Summary of the January 7-8, 1997 Meeting of the
IndeGO States Task Force
Salt Lake City, Utah

[Prepared by Deb Ross, Washington State Energy Policy Group]

The following is a summary of our meeting of January 7-8, based on my recollection and notes. It is not formal minutes. I welcome additions and corrections.

We have scheduled no further meetings at this time. However, the IndeGO organizers expressed the hope that we might be able to schedule a third meeting some time in March. Bill Pascoe and I will be in touch to find a mutually acceptable time and place once the IndeGO steering committee meeting has completed its detailed schedule (see below).

Many thanks are due to Jeff Burks for hosting the meeting; to task force members Jim Miernyk and Phil Carver who led discussions on governance and regulatory issues; and to task force members for attending and participating in e-mail discussions. Thanks also to IndeGO organizers who attended the meeting on Wednesday. Finally, many, many thanks to WIEB and the Department of Energy for funding travel to IndeGO task force events!

January 7, 1997

The meeting began at 3:30 PM. In attendance were Deb Ross and Arne Olson (Washington Energy Policy Group), Larry Nordell and Alan Davis (Montana DEQ), Becky Wilson and Rich Collins (Utah PSC); Kent Evans (Utah DPU); Bernard Somdah (Oregon PUC); Stephanie Miller (Idaho PUC); Jeff Burks (Utah DNR); Phil Carver (Oregon DOE); Prem Bahl (Arizona Commission) and Jim Miernyk (Washington UTC).

The first topic of discussion was governance. We had a series of questions outstanding from our previous meeting and from other IndeGO events. Phil Carver led the discussion of these questions. The attached document, which the task force prepared and provided to the organizers, describes the recommendations and additional questions of the task force regarding these governance issues.

We next turned to regulatory issues. Jim Miernyk led this lively discussion. He began by canvassing other regulators on whether they generally supported the notion of IndeGO. Many regulators noted that the commissioners have not yet fully focused on IndeGO so currently have no opinion. Jim then outlined possible approaches the Washington UTC might take to IndeGO filings. He stressed that the UTC has no interest in placing artificial barriers in front of approval. However, it is the opinion of UTC?s attorneys that IndeGO participation will require approval under the transfer of property statute. Under that statute, the filers will have to demonstrate that the proposed transfer is in the public interest.

Jim outlined three possible regulatory matters: jurisdictional issues, policy issues, and technical ratemaking issues. For each, the commission will have to determine what is in the public interest, and what is the burden of proof. The group spent the most time discussing policy issues. Jim believed that IndeGO participants will have to demonstrate that IndeGO is at a minimum consistent with, and perhaps actually promote, existing regulatory policy regarding electricity restructuring. Thus, the filing might include at a minimum a demonstration that IndeGO participation is consistent with UTC positions on retail access. The filing would also have to demonstrate that it will result in reduced costs or other benefits to citizens. This may be challenging if the proponents are not able to show that IndeGO participation will result in transmission savings, but will promote other benefits such as increased efficiency in generation or increased reliability. Regulators will also want an idea of likely retail rate impacts.

While some task force members supported the approach that Jim outlined, others had concerns that it implied a lengthy and detailed filing that could place IndeGO formation in jeopardy.

The meeting adjourned at 6:00 with the decision to amend the agenda to continue the regulatory discussion the following morning.

Wednesday, January 8

The meeting began at 8:30 AM with a continuation of the discussion of the previous day. The group was unable to reach consensus on the preferred regulatory approach at the state level. In general, utility regulators tended to stress the need to demonstrate that IndeGO would benefit their citizens, with some energy offices concerned that too-strict adherence to regulatory requirements would threaten formation. The attached document expresses several of the viewpoints.

The IndeGO organizers joined us at 10 AM. The following IndeGO or utility representatives were present: Chuck Durick (Idaho Power), Kristi Wallis (consultant to IndeGO), Marcus Wood (attorney for PacifiCorp), Bill Pascoe (Montana Power), Ken Morris and Steve Walton (PacifiCorp). In addition we were joined by Jim Byrne, manager of WRTA, and Jim Galanis, Utah DNR.

Bill began with an update. IndeGO has hired Kristi Wallis to help IndeGO organizers keep on task. She has many years of experience in the utility industry. The steering committee will be meeting Thursday and Friday. By then, the group hopes to have a detailed schedule listing key milestones to meet a July 1 filing date. IndeGO will share this with the task force when it is available. IndeGO may reschedule the public forums scheduled for early February.

We then went on to discussing regulatory issues. Jim Miernyk summarized the task force?s discussions. We focused some attention on the difficulty of preventing cost shifting under a retail access regime. The methodology for calculating the transmission component of rates currently differs between FERC and some local regulators. It is not contemplated that anyone would attempt to force local regulators to use FERC?s methodology in calculating the transmission component of retail rates in an IndeGO environment. However, if retail access and unbundled rates become a reality, some cost shifting may result when some retail customers choose direct transmission services and others choose unbundled services from their local distribution company. The IndeGO organizers acknowledged that this would be a case where retail access could result in cost shifting. However, some did not believe that this was an issue unique to an IndeGO environment. It would equally apply, they stated, to retail access without IndeGO.

We also discussed the challenge of finding that IndeGO is in the public interest, without a showing of transmission savings. We also focused on the question whether each state would require a positive benefit (or at least no negative impact) to its own citizens. There seemed to be a consensus that this would be needed. However, it was noted that statutes are relatively vague on what is required. For example, in Washington, the utilities need not show that benefits accrue to ratepayers in particular. Regulators could consider the "public interest" from a broader perspective.

Each regulator present then had the opportunity to express its state?s individual perspective.

