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Long-Term Transmission Rights (“LTTRs”) William H. Dunn, Jr. Gestalt, LLC/Sunset Point, LLC

APPA 2007 National Conference Session #10: LTTR, FCM, RPM, MRTU: Do More Acronyms Mean Better RTO Markets? June 25, 2007. Long-Term Transmission Rights (“LTTRs”) William H. Dunn, Jr. Gestalt, LLC/Sunset Point, LLC. Outline of presentation. What’s the problem Negative aspects What was done

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Long-Term Transmission Rights (“LTTRs”) William H. Dunn, Jr. Gestalt, LLC/Sunset Point, LLC

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  1. APPA 2007 National ConferenceSession #10: LTTR, FCM, RPM, MRTU:Do More Acronyms Mean Better RTO Markets?June 25, 2007 Long-Term Transmission Rights (“LTTRs”) William H. Dunn, Jr. Gestalt, LLC/Sunset Point, LLC

  2. Outline of presentation • What’s the problem • Negative aspects • What was done • The FERC guidelines • What happened in New England • Current state of play

  3. What’s the problem? • In the old Order No. 888 world Load Serving Entities (“LSEs”) could commit to remote high fixed cost, low energy cost resources and know they would receive the benefit of the low cost energy • In the world of Locational Marginal Pricing (“LMP”) with Financial Transmission Rights (“FTRs”) limited to a maximum of 1 year, LSEs can end up paying both high fixed costs and high effective (delivered) energy prices • This creates a disincentive to invest in remote baseload plants, such as coal and nuclear • This also creates a disincentive to invest in remote renewable resources that may not be baseload but also tend to have high fixed costs and low variable costs • Under either world, the LSE is paying its pro-rata share of the annual transmission revenue requirements • The LMP/FTR world is essentially a short-term focus world, while public power systems still have a long-term focus

  4. Power supply in the Order No. 888 world Potentially constrained transfer capability L1 1,500+ MW Bus A Bus B 1,000 MW $200/kW-Yr $20/MWh 80% annual capacity factor 500 MW $50/kW-Yr $100/MWh 50% annual capacity factor G1 G2 Ignoring other sources of supply and other LSEs: LSE pays the annual cost of G1 ($200 million for capacity plus $140 million for energy) LSE pays the annual cost of G2 ($25 million for capacity plus $219 million for energy) Delivered cost of G1 energy is $48.52/MWh Delivered cost of G2 energy is $111.42/MWh When there is a constraint between G1 and G2/L1, the LSEs supporting the cost of the transmission system share in the incremental cost of any redispatch to resolve the problem.

  5. Power supply in the LMP/FTR world Potentially constrained transfer capability L1 1,500+ MW Bus A Bus B 1,000 MW $200/kW-Yr $20/MWh 80% annual capacity factor LMP = $20/MWh when running* 500 MW $50/kW-Yr $100/MWh 50% annual capacity factor LMP = $100/MWh when running* G1 G2 Ignoring other sources of supply and other LSEs: LSE pays the annual cost of G1 ($200 million for capacity plus $140 million for energy) LSE pays the annual cost of G2 ($25 million for capacity plus $219 million for energy) Delivered cost of G1 energy is $48.52/MWh Delivered cost of G2 energy is $111.42/MWh Congestion rate is $80/MWh when there is a constraint between G1 and G2/L1 In hours of constraint, the effective delivered cost of G1 energy to L1 goes from $20/MWh to $100/MWh, without FTR/LTTR hedging, and the total delivered cost of G1 capacity & energy to L1 goes from $48.52/MWh to $128.52/MWh, which would be more than the total delivered cost of G2 capacity & energy * Simplifying assumption that each unit is marginal on its side of the constrained interface.

