Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, Joseph T. Kelliher, and Suedeen G. Kelly.
Midwest Independent Transmission System Operator, Inc., Public Utilities With Grandfathered Agreements in the Midwest ISO Region
1. On March 31, 2004, the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) filed a proposed Open Access Transmission and Energy Markets Tariff (TEMT) pursuant to section 205 of the Federal Power Act (FPA), 16 U.S.C. 824d (2000). The proposed TEMT contains the terms and conditions necessary to implement a market-based congestion management program, including a Day-Ahead Energy Market, Real-Time Energy Market and Financial Transmission Rights (FTR) Market, on December 1, 2004. It also presents the Commission with the critical threshold issue of how to treat approximately 300 grandfathered agreements (GFAs) currently in force in the Midwest ISO region.
2. The Midwest ISO states that the integration of the GFAs into its energy markets is “important to the success and reliability” of those markets, and that absent the integration of the GFAs, third parties may be subject to substantial costs that could threaten the markets' viability. As discussed below, it proposes a methodology, for approval under section 205, that it argues would enable the GFAs to function within the Midwest ISO's proposed energy markets.
3. The Midwest ISO's proposed method of congestion management is a high priority for the Commission, due to its reliability benefits and its economic efficiency benefits, but we firmly believe that it should not start until the GFA issue is more completely addressed. As a stepping stone to our consideration of the proposed TEMT, this order initiates a three-step process to address the GFAs and offers an option for settling the GFAs. In addition, this order presents a revised timeline to guide us, and the parties to this proceeding, through the process of considering the TEMT filing and implementing the Midwest ISO's proposed energy markets. We wish to emphasize that setting out this timeline does not amount to preapproval or prejudgment of the merits of the Midwest ISO's TEMT filing. Rather, we recognize that the Midwest ISO has been attempting to implement its congestion management proposal for some time, and that resolution of this critical issue is required. We wish to provide more time for the parties to complete these intermediate steps. To provide sufficient due process for GFA parties, allow appropriate allocation of FTRs and ensure that market participants have sufficient time to perform market trials, the Commission moves the date for implementation of the energy markets to March 1, 2005.
4. Today's order benefits customers by clarifying the procedural steps that will be necessary to open the Midwest ISO energy markets by March 1, 2005, and by taking measures necessary to ensure that the GFAs and other market participants are treated fairly and reasonably if the TEMT is approved.
5. In an order dated December 20, 2001, the Commission found that the Midwest ISO's proposal to become a Regional Transmission Organization (RTO) satisfied the requirements of Order No. 2000, and thus granted the Midwest ISO RTO status. The Commission also determined that the Midwest ISO's proposal for congestion management was a reasonable initial approach to managing congestion and satisfied the requirements of Order No. 2000 for Day 1 operation of an RTO. It directed the Midwest ISO to coordinate its Day 2 congestion management efforts with the pending rulemaking on Standard Market Design.
6. To address the Commission's instruction that the Midwest ISO remain mindful of the proposed Standard Market Design in developing its Day 2 congestion management proposal, the Midwest ISO filed a Petition for Declaratory Order that sought the Commission's endorsement of the general approach represented in three proposed market rules (Market Rules). The Market Rules would provide for: (1) A security-constrained, centralized bid-based scheduling and dispatch system (i.e., day-ahead and real-time market rules); (2) FTRs for hedging congestion costs; and (3) market settlement rules. The Commission approved the general direction of the Midwest ISO's energy markets proposals, reserving judgment on some issues and providing guidance on others as discussed below. The Commission affirmed many of its conclusions on rehearing.
7. On July 25, 2003, the Midwest ISO filed a proposed TEMT pursuant to FPA section 205 (July 25 Filing). Like the instant filing, the July 25 Filing included terms and conditions necessary to implement the Midwest ISO's Day-Ahead Energy Market, Real-Time Energy Market and FTR Market. The filing met with numerous protests, many of which alleged that the proposed tariff was incomplete and that its filing was premature. The Midwest ISO filed a motion to withdraw the proposed TEMT, but it requested “any and all guidance the Commission can give the Midwest ISO and its stakeholders on the matters presented in the July 25th Filing.”
8. The Commission granted the Midwest ISO's motion to withdraw the July 25 Filing and provided, on an advisory basis, guidance on a number of issues raised in that filing. The Commission stated in the TEMT Order that it expected its guidance to better enable the Midwest ISO to prepare and file a complete version of the TEMT or a similar proposal.
II. Revised Transmission and Energy Markets Tariff
9. Through the revised TEMT filed on March 31, 2004, the Midwest ISO again proposes to implement real-time energy imbalance services and a market-based congestion management system via a centralized platform for the dispatch of generation resources throughout the Midwest ISO region. It plans to implement day-ahead and real-time energy markets with locational marginal pricing (LMP), and allocate and auction FTRs to allow market participants to hedge against the costs of congestion in Start Printed Page 32103the Day-Ahead Market. The Midwest ISO seeks an effective date of December 1, 2004, for its new tariff.
10. The Midwest ISO explains that it would like to implement limited sections of the TEMT on an earlier schedule in order to resolve two issues that will be critical to starting the markets. First, the Midwest ISO notes that a large number of GFAs are in force in its region, and that in order to accommodate GFA transactions in the energy markets, it needs the parties to the GFAs to decide how transactions pursuant to their agreements will be treated in the energy markets. The Midwest ISO proposes an Expedited Dispute Resolution (EDR) process that will allow parties to GFAs to decide which party to each GFA will serve as the Market Participant for that GFA. It asks the Commission to make the portions of its tariff relevant to EDR effective on June 7, 2004.
11. The Midwest ISO also requests that the Commission make effective on June 7, 2004, all portions of the TEMT that pertain to FTRs. The Midwest ISO has developed a four-tiered nomination method that will allow Market Participants to nominate Candidate FTRs (CFTRs) associated with point-to-point or network transmission service subject to the TEMT. The Midwest ISO plans for the FTR nomination process to begin in July 2004 and continue through the fall of 2004.
A. Procedural Matters
12. Notice of the Midwest ISO's filing was published in the Federal Register, 69 FR 18893-94 (2004), with interventions and protests due on or before May 7, 2004. The parties listed in Appendix A filed interventions, protests and comments. Otter Tail Power Company (Otter Tail) filed a supplemental protest on May 17, 2004. The Midwest ISO filed an answer to the protests on May 19, 2004, and an amendment to its answer on May 20, 2004. The Midwest TDUs  and Cinergy Services, Inc. (Cinergy) filed comments responding to the protests on May 21, 2004; the Midwest TDUs' filing included an answer to the Midwest ISO's answer. National Rural Electric Cooperative Association (NRECA) and Dairyland Power Cooperative, Inc. (Dairyland) filed answers to the Midwest ISO's answer on May 24, 2004.
13. Pursuant to rule 214 of the Commission's rules of practice and procedure, 18 CFR 385.214 (2003), the notices of intervention and timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding. We will accept the motions of Manitoba Hydro and Xcel Energy Services, Inc. (Xcel) to intervene out of time. Given the early phase of the proceeding and the parties' interest, the late interventions will not disrupt the proceeding. For the same reasons, we will accept Otter Tail's supplemental protest.
14. Rule 213(a)(2) of the Commission's rules of practice and procedure, 18 CFR 385.213(a)(2) (2003), prohibits an answer to a protest or answer unless otherwise ordered by the decisional authority. We will accept the answers because they have provided information that assisted us in our decision-making process.
B. Treatment and Analysis of GFAs
1. The Midwest ISO's Proposal
a. Description of GFAs
15. The TEMT identifies GFAs as “agreements executed or committed to prior to September 16, 1998, or ITC Grandfathered Agreements that are not subject to the specific terms and conditions of the [TEMT] consistent with the Commission's policies,''  and that are listed in Attachment P to the Midwest ISO's open access transmission tariff (OATT). The Midwest ISO notes the Commission's prior approval of special treatment for transmission service under GFAs for a six-year transition period, and states that transmission service taken under GFAs is separate from transmission service taken under the OATT. The Midwest ISO states, however, that allowing holders of GFAs similar scheduling rights to current GFA practice would require a physical reservation, or “carve out,” of transmission capacity in the day-ahead market and until the scheduling deadline prior to real-time dispatch. The Midwest ISO day-ahead energy market would be scheduled around this reservation and adjustments to the reliability unit commitment (RUC) would also be required to support reliability. This “cannot be accomplished without negatively impacting the Midwest ISO's ability to reliably operate the Energy Markets and without placing excessive financial burden on other Market Participants.”  Accordingly, as described below, the Midwest ISO proposes a tariff methodology to allow the GFAs to function under the TEMT, and advocates that this treatment be used until at least February 1, 2008. Two years before that time, it proposes to begin to evaluate the GFAs' impact on the energy markets under this tariff proposal; one year before that time, it will file a new proposal for the treatment of the GFAs.
16. The Midwest ISO states that it has reviewed all contracts listed in Attachment P to the OATT. It says that specific details of the contracts, such as usage, scheduling requirements and megawatt quantity or capacity, are not readily apparent on the face of some of the contracts. The Midwest ISO adds, however, that about half the contracts had a specific megawatt value associated with them, and that in the aggregate those contracts accounted for approximately 20,000 megawatts of capacity. The Midwest ISO projects that the remaining half of the GFAs are likely to be associated with a similar number of megawatts. As a result, it says that up to 40,000 megawatts of capacity—about 40 percent of total load in the region—are likely to be associated with the GFAs. It concludes that the treatment of GFAs will have a significant impact on the total load serviced within the region and that a physical carve-out of the GFAs from the proposed energy markets is not feasible.
17. The Midwest ISO avers that operation of wholesale energy markets Start Printed Page 32104without information related to the flows of energy pursuant to GFAs would pose “substantial reliability risks.”  It also asserts that not requiring parties to the GFAs to schedule consistent with scheduling rules proposed in the TEMT would prevent the Midwest ISO from fulfilling its requirement under Order No. 2000 to develop a market-based congestion management mechanism. Finally, the Midwest ISO emphasizes that the GFAs' extensive impact on the Midwest ISO region makes a physical carve-out of the GFAs unduly burdensome for third parties. It cautions that “absent the integration of [GFAs] into the market, third parties may be subject to substantial costs which may ultimately threaten the viability of the market.” 
b. Scheduling and Settlement Options
18. The Midwest ISO states that, working in conjunction with a task force, it developed a solution to treat GFAs in a way that would: (1) Leave the parties to the GFAs “financially indifferent upon implementation of the energy markets;” as described below; (2) avoid negatively impacting the Midwest ISO's ability to operate energy markets; and (3) avoid placing undue burdens on third parties. The Midwest ISO argues that its proposal, described below, does not abrogate the terms of the agreements; therefore, the proposed treatment should be reviewed under the just and reasonable standard. In the alternative, the Midwest ISO argues that if the Commission determines that any portion of the Midwest ISO's proposed treatment of the GFAs amounts to reformation of those agreements, Commission should consider such treatment to be in the public interest pursuant to section 206 of the FPA and the Mobile-Sierra doctrine.
