bilateral procurement obligation placed on Load-Serving Entities (LSEs) by the California Public Utilities Commission (CPUC) under D.04-10-035 + successor decisions.

Structure:

• LSEs must show 115% of forecast peak load procured 1 year forward (system RA).
• Local RA for transmission-constrained sub-areas (San Diego, LA Basin, Big Creek-Ventura, Humboldt, Sierra, Bay Area).
• Flexible RA for ramping needs (post-2014, the “duck-curve” reform).
• Slice-of-Day RA (2024+) — adds a 24-hourly demonstration requirement for procurement adequacy in each hour of a representative day, addressing the increasingly hour-specific reliability needs in a high-solar + high-storage grid.

RAAIM — Resource Adequacy Availability Incentive Mechanism — financial incentive layered on the bilateral RA construct. Components:

• Availability assessment based on Forced Outage Rate + Use-Limited Resource performance during summer + winter capability periods + ramp + reserve windows.
• Penalty for under-performance against accredited availability — typically expressed as $/kW-month adjustment to RA payment.
• Bonus for over-performance.

RAAIM essentially imports a partial Capacity Performance-style availability obligation into the bilateral RA framework without a centralised capacity auction. RA prices are opaque (not centrally cleared) but reflected in residual procurement + proxy cost analyses: 2024 figures suggest $4-7/kW-monthsystemRA,$15-25/kW-month for scarce local-RA capacity in San Diego + LA Basin.

The CPUC has repeatedly considered a centralised capacity market (most recently 2022-23 proceeding) but stalled on stakeholder objections — primarily concerns about CAISO governance + state-jurisdictional implications + investor-owned utility cost-allocation politics. The status quo bilateral RA + RAAIM continues.

8. MISO seasonal capacity accreditation

MISO’s Planning Resource Auction (PRA) transitioned to a four-season construct in 2022/23 (Summer, Fall, Winter, Spring) to address rising spring-shoulder reliability gaps from coal retirements + renewable seasonality.

Seasonal Accredited Capacity (SAC) methodology derates resources by season-specific availability. Examples:

• Wind: ~30-40% nameplate accredited in summer; ~15-20% in winter in some zones.
• Solar: ~50-65% summer; ~5-15% winter.
• Coal: ~80-85% all seasons.
• Gas combined cycle: ~85-90% all seasons (slight winter derating for gas-supply risk).
• 4-hour battery: ~50-65% with hour-specific dispatch optimization.

2024/25 PRA outcome: cleared at the Cost of New Entry cap ($719.81/MW-day,or$262,000/MW-year on annualized basis) in MISO North/Central for the summer season — the first time MISO hit its CONE cap and the most explicit market signal of North American capacity shortage. Local Reliability Requirements bind in LRZ 3 (Iowa/Minnesota), LRZ 5 (Missouri), LRZ 6 (Indiana).

The MISO 2024/25 PRA outcome + PJM 2025/26 BRA explosion + ERCOT post-Uri reserve tightness together represent the strongest empirical evidence in a generation that the current capacity-market + RA architectures are not delivering investment + reliability at the rate North American demand growth + retirement schedules require.

9. ISO-NE Pay-for-Performance + PCM redesign

ISO-NE Forward Capacity Market (FCM) runs three years forward via descending-clock (Dutch) auction. CASPR (Competitive Auctions with Sponsored Policy Resources) in 2018+ lets state-subsidised renewables enter via substitution auction after primary clearing.

Pay-for-Performance (PfP) since 2018 ties capacity payment to delivery during Capacity Scarcity Conditions (CSCs):

• Resources earning capacity payments receive bonus payments for over-performance during CSCs.
• Resources earning capacity payments pay penalties for under-performance during CSCs.
• Net financial exposure can exceed the cleared capacity-market payment for poor performers — creating strong incentive for fuel + weatherisation + maintenance investment.

ISO-NE PCM (Prompt and Forward Capacity Market) redesign filed 2024-25:

• Shorter forward horizon (one-year-forward primary auction rather than three).
• Simplified performance incentives.
• Explicit treatment of winter fuel security (gas-pipeline capacity, LNG cargo availability, dual-fuel oil reserves at gas-fired generators).
• Replacement for FCM at delivery year 2028/29 onward.

