From PPAs to MBED: Challenges & Roadmap for Transition

From PPAs to MBED: Challenges and Roadmap for Transition

India’s power sector has been built around long-term, cost-plus Power Purchase Agreements (PPAs) that guarantee fixed-cost recovery and allocate dispatch rights to buyers. That architecture is increasingly misaligned with today’s needs: integrating large shares of variable renewables, reducing total system cost, and sending sharper price signals to both supply and demand. Market-Based Economic Dispatch (MBED) proposes a national, centralized day-ahead optimization of committed capacity, with financial settlements that preserve fixed-cost recovery while making energy dispatch merit-order-based.

Getting from here to there is non-trivial. It requires (i) a legal bridge from PPA-bound dispatch to pooled market scheduling, (ii) settlement redesign that ring-fences capacity payments while making energy a common pool product, (iii) strong transmission access and congestion management under GNA, (iv) integration with ancillary services and resource adequacy, (v) market power mitigation and robust cyber/clearing infrastructure, and (vi) a phased migration plan that begins with the most schedulable portfolios.

Below is a practitioner-oriented explainer and a concrete, phased roadmap tailored to India’s regulatory, institutional, and system realities.

1) Why move beyond PPA-centric dispatch?

Structural frictions created by PPAs

• Fragmented dispatch: Scheduling is tied to buyer-owned entitlements, not least-cost system optimization.

• Two-part tariffs mute short-run price signals: Fixed charges dominate DISCOM bills; short-run marginal costs get buried.

• Inefficient utilization of thermal fleet: Granular optimization across plants is hard when each buyer protects its own contracted portfolio rather than the national merit order.

• Integration of VRE: As solar/wind shares increase, a central optimizer must constantly reshuffle thermal ramps, reserves, and storage to meet net load at minimum cost.

What MBED promises

• Single national dispatch of energy from committed capacity to minimize variable cost subject to security constraints (think SCUC/SCED at national scale).

• Financially neutral to fixed costs: PPA capacity charges continue; energy is settled at a uniform market price (or zonal, if adopted later) with make-whole/contract-for-difference (CfD) style adjustments.

• Consumer-welfare gains: Lower total system cost, better price signals, and fairer allocation of market-wide efficiency benefits to all consumers.

India has already tested pieces of this: the Security Constrained Economic Dispatch (SCED) pilot run by POSOCO (now Grid-India) demonstrated measurable savings from pan-India thermal optimization—evidence that there’s “money on the table” when we dispatch as one system rather than as hundreds of contract silos. While SCED currently faces certain gaming challenges, these can be effectively mitigated through the safeguards outlined later in this document.

2) MBED: How it works

1. Scope: Generators with committed capacity (from legacy PPAs or market contracts) bid their variable (energy) cost into a centralized Day-Ahead optimization; fixed/capacity charges are kept outside energy clearing.

2. Optimization: The market engine (MILP/SCUC with network constraints) minimizes total variable cost subject to unit and transmission constraints.

3. Price formation: Energy clears at a uniform (or zonal) price for each time block; congestion is handled through market splitting or equivalent mechanisms.

4. Settlement:

   • Capacity: Fixed charges continue to flow per PPA (or converted capacity contracts).

   • Energy: Generators are paid the market price for dispatched MWh; buyers pay for their metered offtake at the same price. Side-pockets (uplift/make-whole) ensure generators recover approved variable cost where needed.

5. Hedging: PPAs can be financialized as CfDs against the MBED price; DISCOMs hedge exposure via forwards, RTM, or derivatives (as regulations evolve).

6. System services: Ancillary services procure reserves separately (PRAS/SRAS/TRAS), co-optimized or sequentially, per CERC’s Ancillary Services Regulations, 2022.

7. Design lineage: The idea was first framed by CERC staff (2018) and then taken forward by the Ministry of Power through a 2021 discussion paper proposing a phased start.

3) The enabling reforms that make MBED feasible

• SCED proof-point: 2019–2022 pilot over ~58 GW of ISGS coal reduced variable cost; CERC recognized cumulative savings. This is the technical foundation for “dispatch as one system.”