19. The Midwest ISO proposes to include all schedules and transactions, including those associated with GFAs, in its optimization and pricing procedures. It will allow parties to convert their GFAs to agreements under the TEMT at any time before or after the implementation of the energy markets. It also proposes to require parties that do not voluntarily convert their GFAs to select from among three options—to remain in place for a three-year transition period that will end coincident with the six-year transition period initially approved in 1998  —that will determine what rights and obligations the Midwest ISO will assign to market participants on behalf of the GFAs. All three options for unconverted GFAs will require the parties to submit to the Midwest ISO the following GFA information: (1) The name of the GFA Responsible Entity;  (2) the name of the GFA Scheduling Entity;  (3) the source and sink points applicable to the GFA; and (4) the maximum megawatt capacity permissible under the GFA. The parties must submit this information no later than June 7, 2004. If they cannot agree on the information before then, the Midwest ISO proposes to require them to enter EDR and provide the GFA information to the Midwest ISO no later than July 14, 2004. At the time they submit their GFA information, GFA parties that do not convert their agreements to TEMT service also must select the scheduling and settlement option that will apply to their GFAs.
20. Under Option A, the GFA Responsible Entity will be entitled to nominate the capacity under the GFA for an allocation of FTRs. It will hold the FTRs it receives in the allocation and assume responsibility for credits, debits, rights and responsibilities associated with those FTRs. The Midwest ISO will assess congestion charges and the cost of losses for all transactions under the GFA.
21. Option B provides that the GFA Responsible Entity will not nominate or receive FTRs. The Midwest ISO will charge the GFA Responsible Entity the cost of congestion for all transactions pursuant to the GFA, but—if the GFA Scheduling Entity submits the bilateral transaction schedule a day ahead, in keeping with section 39.1.4—the Midwest ISO will credit back to the GFA Responsible Entity the costs of congestion resulting from day-ahead schedules that the GFA Responsible Entity clears in the day-ahead market. The Midwest ISO will also charge the GFA Responsible Entity the cost of losses for all transactions under the GFA, then—as before, if the GFA Scheduling Entity has timely submitted a conforming schedule for the GFA—credit back to the GFA Responsible Entity the difference between marginal losses and system losses at the GFA source and sink points.
22. Market Participants that select Option C will neither nominate nor receive FTRs. The GFA Responsible Entity will pay marginal losses and the cost of congestion for all transactions pursuant to GFAs without receiving reimbursements as in Option B; they will, however, receive an allocation of excess marginal losses revenue.
b. Schedule 16 and 17 Charges
23. The Midwest ISO notes that Schedules 16 and 17 of the TEMT—which provide for the recovery of costs associated with the administration and allocation of, respectively, FTR services and energy market services—are the subject of a paper hearing in Docket No. ER02-2595-000. The Midwest ISO states that any Commission decisions concerning these schedules ultimately will be incorporated into the TEMT. To Start Printed Page 32105the extent that the determinations apply Schedule 16 and 17 charges to GFA transactions, the Midwest ISO believes that the market participant assessed these charges for GFA transactions should be able to recover those costs in its rates.
2. Protests and Comments
24. The Midwest ISO TOs maintain that the Midwest ISO's proposal is effectively seeking to revise existing contracts without the appropriate legal requirements being satisfied, or it is seeking to impose charges on public utilities to those GFAs without those utilities having a reasonable opportunity to recover the costs. They believe that the Midwest ISO has failed to make the necessary showing under the Mobile-Sierra doctrine that revision of the existing contracts meets the public interest standard. Xcel adds that it believes that GFA customers will be unwilling to pay Schedule 16 and 17 charges for the portion of their load served under the GFA or to participate in the proposed EDR process. Alternately, the Midwest ISO TOs assert that the proposal would impose trapped costs on parties to the contracts and that the Midwest ISO has failed to propose a regulatory mechanism to allow these charges to be recovered by these parties. The Midwest ISO TOs argue that the TEMT provisions regarding grandfathered agreements should be rejected. Further, the Midwest ISO TOs state that there is no operational reason for the Midwest ISO's position that it cannot operate by excluding the GFAs, much as PJM operates its market. The Midwest ISO TOs state that they are willing to provide the Midwest ISO with the operational information that it needs in order to implement the market with a carve-out for the GFAs that would hold the GFAs harmless from any market related costs and charges.
25. FirstEnergy requests that the Commission either amend the GFAs to change the price term in the contract or allow transmission owners to recover TEMT costs through a surcharge in their transmission rates. FirstEnergy states that without these changes, all market participants would subsidize individual contracts while the transmission owner still would bear some uncompensated costs for Schedule 16 and 17 charges. WPS Resources states that the Midwest ISO's proposal discriminatorily favors GFA parties at the expense of the majority of the Midwest ISO's load contrary to the anti-discrimination provisions of the FPA. WPS Resources and WUMS Load Serving Entities assert that such treatment perversely results in transfer of GFA-related costs from parties who retained their GFAs, inconsistent with Commission policy, to those, such as the WUMS utilities, who converted to OATT service. WPS Resources suggests that Option B should be given to all load or GFA parties should be limited to Options A and C.
26. OMS is concerned that the proposed insertion of Option B GFAs into Tier I and II of the FTR allocation process will offset the available CFTRs for non-GFA loads. OMS describes the Midwest ISO's proposal as allowing 100 percent of FTRs for Option B GFAs to be allocated first in Tier I and Tier II. OMS request that the Commission instruct the Midwest ISO that the GFA nominations for GFA holders that select Option B should not be allowed to exceed the tier limits of Tier I (35 percent) or Tier II (50 percent). On the matter of the Midwest ISO's proposed GFA scheduling and settlement options, OMS states that while it believes treating GFAs the same as other network and point-to-point transmission service contracts would be the best alternative, it recognizes that compromises must be made in the transition to an organized energy market. In this regard, OMS requests that the Commission open an investigation of the justness and reasonableness of the impact of the Midwest ISO's proposed GFA options on other market participants and on the overall efficiency of the market in order to inform the Commission on the treatment of the GFAs following the transition period ending February 1, 2008.
27. EPSA concurs with the Midwest ISO's threshold determination that any attempt to physically carve out the capacity associated with the GFAs would threaten reliability and place an unacceptable financial burden on Market Participants. But EPSA, Dynegy, Reliant, PSEG and Cinergy also assert that GFA Option B places an unacceptable financial burden on Market Participants through uplift costs by creating added benefits for the GFAs under Option B that go beyond preserving the material benefits and obligations of the pre-existing contracts. EPSA and Cinergy quote Professor Hogan's Midwest ISO-sponsored testimony in describing these added benefits for GFAs under Option B. Professor Hogan states that under Option B the GFA customer's use-it-or-lose-it feature of physical schedules would be eliminated or substantially reduced; the chance of curtailment under TLR rules would be reduced; the costs of redispatch to accommodate GFA transactions would be shifted to non-GFA parties through uplift charges; and the costs of marginal losses would be reduced to average losses. Dynegy contends that the lack of comparable treatment between grandfathered and non-grandfathered contracts will deter new members from joining the Midwest ISO and deter the development of new generation. Dynegy requests that the Commission reject the Midwest ISO's proposed treatment of the GFAs and direct the Midwest ISO to allocate the market costs of the GFAs to the transmission owners that are parties to the GFAs. Reliant states that since some of the GFAs may not have provisions for paying redispatch costs, that the Commission should reject the Midwest ISO GFA option that provides for a perfect hedge in the Day-Ahead Market. Alternatively, Reliant states that GFA holders should bear the responsibility for congestion costs created by GFA transactions unless these costs are specifically addressed and allocated in the GFA. PSEG states that the Commission should encourage voluntary conversion of the GFAs to OATT service by expediting review of the contract filed at the Commission for conversion. Cinergy states that if the Commission is unprepared to reject Option B outright, that the Commission should require the Midwest ISO to quantify the scope and impact of the uplift under Option B and justify the justness and reasonableness of the uplift to non-GFA market participants.
28. Cinergy asserts that mandatory, binding EDR is unlawful. It states that as the Midwest ISO will not make an Attachment P compliance filing until May 26, 2004, there will only be seven business days for GFA holders to reach agreement before the proposed start of the EDR process. Cinergy states that seven days to resolve GFA issues prior to mandatory EDR is manifestly unjust and unreasonable and should be rejected by the Commission. In addition, Cinergy states that the proposed twenty-five-day window for arbitrators to make their decision, as well as the lack of technically qualified arbitrators, creates a high probability of error in the decision-making process. Further, Start Printed Page 32106Cinergy states that the Midwest ISO's proposal is unclear as to whether the proposed EDR is voluntary and non-binding or mandatory and binding. Cinergy concludes that the Commission alone has jurisdiction over matters related to the relationship between a FERC-filed tariff and a FERC-filed GFA and cannot allow an arbitrator's decision to bind the Commission. Cinergy asserts that the appropriate venue for dispute resolution is at the Commission unless both parties agree to arbitration.
29. Contrary to Cinergy's position, EPSA supports the Midwest ISO's request to approve the proposed EDR process to ensure that all load provide the necessary information for allocation of FTRs. Dairyland believes that any proposed EDR process for GFAs must be voluntary under the Mobile-Sierra doctrine. Midwest TDUs assert that the EDR procedures fail to protect the substantive rights of parties to the GFAs because the EDR process addresses too broad an array of disputes on too tight a timeline and imposes costs that TDUs may pay twice—once through their half of the arbitration costs and again as passed through the transmission owners' rates. They state that the EDR process should be reformed to be more like the Appendix D arbitration process for transmission owner disputes, including allowing informal dispute resolution followed by non-binding mediation, followed by arbitration.
30. The Midwest TDUs, Basin, Midwest Municipal Transmission Group, and others state that the Midwest ISO's proposal would change both the pricing and the economically consequential operational terms of the grandfathered agreements through a generic filing that would not examine the individual contracts being rewritten. These protestors assert that the benefits of an LMP market do not justify taking the rights of GFA holders without compensation. The protestors assert that although the proposed treatment is preferable to the treatment the Midwest ISO proposed in 2003, it still has not provided for real consistency with contractual rights. They state that although Option B comes closest to preserving existing rights it falls short of honoring these rights by: (1) Requiring that average losses be purchased at market prices where in the past they were self-provided; (2) imposing congestion charges for any change between day-ahead and real-time schedules where the contract contains provisions allowing for no-fee schedule changes later than the Midwest ISO's deadlines; (3) applying marginal losses to GFA real-time transactions where average losses applied in the past; (4) requiring parties to follow Midwest ISO-proposed EDR procedures where the contract has different dispute resolution provisions (including preclusion of unilateral rate changes); and (5) allocating a share of the costs of keeping the GFA Option B holders harmless from day-ahead congestion costs to the GFA holders where no such uplift costs were allocated to the contracts in the past.