The PCM redesign reflects ISO-NE’s particular structural challenge: limited natural gas pipeline capacity into New England, dependence on LNG imports + dual-fuel oil reserves, plus a winter-peaking concern increasingly competing with summer cooling load.

10. Why this debate matters

The missing-money + scarcity-pricing debate is not academic. It determines:

1. Reliability outcomes. Will the lights stay on during the next polar vortex, summer heat wave, or low-renewable lull? The 2021 Uri event (200 dead, $50B+ damages, 4.5 days rolling outages, near-blackout escape) is the high-water example of what failure looks like.

2. Investment trajectory. Capacity-market + scarcity-pricing parameters drive multi-billion-dollar investment decisions across the IRA-driven build-out cycle. PJM 2025/26 BRA pumped $12-14B additional capacity revenue into the system; reform unwinds part of that.

3. Retail rate trajectory + political tolerance. Wholesale market design transmits to retail rates with lags. PJM 2025/26 BRA price implications will hit Maryland + Pennsylvania + NJ + Virginia retail rates 2025-27, producing political fallout (Shapiro complaints already filed).

4. Resource mix. Capacity-accreditation reforms (ELCC, SAC) reshape investment-economics for renewables vs storage vs gas vs nuclear. The IRA + state RPS push toward renewables + storage; capacity-market accreditation determines what cleared revenue those resources receive.

5. Federal-state policy interaction. State subsidies (ZECs, RPS), federal subsidies (IRA §45U + §45Y + §48E + §45V), and capacity-market clearing prices interact in ways that produce chronic regulatory + litigation friction (see ferc-and-grid-policy §5 + §6).

The 2024-26 period is the highest-stakes phase of this debate in 20 years. PJM reforms, MISO reform, ERCOT PCM, ISO-NE redesign, FERC Orders 2023 + 1920 + 1977 + 1980 implementation all interact. The outcome will shape the US grid for 2025-2040.

11. Glossary

• BRA — Base Residual Auction (PJM RPM)
• CASPR — Competitive Auctions with Sponsored Policy Resources (ISO-NE)
• CONE — Cost of New Entry (reference unit fixed cost)
• CRM — Capacity Remuneration Mechanism (EU)
• CSC — Capacity Scarcity Condition (ISO-NE PfP trigger)
• DAM — Day-Ahead Market
• ELCC — Effective Load Carrying Capability
• EFORd — Equivalent Forced Outage Rate, demand-weighted
• FCM — Forward Capacity Market (ISO-NE)
• ICAP — Installed Capacity (NYISO)
• LDA — Locational Deliverability Area (PJM zones)
• LOLE — Loss of Load Expectation (events/year)
• LOLP — Loss of Load Probability (per period)
• MOPR — Minimum Offer Price Rule
• ORDC — Operating Reserve Demand Curve (ERCOT, generalised)
• PAH — Performance Assessment Hour (PJM Capacity Performance)
• PCM — Performance Credit Mechanism (ERCOT proposed); also Prompt and Forward Capacity Market (ISO-NE proposed)
• PfP — Pay-for-Performance (ISO-NE FCM)
• PRA — Planning Resource Auction (MISO)
• RA — Resource Adequacy
• RAAIM — Resource Adequacy Availability Incentive Mechanism (CAISO)
• RDPA — Reliability Deployment Price Adder (ERCOT)
• RMR — Reliability Must-Run
• RPM — Reliability Pricing Model (PJM capacity)
• RT — Real-Time
• SAC — Seasonal Accredited Capacity (MISO)
• SCED — Security-Constrained Economic Dispatch
• SRDC — Scarcity Reserve Demand Curve (CAISO)
• SWOC — System-Wide Offer Cap (ERCOT)
• VOLL — Value of Lost Load ($/MWh)
• VRR — Variable Resource Requirement (PJM RPM demand curve)