• GNA framework: General Network Access (2022) unbundles transmission access from specific PPA paths, enabling pooled scheduling and congestion management—a prerequisite for MBED.

• Ancillary Services Regulations (2022): Creates a market/process for procuring reserves; MBED needs reliable reserves for security-constrained dispatch.

• Resource Adequacy (RA) Guidelines (2023): Clarify capacity obligations and planning; MBED works best when energy is optimized in markets and adequacy is procured via capacity obligations (contracts/auctions).

• Exchange or Market Coupling (2025 order): CERC has mandated phased market coupling, beginning with a unified Day-Ahead Market (DAM) price across exchanges by January 2026. Although the current framework covers only voluntary DAM trades, it lays the groundwork for MBED by creating the institutional, technical, and governance infrastructure needed for a single national clearing engine. While MBED will initially cover only PPA-committed capacity, the transition to a unified clearing system under market coupling is a practical precursor. It demonstrates large-scale market data integration, central optimisation, and uniform pricing—capabilities essential for MBED’s success. In time, the same architecture can encompass both voluntary exchange trades and PPA-bound capacity, enabling a single day-ahead dispatch and price for the entire market.

• Increasing flexibility on URS: Policy now allows sale of un-requisitioned surplus (URS) power in open markets under revised SHAKTI/coal linkage terms—another nudge toward market-based energy allocation.

4) The hard problems: What must be solved to transition from PPAs

1. Sanctity of contracts & jurisdiction

   • Dispatch rights are embedded in PPAs approved by SERCs/CERC. MBED must convert physical scheduling rights into financial entitlements without impairing contracted capacity recovery. Clear legal basis, model amendments, and a “no worse off” principle for both buyers and sellers are essential. (2018 CERC staff paper & 2021 MoP paper outline these ideas.)

2. Settlement redesign at scale

   • Two-part tariffs need dual ledgers: capacity (outside energy market) and energy (inside MBED). Make-whole/uplift logic must be transparent, auditable, and time-bound to prevent gaming.

3. Transmission & congestion

   • MBED needs network-aware dispatch (SCUC) and congestion management aligned with GNA. Market splitting or congestion rent allocation rules must be codified so that participants know how curtailment and prices are determined.

4. Integration with Ancillary Services

   • Co-optimization (or tight coordination) with PRAS/SRAS/TRAS, with clear stack priority and performance measurement.

5. Resource adequacy alignment

   • RA ensures enough firm capacity is procured; MBED optimizes energy. Define RA obligations for DISCOMs, contract forms (capacity auctions/CfDs), and performance penalties so MBED isn’t blamed for capacity shortfalls.

6. Market power & gaming safeguards

   • Concentrated portfolios, fuel constraints, and ramp limits create local power. Strong market surveillance, bid caps only as backstops, and must-offer obligations for committed capacity are required.

7. Credit & payment security

   • Today, exchanges require margins; PPAs rely on LC/payment security mechanisms. MBED’s central settlement needs a robust payment waterfall, prudential limits, and state-backed buffers to avoid contagion risk to generators.

8. Data, cyber & clearing engine assurance

   • With coupling and MBED, the market clearing engine becomes critical infrastructure—needing independent audits, cyber hardening, disaster recovery, and full telemetry from SLDCs/ISGS. CERC’s coupling order already points to central data and oversight structures that MBED can leverage.

9. State-centre alignment

   • SERCs approve PPAs and tariffs; CERC governs interstate markets. A jointly owned Model PPA Amendment and Model SERC Order pack can reduce litigation risk and ensure uniform adoption.

10. Distribution-side readiness

• Without retail tariff reform (time-differentiation/ToD, settlement of losses, pass-through rules), market-based signals won’t reach consumers, muting MBED’s benefits.

5) Designing MBED for India: Practical choices

A. Scope and phasing
Start where dispatch is most schedulable and data-rich: central/NTPC coal fleet and other ISGS with standardized variable cost declarations (mirroring SCED’s early scope). Grow to include state PPAs and RE portfolios once settlement rails are proven. (This mirrors the phased approach contemplated in MoP’s 2021 paper.)