31. The Midwest TDUs state that if the Midwest ISO substantiates that GFAs impinge on its ability to successfully operate the LMP market and show that the GFAs represent a large share of the transmission capacity, the Midwest TDUs would forego their legal objections on certain conditions. These conditions include: (1) No reduction in FTR allocation for GFA holders that accept Option B later than the start of the FTR allocation process; (2) assurances that Option B will fully hedge against increased loss charges; (3) assurances that Option B allows holders to schedule their full entitlement in the Day-Ahead market and allows submission of virtual bids; (4) clarification by the Commission that the transition period does not bind the Midwest ISO to make a filing that would eliminate Option B by 2008, but only that MISO will make a 205 filing in 2007 to address the GFA issue; and (5) all GFA holders accept Option A, B or C. MMTG states that its members are open to discussions with the Midwest ISO about modifying the contracts, but that the Midwest ISO cannot make a unilateral section 205 filing to modify the GFAs en masse.
32. Many GFA holders state that the Midwest ISO has not made the “practically insurmountable” public interest showing that is required under the Mobile-Sierra doctrine before altering existing contracts through a section 205 or 206 filing. They request that the Commission reject the Midwest ISO proposal and direct the Midwest ISO to adopt procedures that ensure that both the physical and financial rights under the GFAs are preserved. WPPI supports a complete carve-out of the GFAs from the TEMT. The Midwest TDUs state that Central Hudson is particularly instructive in this situation because, like the Midwest ISO's proposal, it concerned the initial implementation of a regional LMP market. Additionally, the Midwest TDU and other parties request that the Commission suspend the proposed tariff sheets and establish hearing procedures to determine the justness and reasonableness of the Midwest ISO's proposal.
33. Absent assurances that the GFAs' parties will be held financially harmless for the duration of the GFA, Nebraska Public Power District and Omaha Public Power District state that they will not be able to join the Midwest ISO. Nebraska Intervenors state that there are no business or reliability reasons that parties to the GFAs should be assigned additional costs due to the TEMT. None of the Nebraska Intervenors are willing to have their contract rights—either the physical delivery or the financial costs—affected due to participation in the TEMT. Nebraska Intervenors are concerned that the Midwest ISO does not guarantee that the GFA parties will be financially indifferent, only that financial indifference is intended. Great Lakes adds that if the present market redesign does not scrupulously honor existing contracts, financial markets will have no confidence in the sanctity of the arrangement entered into under the new market structure, and access to capital needed to support investment will thereby be degraded.
34. Dairyland, Minnesota Municipal Power Agency (Minnesota Municipal) and Minnkota Power Cooperative, Inc. state that the options the Midwest ISO proposes, including Option B, fail to hold the GFA parties financially indifferent. Dairyland states that GFA parties will be exposed to: (1) Real-time congestion and loss costs for energy imbalance; (2) costs of establishing credit with a third party; (3) increased internal costs to provide information to the Midwest ISO and review billing settlements; and (4) Schedule 16 and 17 charges. Dairyland has a grandfathered contract with Xcel that provides for losses to be repaid in kind and for congestion costs to be shared based on a load ratio cost of redispatch based on true marginal cost of units redispatched on a least-cost basis. Dairyland asserts that it would incur new labor and administrative costs for tracking the costs of Xcel's losses in serving the Dairyland load under this contract. Dairyland also asserts that under the TEMT, redispatch costs would likely be higher than costs under its Xcel contract since they will be based on bids rather than true marginal costs. Dairyland proposes that GFAs be physically carved out of the Midwest ISO's dispatch model and not be held accountable for congestion costs, marginal losses, energy imbalance costs, and Schedule 16 and 17 costs associated with the Midwest ISO market. In order Start Printed Page 32107to address the Midwest ISO's concerns about a physical carve-out, Dairyland proposes that GFA parties be required to give load forecast information to the Midwest ISO on a day-ahead basis and be directed to enter settlement discussions on the issue of market manipulation by the GFA holders.
35. Montana-Dakota Utilities Company (Montana-Dakota) expresses concern that it will incur market costs on behalf of its GFAs with Western Area Power Authority (WAPA) and Basin since the Commission has no authority to order non-jurisdictional, non-Midwest ISO members to comply with the TEMT provisions. Montana-Dakota also suggest that grandfathered transmission service serving load that does not have a Midwest ISO member as its power supplier should be excluded from market impacts. Montana-Dakota states that the Midwest ISO proposal for treatment of GFAs should be rejected and GFAs and Grandfathered Integrated Transmission Agreements should be left intact.
36. Midwest SATCs state that the allocation of functions between GFA parties is a potentially seminal issue, particularly for stand-alone transmission companies that have structured their organizations to avoid certain Market Participant functions that may be implicated by GFAs. The Midwest SATCs request that the proposed EDR process be made voluntary and that load-serving entities be designated for an interim period to act on behalf of the Midwest SATCs in negotiations regarding FTR allocation for the GFAs.
37. Manitoba Hydro states that it is a party to several GFAs that contain provisions for imports and exports from Canada in the same agreement and thus are only partially jurisdictional. In such cases, Manitoba states that it is questionable how the Commission could modify portions of the agreements without altering the non-jurisdictional aspects of the GFA. Manitoba Hydro requests that the Commission clarify that the Midwest ISO's proposed GFA treatment does not apply to any GFAs involving non-jurisdictional entities to the extent such agreements relate to power exported from Canada.
38. Tennessee Valley Authority (TVA) requests that the Commission direct the Midwest ISO to include provisions in the TEMT for TVA to continue to dynamically schedule energy to serve its grandfathered load in the Midwest ISO footprint.
3. The Midwest ISO's Answer and Intervenors' Reply Comments
39. In its Answer, the Midwest ISO reiterates its concern that the creation of a physical carve-out of the capacity associated with the GFAs cannot be accomplished without negatively impacting the Midwest ISO's ability to reliably operate the energy markets and without placing excessive financial burdens on other Market Participants. The Midwest ISO states that it is vital that the GFA transactions be required to meet the same scheduling deadlines and requirements as other transactions.
40. The Midwest ISO states that the EDR process is not intended to supersede the contract rights of the parties, but only to serve as a procedural mechanism to enable the Midwest ISO to obtain the information necessary to initially allocate FTRs. The Midwest ISO states that the EDR process is not binding upon the parties and that it merely provides a recommended data input to enable FTRs to be initially allocated to parties.
41. In answer to protestors' contentions that Option B should be rejected, the Midwest ISO states that its proposed treatment of GFAs appropriately meets both the Commission's general directive to address phantom congestion in a way that is consistent with GFA contractual rights and the specific need to ensure reliable operation of the Energy Markets.
42. The Midwest TDUs endorse OMS's arguments that the costs of fully honoring GFAs should be uplifted broadly. They say that OMS takes a step toward better allocation of the associated costs by proposing to hold back in Tier I 35 percent, rather than 100 percent, of non-issued FTRs. They add, however, that it would be simpler and fairer to hold back nothing and uplift all of the Option B refund costs.
43. The Midwest TDUs rebut the assertions of Cinergy, Constellation, Dynegy and EPSA that Option B will leave GFA holders better off than they are under their existing contracts. The Midwest TDUs also note that any potential advantages that could be attributed to Option B are offset by disadvantages, mostly in the form of increased costs.
44. Dairyland argues that the Midwest ISO's representations in the Transmittal Letter and in its Answer regarding EDR are inconsistent with the wording of section 12A of the proposed TEMT. Dairyland notes that section 12A allows for more than data gathering necessary to allocate FTRs, and that it would make EDR mandatory and binding. Dairyland states that it understands the Midwest ISO's need to gather data necessary to allocate FTRs, but that the EDR proposal goes beyond that need and seeks for GFA holders to resolve unrelated issues—specifically, those of the GFA Responsible Entity and Scheduling Entity. Dairyland urges the Commission to reject section 12A of the TEMT.
45. In Order No. 2000, the Commission affirmed that RTOs must ensure the development and operation of market-based mechanisms to manage congestion. The Commission declined to prescribe a specific congestion pricing mechanism, but observed that markets based on LMP and financial rights for firm transmission service “appear to provide a sound framework for efficient congestion management.” The Commission further encouraged the Midwest ISO to create an LMP-based approach to congestion management since the time the Midwest ISO was approved as an RTO.
46. The Commission has also indicated that it wants to preserve the rights of existing users of the Midwest ISO's transmission grid. The Declaratory Order noted that the Midwest ISO must strive to keep existing customers whole following implementation of a new market-based congestion management system. Accordingly, the Commission directed the Midwest ISO to continue to seek broad consensus among its participants regarding the future allocation of existing rights. The Commission made a similar statement in the TEMT Order, noting that:
Understanding what rights grandfathered contracts convey and the impact the contracts might have on the proposed markets is essential to develop a fair resolution of the grandfathering issue. We expect * * * that the Midwest ISO will work to resolve the issue of FTR allocation in tandem with the issue of the treatment of grandfathered contracts, as the two issues are linked.
47. The Midwest ISO's congestion management proposal and the preservation of all aspects of the GFAs may be incompatible. The Midwest ISO states several times in the TEMT filing that allowing GFA holders to schedule only in real time, which will require reservation or carve-out of substantial Start Printed Page 32108transmission capacity until the GFA schedules are submitted, may threaten the markets' operation, impair reliability and shift GFA-related costs to third parties. In light of its concerns, it states that, should the Commission find any portion of its proposed treatment of GFAs to constitute a reformation of the GFAs, the Commission should consider such treatment in the public interest pursuant to the Mobile-Sierra doctrine.
48. While we note the Midwest ISO's preference for voluntary conversions or the assignment of scheduling responsibility under section 205 of the FPA, we are concerned that these proposed approaches will not be sufficient to resolve the issue. We cite to the numerous protests to the Midwest ISO's process and the lack of interest, if not opposition of parties, to the proposed scheduling and settlement options or to the concept of assigning the scheduling responsibility to transmission owners.
49. The Commission has a responsibility under the FPA to ensure that jurisdictional rates in wholesale power markets remain just and reasonable. We must ensure that public utility sellers do not charge unjust and unreasonable wholesale rates, and that the market structures and market rules affecting the wholesale rates of public utility sellers do not result in, or have the potential to result in, wholesale rates, charges or classifications that are unjust, unreasonable, unduly discriminatory or preferential. However, we also regard any potential modification of the GFAs with great seriousness, and we are unwilling to decide an issue of such magnitude without more information.