  6. Some of the negative aspects • As indicated on the previous slide, LSEs pay congestion charges in additional to the transmission charges to support the cost of the transmission system with no way to hedge such congestion charges on a long-term basis • These congestion charges, calculated in the Day-Ahead Market (DAM), can be caused by virtual trading (i.e., phantom congestion) and are applied to ALL transactions, not just those in the DAM • These congestion charges can be significant even when the load and generator are in the same zone • In many cases there are insufficient FTRs available to hedge existing long-term resource commitments, never mind new remote baseload and renewable resources, and the future costs of these FTRs are unknown • LSEs are subject to two forms of pro-rationing; one when they cannot obtain the FTRs they need and the other when the FTRs allocated are not fully funded (i.e., insufficient congestion rents are collected to pay the FTR holders)

  7. What was done about the problem • APPA Issued its “Restructuring at the Crossroads” Policy Paper in late 2004 • In early 2005, a small APPA task force was formed and discussions were held with FERC staff on the issue and its ramifications • In May 2005 FERC issued a request for comments on the LTTRs issue, including an attached FERC Staff Discussion Paper • In June 2005 APPA filed comments as requested, including an attached Concept Paper on LTTRs • In August 2005 President Bush signed Energy Policy Act 2005 • In February 2006 FERC issued an LTTR Notice of Proposed Rulemaking (“NOPR”) • In March 2006 APPA submitted its comments on the NOPR and in April 2006 submitted Reply comments • FERC issued its Order No. 681 Final LTTR Rules in July 2006, which Rules were clarified in Order No. 691 A in November 2006

  8. The FERC LTTR Guidelines (1) • Guideline (1): The long-term firm transmission right should specify a source (injection node or nodes) and sink (withdrawal node or nodes), and a quantity. • Guideline (2): The long-term firm transmission right must provide a hedge against day-ahead locational marginal pricing congestion charges or other direct assignment of congestion costs for the period covered and quantity specified. Once allocated, the financial coverage provided by a financial long-term right should not be modified during its term (the “full funding” requirement) except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization.

  9. The FERC LTTR Guidelines (2) • Guideline (3): Long-term firm transmission rights made feasible by transmission upgrades or expansions must be made available upon request to any party that pays for such upgrades or expansions in accordance with the transmission organization’s prevailing cost allocation methods for upgrades or expansions. • Guideline (4): Long-term firm transmission rights must be made available with term lengths (and/or rights to renewal) that are sufficient to meet the needs of load-serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. The length of term of renewals may be different from the original term. Transmission organizations may propose rules specifying the length of terms and use of renewal rights to provide long-term coverage, but must be able to offer firm coverage for at least a 10 year period.

  10. The FERC LTTR Guidelines (3) • Guideline (5): Load-serving entities must have priority over non-load serving entities in the allocation of long-term firm transmission rights that are supported by existing transmission capacity. The transmission organization may propose reasonable limits on the amount of existing transmission capacity used to support long-term firm transmission rights. • Guideline (6): A long-term transmission right held by a load-serving entity to support a service obligation should be re-assignable to another entity that acquires that service obligation. • Guideline (7): The initial allocation of the long-term firm transmission rights shall not require recipients to participate in an auction.

  11. Other impacts of Order No. 681 • Order No. 681 required Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”) operating “Day 2” markets (i.e., markets using LMPs and FTRs) to file within 6 months proposals to provide LTTRs • Seeing the handwriting on the wall, RTOs like ISO-NE, which had been opposing the efforts of public power to develop LTTRs, suddenly decided to form working groups to address the issue • Since most market participants in Day 2 markets have a short-term focus, and the representatives of some ISOs/RTOs like ISO-NE were philosophically opposed to LTTRs, making progress on these working groups, at least in New England, was a challenge

  12. Positive aspects of ISO-NE’s LTTR proposal • After long debate, ISO-NE filed a proposal that meets many of the Guidelines and has many aspects supported by the New England Public Systems (“NEPS”). Some of the unique aspects include: • Creation of two types of LTTRs, Allocated and Auctioned • Requirement that the LSE attest to both a long-term service obligation and a long-term power supply entitlement to receive Allocated LTTRs • Restriction on amount of Allocated LTTRs based on annual load factor and use of up to 25% of the non-radial transmission system • Fully fund LTTRs and short-term FTRs by having ARR holders provide any congestion rent shortfalls (and receive any excesses) • Because New England does not allocated Auction Revenue Rights (“ARRs”) based on use, like PJM, this created a need to develop an alternative mechanism for LSEs to receive (Guideline #7) and renew (Guideline #4) LTTRs, and this is where problems developed and continue