B. Pricing model

• Uniform/Zonal price with market splitting (status-quo friendly) in the near term; revisit granular pricing (nodal/LMP) only after metering, GNA & congestion management mature.

C. Bidding & must-offer

• Must-offer from committed capacity (save verified outages/fuel constraints), cost-based or price-capped bids during transition to curb abuse. Disclose reference variable costs and fuel linkages.

D. Settlement logic

• Capacity: Paid per PPA (or converted capacity contract).

• Energy: Paid/charged at MBED price; reconcile with approved variable cost via make-whole only for verified constraints to avoid windfalls.

• URS: Incentivize declaration and market sale (recent policy direction is already enabling this).

• E. Co-optimization with Ancillary Services

• Procure SRAS/TRAS for flexibility; allow storage and demand response to participate, per the 2022 Regulations and detailed procedures.

F. Governance & surveillance

• Independent Market Monitoring Unit under CERC/Grid-India, real-time dashboards for bid/dispatch anomalies, and ex-post behavior screens (e.g., withheld capacity, sudden variable cost spikes).

G. IT/clearing assurance

• Annual third-party audits of clearing engines and cyber posture; mandated failover sites; reproducible clearing results with sealed input logs. (The market coupling order’s data-sharing and oversight scaffolding is a solid starting point.)

6) A phased roadmap (2025–2028)

Phase 0 (Now–Q1 2026): “MBED-ready markets”

• Operationalize Exchange or market coupling in DAM per CERC order; implement common data interfaces to Grid-India; finalise audit & backup roles.

• Publish MBED rulebook (exposure draft): model PPA amendment, settlement handbook, uplift/make-whole rules, prudential margin & payment waterfall.

• Dry-run SCUC/SCED on historical days using candidate MBED scope to validate engine performance.

• URS & fuel flexibility: Codify URS sale protocols across all coal linkage types

Phase 1 (Q2 2026–Q1 2027): “Contained MBED”

• Scope: NTPC & select ISGS coal stations + storage/ancillary resources; must-offer for committed capacity.

• Pricing: Uniform/zonal price with market splitting; 96 blocks/day.

• Settlement: Capacity outside market; energy at MBED price; limited, transparent uplift.

• Safeguards: Bid caps during transition; mandatory variable cost disclosures; MMU in place.

Phase 2 (Q2 2027–Q4 2027): “Portfolio expansion”

• Onboard state-owned coal fleets and PPAs with standard terms; begin portfolio-level CfD conversions for DISCOMs (so their consumers see hedged, predictable tariffs while energy clears in MBED).

• Co-optimize ancillary (at least sequentially day-ahead) to reduce uplift and improve ramping feasibility.

Phase 3 (2028): “Whole-of-market MBED”

• Cover majority of dispatchable capacity (thermal, hydro with agreed water/value rules, storage), align with RA obligations and DSM revisions.

• Evaluate granular pricing (more zones or nodal pilots) only if metering, congestion accounting, and SLDC-IT maturity allow.

7) What does this mean for key stakeholders?

DISCOMs

• Pros: Lower pooled variable cost; better access to flexibility; simplified procurement (buy energy at one price, hedge separately); reduced take-or-pay waste.

• Cons/risks: Exposure to short-run price volatility unless hedged; need robust working-capital, safeguard from gaming and prudential frameworks.

Generators

• Pros: More consistent dispatch based on true merit order; opportunity revenue for flexible plants/storage/ancillaries; URS monetization.

• Concerns: Fear of under-recovery if uplift is opaque; credit risk from central settlement; need for transparent variable cost pass-through rules.

States/SERCs

• Pros: System-wide savings flow to retail tariffs; improved reliability through centralized optimization and ancillary procurement.

• Concerns: Jurisdiction and tariff control; ensuring state PPAs’ consumer-specific benefits aren’t diluted—addressed via financial hedges/CfDs and settlement reports mapping MBED savings to each buyer.

Consumers

• Pros (consumer-welfare lens): lower total system cost, sharper price signals enabling DSM/time-of-day retail pricing over time, and fairer allocation of efficiency gains across DISCOMs.