50. The Midwest ISO has proposed EDR in order to gather the GFA information. EDR, as described above, is an expedited arbitration proceeding designed to identify the GFA information and report it to the Midwest ISO. While the Commission agrees that identifying the GFA information is critical, we find that the proposed EDR process is fatally flawed. We agree with Dairyland that the Midwest ISO's proposal must be voluntary because it could affect the substance of GFAs. We are sympathetic to Cinergy's and Midwest TDUs' assertions that EDR provides for resolution of too many issues in too short a time frame, and we want to provide the parties more time (and options) to identify and address disputes regarding the GFA information. We also note that the proposed EDR provisions do not adequately address our own need for the GFA information, and that the GFA information is critical to our consideration of the merits of the TEMT filing.
51. For the reasons described below, we will institute a proceeding under section 206 of the FPA, for the initial purpose of enhancing our understanding of the GFAs and to determine whether any of the GFAs need to be modified. Our goal is to ensure that the GFAs are accommodated in the Midwest ISO's energy markets in a way that will not harm reliability or third parties, yet preserves the commercial bargain between the parties. In order to achieve this end, our procedure for the GFAs will elicit the GFA information directly from the parties, without need for arbitrators, and thereby supersede the Midwest ISO's EDR proposal.
52. We acknowledge Dairyland's concerns about the costs of EDR, the Midwest TDUs' desire for multilayer dispute resolution processes, and several commenters' concerns about resolving many issues in a short time frame. We have designed the GFA process to allow parties to focus their attention and their resources on the issue or issues that most need their attention. We also intend to allow parties to take advantage of all dispute resolution procedures available to them so that they may make the most effective use of the time available and minimize their dispute resolution costs. We strongly encourage parties to work together and to reach agreements informally.
a. Concerns Regarding Provision of Reliable Service
i. Lack of Information Regarding GFAs
53. The Commission is very concerned about the effect that a physical carve-out of the GFAs will have on the reliability of the Midwest ISO's dispatch and transmission operations. As an initial matter, we note that there is very little transparency regarding transactions that take place under the terms of GFAs. The Midwest ISO is unsure how many megawatts of capacity the GFAs represent, or where the source and sink points of the GFA transactions will be. As the transmission provider, the Midwest ISO will also need to know the schedules for net power injections and withdrawals in order to coordinate scheduling and redispatch functions. In terms of economic and reliability impact, the lack of information makes it difficult to forecast which parts of the Midwest ISO region will be adversely affected and whether some areas will be clearly disproportionately impacted. The Commission therefore believes that having parties to GFAs produce GFA information will better enable the Midwest ISO to reliably operate the transmission system.
ii. GFA Scheduling Requirements and Reliability
54. Our primary concern with scheduling GFAs in the Midwest ISO Day 2 market using physical carve-out methods is its potential impact on reliability. We anticipate reliability benefits associated with the Day 2 market, some flowing from ongoing system operational improvements subsequent to the August 14, 2003, blackout and some from the better regional coordination and reduction in frequency of Transmission Line-Loading Relief (TLRs) that can be expected from the Day 2 market's centralized, security-constrained scheduling and dispatch and the use of LMP. We believe that the carve-out approach could undercut some of these reliability benefits.
55. One reliability implication of the carve-out approach is the greater degree of uncertainty that not scheduling GFAs in the day-ahead market will introduce into the overall Midwest ISO scheduling and dispatch process. As Professor Hogan points out in his testimony, if GFAs are exempt from day-ahead scheduling, then the Midwest ISO has to make assumptions about the GFA schedules that are likely to flow in real time. At one extreme, the Midwest ISO could decide not to set aside any capacity for GFAs in the day-ahead schedule, then adjust that schedule to accommodate real-time GFA schedules. Alternatively, the Midwest ISO could reserve some capacity a day ahead, in anticipation of the actual GFA schedules. In either case, the Midwest ISO is left with some level of uncertainty regarding real-time schedules and some possible threat to reliability. For example, if the Midwest ISO forecasts in its day-ahead schedule and reliability unit commitment substantially more GFA schedules or load than actually flows, then real-time demand could exceed available supply and in some instances require load shedding. In other cases, last-minute physical scheduling could require resort to TLRs to manage congestion if there is not sufficient generation available for redispatch. Hence, as Professor Hogan points out with regard to this issue, “if the Midwest ISO did not forecast correctly, as could easily and often be the case, then the consequences could be more serious * * * and, in the extreme, [have] reliability impacts on the system as a whole.” 
56. We are concerned that the Midwest ISO not create conditions for TLRs in the Day 2 markets due to scheduling of GFAs using the physical carve-out when there are better alternatives. The Final Report on the August 14, 2003, Blackout recommends that TLRs should not be used in situations involving an actual violation of an Operating Security Limit. The Start Printed Page 32109Blackout Report finds that “the TLR procedure is cumbersome, perhaps unnecessarily so, and not fast and predictable enough for use [in] situations in which an Operating Security Limit is close to or actually being violated.”  In addition, reliance on TLR and curtailments events to manage congestion shifts decision-making responsibility from the Midwest ISO to individual control areas. Dr. McNamara testifies that most control area operators perform the dispatch function for their respective control areas, and they are able to coordinate flows with neighboring control areas only to a limited extent. He adds that the Midwest ISO cannot accommodate requests for transmission service by assuming that redispatch will be available, because individual control areas are not required to accommodate all transactions. Dr. McNamara further testifies that TLRs are an imprecise tool for managing congestion and ensuring reliability because each control area affected by a TLR has a choice of how to respond, and they may not all respond the same way. As such, it is not possible for reliability coordinators to use TLRs to maintain power flows at operating security limits on a sustained basis. In short, TLRs tend to degrade reliability.
57. Recently PJM's LMP-based market has expanded into Illinois such that there are significant interactions between the grids of the Midwest ISO and PJM, and reliability and efficiency will be improved if these two markets use a common platform.
58. Reliability could be impaired under the carve-out approach not just through the scheduling uncertainty, but by the sheer volume of scheduling changes in real time. We are concerned about requiring the Midwest ISO operations personnel to schedule a significant number of GFA transactions within minutes before the trading hour begins—especially for a market in initial startup over a 15-state footprint, with 12,000 price nodes and extensive seams. Our concern is heightened by the fact that when the market starts, the Midwest ISO will be handling GFA transaction scheduling for the first time for the portion of GFAs not originally incorporated into the Open-Access Same-Time Information System (OASIS).
b. Undue Discrimination Concerns
59. The Midwest ISO states that the energy markets will be severely compromised if it must carve the GFAs out of the market, and therefore concludes that the GFAs should be modified to meet the requirements of the energy markets. Numerous GFA holders argue, however, that modification of the GFAs will contravene Commission policy in favor of the sanctity of contracts. We are instituting this proceeding to determine whether carving out the contracts may have unduly discriminatory results.
60. The Midwest ISO's filing estimates that GFAs account for at least 20 percent, and perhaps more than 40 percent, of the capacity of the Midwest ISO transmission system. Analysis submitted by the Midwest ISO in the July 25th Filing and answer thereto shows that a majority of the GFAs do not explicitly allocate the costs of congestion to contract parties, and none of the GFAs require marginal losses (although many GFA holders pay average losses). If the GFAs are not interpreted consistent with the regional market rules, non-parties to the GFA contracts may be required to bear a disproportionate percentage of the market costs, including the costs of administering the markets under Schedules 16 and 17.
61. One major problem with simply physically carving out GFAs and allowing them to schedule flexibly in real time (similar to current practice) is that this may create “phantom” congestion, congestion in the day-ahead market caused by the need to accommodate the scheduling of the GFAs. Such congestion may shift additional costs to parties transacting under non-GFA contracts. Scheduling for GFAs under a physical carve-out would not be tied to energy market scheduling requirements; therefore, parties to these contracts may schedule on short notice, with greater flexibility than non-GFA transmission users. The Midwest ISO must therefore assume that all capacity represented in GFAs will be used and, in the day-ahead market, reserve that capacity for GFA transactions even if it is unlikely that all the capacity will be utilized. As a result, transmission paths may become artificially congested more quickly than they would if all transactions were scheduled at the same time. The result—phantom congestion—would be reflected in LMP prices; consequentially, those prices may become artificially elevated.
62. We are instituting this proceeding to determine whether, if we require the Midwest ISO to carve the GFAs out of the market without conforming those contracts to the regional market rules, there is potential for unduly discriminatory results. The Commission takes seriously the Midwest ISO's concern that the sheer volume of capacity subject to unique scheduling requirements under GFAs may produce unduly discriminatory effects. While the Midwest ISO proposes to offer options to GFA holders that will, for the most part, hold them financially indifferent in the new markets, we believe that the Midwest ISO's proposal may impact the physical and financial rights between GFA holders. We cannot thoroughly evaluate the proposed TEMT unless we develop a full understanding of the effect of the Midwest ISO's proposed tariff changes on the GFAs, and the magnitude of the GFAs' impact on the proposed energy markets.
c. Effects on Economic Efficiency
63. The physical carve-out method of scheduling GFAs can also adversely impact the anticipated economic efficiency gains in the Day 2 market by allowing entities that schedule in this way to increase market prices for energy and congestion. This is due to more expensive generation being settled through the Midwest ISO energy markets to resolve the apparent congestion. Also, the release of unused physical transmission reservations may not happen with sufficient time for an efficient dispatch over the operating day. Moreover, to the extent that the holder of the GFA can benefit from the impact of its scheduling on market prices, it has little incentive to participate in the market efficiently.
64. As stated above, TLRs could occur under some methods for scheduling GFAs under carve-out scenarios. This will produce adverse economic effects in addition to the adverse reliability effects discussed above. Also, the Start Printed Page 32110Commission has been encouraging the Midwest ISO to develop alternatives to TLRs for managing congestion. In light of the Blackout Report's findings, this goal takes on increased urgency. We continue to favor an approach to reliability coordination that will enable the Midwest ISO to rely more on price signals, and less on curtailment, in its Day 2 markets. We believe that the LMP mechanism will be much more effective at providing the economic benefits of efficient congestion management in the Midwest ISO region if all transactions—including those under GFAs—are scheduled in the day-ahead market.
C. Three-Step Analysis of GFAs
65. As described above, the Commission believes that the development of the Midwest ISO as an RTO has reached a point at which the Commission must examine the potential conflict between our desire to preserve the GFAs and our instructions that the Midwest ISO should develop a market-based system of congestion management. We propose to analyze the GFAs in order to give us a more comprehensive understanding of their effects on the energy markets, and the effect of the energy markets on the GFAs. We believe that the Midwest ISO TOs have accurately identified the risk of litigating the GFA issue: The Commission's options include modifying contracts or requiring the TOs to bear the cost of taking service to fulfill the contracts as they exist today. We prefer, and strongly encourage, settlement of the GFAs. As described below, parties may choose to settle their GFAs by voluntarily accepting the treatment of GFAs that the Midwest ISO proposes in its tariff.