In Utah (Rich Collins and Kent Evans), there has not yet been much regulatory focus on IndeGO. Some regulators have expressed the view that utilities will have to show that rates won?t increase. They would, however, like to facilitate the formation of IndeGO. In terms of a time frame, a full blown rate case would take up to 240 days, but it?s not clear whether the transfer statute has the same time line.

In Idaho (Stephanie Miller), there hasn?t been extensive discussion of IndeGO at the commission level. She believes that IndeGO would come under the transfer of property statute, which has no statutory clock. The standard for transfer cases is "no harm." The Commission traditionally looks at the total impact, not class by class.

In Oregon (Bernard Somdah), all three Oregon commissioners signed the Declaration of Independence supporting the general notion of ISOs. Probably some filing will be required. The standard is "no harm." The commissioners have asked IndeGO organizers for a filing as soon as possible.

The energy offices then expressed some views. Montana, Oregon, Utah, Washington and the Power Planning Council were represented and generally expressed favorable views towards ISOs and IndeGO. Most did not believe their own regulatory requirements required extensive filings, although they will have to review siting authorities to determine whether the transfer to IndeGO will require amendments to certificates. Some energy offices may intervene in FERC and/or state proceedings, and comment on Bonneville?s EIS.

Marcus Wood then commented on his personal views of these issues. He stressed that he was not at this point speaking on behalf of IndeGO.

It should be in the interest of all IndeGO organizers to assure that state regulators are happy with their utilities? participation in IndeGO. Nonetheless, he does not believe that the transfer statutes necessarily apply to the type of transaction (long-term contracts) that the organizers are now proposing. Furthermore, the California experience has shown that FERC is willing to essentially preempt state jurisdiction on ISO matters, at least when state conditions imposed on ISO formation are inconsistent with FERC?s views.

It is not practical for there to be a multitude of different requirements for each IndeGO state. IndeGO formation will require uniformity among all states. Furthermore, since utilities are not making money on IndeGO, they may withdraw if regulatory requirements are unduly onerous.

Marcus suggested that regulators consider using accounting treatment petitions to review IndeGO, rather than transfer statutes. Such petitions would include proposals for splitting transmission and distribution, and request deferred accounting for IndeGO expenses. The utility would remove the transmission component of the split from rate base, with IndeGO access fees and congestion charges considered expenses. The advantage of an accounting petition over a transfer petition is that commissions can more easily tailor the standard of review to the matter at hand. Transfer statutes, on the other hand, may require quite specific findings that will be difficult to prove for IndeGO. Thus, the commission could make a preliminary finding approving the accounting and reserve its options to revisit them under future rate cases or other proceedings. The basic message is: look at all regulatory alternatives and pick the one that preserves the most flexibility for regulators.

In terms of the sequence of events, Marcus believes (again, his own opinion), that it will be as follows:

1. around July 1: simultaneous FERC and state filings
2. States begin to work on appropriate transmission/distribution split for own proceedings; make preliminary findings that they forward to FERC; FERC presumably defers to state findings in accordance with Order 888
3. States determine their own data needs and convey them to FERC as well
4. FERC approval
5. State final orders

The task force asked Marcus where Bonneville is in the process. He answered that Bonneville needs to pick up the level of efforts. There are both practical problems and political issues to address. We explored the possible impacts of legislation that IOUs might introduce to separate Bonneville and prohibit generation costs from being assigned to transmission. If the legislation has been introduced but is still pending as of the filing date, how will this affect the formation? Marcus and others opined that the IndeGO organizers will withdraw if generation is put on wires. Therefore, if the matter is still unresolved as of the filing, the bylaws might contain a provision allowing for an "out" if Bonneville generation is put on the wires. Or, the bylaws (and FERC approval) could provide for direct assignment to Bonneville customers.

We then turned to brief discussions of pricing, planning and governance.

Pricing. We noted that NRTA is having a pricing committee meeting on the 14th to discuss IndeGO pricing alternatives. This meeting will be considered part of task force activities, and task force members are encouraged to attend.

We briefly discussed the question whether the pricing committee has recommendations on the appropriate billing determinants for the access fee. For example, will it be capacity related only, and if so, 1 CP, 12 CP, 52 CP, etc.? Answer: no firm determination yet. Will the access fee reflect changing billing determinants over time as the relative contribution to CP changes? Answer: yes.

Chuck Durick also briefly discussed some proposals on pricing that might dilute the "purity" of the marginal cost signal. The pricing committee and Chuck will discuss these in more detail on the 14th.

Planning. The main question was who does studies of nontransmission alternatives within zones. Between zones, there may be "menus" of options, but owners will have to make ultimate decisions on relieving congestion. However, within a zone there is no clear entity that has the financial interest to find the least cost solution. Steve Walton acknowledged that this could be an issue and will take this question to the steering committee or planning committee.

Governance. We described our recommendations on governance as set forth in the attached recommendations. Marcus questioned the need to have a vote from the commission class on board membership, indicating he was concerned that if commission class members get a vote, other interests will want a vote, too. The task force reiterated its recommendation and discussed briefly the advantages of having a vote on board membership.

Next steps.

Marcus would like to have a meeting with attorneys representing the regulators in the various IndeGO states to discuss a coordinated filing approach. The task force recommended that IndeGO set this up independently and not under the sponsorship of the task force.

Bill Pascoe indicated a desire to meet with the task force some time in March to discuss any remaining matters. Steve Walton indicated that IndeGO organizers will have to make final substantive decisions by mid-May to meet a July 1 filing date. Therefore, the CREPC meeting scheduled for the latter part of May will have to be in the nature of a report rather than a request for input from CREPC. Of course, CREPC and any state can take a position on any issue before FERC or state proceedings after the filing has occurred.