20000113Stephanie's FERC Testimony1.doc

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

ARIZONA PUBLIC SERVICE COMPANY

v.

IDAHO POWER COMPANY

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DOCKET NO. EL9944003

DIRECT TESTIMONY OF
STEPHANIE MILLER
ON BEHALF OF
THE IDAHO PUBLIC UTILITIES COMMISSION

I. QUALIFICATIONS AND EMPLOYMENT HISTORY

Q. Please state your name and business address.
A. My name is Stephanie Miller. My business address is Idaho Public Utilities Commission, P.O. Box 83720, Boise, Idaho, 83720-0074.
Q. By whom are you employed and in what position?
A. I am employed by the Idaho Public Utilities Commission (IPUC) as Administrator of the Utilities Division.
Q. How long have you been employed by the IPUC?
A. I have been employed by the IPUC for approximately 21 years.
Q. Please describe your education and experience in utility regulation.
A. I graduated from Boise State University in 1977 with a degree in accounting and have been a CPA since 1980. I have held my current position, in which I manage the IPUC technical staff, since 1986. Before that, I held the positions of Auditor, Director of Rates and Engineering, and Research Director at the IPUC.
II. PURPOSE OF TESTIMONY
Q. What is the purpose of your testimony?
A. I am not an expert on the actual calculation of Capacity Benefit Margin (CBM) or Transmission Reliability Margin (TRM). Therefore, I express no opinion on the accuracy of Idaho Power’s calculation. However, the Idaho Public Utilities Commission has the statutory duty to regulate Idaho Power. In regulating Idaho Power, the IPUC sets Idaho Power’s rates for native load customers and protects the quality of service for those customers. Quality of service includes reliability of service. CBM and TRM are two calculations that are necessary to calculating Available Transmission Capability (ATC) or that transmission capacity that is made available to potential transmission service customers like Arizona Public Service Company (APS). Reserves for CBM are required to maintain service reliability. CBM reserves are defined by the Western Systems Coordinating Council (WSCC) as “that amount of transmission transfer capability reserved by load-serving entities to ensure access to generation from interconnected systems to meet generation reliability requirements.” Reserves for TRM also reflect the need for reliability and TRM is defined by the WSCC as “that amount of transmission transfer capability necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions.” Therefore, the IPUC is very concerned about this proceeding. The primary purpose for my testimony is to ensure that Idaho Power Company’s native-load customers continue to receive the reliability to which they are entitled under Idaho law and not be compromised by additional use of the system. I will also address the effect of FMC Corporation’s contract with Idaho Power. FMC has been a native-load retail customer for years and the latest FMC contract was approved by the IPUC last year. In particular, after reading Arizona Public Service Company’s testimony, I will clarify that the FMC contract service provisions provide firm service and address Arizona Public Service Company’s apparent misunderstanding of that contract.

III. SUMMARY
Q. Please summarize your testimony.
A. Both CBM and TRM reflect certain reliability reserves that Idaho Power and other generation and transmission providers need to remove from the calculation of ATC in order to accommodate reasonable uncertainties in system conditions and to provide flexibility for secure system operations. The appropriateness of including CBM and TRM is reflected in the Western Interconnection “Determination of Available Transfer Capability within the Western Interconnection,” a document that has been approved by the western Regional Transmission Associations and Western Systems Coordinating Council (WSCC) to which both APS and Idaho Power belong, as well as in other documents. Through regulated rates, the Idaho Power native-load customers support the construction of capacity in the transmission system designed to accommodate certain foreseeable adverse events – in other words – to insure reliability for the native-load customer if those events occurred. Those customers deserve the benefits of that built in reliability.

APS also mischaracterizes the FMC contract with Idaho Power. The FMC contract is subject to the IPUC’s authority. The IPUC regards the contract as requiring Idaho Power to provide firm transmission service to FMC. Moreover, the FMC contract does not qualify as a non-firm contract under the FERC Order No. 888 because FMC’s load cannot be interrupted to provide transmission to another customer. With the exception of a base load of 17 MW, power supplied to FMC can be only temporarily shed in certain limited emergency situations. While the terms “interruptible” or “interrupt” are used in the FMC contract, it does not mean service to FMC is non-firm or “interruptible” as the term in used by FERC. The IPUC would entertain a service complaint from FMC if Idaho Power were to begin treating FMC as a non-firm power customer.
IV. BACKGROUND
Q. Generally speaking, what is the IPUC position concerning transmission access and competition in wholesale power markets?
A. The IPUC generally supports the concepts but believes that competition in the wholesale power market must not adversely impact native-load customers who in many instances provided the original capital for the facilities – including facility upgrades designed to provide service reliability in the face of certain foreseeable catastrophic events. The IPUC has publicly stated that competition in wholesale electricity markets can be advantageous for electric consumers, including native-load. The IPUC understands the critical role that open transmission access plays in wholesale competition. However, the IPUC has a statutory obligation to make sure that non-native-load customers do not gain an unfair advantage in the use of Idaho utility facilities to realize the benefits of competition at the expense of Idaho native-load customers.