66. We have three goals for our analysis of the GFAs. First, we hope that the investigation will clarify the contracts in such a way to add specificity. To that end, we will require that jurisdictional public utility parties to GFAs produce relevant GFA information and we will invite any non-jurisdictional parties to GFAs to do likewise on a voluntary basis. Second, we hope to isolate third parties from costs caused by GFAs. Knowing more about the GFA information will help us evaluate the magnitude of the phantom congestion and cost shifts that GFAs could cause. Third, we hope to preserve the commercial bargain between the parties and we plan to ensure that the Midwest ISO's proposed energy markets can operate reliably at their inception. The greater our understanding of GFAs, the more confident we can be of achieving these goals.
67. Today we will initiate, in Docket No. EL04-104-000, a narrowly-focused, three-step analysis designed to provide the basis for us to decide whether GFA operations can be coordinated with energy market operations, whether and to what extent the TOs should bear the costs of taking service to fulfill the existing contracts and whether and to what extent the GFAs should be modified. We note that this process does not foreclose parties to GFAs agreeing at any time to voluntarily convert their transmission and energy markets service to service under the TEMT, thereby making them eligible for the FTR nomination process in accord with other customers currently served under the Midwest ISO OATT. We note that FTR allocation for such conversion could only occur on the regular Midwest ISO annual allocation schedule or on an otherwise-available basis.
1. Step 1: Paper Hearing
a. Contract Information
68. The Commission cannot fully analyze the proposed TEMT, its effect on the GFAs or the GFAs' effect on it without additional GFA information. As stated above, it is imperative that we know the number and location of megawatts represented under GFAs, and how the GFAs are used in practice. This will help us to understand the effect of the GFAs on the proposed energy markets. Accordingly, the first step of our analysis will require jurisdictional public utilities providing or taking service under GFAs, and invite any non-jurisdictional parties on a voluntary basis, who provide or take service under GFAs, to submit the following GFA information to the Commission: (1) The name of the GFA Responsible Entity, as defined in the proposed TEMT; (2) the name of the GFA Scheduling Entity, as defined in the proposed TEMT; (3) the source point(s) applicable to the GFA; (4) the sink point(s) applicable to the GFA; (5) the maximum number of megawatts transmitted pursuant to the GFA for each set of source and sink points; and (6) whether any modification to the GFA is subject to a “just and reasonable” standard of review or a Mobile-Sierra “public interest” standard of review. If the parties agree that their GFA will not be in effect as of the March 1, 2005, start date of the Midwest ISO's energy markets, the parties are directed to jointly file a statement to that effect in lieu of the above information. This information must be filed with the Commission, in Docket Nos. ER04-691-000 and EL04-104-000, on or before June 25, 2004.
69. If parties to each GFA are able to agree on the GFA information, they should file the GFA information jointly. Parties with multiple GFAs between them are encouraged to submit a single filing that covers all GFAs on which they can agree. Joint filings should clearly specify, in the title or in a transmittal letter, that the filing is a joint interpretation of GFAs and identify the subject GFAs by the number associated with each agreement in Attachment B to this order. The parties should make a simple statement in their joint filings to indicate whether or not they are willing to voluntarily convert their contract to TEMT service or settle their GFA by accepting the Midwest ISO's proposed treatment of GFAs.
70. GFAs that are the subject of joint filings will not be included in the hearing described in Step 2. Instead, the Commission will evaluate these joint filings as a group to help determine the effects of the GFAs on the proposed energy markets and, in the order described in Step 3, determine whether GFAs that are not converted or settled can be incorporated into the energy markets as written.
71. If parties to a particular GFA or GFAs are not able to agree on the GFA information, then the Commission will require each party to file its own interpretation of the GFA. (If the parties have agreed on some, but not all, GFA information, they should note in their separate filings their areas of agreement and disagreement.) The title or transmittal letter on a single-party filing should indicate the name of the party making the interpretation and identify the subject GFAs by the number associated with each agreement in Attachment B to this order. Parties that Start Printed Page 32111submit such filings will proceed to Step 2 of the Commission's analysis.
b. Additional Evidence and Comments
72. In addition, to assist the Commission in determining whether to modify GFAs that are not settled (see settlement discussion below), we will require the Midwest ISO to provide additional information as to the reliability and economic benefits of its proposed congestion management system with GFAs included in the market. As we noted in Order No. 2000, an LMP-based congestion management system appears to provide a sound framework for efficient congestion management. In its filing, the Midwest ISO provided general information and testimony on the impact of TLRs in the Midwest ISO region, including the reliability impacts of TLRs and curtailment events on the coordination of flows between neighboring control areas. We seek specific evidence for the record in the Docket No. EL04-104-000 proceeding. Thus, we direct the Midwest ISO and its Independent Market Monitor to submit evidence of the historical reliability impact of TLRs in the Midwest ISO region. Additionally, the Midwest ISO is directed to submit evidence that examines in detail how a carve-out of the GFAs would impede the reliability of the proposed Day 2 markets.
73. Further, the Midwest ISO did not file information that quantified the cost savings in moving from its current congestion management process (that relies predominantly on TLRs) to its proposed LMP-based congestion management system as applied to GFAs. We direct the Midwest ISO to file information on the economic impacts of TLRs in its region and quantify the benefits of the proposed congestion management system, focusing on how a carve-out of the GFAs would impede these costs savings. We also direct the Midwest ISO to include all workpapers and assumptions supporting its quantification of the economic benefits of the proposed congestion management system as it applies to the GFAs. We direct the Midwest ISO to file this evidence on reliability and economic impacts by June 25, 2004. Parties will have 14 days to comment on the Midwest ISO analysis.
74. The Commission also seeks comments from all affected parties on: (1) Whether keeping the GFAs separate from the market would negatively impact reliability; (2) the extent to which GFAs shift costs to third parties; and (3) whether keeping the GFAs separate from the market would result in undue discrimination. These comments should not be repetitive of the protests already filed in this docket, and must be filed directly with the Commission no later than June 25, 2004. We encourage parties with similar interests to combine their responses into a single pleading; however, these responses should not be combined with the GFA information filings described above. Parties will have 14 days to submit reply comments.
2. Step 2: Trial-Type Hearing
75. The Commission will consider all GFA information on which parties cannot agree to be disputed issues of material fact. Accordingly, we will set such GFAs for hearing before one or more administrative law judges (ALJs) under section 206 of the FPA. The sole objective of the trial-type hearing will be to identify GFA information for every GFA on which the parties have not agreed by June 25, 2004.
76. In order to accommodate the March 1, 2005, implementation of the energy markets, as well as the schedule we will set forth below for nomination of FTRs under the proposed TEMT, hearing proceedings will be narrowly focused and expedited. Hearing proceedings will begin on June 28, 2004, and terminate on July 23, 2004. The Commission will require the presiding ALJ or ALJs to issue written findings, and to orally present these written findings at the Commission meeting of July 28, 2004, on the following: (1) The name of the GFA Responsible Entity, as defined in the proposed TEMT; (2) the name of the GFA Scheduling Entity, as defined in the proposed TEMT; (3) the source point(s) applicable to the GFA; (4) the sink point(s) applicable to the GFA;
(5) the maximum number of megawatts transmitted pursuant to the GFA for each set of source and sink points; and (6) whether the GFA is subject to a “just and reasonable” standard of review or a Mobile-Sierra standard of review. Parties will be allowed to file written exceptions to ALJ findings by August 17, 2004. Briefs opposing exceptions will not be allowed.
77. In the event that GFA parties reach agreement on their GFA information prior to the conclusion of the ALJ proceeding, they should immediately seek the ALJ's permission to withdraw from the hearing proceeding. If the ALJ grants permission, the parties must immediately make a joint filing with the Commission as described in Step 1. Parties may voluntarily agree to convert or settle their GFAs in this filing. Such filings are due no later than July 27, 2004, the day before the ALJ's report issues.
3. Step 3: Order on the Merits
78. Following the ALJ's oral presentation, the Commission will use the GFA information provided by the parties or the ALJ, together with the parties' evidence and comments, discussed in paragraphs 72-74 above, and information on voluntary conversion of GFAs to transmission and energy market service or GFA service under the TEMT, to determine in a subsequent order: (1) Whether the GFAs can function as written within the proposed energy markets; (2) whether the GFAs can function within the energy markets under the Midwest ISO's proposed treatment (which the Commission retains the right to amend); or (3) whether modifications to the GFAs should be required. The Commission will make every attempt to expedite this order, keeping in mind the timeline described below, so that all Midwest ISO market participants may begin their FTR nominations on October 1, 2004.
D. Opportunity to Settle
79. At this time, we do not make a finding on the justness and reasonableness of the Midwest ISO's proposed scheduling and settlement options for treatment of GFA transactions under the TEMT. Protests on this proposed treatment and particularly on the proposed Option B indicate that some GFA parties, as well as non-GFA parties, believe that the proposed treatment creates added benefits for the GFAs that go beyond preserving the material benefits and obligations of the pre-existing contract, thereby shifting costs to non-GFA parties or non-GFA loads. Other GFA parties assert that while Option B provides some assurance that they will be kept financially indifferent, Option B does not go far enough in preserving the benefit of the bargain in their contracts. The Commission will not know the extent of the benefits and obligations under each GFA unless and until the Commission examines each contract in a hearing context.
80. To avoid the expensive and time-consuming hearing process that would otherwise be necessary and to provide all parties the benefits of a functional organized market in a more timely manner than would otherwise be possible, the Commission strongly encourages GFA settlements and intends to process such settlements expeditiously. We would be receptive to GFA parties voluntarily agreeing, in settlement, to accept one of the Midwest Start Printed Page 32112ISO's proposed scheduling and settlement options for treatment of GFA transactions, or to convert their contracts to TEMT service. Further, we clarify that, if the Commission approves a settlement, it does not intend to later revisit its decision when it addresses the non-settling parties' GFAs.
81. Although we note Dr. Hogan's concern that Option B of the Midwest ISO's proposed GFA treatment could undermine the efficient scheduling properties of the LMP-based tariff, we believe that the Midwest ISO's proposed GFA treatment provides a fair basis for GFA holders to settle and incorporate the GFAs into the Day 2 markets. We also expect that parties that settle on the GFA scheduling provisions provided in the proposed GFA treatment, including the proposed Option B, will schedule transactions consistent with legitimate business purposes.
82. The optional GFA scheduling and settlement treatment, including Option B, as drafted in the Midwest ISO proposal, will be available to GFA parties that jointly provide GFA information to the Commission in Step 1 (or prior to the conclusion of Step 2) of our three-step analysis, and that jointly indicate that they want to accept this treatment. Such settlements avoid litigation of GFA issues and further the Commission's goals in facilitating voluntary resolution of these issues prior to the start of the Midwest ISO energy markets.
83. Such settlements also preserve the parties' rights to comment on the Midwest ISO's section 205 proposal for treatment of the GFAs after the transition period, which it proposes to file no later than 12 months prior to the end of the transition period. We instruct the Midwest ISO to provide a report no later than 12 months prior to the end of the transition period to examine the impact of the initial GFA treatment, as selected by GFA parties through this settlement process, on other market participants and the overall efficiency of the market.