  13. Negative aspects of ISO-NE’s LTTR proposal (1A) • Pricing of Allocated LTTRs • The ISO-NE proposal prices Allocated LTTRs at the price determined for each future year by the auctions for Auctioned LTTRs • The proposal requires LSEs to commit to Allocated LTTRs and then pay the yearly prices determined in the subsequent auctions for Auctioned LTTRs • ISO-NE admits that to protect themselves from uncapped prices, LSEs would have to bid their Allocated LTTRs into the auction at the maximum price they are willing to pay • The auctions for future years (e.g., year 5) may not have sufficient participation (since most market participants have a short-term focus) to produce realistic results and an even more limited portion of the transmission system is made available in future years for Auctioned LTTRs • This approach violates Guideline #7

  14. Negative aspects of ISO-NE’s LTTR proposal (1B) • NEPS pricing proposal • Each LSE receiving Allocated LTTRs would forgo receiving a predictable percentage of its ARR revenues based on its relative number of Allocated LTTRs as compared to its load • As a result, the amount paid for the LTTRs would vary as ARR revenues vary • Currently, each LSE’s allocation of ARR revenue is based on its load ratio share of the load in the zone at the time of the system monthly peak • Instead, NEPS proposed the allocation of ARR revenues be based on monthly energy, with the monthly energy of LSEs receiving Allocated LTTRs being reduced by the quantity of energy hedged by their Allocated LTTRs at a 100% capacity factor • LSEs in the zone not receiving Allocated LTTRs would, as a result, receive a larger share of the zonal ARR revenues • This provides another incentive to only use Allocated LTTRs for baseload or renewable energy resources

  15. Negative aspects of ISO-NE’s LTTR proposal (2) • Term and renewal provisions • The ISO-NE proposal provides Allocated LTTRs for an initial term of 5 years and renewable in 5 year blocks • To hedge a term that is not divisible by 5, an LSE will have to participate in the auctions for FTRs and Auctioned LTTRs or in the bilateral market for LTTRs/FTRs to hedge its risks in the years above those divisible by 5 • NEPS term and renewal proposal • NEPS proposed that the initial term of an Allocated LTTR be no less than 5 years or more than 10 years • Renewals would be automatically granted on 5 years notice • This allows LSEs to hedge contracts of any number of years, but LSEs would still have to rely on the short-term FTR market for any partial years • Once an LSE elects not to renew, the Allocated LTTR becomes fixed at the remaining 5 years • This approach actually provides ISO-NE with more advanced notice of renewals and is a better approach to Guideline #4

  16. Current state of play • FERC has accepted the LTTR proposal of PJM • In the case of PJM, their existing multi-step ARR allocation process was modified to provide a step in Stage 1 for the allocation of LTTRs up to a base load amount and then additional FTRs based on historical use of the transmission system • The rest of the PJM ARR allocation process (Stage 2, multi-round) stayed similar to the current ARR allocation process and FTRs can be requested from any location (i.e., non-historical) • All these ARRs can then be directly converted to FTRs/LTTRs • At a high level, in the case of MISO FERC accepted an approach to LTTRs that is very similar to PJM’s with an emphasis on baseload resources for their Stage 1A long-term ARRs • At the time of the drafting of these slides (early June), FERC had still not acted on the ISO-NE proposal • If FERC acts prior to the APPA National Conference, I will have to summarize their actions verbally!

  17. Contact Details William H. Dunn, Jr. Executive Consultant Gestalt, LLC/Sunset Point, LLC 10 Sunset Point Yarmouth, ME 04096 (207) 847-9345 wdunn@gestalt-llc.com

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