12. Cross-references

• _index — library index
• electricity-markets-and-grids — umbrella market structure
• electricity-markets — companion overview
• capacity-and-ancillary-services-markets — product-by-product capacity + AS detail
• ferc-and-grid-policy — federal regulatory layer + MOPR
• transmission-and-grid-services — transmission planning + grid services
• demand-response-and-flexibility — demand side + VPP + DER aggregation
• grid-stability-inertia-and-frequency-response — physics of frequency response
• microeconomics — auction theory + market design economics

13. References

Foundational papers:

• Hogan 2005 On an Energy-Only Electricity Market Design for Resource Adequacy.
• Hogan + Pope 2014 Demand-Side Reserve Pricing in the Texas ERCOT Wholesale Electricity Market (commissioned by ERCOT).
• Cramton + Stoft 2005 A Capacity Market that Makes Sense (Electricity Journal).
• Cramton + Stoft 2008 Forward Reliability Markets: Less Risk, Less Market Power, More Efficiency (Utilities Policy).
• Joskow 2007 Competitive Electricity Markets: Have they been worked out? (Yale Journal on Regulation).
• Joskow 2008 Capacity Payments in Imperfect Electricity Markets (Utilities Policy).
• Stoft 2002 Power System Economics: Designing Markets for Electricity (IEEE-Wiley).
• Borenstein 2002 The Trouble with Electricity Markets (J Economic Perspectives).

ERCOT-specific:

• ERCOT 2014 Implementation of Operating Reserve Demand Curve technical report.
• PUCT 2022 System-Wide Offer Cap and Operating Reserve Demand Curve Reform (Order following Uri).
• FERC + NERC 2021 Inquiry into Bulk-Power System Operations During February 2021 Cold Weather Event (November 2021).
• ERCOT IMM (Potomac Economics) annual State of the Market reports 2014-2024.
• Texas SB 3 + SB 2 + HB 17 (2021 87th Legislature, post-Uri).

Capacity-market:

• PJM Monitoring Analytics annual State of the Market reports.
• MISO Independent Market Monitor (Potomac Economics) annual State of the Market reports.
• ISO-NE Internal Market Monitor + External Market Monitor (Potomac Economics) reports.
• NYISO Department of Market Monitoring + IMM reports.
• CAISO Department of Market Monitoring annual reports.
• Brattle Group capacity-market reviews (multiple, 2017-2024).
• Tierney 2024 + Tierney + Schatzki Analysis Group reviews.

VOLL estimation:

• Sullivan + Eto + Schellenberg 2009 Updated Value of Service Reliability Estimates for Electric Utility Customers in the United States (LBNL).
• Schröder + Kuckshinrichs 2015 Value of Lost Load: An Efficient Economic Indicator for Power Supply Security? (Renewable + Sustainable Energy Reviews).
• ACER 2023 Methodology for Calculating the Value of Lost Load.

Regulatory + policy:

• FERC Orders 745, 755, 825, 841, 1000, 1920, 2222, 2023.
• PUCT proceedings on Performance Credit Mechanism (2023-2026).
• PJM capacity-market reform stakeholder process documents (2024-2026).
• CPUC RA proceedings (D.04-10-035 + successors; 2022-23 centralised-capacity-market proceeding).

Industry analyses:

• ICF + Wood Mackenzie + S&P Global Market Intelligence capacity-market quarterly reports.
• LCG Consulting capacity-market analyses.
• Energy + Environmental Economics (E3) + Astrapé Consulting + Brattle resource adequacy + ELCC studies.
• Cramton + Stoft + Wilson industry consulting reports on market design.

Reviews + summaries:

• Cramton 2017 Electricity Market Design (Oxford Review of Economic Policy).
• Newbery 2017 Tales of Two Islands: Lessons for EU Energy Policy from Electricity Market Reforms (Energy Policy).
• Schittekatte + Meeus 2020 Least-Cost Distribution Network Tariff Design in Theory and Practice (Energy Journal).
• Bushnell + Mansur + Saravia 2008 Vertical Arrangements, Market Structure, and Competition (AER) — context on energy-market design.