FERC Standard Market Design Working Papers Northwest Power Planning Council Whitefish, MT May 14, 2002

Overview Aims: Reform the Order 888 open access tariff, under which most transmission provided today, to incorporate standard market design (SMD) Apply to RTOs, IOUs (not in an RTO) – no mention of reciprocity (but was included in Order 888) Some confusion about RTOs vs. individual utilities Lead to NOPR in the summer, final rule end of year General Principles Major specific proposals and issues raised in papers Potential Northwest issues May 14, 2002

General Principles – 1 Common framework; reduce transaction costs and seams problems; fair, well defined and understandable Operation of imbalance markets and transmission systems by entities independent of market participants (affects non-RTO IOUs) Energy and transmission markets accommodate and expand customer choices Technology- and fuel-neutral market rules (supply and demand resources, large and small resources) Price signals that reflect time and locational value of energy (but not full substitute for planning and expansion process for transmission, generation and demand response) May 14, 2002

General Principles – 2 Demand response is essential Transmission owners continue opportunity to recover costs; merchant lines have no regulatory assurance of recovery Customers with existing contracts (including implicit) receive same level and quality of service; unused capacity available to others SMD not static; shouldn’t inhibit adaptation to regional requirements or hinder innovation. May 14, 2002

Transmission Service Network Access Service: offer to all customers including vertically integrated utilities All service to retail and wholesale loads – transition issues Combine flexibility of network service with tradable rights of point to point service; replaces both Service defined by source and sink (includes individual nodes and aggregations into hubs) Access fee allows access to all sources and sinks Congestion managed via locational marginal pricing (LMP) Congestion cost covered by transmission rights or paid on each transaction May 14, 2002

Transmission Rights – 1 Provide hedge against transmission congestion by allowing receipt of congestion payments, which offset congestion charges to transaction Congestion charges set by difference in nodal prices Rights provide cash if transmission not scheduled [RTOW: rights expire if not used; do not provide cash] Transmission constructor receives rights Converting rights holder either receives new rights or money from rights auction – an open issue [RTOW: new rights] Schedules accepted whether or not they have associated transmission rights – rights are financial only May 14, 2002

Transmission Rights – 2 Variation 1: can be either source-to-sink or flowgate Source-to-sink: Complete hedge against congestion on all impacted paths [RTOW: source-to-sink only] Flowgate: partial hedge against congestion on a path Variation 2: can be either options or obligations Options: right to transmit or “collect” congestion payment [RTOW: option only] Obligation: requirement to transmit or “collect” payment “Collect” can mean “pay” if congestion reverses Obligations must be offered and options must be offered on request May 14, 2002

Energy Market Design Transmission provider must operate both day ahead and real time (imbalance) markets [RTOW: no day ahead energy market] Day ahead market: joint schedule to maximize combined value of transmission, energy and ancillary services Both day ahead and real time markets are bid-based and security constrained Day ahead market is voluntary (real time market does not specify voluntary; not clear whether intended or not) Both markets must accommodate demand side participation May 14, 2002

Day Ahead Energy Market – 1 Should fully accommodate bilateral transactions and self-supply Cannot require balanced energy schedules [RTOW: requires balanced schedules] May need to limit bidding flexibility to mitigate market power Recognizes need to accommodate characteristics of energy limited resources (e.g., hydro) in bidding Must allow multi-part bids (start up, no load, energy) Start up costs not covered by hourly prices (based on energy bids only) are uplifted [RTOW: not contemplate multi-part bids] May 14, 2002

Day Ahead Energy Market – 2 Settle buyers and sellers at nodal prices If requested, transmission provider should provide trading hubs (weighted averages of nodal prices) Day ahead results must be financially binding on buyers and sellers Imbalances (including deviations from schedules) settled at real time prices, for both buyers and sellers [RTOW: requires balanced schedules, so schedule coordinator (the agent) faces any net imbalance, not buyers and sellers independently] May 14, 2002

Real Time Energy (Imbalance) Market All imbalances, even in bilateral energy markets, settled at imbalance price No multi-part bids Accommodates scheduling by energy limited resources Settles at nodal prices in 5 minute increments [RTOW: not specified] Imbalances that threaten reliability may require special rules including penalties May 14, 2002

Other Markets Regulation and operating reserves – load serving entity (LSE) responsible for procuring or paying for Must accommodate bilateral transactions and self-supply Transmission provider must have bid based day ahead and real time markets for these so can procure for LSEs [RTOW: scheduling coordinator responsibility] Transmission capability must be calculated regionally, by independent entity if owner not part of RTO Regional long term planning and expansion – RTO chooses solution (transmission, generation or demand side) and implements [RTOW: limited RTO choice and implementation role] May 14, 2002

Market Power Monitoring / Mitigation Focus on detecting economic and physical withholding Must have bid cap (demand response proxy) until sufficient demand response in place [RTOW: no proposal] May identify generators that must run for local reliability and have local market power Must coordinate maintenance and outage schedules for generation and transmission [RTOW: not generation] RTO Must have independent market monitoring unit (MMU) reporting directly to FERC and to RTO independent board MMU monitors all regional markets, especially for withholding MMU reports periodically to FERC; proposes rule changes May 14, 2002

Generation Adequacy – 1 Principles: SMD may include measures to ensure [RTOW: does not] Prefer state/regional reliability authorities coordinate to set long-term reserve margin for LSEs Transmission provider should avoid curtailing LSE loads if provided for themselves (if possible) Specific alternatives: Rely on prices and supply/demand information Require capacity obligation for operating reserves only, e.g., by forward contracts May 14, 2002

Generation Adequacy – 2 Require a regional supply or capacity obligation, imposed on all LSEs Region could be RTO Alternative enforcement mechanisms: E.g., no curtailments, administrative penalties, condition of receiving transmission rights, etc. Alternative timing requirements: E.g., years, seasons or months ahead Impose supply obligation on LSEs only if projected reserves fall below trigger level May 14, 2002

Rate Issues – Open Questions – 1 Some regional deference on these questions, especially if RTO in place Who pays the access charge? All schedules? Only loads? Only those who get rights? [RTOW: combination of first two] Should access charge apply to exports and wheel-throughs? Yes? No? Yes, through reciprocity payments? Yes, but lower? [RTOW: Yes, but will work on reciprocity] Access charge based on peak or energy? Monthly peak? Annual peak? Total energy? [RTOW: monthly peak] May 14, 2002

Rate Issues – Open Questions – 2 Transition of service to new tariff (including existing contracts and bundled retail service) [RTOW: voluntary] Transition on implementation? Bundled service on implementation with incentive for contracts? Regional variations? (only if RTO in place) Allocation of transmission rights Assign to existing customers? To all that pay access charge? [RTOW: existing customers] Assign? Auction (money to existing customers)? Regional variation, if RTO in place? [RTOW: assign] May 14, 2002

Potential Northwest Issues Hydro coordination and flexibility, no day ahead unit commitment Protect current rights holders who do not want to convert Service to bundled retail loads – state jurisdictional issue Voluntary bids (recognize opportunity cost issues for hydro) Options, not obligations for transmission rights Allow RTO to require balanced schedules Day ahead formal energy market? RTOW: none proposed Generator maintenance requirement Demand response responsibility: state/utility or RTO? May 14, 2002