8)    Anticipating & managing likely problems

• Fuel pass-through timing: Align coal/gas price adjustments with MBED settlement cycles to avoid systematic uplift drift.

• Hydro coordination: Water value and multi-day constraints require special treatment (hydro schedules often need rolling horizons).

• RE priority: India has historically granted “must-run” to VRE; in MBED this becomes must-schedule unless security-limited, while still letting curtailment be priced and compensated transparently through market rules.

• MILP duality gaps: Keep them bounded and publish metrics; apply gate closure times that are realistic for SLDCs/ISGS.

• Data quality: Telemetry and declarations (ramp rates, min up/down times) must be audited; misdeclaration penalties should be real and swift.

9) A minimal legal & regulatory package

1. CERC MBED Regulations: Defining scope, participation, bidding, clearing, settlement, prudential norms, and penalties.

2. Model PPA Amendment: Transforming physical dispatch rights into financial settlement rights (capacity kept whole; energy goes to pool).

3. SERC Companion Orders: Recognizing MBED settlements as tariff-consistent pass-throughs; spelling out consumer benefit flow-through.

4. Market Surveillance Code: Powers and processes for the MMU; data-sharing mandates (building on market coupling directions).

5. Ancillary & RA harmonization: Cross-references to 2022 Ancillary Regulations and 2023 RA Guidelines to keep the design coherent.

10) What success looks like (12–24 months into MBED)

• Measured reduction in all-India variable cost versus counterfactual portfolios, similar to (and ideally exceeding) SCED savings, but now across a wider scope.

• Lower uplift share of total payments as co-optimization and data quality improve.

• Transparent congestion metrics (number of split intervals, congestion rent use) under GNA.

• DISCOM hedging maturity: Share of load with CfD/forward coverage; variance of procurement cost reduces despite dynamic MBED prices.

• Consumer tariffs: Evidence that pooled efficiency gains flow through ARR and tariff orders.

 11) Safeguards from Gaming

Right now, with the current PPA + FCA model, a generator can artificially lower its provisional ECR to get scheduled in MBED (or SCED), sell more energy, and later use post-facto fuel cost adjustments to recover the shortfall from the original PPA buyer — which means the scheduling benefit of URS goes to the “wrong” party and the paying DISCOM doesn’t actually benefit.

Why the problem occurs

1. In MBED/SCED merit order → Lower ECR → more dispatch → more URS (requisitioned surplus) gets sold to other buyers at the market clearing price.

2. In PPA settlement → Original PPA buyer still pays for the full actual fuel cost after FCA adjustment.

3. Result → Scheduling benefit of selling URS is retained by the generator (and possibly shared with new buyer via market price), but the cost risk is pushed back to the PPA buyer who didn’t even get the extra power.

Fixing the benefit pass-through

One needs a mechanism that ties URS revenue directly back to the paying DISCOM, so that lowering variable cost for gaming can’t create a windfall for the generator at someone else’s expense.

Here’s how it can be designed:

Option A. Settlement segregation: original buyer vs. new buyer

MBED/SCED settlements must tag each MWh to:

- Contracted or original Buyer (PPA capacity obligation)

- URS Sale or new Buyer (market/exchange schedule)

Any URS sale proceeds must first offset the original buyer’s variable cost before the generator retains any margin.

Option B. Marginal cost floor for MBED bids

For MBED bidding, apply a cost-verified floor price = approved ECR based on actual recent fuel invoices.

Prevents the generator from declaring artificially low ECR to win dispatch.

If actual cost ends up higher, uplift/make-whole is paid only for MWh delivered to the contracted buyer, not for URS sales.

c). URS revenue credit rule

If a unit sells URS at market price above the PPA variable cost:

Step 1: Credit difference between market price and variable cost to the original PPA buyer (in proportion to capacity share surrendered).

Step 2: Generator retains any balance only after the buyer’s cost has been fully offset.

This is similar to the CERC URS sharing mechanism already applied in inter-state stations but must be enforced in MBED’s central settlement ledger.

d). No FCA recovery for URS MWh

Amend regulation so that fuel cost adjustment is not recoverable from the PPA buyer for MWh sold as URS.