E. Revised TEMT Processing and Energy Markets Startup Timelines
1. The Midwest ISO's Proposal
84. The Midwest ISO requests an effective date of June 7, 2004, for sections of the tariff pertaining to the EDR process and the initial FTR allocation. It states that the requested effective date for the FTR allocation provisions coincides with the requested effective date for the EDR process and will allow all Market Participants and the Midwest ISO certainty as to the final FTR allocation methodology prior to the start of the initial FTR allocation process on July 15, 2004.
85. The Midwest ISO proposes an FTR process developed with significant input from stakeholders that features several rounds of nominations and restoration of FTRs for base load generation. All FTR nominations and restoration are subject to a single Simultaneous Feasibility test. The Midwest ISO proposes that the first nomination of FTRs take place on July 15, 2004. It will provide an initial FTR allocation to market participants on September 30, 2004, and begin the auction process on October 4, 2004. The October auctions will then be used as a basis for market trials prior to market startup on December 1, 2004.
86. The Midwest ISO raises non-tariff concerns related to the December 1, 2004, start date. These concerns include matters related to the impact of a December 1, 2004, energy market start date in light of the reporting requirements contained in the Sarbanes-Oxley Act of 2002;  the readiness of the Midwest ISO to begin market operations; the existence of seams agreements between the Midwest ISO and its neighboring entities; and the integrated nature of certain transmission systems in the Mid-Continent Area Power Pool (MAPP) region.
87. The Midwest ISO notes that prior to the TEMT filing, many of its stakeholders raised concerns associated with meeting the requirements of the Sarbanes-Oxley Act. Under section 404 of the Sarbanes-Oxley Act, all companies registered with the Securities and Exchange Commission (SEC) must report on the effectiveness of the company's internal controls over financial reporting, as well as obtain a report from an outside auditor attesting to the effectiveness of the internal controls. These assessments will cover the reporting year ending December 31, 2004, and must be submitted to the SEC in early 2005. With a market start date of December 1, 2004, SEC-registered companies within the Midwest ISO would report on controls governing one month's worth of market transactions.
88. The Midwest ISO states that it has repeatedly committed to its stakeholders that it will not commence the Energy Markets on December 1, 2004, unless it is ready to operate effectively. The Midwest ISO also states that if it is unable to substantially accomplish metrics related to its market implementation plan, it will announce a delay in the commencement of the Energy Markets.
89. The Midwest ISO notes that prior to the TEMT filing, many of its stakeholders raised concerns associated with the seams between the Midwest ISO and its neighbors. The Midwest ISO acknowledges the importance of developing seams agreements or operating agreements similar to the Joint Operating Agreement between the Midwest ISO and PJM Interconnection, L.L.C.;  however, it does not believe that the lack of these agreements bar the initiation of market operations. The Midwest ISO states that it is discussing seams issues with Midwest ISO members and non-members in the MAPP region in an effort to address the treatment of the integrated transmission systems of those entities in the energy markets. The Midwest ISO has agreed to provide the integrated transmission agreements of the MAPP region similar treatment to the treatment it offers GFAs.
2. Protests and Comments
90. A number of parties want to delay the market startup, and they cite a wide range of reasons to support this view. The most common argument is that the Sarbanes-Oxley audit requires delay. The Midwest ISO's Answer indicates that it would not oppose such a delay.
91. Detroit Edison, Xcel Energy Services and Consumers Energy recommend that market startup be conditioned on readiness approval from NERC. They cite NERC's concerns from the August 14, 2003, blackout and the significant reliability challenges associated with the control area interfaces. Montana-Dakota states the market should not start until Midwest ISO demonstrates that reliability, as Start Printed Page 32113measured by network model and state estimator accuracy and successful completion of reliability metrics, is better than the level achieved before the Midwest ISO was formed.
92. A number of parties, including Midwest TDUs, the Wisconsin Commission and Nebraska Intervenors contend that market delay is warranted due to reliability concerns associated with many control areas. They argue that the market should not start until the seam issue between jurisdictional and non-jurisdictional members of MAPP is resolved with a comprehensive agreement. Midwest TDUs and Cinergy also consider the American Electric Power seam a problem. They request a delay until either a seams agreement is executed (in the Midwest TDUs' opinion) or American Electric Power is integrated into PJM (in Cinergy's opinion). A number of these same parties also contend that the markets should not start until the flaws associated with initial FTR allocations are resolved and several market trials are run. In contrast, Exelon and Coalition MTC state that the Midwest ISO market start must stay on schedule to ensure, respectively, that the joint and common market with PJM can be realized and that customers receive the benefits of the energy market.
93. The Midwest ISO responds in its Answer that while the proposed milestones are still appropriate, there would be benefits from additional system training, performance and testing activities.
94. Recognizing the impact that the above-detailed procedures for interpreting the GFAs will have on the schedule for apportioning FTRs, and the need to have sufficient market trials in advance of implementation of the Day 2 market, the Commission directs the Midwest ISO to move the start of the energy market from December 1, 2004, to March 1, 2005. Extension of the start date will allow more time to complete the initial allocation of FTRs, including an update of the model to include changes to the system occurring up to June 2004. This extension will also address the Sarbanes-Oxley Act compliance issue mentioned by commenters.
95. The illustrative FTR allocation filed by the Midwest ISO does not meet the requirement set forth in the Declaratory Order. The Declaratory Order directed information showing “each market participant's expected allocation of FTRs based on the proposed tariff allocation method, the Candidate FTRs, and any proposed pro rata reduction in the Candidate FTRs.” We will expect the Midwest ISO to file an initial FTR allocation with the expected allocation of FTRs, not an illustrative allocation, 90 days prior to the start of the market. The filing should be made concurrent with, or prior to the beginning of, market trials. If the Midwest ISO believes this information to be commercially sensitive, it may file such information with the Commission and request that it be kept confidential. The Commission will act on the request for confidential treatment at that time.
96. We will also revise the schedule for FTR nominations. The later time frame will permit the Commission time to complete its analysis of the GFAs and the Midwest ISO time to continue to refine its FTR allocation model. We expect Tier I nomination to take place on October 1, 2004, and Tier IV nomination to be completed by December 1, 2004.
97. Given the new schedule for the FTR allocation process, we anticipate that the Midwest ISO will begin initial market trials in early December 2004 and complete them in January 2005. We will also expect the Midwest ISO to provide a report to the Commission on the results of initial market trials, no later than 45 days prior to the start of the energy markets. We share the parties' concerns that the market needs to be at a high level of readiness on the start date. Accordingly, our assessment of whether the market is ready to start will be based on our ongoing analysis of market trials, readiness metrics and NERC reliability reports throughout this pre-market period.
98. We direct the Midwest ISO to continue to pursue seams agreements with neighboring entities, regardless of the outcome of this proceeding.
99. In addition, we direct the Midwest ISO to (work with its stakeholders to) develop default mechanisms and procedures for instances where communication failures cause a loss of the Midwest ISO dispatch signal to any Control Area. Such fail-safe procedures must be in place prior to the start of the energy markets.
100. Given the change to the start date for the Energy Markets, the Commission finds that it is no longer necessary to act by June 7, 2004, on the FTR or the EDR provisions of the proposed TEMT. We will accept and suspend the FTR provisions contained in Module C, Section IV, Original Sheet Nos. 602-77, as described below. We will reject the EDR provisions contained in Module A, Section 12A, Original Sheet Nos. 212-15, and any other tariff sheets proposed to become effective June 7, 2004. The Commission recognizes the need for a timely order on the GFAs and the FTR allocation proposal to permit nominations to begin on October 1, 2005.
101. Our preliminary review of the proposed FTR provisions indicates that the Midwest ISO's proposal has not been shown to be just and reasonable, and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful. Therefore, we will accept the FTR provisions contained in Module C, Section IV, Original Sheet Nos. 602-77, for filing and suspend them, to become effective on or before November 7, 2004, subject to refund and further orders in this proceeding.
The Commission orders:
(A) Module A, section 12A, Original Sheet Nos. 212-15, pertaining to Expedited Dispute Resolution, is hereby rejected, as described in the body of this order.
(B) Module C, Section IV, Original Sheet Nos. 602-77, pertaining to Financial Transmission Rights, is hereby accepted and suspended, to become effective on or before November 7, 2004, subject to refund and further orders in this proceeding.
(C) Pursuant to the authority contained in, and subject to the jurisdiction conferred upon the Federal Energy Regulatory Commission by, section 402(a) of the Department of Energy Organization Act and by the Federal Power Act, particularly section 206 thereof, and pursuant to the Commission's rules of practice and procedure and the regulations under the Federal Power Act (18 CFR chapter I), the Commission sets for hearing all GFAs under which jurisdictional public utilities provide or take service in the Midwest ISO region, as discussed in the body of this order.
(D) The Secretary shall promptly publish this order in the Federal Register.
(E) The refund effective date established pursuant to section 206(b) of the FPA will be 60 days following publication in the Federal Register of this order, as directed in Ordering Paragraph (D) above.
(F) Parties to this proceeding that are providing or taking service under GFAs enumerated in Appendix B to this order are directed to file GFA information no later than June 25, 2004, as described in the body of this order.
(G) Pursuant to the authority contained in and subject to the jurisdiction conferred upon the Federal Energy Regulatory Commission by section 402(a) of the Department of Energy Organization Act and the Federal Power Act, particularly sections Start Printed Page 32114205 and 206 thereof, and pursuant to the Commission's rules of practice and procedure and the regulations under the Federal Power Act (18 CFR chapter 1), a public hearing shall be held in Docket Nos. ER04-691-000 and EL04-104-000 to investigate the GFAs for which parties do not jointly submit GFA information, as discussed in the body of this order. As discussed in the body of this order, we will hold the proceeding in abeyance until June 28, 2004, to allow GFA parties time to make their GFA information submissions.
(H) A presiding administrative law judge, designated by the Chief Administrative Law Judge, shall convene a conference in this proceeding, to be held as soon as practicable after the date on which the Chief Judge designates the presiding judge, in a hearing room of the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. Such conference shall be held for the purpose of establishing a procedural schedule. The presiding administrative law judge is authorized to establish procedural dates, and to rule on all motions (except motions to dismiss), as provided in the Commission's rules of practice and procedure.
(I) The presiding administrative law judge is directed to issue written findings summarizing the result of the hearing proceeding, and to present these findings to the Commission at its public meeting on July 28, 2004.
(J) The Midwest ISO is hereby directed to continue to pursue seams agreements with neighboring entities and to develop default mechanisms and procedures as described in the body of this order.
(K)The Midwest ISO is hereby directed to file the reports described in the body of this order.Start Signature
By the Commission.
Parties Filing Interventions
BP Energy Company
Central Iowa Power Cooperative
Clay Electric Cooperative, Inc.
Coral Power, L.C.C.
