99-2-000_comments.doc

UNITED STATES OF AMERICA
BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

REGIONAL TRANSMISSION ORGANIZATIONS )
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DOCKET NO. RM992000

COMMENTS OF THE IDAHO PUBLIC UTILITIES COMMISSION

I. Introduction
The Idaho Public Utilities Commission (IPUC) wishes to thank the Federal Energy Regulatory Commission (FERC or Commission) for reinvigorating Western progress toward development of a Regional Transmission Organization (RTO). The document on which we take this opportunity to comment seems to give evidence that the Commission has listened to state concerns. We actively participated in the earlier consultation under Section 202(a) that aided FERC in development of this NOPR and we are pleased that the NOPR (Docket No. RM99-2-000) generally acknowledges state recommendations.
The IPUC shares the Commission’s belief that development of an efficient wholesale market for power is important. We agree that competition in wholesale electricity markets may be the best way to protect the national public interest and ensure that electricity consumers pay the lowest possible price for reliable service. We believe this even though Idaho has no plans now to implement retail access in the foreseeable future. Idaho is a very low (if not the lowest) cost state with no obvious incentive to move toward retail competition and little public clamor for access to markets. An active wholesale market in the West over the last decade has enabled us to keep costs down and rates low. We know that further development of an efficient wholesale market will be an uneven process with fits and starts and will take some time. Only after an effectively functioning market is available will Idaho be willing to consider participating in retail access.
FERC Consultation Under Section 202(a)
At the Western region consultation in Las Vegas on February 12, the IPUC comments pointed out electrical differences between the Northwest and the rest of the country. As part of the Western Interconnection we have: 1) a common grid already; 2) differences between hydroelectricity and thermal resources, requiring an active wholesale market and characterized by huge variability; and 3) a major institutional problem with the public-private split featuring the Bonneville Power Administration (BPA) as a major force. There is perceived to be great difficulty in melding BPA into any transmission organization with private utilities.
To a supplemental question about how to make sure that publicly owned transmission is included in any RTO, the IPUC suggested that FERC pressure may be an additional implementing force in bringing about whatever Northwest changes are required, either in the Federal Power Act or in BPA’s enabling statutes. We continue to believe that this is an important role that FERC could play in the development of RTOs in the Western Interconnection.
IPUC comments also mentioned Avista’s Independent Grid Scheduler (IGS) as a worthwhile first step in the transition to more full-featured RTOs and asked FERC to encourage such developments. We do not believe the NOPR has helped in this regard. It appears that FERC specifically forbids the approach Avista has embarked upon with its Independent Scheduling Administrator (ISA) or the very similar Independent Grid Scheduler (IGS), an approach that has a certain appeal to us as the beginning of an evolution to something stronger.
In the section on minimum functions, pages 156-159 of the NOPR, the language reads as follows:
An organization like an independent scheduling administrator that simply monitors the scheduling decisions of current transmission owners and offers dispute resolution services in case of a dispute would not (emphasis added) qualify as an RTO.

The NOPR states that in carrying out required functions, the RTO must satisfy each of the standards discussed, or demonstrate that an alternative proposal is consistent with or superior to satisfying the standard (emphasis added) (NOPR, page 159). In pursuit of deference to states and to the overall wisdom of allowing regional organizations to define their own solutions to their specific problems, IPUC believes that outright prohibition of such an evolutionary step undertaken in this region should not be adopted.
We remain comfortable with the slightly expanded current efforts toward some form of Independent Grid Scheduler (IGS) or Independent System Administrator (ISA) as positive steps in the direction of an ISO or a TRANSCO for several reasons. Such initial advantages include that it can be accomplished now, without major institutional reform or cost shifts, without creating a need for more IPUC oversight, and without foreclosing any future transformation into an ISO or a TRANSCO. Perhaps some leeway is called for in this matter.
IPUC continues to believe that regional solutions are the optimal answer to transmission problems. What we have learned in consultation with other states and in various forums devoted to consideration of RTO questions is that Idaho’s problems as a Northwest state and a part of the Western Interconnection are not the same as those of the eastern United States. Our region has for a long time relied on transmission and power exchanges to optimize the benefits to be gained from seasonal variation and divergence in loads and resources. Given that long-standing use of wholesale power markets, we question whether the benefits of more refined integration through RTOs are significant enough to warrant the imposition of large and costly solutions.
IPUC comments asked FERC to consider the cost-effectiveness of reliability measures rather than imposing bald mandates. The NOPR responded appropriately, at page 107, by saying that “the cost of meeting the minimum RTO requirements need not be large” and that the proposed rule allows each region “to design an RTO that has costs commensurate with the regional benefits expected.”
We in the Western Interconnection are moving in the right direction, through regional organizations like the Western Interconnection Coordination Forum (WICF) and the Committee for Regional Economic Power Coordination (CREPC). Our Western States Coordinating Council (WSCC) just achieved FERC approval (in Docket No. EL-99-23-000) of a pathbreaking Reliability Management System (RMS). We are moving jointly on an interconnection basis with interested parties, including state commissions, utilities, industry groups, and power marketers all sitting down together, something we have come to understand is quite uncharacteristic of some other regions of the country. In light of such progress and with this proceeding providing the ultimate stimulus to action, we ask FERC to accept progress as defined by the needs of each region.
Congressional Testimony
IPUC testimony before the Senate Energy and Natural Resources Committee on May 25, 1999 cited two points of view relevant to these comments.
First, the North American electric power system is divided into distinct, and largely electrically-isolated grids. This means that regional, grid-based solutions are needed to any problems.
Second, in the Western Interconnection, the Committee for Regional Electrical Power Cooperation (CREPC) is a unique body of all state and provincial agencies with electric power responsibilities. CREPC enables states and provinces to see the regional implications of their actions, allows coordination among the participants in the grid, and provides an ongoing forum for states and provinces to collectively interact with the western electric power industry. Any federal legislation should provide for FERC deference to regional solutions developed through joint efforts of states and industry that are developed on a grid-wide basis. IPUC believes that FERC had it right in the NOPR (page 6) when it stated its belief “that regional approaches to the numerous issues affecting the industry may be the best means to eliminate remaining impediments to properly functioning competitive markets.”
A one-size-fits-all national solution is a prescription for unproductive conflict and delay which benefits no one except those who profit by litigation. The Commission has recognized this reality in the deference it has granted to regional transmission groups, of which the first three in the nation are in the West. The Commission has reinforced many times its correct conclusion that the creation of efficient markets requires regional solutions.
The NOPR seems to square with CREPC comments that it is not appropriate for FERC to direct the formation of specific regional transmission organizations (RTOs) within specified geographic boundaries within the Western Interconnection. Moreover, the NOPR seems also to honor CREPC’s basic assumptions that the decision on whether to authorize retail competition within a state remains a state decision and that the Western Interconnection will continue to be electrically separated from other interconnections.