This removes the incentive to dump fuel cost risk back on the contracted buyer after benefiting from market sales.

e). Example

Assumptions

• Contracted energy: 100 MWh

• Scheduled by original buyer: 60 MWh → URS = 40 MWh

• Declared ECR: ₹3.00/kWh

• Actual fuel cost: ₹3.50/kWh

• Market price for URS: ₹4.00/kWh

Key calculations (for URS = 40 MWh = 40,000 kWh)

• URS revenue = 4.00 × 40,000 = ₹160,000

• URS actual fuel cost = 3.50 × 40,000 = ₹140,000

• URS margin over actual = 160,000 − 140,000 = ₹20,000

• Original buyer’s avoided variable cost at declared ECR = 3.00 × 40,000 = ₹120,000

Two crediting rules one can choose (policy design choice)

1. Rule A — “Margin-only credit, no FCA on URS MWh”

   • Credit the margin above actual cost on URS to the original buyer, i.e., (Market Price − Actual Cost) × URS MWh.

   • With numbers: (4.00 − 3.50) × 40,000 = ₹20,000 credited to the original buyer.

   • Generator cannot later recover FCA for these URS MWh from the original buyer.

2. Rule B — “Revenue-to-baseline credit (stronger buyer protection)”

   • Credit URS revenue up to the buyer’s avoided variable cost at declared ECR, i.e., min(Market Price, Declared ECR) × URS MWh.

   • With numbers: min(4.00, 3.00) × 40,000 = ₹120,000 credited to the original buyer.

   • Generator keeps any excess over this cap only if policy allows (here, excess would be 160,000 − 120,000 = ₹40,000).

Interpretation & when to use which

• Rule A is simpler and aligns with “no FCA on URS MWh,” preventing the classic gaming where cost gets pushed back to the PPA buyer.

• Rule B is stricter in favor of the buyer, ensuring that at least the avoided variable cost (at declared ECR) is returned to the buyer before the generator retains any upside. This is closer to legacy URS-sharing intuitions in inter-state stations.

f). Bottom line

To stop this kind of gaming:

• Lock ECR to a verified cost floor for MBED dispatch.

• Tag and separate URS sales in the central settlement.

g)  Safeguards Against Gaming

Following safeguards are suggested for MBED implementation:

1. Gate-Closure on ECR Adjustments – Once bids are submitted for day-ahead MBED clearing, no retrospective revision of ECR should be allowed for that delivery day. Fuel cost adjustments should apply only prospectively after regulatory verification.
2. URS Revenue Sharing with Original Buyer – If URS from a contracted generator is dispatched to another buyer at a higher price, the incremental revenue should be credited back to the original PPA buyer, either fully or in a regulator-specified ratio.
3. Independent Verification of Fuel Cost Inputs – Heat rate, GCV, and fuel price declarations must be validated by the Market Monitoring Unit (MMU) before allowing them into the bid stack, to prevent deliberate under-declaration.
4. Price Floors and Ceilings During Transition – Until market depth develops, cost-based price floors and ceilings should be imposed to prevent both predatory bidding and excessive windfall gains.
5. Audit and Penalty Mechanisms – Any ex-post detection of bid manipulation, including artificial lowering of ECR to influence dispatch, should trigger financial penalties, disqualification from market participation for a period, and public disclosure.
6. Real-Time URS Tagging in MBED Engine – The MBED dispatch software should automatically tag and log which portion of a generator’s output is serving the original buyer and which is URS, enabling transparent settlement.
Implementing these safeguards will ensure that MBED delivers genuine economic efficiency benefits to the power system, while protecting DISCOMs and consumers from strategic market manipulation.

12) Closing thought: Pragmatism over perfection

India doesn’t need to leap to a textbook LMP market overnight. A pragmatic MBED—uniform/zonal prices, capacity outside energy, transparent uplift, and strong governance—can unlock billions in avoidable costs while improving reliability. The building blocks are already in motion: SCED learnings, Ancillary Services, GNA, Resource Adequacy, and even policy shifts enabling URS market access. The challenge now is to stitch them together with careful phasing and ironclad settlements so that no party is worse off in the transition—and consumers are better off by design.