The Energy Authority
Environmental Law and Policy Center of the Midwest
Illinois Commerce Commission
Illinois Municipal Electric Agency
Indiana Office of Utility Consumer Counselor
Indianapolis Power & Light
Iowa Utilities Board
Michigan Public Power Agency and Michigan South Central Power Agency
Minnesota Office of the Attorney General
TVA—Tennessee Valley Authority
WAPA—Western Area Power Administration
Parties Filing Interventions and Protests or Comments
Alliant—Alliant Energy Corporate Services, Inc.
Ameren—Ameren Services Company
American Forest & Paper Association
AMP-Ohio—American Municipal Power-Ohio, Inc.
ATCLLC—American Transmission Company LLC
Basin, et al.—Basin Electric Power Cooperative, East River Electric Power Cooperative, Inc., Central Power Electric Cooperative, Inc. and Capital Electric Cooperative, Inc.
Cinergy—Cinergy Services, Inc.
Cleveland—City of Cleveland, Ohio
Coalition MTC—Coalition of Midwest Transmission Customers
Constellation—Constellation Power Source, Inc., Constellation Generation Group, LLC and Constellation NewEnergy, Inc.
Consumers—Consumers Energy Company
Corn Belt—Corn Belt Power Cooperative
Crescent Moon Utilities—Basin Electric Power Cooperative, Heartland Consumers Power District, Minnkota Power Cooperative, Inc., NorthWestern Energy, Sunflower Electric Power Corporation and the Upper Great Plains Region of the Western Area Power Administration
Dairyland—Dairyland Power Cooperative
Detroit Edison—Detroit Edison Company
Dominion—Dominion Retail, Inc., Dominion Energy Marketing, Inc. and Troy Energy, LLC
Duke—Duke Energy North America, LLC
Dynegy—Dynegy Power Marketing, Inc. and Dynegy Midwest Generation, Inc.
Edison Mission—Edison Mission Energy, Edison Mission Marketing & Trading, Inc., and Midwest Generation EME, LLC
ELCON/AISI/ACC—Electricity Consumers Resource Council, American Iron and Steel Institute and American Chemistry Council
Epic and SESCO—Epic Merchant Energy LP and SESCO Enterprises LLC
EPSA—Electric Power Supply Association
FirstEnergy—FirstEnergy Service Company
Great Lakes—Great Lakes Utilities
Great River—Great River Energy
IMEA—Illinois Municipal Electric Agency
Indianapolis P&L—Indianapolis Power & Light Company
LG&E—LG&E Energy LLC
Manitowoc Public Utilities
MAPP—Mid-Continent Area Power Pool
Marshfield—Marshfield Electric & Water Department
Michigan Commission—Michigan Public Service Commission
MidAmerican—MidAmerican Energy Company
Midwest Municipal Transmission Group
Midwest ISO TOs—Ameren Services Company, as agent for Union Electric Company d/b/a AmerenUE, Central Illinois Public Service Company d/b/a AmerenCIPS, and Central Illinois Light Co. d/b/a AmerenCilco; Aquila, Inc. d/b/a Aquila Networks (f/k/a Utilicorp United, Inc.); City Water, Light & Power (Springfield, Illinois); Hoosier Energy Rural Electric Cooperative, Inc.; Indianapolis Power & Light Company; LG&E Energy Corporation (for Louisville Gas and Electric Co. and Kentucky Utilities Co.); Minnesota Power (and its subsidiary Superior Water, L&P); Montana-Dakota Utilities Co.; Northern Indiana Public Service Company; Northern States Power Company and Northern States Power Company (Wisconsin), subsidiaries of Xcel Energy, Inc.; Northwestern Wisconsin Electric Company; Otter Tail Corporation d/b/a Otter Tail Power Company; Southern Illinois Power Cooperative; Southern Indiana Gas & Electric Company d/b/a Vectren Energy Delivery of Indiana); and Wabash Valley Power Association, Inc.
Midwest SATCs—American Transmission Company LLC, GridAmerica LLC, International Transmission Company and Michigan Electric Transmission Company, LLC
Midwest TDUs—Great Lakes Utilities, Indiana Municipal Power Agency, Lincoln Electric System, Madison Gas and Electric Company, Midwest Municipal Transmission Group, Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services, Southern Minnesota Municipal Power Agency, Upper Peninsula Transmission Dependent Utilities and Wisconsin Public Power, Inc.
Minnesota Municipal—Minnesota Municipal Power Agency
Minnesota Entities—Minnesota Public Utilities Commission and Minnesota Department of Commerce
Minnkota—Minnkota Power Cooperative, Inc.
Mirant—Mirant Americas Energy Marketing, LP, Mirant Zeeland, LLC and Mirant Sugar Creek, LLC
Montana-Dakota—Montana-Dakota Utilities Company
Municipal Participants—Michigan Public Power Agency, Michigan South Central Power Agency, Department of Municipal Services of Wyandotte, Michigan and City of Hamilton, Ohio
Nebraska Intervenors—Lincoln Electric System, Omaha Public Power District and Nebraska Public Power District
Nebraska Public Power District
NiSource Companies—Northern Indiana Public Service Company, EnergyUSA-TPC Corp. and Whiting Clean Energy, Inc.
North Dakota Commission—North Dakota Public Service Commission
NRECA—National Rural Electric Cooperative Association
Ohio Commission—Public Utilities Commission of Ohio
Ohio REC—Ohio Rural Electric Cooperatives, Inc. and Buckeye Power, Inc.
OMS—Organization of MISO States
Otter Tail—Otter Tail Power Company
PSEG—PSEG Energy Resources & Trade LLC
Reliant—Reliant Energy, Inc.
Southern Minnesota—Southern Minnesota Municipal Power Agency
Southwestern—Southwestern Electric Cooperative, Inc.
Soyland—Soyland Power Cooperative, Inc. Start Printed Page 32115
Steel Producers—Steel Dynamics—Bar Products Division and Nucor Steel
Strategic Energy, LLC
TVA—Tennessee Valley Authority
WEPCO—Wisconsin Electric Power Company
Wisconsin Commission—Public Service Commission of Wisconsin
Wisconsin Retail Customers Group—Citizens” Utility Board, Wisconsin Industrial Energy Group, Inc., Wisconsin Paper Council and Wisconsin Merchants Federation
Wisconsin Transmission Customer Group
WPPI—Wisconsin Public Power Inc.
Wolverine—Wolverine Power Supply Cooperative, Inc.
WPS Resources—WPS Resources Corporation
WUMS Load-Serving Entities—Wisconsin Electric Power Company, Edison Sault Electric Company, Wisconsin Public Service Corporation, Upper Peninsula Power Company, Wisconsin Power and Light Company, Madison Gas and Electric Company, Wisconsin Public Power, Inc. and Manitowoc Public Utilities
Xcel—Xcel Energy Services Inc.
Appendix BStart Printed Page 32116 Start Printed Page 32117 Start Printed Page 32118 Start Printed Page 32119 Start Printed Page 32120 Start Printed Page 32121 Start Printed Page 32122 Start Printed Page 32123 Start Printed Page 32124 Start Printed Page 32125 Start Printed Page 32126 Start Printed Page 32127 Start Printed Page 32128 Start Printed Page 32129 Start Printed Page 32130 Start Printed Page 32131 Start Printed Page 32132 Start Printed Page 32133 Start Printed Page 32134 Start Printed Page 32135 Start Printed Page 32136 Start Printed Page 32137 Start Printed Page 32138 Start Printed Page 32139 Start Printed Page 32140 Start Printed Page 32141 Start Printed Page 32142 Start Printed Page 32143 Start Printed Page 32144 Start Printed Page 32145 Start Printed Page 32146 Start Printed Page 32147 Start Printed Page 32148 Start Printed Page 32149 Start Printed Page 32150 Start Printed Page 32151 Start Printed Page 32152 Start Printed Page 32153 Start Printed Page 32154 Start Printed Page 32155 Start Printed Page 32156 Start Printed Page 32157 Start Printed Page 32158 Start Printed Page 32159 Start Printed Page 32160 Start Printed Page 32161 Start Printed Page 32162 Start Printed Page 32163 Start Printed Page 32164 Start Printed Page 32165 Start Printed Page 32166 Start Printed Page 32167 Start Printed Page 32168 Start Printed Page 32169 Start Printed Page 32170 Start Printed Page 32171 Start Printed Page 32172 Start Printed Page 32173 Start Printed Page 32174 Start Printed Page 32175 Start Printed Page 32176 Start Printed Page 32177 Start Printed Page 32178 Start Printed Page 32179 Start Printed Page 32180 Start Printed Page 32181 Start Printed Page 32182 Start Printed Page 32183 Start Printed Page 32184 Start Printed Page 32185 Start Printed Page 32186 Start Printed Page 32187 Start Printed Page 32188 Start Printed Page 32189 Start Printed Page 32190 Start Printed Page 32191 Start Printed Page 32192 Start Printed Page 32193 Start Printed Page 32194 Start Printed Page 32195 Start Printed Page 32196 Start Printed Page 32197 Start Printed Page 32198 End Preamble
1. The public utilities providing service under these GFAs are listed by contract in Appendix B.Back to Citation
2. Transmittal Letter at 11.Back to Citation
3. Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (Jan. 6, 2000), FERC Stats. & Regs. ¶ 31,089 (2000), order on reh'g, Order No. 2000-A, 65 FR 12088 (Feb. 25, 2000), FERC Stats. & Regs. ¶ 31,092 (2000), aff'd, Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).Back to Citation
4. Midwest Independent Transmission System Operator, Inc., 97 FERC ¶ 61,326 (2001), order on reh'g, 103 FERC ¶ 61,169 (2003).Back to Citation
5. Midwest Independent Transmission System Operator, Inc., 102 FERC ¶ 61,196 (2003) (Declaratory Order).Back to Citation
6. Midwest Independent Transmission System Operator, Inc., 103 FERC ¶ 61,210 (2003) (Declaratory Order Rehearing).Back to Citation
7. Motion to Withdraw Without Prejudice the July 25 Energy Markets Tariff Filing at 5 (Docket No. ER03-1118-000, Oct. 17, 2003).Back to Citation
8. Midwest Independent Transmission System Operator, Inc., 105 FERC ¶ 61,145 (2003) (TEMT Order), reh'g dismissed, 105 FERC ¶ 61,272 (2003).Back to Citation
9. Great Lakes Utilities, Indiana Municipal Power Agency, Lincoln Electric System, Madison Gas and Electric Company, Midwest Municipal Transmission Group, Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services, Southern Minnesota Municipal Power Agency, Upper Peninsula Transmission Dependent Utilities and Wisconsin Public Power, Inc.Back to Citation
10. Module A, Section 1.126, Original Sheet No. 82. An ITC Grandfathered Agreement is “an agreement under which an [independent transmission company] will perform pursuant to its terms and conditions, consistent with the Commission's policies, rather than under the terms of this tariff or the ITC Rate Schedule.” Module A, Section 1.161, Original Sheet No. 89.Back to Citation
11. See id. We note that in a separate proceeding, the Midwest ISO filed to revise Attachment P. The proposed revisions were meant to update and clean up the list of GFAs in the attachment. The Commission accepted the filing and ordered the Midwest ISO to make further revisions. See Midwest Independent Transmission System Operator, Inc., 105 FERC ¶ 61,387 (2003), further order, 106 FERC ¶ 61,288 (2004).Back to Citation