V. THE EFFECT OF CBM AND TRM ON RELIABILITY FOR NATIVE LOAD CUSTOMERS
Q. Describe Idaho Power’s native-load customers.
A. Idaho is an agricultural state whose general welfare is affected by the health of the farming industry. While Idaho Power has traditional native-load customers like residential, hospital and public safety customers, and special contract industrial customers like FMC and Micron, it also has a significant group of agricultural native-load customers heavily dependent on reliable power – irrigators. These irrigation customers are strongly impacted by unreliable power. Even a relatively short outage can impact and damage crops.
Q. Why is it reasonable to protect the reliability of service for native-load customers?
A. The explanation originates in the open access transmission definition of native load customers. The Idaho Power Company, Open Access Transmission Tariff, Original Sheet No. 12 states it as follows:
The wholesale and retail power customers of the Transmission Provider on whose behalf the Transmission Provider, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate the Transmission Provider’s system to meet the reliable electric needs of such customers.
Under IPUC regulation, and long before FERC Order No. 888, Idaho Power constructed its existing transmission and generation system to meet the electric needs of its native-load customers. This includes building the facilities to provide native-load customers reliable service in the event certain contingencies occur -- such as loop flow or the outage of generation. Through regulated rates those native-load customers have supported the investment in both the generation facilities and the transmission facilities. The investment in those facilities has been supported by native-load customer rates and were constructed to not only meet present and anticipated native-load needs but to accommodate certain foreseeable adverse events to ensure reliable service to the native-load customer, as well. Rates were set by the IPUC to compensate Idaho Power for the investment in facilities including the additional capacity to assure reliability in the event adverse events occur. Native-load customers of Idaho Power, and other investor-owned utilities in Idaho are still protected as a matter of Idaho law with respect not only to reliable service, but with respect to the rates they pay, as well. The IPUC has a statutory duty to ensure that these customers receive safe, reliable, and efficient service at fair, just, and reasonable rates. Idaho Code §§ 61-302 and 61-501. To protect the native-load customers from the potential adverse consequences created when non-native-load customers use the transmission system – a system primarily constructed to serve Idaho Power’s native-load -- any additional use of the system must not compromise the reliable operation of the system or increase the costs to be paid by these customers.
Put in context, if APS is sold non-firm transmission in the exact amount of transmission it now requests as firm transmission, presumably it would receive power just as requested until one of the adverse events occurs. At that time, it would be curtailed. However, until one of those adverse events occurs – the same ones that drive the calculation of TRM and CBM – it receives its transmission. The IPUC’s position is that is how it should be. The reserves retained for reliability in the system should inure to the benefit of the native-load customers because they have supported through rates the investment in the capacity designed to protect them when those events occur. In a nutshell, if APS’s request for firm service is granted, the native-load customer would then bear the risk of adverse events occurring – events they attempted to insure against by paying rates designed to compensate Idaho Power for building reliability into the system. In effect, APS would receive the benefits for which native-load customers have previously supported through rates.
Q. Have you reviewed the testimony filed by APS and Idaho Power witnesses in this case?
A. Yes, I have.