Idaho specific concerns
The NOPR contains a few noteworthy items that are of specific concern to the IPUC and the welfare of Idaho electricity customers. We take them in order of concern to us.
1. Native Load. There is barely a mention of “native load preference,” which is very important to still-regulated utilities and states but which seems nothing but an outmoded obstacle to those promoting an efficient common carrier transportation network. In March 30 responses to additional questions posed by Chairman Hoecker in Docket No. RM99-2-000 as to whether RTOs would interfere with the IPUC’s ability to keep the benefits of low-cost local generation resources with the state’s retail ratepayers, IPUC indicated its belief that the key element in this equation is likely the way in which ‘native load preference’ is interpreted.
Our concern regarding native load is further enhanced because Idaho’s largest electric utilities depend upon hydropower generation. On average, hydropower generation serves more than half of Idaho’s native load. The IPUC has long advocated that dependency on hydropower generation to serve native load customers places unique requirements upon electric utilities. More specifically, hydropower utilities must have sufficient transmission capacity to accommodate unpredictable and seasonal variations in water resources. The IPUC has required that utilities build their transmission systems to assure that they can import power from alternate resources in low water years to serve native load retail customers. RTO policies must possess sufficient flexibility to accommodate the needs of hydropower utilities and their long-standing requirements to serve native retail load. In this regard, we concur in the comments submitted by Idaho Power Company concerning its obligations to serve native load.
Perhaps it is appropriate to create a definition of native load that helps reconcile the difference between the responsibilities of the old regulated regime and the openness of the new deregulated one. Native load responsibility should not be glibly cited whenever a utility chooses not to offer transmission service, but certain states clearly still feel the burden of paying close attention to the needs of native customers of utilities with a continuing obligation to serve.
There are just eight specific references (identified by MS Word and listed as Exhibit 1) to the term “native load” in the NOPR. The first one sets up a disjunction between two types of action, one “motivated by an intent to favor affiliates” and one that “simply resulted from the need to serve native load customers.” This disjunction seems to provide positive recognition that the type of action needed to serve native load is a worthy exercise for transmission providers, but further references seem rather to highlight only the negative aspects of native load considerations, such as its potential for strategic use or self-dealing by the transmission provider. The second, third and fourth references to native load detail assertions that native load is a catchword used to refuse service to power marketers and to distort a properly functioning OASIS, providing an inherent advantage to existing transmission utilities.
The fifth, sixth, seventh and eighth references, the first two of which refer specifically to states like Idaho that do not have retail access, indicate the potential for a RTO to reduce retail rates by expanding the market region for both buying and selling power and allowing greater scope for a regional approach to resource planning and congestion management. We believe that wider scope already characterizes the broad markets of the Western Interconnection and the vibrant flow of power between the Northwest and the Southwest. In other words, those benefits are to a large extent already in existence and would not be greatly expanded through creation of a formal RTO.
Moreover, the failure to adequately consider native load in the NOPR is inconsistent with the Eighth Circuit’s recent decision, Northern States Power Company v. Federal Energy Regulatory Commission, No. 98-3000 (8th Cir. May 14, 1999) (1999 WL 301458) to be reported at 176 F.3d 1090. The Eighth Circuit recognized the importance of protecting native load customers and decided that a FERC decision adversely affecting a state’s authority to regulate rates for and reliability of service to native load retail customers is impermissible. The IPUC contends that in the absence of evidence of an undue burden on interstate commerce, FERC should acknowledge both the importance of considering native load for retail native load customers in the RTO and continued state authority to regulate rates and reliability of service for those retail native load customers.
2. Capacity Benefit Margin. Related closely to our first point, we note our continuing interest in another proceeding now underway at FERC, Docket No. EL-99-46-000, dealing with capacity benefit margin (CBM) and its use in computing available transmission capacity. Capacity benefit margin, the amount of transmission transfer capability reserved by utilities to ensure access to generation from interconnected systems for assuring generation reliability, seems vital to many of our utilities that depend on the ability to import generation to meet native loads during periods of low water. Without arguing the technical or legal merits of CBM here, we note that certain short-term steps undertaken by FERC in a July 28 Order (88 FERC ¶ 61,099) may go a long way toward resolving complaints over what are permissible uses of transmission capacity. Just requiring the posting of CBM on OASIS with a narrative explanation of its derivation and directing that transmission providers make periodic re-evaluations of their CBM is a very positive step that should provide some transparency to potential users of transmission capacity while still allowing appropriate consideration for native load.
3. Bonneville Power Administration. Pages 210-206 of the NOPR discuss incentives that would make it easier for transmission owners to turn over control of their transmission assets to an RTO. Given the major importance of BPA high voltage transmission facilities in the Northwest, it is imperative that any major RTO find a way to combine the public assets of BPA with the private assets of investor-owned utilities (IOUs). However, many parties in the Northwest are wary of federal control of transmission. The IPUC acknowledges that a Northwest RTO must make use of the widespread BPA transmission system and its two major control centers, but believes it is possible to achieve this without BPA in control. A real incentive to the formation of an RTO in our region may be to insure that any organization finally approved will be neither federally controlled nor directed from a control center at its current location.
Conclusion
The IPUC notes that the NOPR promises a collaborative in the spring of 2000 to further promote the voluntary development of RTOs. We applaud this initiative and believe it makes clear that the process of developing RTOs to effect reasonably competitive wholesale markets will be an ongoing process that calls for mature cooperation between Federal and state regulators on a continual basis.
The IPUC, representing a low cost state with no immediate plans to implement retail access, is nevertheless not “just saying no” to this FERC initiative. We believe the process of RTO formation is ultimately doable by all parties, to the ultimate benefit of electricity customers at all levels. We pledge to continue to work within our region on a collective response to the need for more effective wholesale power markets as outlined in the FERC NOPR.

