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Participant Funding Does Competitive Generation Require Competitive Transmission? Robert J. Michaels California State University, Fullerton and Tabors.

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Presentation on theme: "Participant Funding Does Competitive Generation Require Competitive Transmission? Robert J. Michaels California State University, Fullerton and Tabors."— Presentation transcript:

1 Participant Funding Does Competitive Generation Require Competitive Transmission? Robert J. Michaels California State University, Fullerton and Tabors Caramanis & Associates, Cambridge Center for Business Intelligence Transmission Expansion Conference Alexandria, Virginia October 8, 2003 © 2003 Robert J. Michaels

2 Why Participant Funding, why now?  Competitive generation and centralized transmission An uneasy and possibly inefficient coexistence Particularly with market and policy uncertainties  Different roads to participant funding – SeTrans, PJM, and Order 2003 Concerns of their critics – serious obstacles or just self-interest? FERC gets its say in SMD / WPMP  After Policy Uncertainty, what questions remain?  Conclusions

3 Generation and transmission  Substitutes in production of delivered electricity  Efficient operation and investment require economically rational pricing  Generation went to market, transmission stayed with utilities and regulators Energy at marginal cost, transmission at average cost Basic grids from pre-market times, planned for utility-owned generation How different is planning under ISOs / RTOs?  Inefficient choice of generator locations, aggravated by gas/electric rate design

4 New transmission in today’s industry  Utilities remain autonomous or RTOs plan lines utilities will (usually) own  Inadequate returns, financial and political uncertainty affect construction Treatment of access charges and LMP Uncertainty about competition in past, Standard Market Design in future  Siting difficulties, state and fed jurisdictions  Blackout-related panic may not restore investment levels $5 billion in 1975, $2 billion in 2000

5 SeTrans: Participant Funding at FERC  7/02: Responding to concerns about export of benefits, SeTrans proposes to FERC: “Base Plan” lines for reliability, collectively funded Participant Funded [PF] for generation developers, native loads, transmission-dependent utilities  Opposition from states, others SEARUC: Region only benefits if there is PF IPPs, public power, co-ops, industrial users prefer rolled-in transmission  10/02: FERC accepts SeTrans basics But orders rehearing re cost allocations

6 Objections to SeTrans  Beneficiaries of rolled-in pricing Approve of PF if beneficiaries are distant  Impossibility of measuring and assigning benefits When upgrade has multiple purposes  Utilities will classify lines to raise rivals’ costs and benefit own plants  Scale economies require large investments, cause CRRs to lose value  Does SeTrans’s survival depend on content of energy bill?

7 After SeTrans I  FERC rejects direct assignment of network facilities, citing precedent  ‘02 Energy bill wants FERC to allow PF as option, ’03 draft asks for PF rules  ’02 SMD and ’03 Wholesale Platform  11/02 tech conference consensus that RTOs offer PF as option  6/03 Entergy asks for interim institution of PF prior to opening of SeTrans

8 After SeTrans II  7/03 FERC issues interconnection rule, PF an option  7/03 National Grid proposes “beneficiary funding” for eastern New York upgrades FERC staff earlier said RTO zones and RTOs themselves could be defined as beneficiaries

9 After SeTrans III  7/03 NEPOOL, ISO-NE propose PF for market investments with clear beneficiaries How permanent are beneficiaries in New England?  8/03 NE regulators and IPPs ask for broader PF Bring up inconsistency between “socialized” funding and LMP Claim NEPOOL originally socialized due to erroneous assumptions about non-congestion. Propose allocating 25% of costs to pool, 75% to beneficiaries unless unidentifiable, roughly like PJM  9/03 Connecticut regulators object re identifiability of benefits

10 3/03 PJM transmission owners’ filing  Time line first looks at unhedgeable congestion Conflict: All congestion hedgeable at some cost, but use of gross volumes will be inefficient  Then one year for relief suggestions Demand management, new IPPs, merchant lines  Incentives for line construction v. overcollection  Can PJM order construction of transmission unrelated to reliability? Can they set a bright line around base additions and leave PF for a residual? What will PJM governance allow?

11 PJM’s critics  Hogan: Participants may hold out on funding until base facility is needed Who decides in a dispute over base v. PF? Bright-line standards or constant quarreling? Will base or PF be treated as a residual?  IPPs and others: Proposal will ensure bias toward transmission solutions Did transmission owners circumvent PJM protocols to bring this forward? No principles re evaluating substitutes to a link  PF may discourage lines to distant sources that raise fuel diversity

12 Order 2003: New Interconnection Rules  Part of the RTO push They are allowed PF as a flexible option  Standardization and regional committees? Details of cost allocation, etc. to develop in dockets  Non-RTOs get less choice Generator pays to interconnection + other necessary upgrades These to be refunded 5 years after operation begins Generator also pays for grid upgrades to serve its own load  Similar rule likely for generators under 20 MW  Munis and Coops request stay

13 Open questions I  How to induce PF construction that acknowledges ultimate scale economies  Are there competitive issues re strategic use of PF transmission Will market monitors have a say?  Will allocation of CRRs net of counterflows always be sufficient (and efficient) payment for a PF line?

14 Open Questions II  Do all parties benefit pro rata from reliability of additions? If they do not, are zones and license plate rates sufficient for efficiency? If contribution to reliability of nonprincipals is small, need not consider socialization of costs  Will PF discriminate against distributed generation or demand flexibility?  Can a cost allocation scheme be instituted that does not invite disputes over every addition?

15 What markets are really about  Existing paradigm assumes easy determination of needed lines This view once applied to generation too  If lines are obvious, funding scheme is of secondary importance  Edelston: “We cannot optimally plan the transmission system any longer, and we should not try and pretend that we can” If so, is PJM a step backward?

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