Q. As you understand CBM and TRM, what are these calculations designed to do?
A. Both calculations are designed to reflect transmission reserves necessary to protect customers when certain reasonably foreseeable adverse events occur. The correct calculation of CBM and TRM for the Brownlee-East constraint and continued inclusion in calculating ATC is vital to ensuring that native load customers are not adversely affected. The calculation must consider the concurrence of potential and foreseeable adverse events in order to furnish the native-load customer with the benefits of the reliability they paid for in IPUC approved rates. The catastrophic 1996 “blackout” event, a cascading outage affecting the entire western United States grid and not just Idaho Power native-load customers, clearly demonstrated that the loss of two Bridger units, for example, is not a completely remote or unlikely event. APS witnesses apparently do not challenge the underlying calculation of Idaho Power’s Brownlee-East CBM. Instead, they seem to argue that certain aspects of Idaho Power’s administrative conduct should override the impact possible events reflected in the calculation may have on ATC. They seem to suggest that either Idaho Power should be “punished” for alleged wrongful dealings by removing CBM from the ATC calculation in whole or in part or CBM should be reduced to reflect transactions APS argues are available elsewhere on the system. I disagree with both assertions.
Q. Are you taking a position on whether Idaho Power has adequately separated its operational functions as required by FERC?
A. No, I am not. Although APS witness Hansen spends considerable time on the issue and his allegations are serious, I see the question of Idaho Power’s conduct as a separate issue from whether Idaho Power has adequate transmission capacity to provide the service requested by APS. It is entirely irrelevant to the matters set for hearing in this docket by the FERC in its June 17, 1999, order. Alleged improper separations are a matter for the FERC and do not affect the reasonableness of the CBM or TRM calculations. Moreover, FERC has set those issues aside in Case No. EL99-44-002. Whatever action the FERC may decide to take on APS’ allegations, it does not affect the question of whether there is ATC available to accommodate APS’ request for service. In no event, should FERC entertain a proposal that would affect reliability to the native-load customer. If FERC finds that Idaho Power allowed improper contact between the transmission and marketing groups at Idaho Power as alleged by APS, FERC may address that alleged impropriety directly to Idaho Power without penalizing the native-load customer.
Q. Mr. Hansen also testified that Idaho Power initially indicated it could provide at least some of the transmission requested by APS and later reneged on the deal. Should Idaho Power be required to honor its initial representations to APS?
A. First, similar to my last response, the issue of whether Idaho Power misled APS or took too long in evaluating APS’ request is entirely irrelevant to the matters set for hearing by the FERC in its June 17, 1999, order. This does not affect the reasonableness of the CBM or TRM calculations or the existence of ATC. Whatever action the FERC may decide to take on APS’ allegations should be separate from the question of whether there is ATC available to accommodate APS’ request for service. Idaho Power may have handled this matter better and it may have taken it longer than it should to determine whether it could meet the request, but requiring it to honor any initial or informal representations by providing the capacity requested by APS would be grossly unfair to Idaho Power’s native-load customers. The reservation of capacity on the Brownlee-East path must reflect both a correctly calculated CBM and a correctly calculated TRM to ensure that Idaho Power’s native-load customers are protected from the risk of increased cost and reduced reliability as a result of use of the transmission system by new transmission customers. The issue here is the determination of the appropriate calculation of reserves for CBM and TRM. The APS request should not be granted or denied on the basis that Idaho Power somehow acted improperly. FERC must not penalize native load customers for errors in procedure on the part of Idaho Power by allowing a use of the transmission system that imposes risk on these customers.
VI. THE FMC CONTRACT
Q. Is the contract between FMC Corporation and Idaho Power under the jurisdiction of the IPUC as a native-load retail contract?
A. Yes. By statute, the rates, terms and conditions of service between Idaho Power and FMC are subject to the active and continued supervision of the IPUC. Idaho Code §§ 61-301 and 502. In fact, there have been numerous proceedings before the IPUC and state courts involving FMC and Idaho Power.
Q. Please describe the latest FMC contract approved by the IPUC last year.
A. Relevant to APS’ testimony, the FMC contract does allow Idaho Power to shed a portion of FMC’s load under certain limited emergency conditions. Idaho Power, however, cannot shed FMC load to provide for another customer or for economic reasons. Moreover, if Idaho Power were to do that, the IPUC would have authority to order Idaho Power to restore service to FMC and assess any appropriate sanction. In addition, the IPUC retains statutory authority to approve and supervise curtailment plans involving native-load customers. Idaho Code § 61-531. Therefore, contrary to APS’ assertions, the quality and reliability of FMC’s service must not be negatively affected by the use of the Idaho Power transmission system by a new transmission customer and FMC’s contract is not a non-firm contract.
Q. APS characterizes FMC as an “interruptible” load. Is it interruptible and non-firm under FERC Order No. 888?
A. No. It is a native-load special contract customer subject to the jurisdiction and continued active supervision of the IPUC. In order to understand the FMC contractual relationship one must consider the historical context. FMC and Idaho Power have long had a contract for service – beginning prior to FERC Order No. 888 and the move toward open access tariffs and competition. Terms like “interruptible” and “curtailable” were sometimes used interchangeably – even by the IPUC. A careful review of the present contract demonstrates that FMC is not a non-firm native-load customer. While the contract anticipates that in an emergency load shedding situation – transfer trip for example – Idaho Power could shed all of FMC’s first block of power above 17MW and all of FMC’s second block of power this would not change FMC to a non-firm customer even as defined in FERC Order No. 888. The APS proposal to reduce Idaho Power’s calculation of CBM by approximately 230 MW to reflect the FMC contract would create reduced reliability and should not be required. Adoption of APS’ proposal would also change the very nature of the contract into a non-firm contract – an action neither party agreed to nor the IPUC intended.
Q. Does that conclude your testimony?
A. Yes.
Exhibit No. IPU-1
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