RESPECTFULLY submitted this 20th day of August 1999.

Donald L. Howell, II
Deputy Attorney General

ATTORNEY FOR THE
IDAHO PUBLIC UTILITIES COMMISSION
PO Box 83720
Boise, ID 83720-0074

Street Address for Express Mail:
472 W Washington
Boise, ID 83702-5983

N:99-2-000_comments

EXHIBIT 1

NATIVE LOAD references in FERC NOPR on RTOs (RM99-2-000)
Pagination as defined by MS Word find function

1. (p. 80) It is often hard to determine, on an after-the-fact basis, whether an action was motivated by an intent to favor affiliates or simply resulted from the need to serve native load customers or the impartial application of operating or technical requirements.

2. (p.89) As we recently explained in Louisville Gas & Electric Company, et al., 82 FERC ¶ 61,308 at 62,222 & n.39 (1998), a properly structured ISO, or other transmission entity can eliminate the potential for the strategic use of a transmission owner's priority to use internal system capacity for native load.

3. (p.92) In one case, a power marketer asserts that a transmission provider has refused service over an interconnection on the basis that the transmission provider needs all the ATC for native load.

4. (p.110) Similarly, EPSA has told us that "the present transmission regime gives existing transmission-distribution utilities an inherent advantage to reserve capacity for their own native load use, and provides them with no incentive to maintain a properly functioning OASIS."

5. (p.141) Those states that do not have retail access can nevertheless benefit from an RTO as their utilities enjoy the benefits of the RTO to lower native load generation rates by buying and selling power over a larger market area.

6. (p.142) Where there is no retail access, state authorities can continue to ensure that a utility with a monopoly franchise sells its lowest cost power to local native load, even if the utility's transmission is operated by an RTO.

7. (p.142) Indeed, an RTO could actually lower retail rates by expanding the market region for the utility to sell the higher cost power not sold to native load and sharing in the benefits of region wide resource planning and congestion management. And finally, utilities that now have low cost generation will help assure access to future low-cost generation plants by participating in an RTO. New low-cost generation plants are more likely to be attracted to regions with a well-functioning regional market governed by an RTO. In other words, a state that is low-cost today may not be low-cost tomorrow without an RTO in its area.

8. (p.146) Our proposal is aimed at developing RTOs that would provide the forum and have the geographic scope for a regional approach to transmission pricing reform. The proposed rule would also permit flexibility for experimenting with innovative forms of congestion management, which would mean fewer TLR curtailments and more assurance that native load is served.

IPUC COMMENTS 10 Docket No. RM99-2-000