12. See Midwest Independent Transmission System Operator, Inc., et al., 84 FERC ¶ 61,231 at 62,167, 62,169-70 (1998) (Formation Order) (granting conditional approval for ten public utilities to transfer operational control of their jurisdictional transmission facilities to the Midwest ISO, and deferring placement of existing wholesale loads and bilateral agreements for six years).Back to Citation
13. Transmittal Letter at 9.Back to Citation
14. See Module C, Section 38.8.4, Original Sheet No. 454.Back to Citation
15. See Transmittal Letter at 9-10; McNamara testimony at 82-83.Back to Citation
16. The Midwest ISO's analysis assumed a peak capacity of 97,000 megawatts. Since the time of the analysis, Ameren Corporation has announced that it will purchase Illinois Power, and that Illinois Power will join the Midwest ISO. See McNamara Testimony at 84 n.5. Ameren itself was successfully integrated into the Midwest ISO on May 1, 2004.Back to Citation
17. Transmittal Letter at 11.Back to Citation
18. Transmittal Letter at 11.Back to Citation
19. Transmittal Letter at 11-12.Back to Citation
20. In support of this proposition, the Midwest ISO cites Northeast Utilities Service Company, 66 FERC ¶ 61,332, reh'g denied, 68 FERC ¶ 61,041 (1994), aff'd sub nom. Northeast Utilities Service Company v. FERC, 55 F.3d 686 (1st Cir. 1995).Back to Citation
21. See United Gas Pipeline Company v. Mobile Gas Service Corp., 350 U.S. 332 (1956); FPC v. Sierra Pacific Power Company, 350 U.S. 348 (1956).Back to Citation
22. See Formation Order at 62,167, 62,169-70.Back to Citation
23. The GFA Responsible Entity, which must be a Market Participant under the TEMT, will be financially responsible for Market Activities charges, Schedule 16 and 17 charges, Transmission Usage Charges and debits or credits associated with FTRs held by the GFA Responsible Entity. See Module C, Section 38.8.1, Original Sheet No. 443.Back to Citation
24. The GFA Scheduling Entity—which can be the GFA Responsible Entity or its agent—will submit bilateral transaction schedules under the TEMT for sales or purchases of energy under the GFA. See Module C, Section 38.8.2, Original Sheet No. 444.Back to Citation
25. See Module C, Section 38.2.5.j, Original Sheet No. 402.Back to Citation
26. See Module C, section 38.2.5.j, Original Sheet Nos. 400-02. EDR will address disputes involving the designation of GFA information in the event that parties cannot resolve the disputes informally or pursuant to dispute resolution procedures specified in their GFAs. See Module A, section 12A.1, Original Sheet No. 212. Each party (or group of parties) to GFAs for which GFA information has not been submitted to the Midwest ISO by June 7, 2004, will select an arbitrator, and the two arbitrators will select a third arbitrator to chair the arbitration panel. See Module A, section 12A.2, Original Sheet No. 213. The arbitrators will have 25 days to render a decision, and the parties must notify the Midwest ISO of that decision by August 1, 2004. The Midwest ISO proposes that the arbitrators' decision will be final and binding; appeal will lie only on the grounds that the arbitrators' conduct, or their decision, violated the standards set forth in the Federal Arbitration Act and/or the Administrative Dispute Resolution Act. See Module A, section 12A.3, Original Sheet No. 214.Back to Citation
27. See Module C, section 38.2.5.j, Original Sheet No. 400-02.Back to Citation
28. See Module C, section 38.8.3.a, Original Sheet Nos. 445-46.Back to Citation
29. See Module C, section 38.3.3.b.i, Original Sheet No. 447.Back to Citation
30. If a revenue inadequacy results, the Midwest ISO will compensate the GFA Responsible Entity for the costs of congestion by assessing debits on all Market Participants on a pro rata basis. See Module C, Section 38.8.3.b.ii, Original Sheet Nos. 448-50.Back to Citation
31. The TEMT states that the Midwest ISO will determine the difference between marginal losses and system losses “on an equitable basis.” Module C, section 38.8.3.b.iii, Original Sheet No. 451. The Midwest ISO further notes that this mechanism will be different from the mechanism used to refund overcollections of loss revenues to parties to non-GFA transactions. See Transmittal Letter at 14.Back to Citation
32. See Module C, section 38.8.3.c, Original Sheet No. 452.Back to Citation
33. Market Participants will nominate in four tiers: (1) Tier 1 nomination, for up to 35 percent of entitlement; (2) Tier II nomination, for up to 50 percent of entitlement; (3) Tier III nomination, for up to 75 percent of entitlement; and (4) Tier IV nomination, for up to 100 percent of entitlement.Back to Citation
34. See Gribik testimony at 30. A Market Participant with 700 MW of Network Integration Transmission Service peak load and 500 MW of GFA Option B service would be eligible to nominate 420 MW in Tier I ((700 MW + 500MW) x .35). The Tier I nomination would be for the full amount of GFA Option B service with 80 MW of GFA Option B service setting nominations in Tier II.Back to Citation
35. Midwest TDUs, Basin, Midwest Municipal Transmission Group, Corn Belt, Minnesota MPA, Manitoba Hydro, Montana-Dakota, NRECA, Detroit Edison, Wisconsin Transmission Customer Group and Alliant.Back to Citation
36. See Order No. 2000 at 31,126.Back to Citation
37. Id. at 31,126-27.Back to Citation
38. See Declaratory Order at P 29-32; Declaratory Order Rehearing at P 27-31; TEMT Order at P 22 (encouraging the Midwest ISO to resubmit its energy markets proposal).Back to Citation
39. Declaratory Order at P 64. (“We continue to believe that customers under existing contracts, both real or implicit, should continue to receive the same level and quality of service under a standard market design.”).Back to Citation
40. See id. at 68.Back to Citation
41. TEMT Order at P 60.Back to Citation
42. See Hogan testimony at 8-9 (“[V]oluntary conversion of the GFAs to revised agreements consistent with the Midwest ISO [TEMT] should be preferred and encouraged.”), 32-34, 54.Back to Citation
43. See McNamara testimony at 84-85.Back to Citation
44. See Hogan testimony at 23-24.Back to Citation
45. About 55 percent of the capacity associated with the 145 GFAs for which the Midwest ISO could develop data is located in the eastern half of the Midwest ISO region and about 45 percent is located in the western half. See Transmittal Letter at 10.Back to Citation
46. See McNamara testimony at 17-23, 31-32.Back to Citation
47. See Hogan testimony at 26-28.Back to Citation
48. U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003, Blackout in the United States and Canada: Causes and Recommendations at 163 (2004) (Blackout Report).Back to Citation
49. Id.Back to Citation
50. See McNamara testimony at 11-14.Back to Citation
51. See id. at 12-13.Back to Citation
52. See id. at 14-15.Back to Citation
53. See California Independent System Operator Corporation, 106 FERC ¶ 63,026 at P 82-83 (2004) (Initial Decision) (“Considering that the ISO typically has 1300 Schedule changes in the hour-ahead market, significant computing time is necessary to produce final hour-ahead schedules; even if those schedules could be provided to scheduling coordinators within the twenty minutes prior to the trading hour, that time would be too short for market participants to modify and coordinate their schedules.”).Back to Citation
54. See McNamara testimony at 82; Hogan testimony at 25-29.Back to Citation
55. See id. The opposite circumstance, underestimating GFA scheduling, results in unnecessary day-ahead redispatch costs on other parties. See Hogan testimony at 28.Back to Citation
56. As an example of inefficiencies related to TLRs, TLR curtailment quantities have been more than three times larger on average than the potential redispatch amounts. As well, the Market Monitor notes the increased utilization of real-time redispatch in energy markets See, 2003 State of the Market Report (p. 20) prepared by the Midwest ISO Independent Market Monitor, April 2004. Also, Dr. McNamara notes that following NERC procedures, the Midwest ISO has had to curtail a 135 MW transaction to achieve as little as 7 MW of relief on a constrained flowgate. McNamara testimony at 16.Back to Citation
57. Note that this is somewhat different from the TEMT's requirements, which call for “the maximum megawatt capacity permissible under the GFA.” Module C, section 38.2.5j, Original Sheet No. 402 (emphasis added). For GFAs that do not contain language specifying a maximum number of megawatts, the parties to the GFA should submit at least three years' worth of historical data, to demonstrate what transactions they have made pursuant to the GFA.Back to Citation
58. See United Gas Pipeline Company v. Mobile Gas Service Corp., 350 U.S. 332 (1956); FPC v. Sierra Pacific Power Company, 350 U.S. 348 (1956).Back to Citation
59. Attachment B includes the Midwest ISO's Attachment P, List of Grandfathered Agreements, that is currently effective in the Midwest ISO tariff, modified to number each agreement. This version of Attachment P is subject to a further compliance filing. See 106 FERC ¶ 61,288 (2004).Back to Citation
60. See Hogan testimony at 54.Back to Citation
61. See generally Investigation of Terms and Conditions of Public Utility Market-Based Rate Authorizations, 105 FERC ¶ 61,218 (2003), reh'g granted in relevant part, 107 FERC ¶ 61,175 (2004).Back to Citation
62. This includes the Option B treatment as described in the Midwest ISO's proposed tariff under Module C, Section 38.8.3(b), Original Sheet Nos. 447-51 and Module C, Section 43.2.4(a) “ (d), Original Sheet Nos. 613-25.Back to Citation
63. We note that the Midwest ISO filed on April 28, 2004 an illustrative allocation of the FTRs. The Midwest ISO states that it filed the illustrative allocation to comply with the Declaratory Order and an order issued on March 28, 2003. See Midwest Independent System Operator, Inc. 102 FERC ¶ 61,338 (2003) (March 28 Order). In the March 28 Order, the Commission directed the Midwest ISO to file FTR information at least 60 days prior to the Midwest ISO's final TEMT filing.Back to Citation
64. Pub. L. 107-204, 116 Stat. 745 (2002) (to be codified in scattered sections of 15 U.S.C.).Back to Citation
66. See Transmittal Letter at 22-23.Back to Citation
67. See Midwest Independent Transmission System Operator, Inc. and PJM Interconnection, L.L.C., 106 FERC ¶ 61,251 (2004).Back to Citation
BILLING CODE 6717-01-P
[FR Doc. 04-12579 Filed 6-7-04; 8:45 am]
BILLING CODE 6717-01-C