Attach 90 Response 2.2 Staff Comments 8.23.00.doc

SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 1895

Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983

Attorney for the Commission Staff

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE FILING BY IDAHO POWER COMPANY OF ITS 2000 ELECTRIC INTEGRATED RESOURCE PLAN (IRP). )
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CASE NO. IPC-E-00-10

COMMENTS OF THE COMMISSION STAFF

COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of Filing, Notice of Comment Deadline issued on August 3, 2000, submits the following comments.
On June 29, 2000, the Idaho Power Company (Idaho Power; Company) filed its 2000 Integrated Resource Plan (IRP) with the Idaho Public Utilities Commission (Commission). The IRP describes the Company’s loads and resources, provides an overview of technically available resource options including conservation and establishes a demonstrated need for resources in 2004. The Company’s filing is pursuant to a biennial requirement established in Commission Order No. 22299, Case No. U-1500-165 and an authorized postponement granted in Order No. 27700, Case No. IPC-E-97-8. On August 3, 2000, the Commission issued a Notice of the filing and established an August 23 deadline for comments.
Idaho Power’s most recent Integrated Resource Plan was filed with the Commission on June 2, 1997. It was acknowledged by the Commission in Order No. 27064 issued on July 29, 1997.

Load Forecast
Three load forecasts have been developed for Idaho Power’s 2000 IRP. The three forecasts define a range of possible load growths in the Idaho Power service territory during the 2000 through 2009 planning period. The expected load growth rate is 1.76 percent per year over the ten years of the planning period. This is higher than the forecast of 1.27 percent in the 1997 IRP.
Low and high load forecasts were also prepared to recognize the uncertainty inherent in the forecasting process. The high load growth forecast of 2.32 percent per year assumes a load growth rate that is exceeded by only 10 percent of historic load growth rates. The low growth forecast of 1.21 percent is a growth rate that was exceeded by 90 percent of the historical growth rates. Both the low and high load forecasts are higher than comparable forecasts in the 1997 IRP. The higher load forecasts in the 2000 IRP are primarily caused by revised economic forecasts and new estimates of consumption per household.
All of Idaho Power’s off system sales contracts, except for one small 3 MW contract, expire before 2004. Thus, no additional off–system sales are included in the load forecast. The future load of FMC has been estimated to remain at 120 MW, the size of FMC’s first block. The effect of demand-side management programs has been accounted for in estimates of future usage by customers; however, no explicit reductions in load as a result of specific DSM programs has been assumed.

Resource Adequacy
In the IRP modeling process, monthly demand and energy requirements are compared throughout the planning period against the generating capability of Idaho Power’s power supply system. This comparison reveals the Company’s future need for additional capacity and energy resources.
With expected loads and median water conditions, the Company will experience energy deficiencies in the summer months of July and August in all ten years of the forecast. Additionally, the Company will experience winter energy deficiencies in November and December. Summer deficiencies are expected to increase from approximately 110 MW in 2000 to approximately 580 MW in 2009. Winter deficiencies are expected to increase from approximately 50 MW in 2000 to approximately 330 MW in 2009.
When low water conditions occur, a greater number of months have expected deficiencies. Summer deficiencies begin earlier (typically in May) with initial May through August deficiencies of approximately 260 MW increasing to deficiencies of approximately 640 MW by 2009. Winter deficiencies in November and December are expected to increase from approximately 160 MW in 2000 to approximately 450 MW in 2009. After 2007, Idaho Power is energy deficit in all months of the year.
Under a combination of low water and high load growth, Idaho Power’s energy deficits increase even further. In 2004, the Company shows a minor spring surplus, but deficiencies the remainder of the year. After 2004, the Company is always deficit under these conditions.
Idaho Power has determined that its existing resources plus market purchases of 250 average megawatts of energy in July and August, and 200 average megawatts of energy in November and December are sufficient to meet load growth until the year 2004. Beginning in 2004, additional resources must be available to serve expected loads.

Resource Options
To meet forecast loads at least cost throughout the ten-year planning period, Idaho Power considered multiple resource acquisition strategies. These strategies include increased monthly and energy capacity purchases from the Pacific Northwest power market to meet seasonal deficiencies and the acquisition of additional generating capability from a portfolio of various generating technologies. From those multiple resource strategies three strategies were chosen for final analysis and review: 1) a market purchase strategy, 2) a combined-cycle gas-fired turbine strategy and 3) a simple-cycle gas-fired combustion turbine strategy.

Market Purchases
Seasonal purchases of energy and capacity was the preferred strategy selected in the 1997 IRP. In the 2000 IRP, the Company plans to use market purchases from the Pacific Northwest throughout the planning period to supplement Company resources in July, August, November and December. These market purchases are placed in the resource plan in increments of 200MW and 250 MW. Market purchases beyond the initial 200 MW and 250 MW were determined not to be the optimum strategy because the delivery of increased market purchases from the Pacific Northwest would require substantial additional transmission facilities to relieve existing constraints in Idaho Power’s transmission system.

Generating Technologies
Seven generic generating resources using currently available technologies including gas-fired and coal-fired thermal generation, renewable resource generating technologies such as solar, geothermal, wind power, and generation from fuel cells were considered to identify the optimal resource strategy for the 2000 IRP. Two of these technologies, a 250 MW combined-cycle gas-fired combustion turbine and a 250 MW simple-cycle gas-fired combustion turbine were selected as the core resources for the second and third resource strategies in the final evaluation.
Fuel cells, solar photovoltaic panels, wind power, geothermal, and solar thermal generation were also considered, but their relatively higher current costs precluded their selection in the 2000 IRP as a bulk power system resource. If the cost of some of these technologies can be reduced, it is conceivable that such resources could have applications in a distributed generation strategy. Distributed generation resources may be economic alternatives to expansion of the transmission and distribution system and may improve system reliability.
A coal-fired generation strategy was not selected for the final analysis evaluation because of this technology’s longer construction and permitting lead times, environmental issues, and because its operating characteristics do not conform to the desired peaking plant characteristics.

Least-Cost Plan
Prior to 2004, the Company expects to be able to satisfy its load requirements with existing generation resources and seasonal purchases from the Pacific Northwest. Beginning in 2004, transmission restrictions will cap the Company’s ability to satisfy monthly capacity deficiencies with purchases from the Northwest. Therefore, the acquisition of generation resources, either by construction of a simple-cycle combustion turbine by Idaho Power or by means of a power purchase contract that provides Idaho Power with the same operational flexibility Idaho Power would have with a simple-cycle combustion turbine it owned, has been determined by Idaho Power to be the optimal strategy for satisfying load requirements during the next ten years.

Near-Term Action Plan
During the next two years Idaho Power states that it will take the following steps to address its resource needs:
( Purchase seasonal energy and capacity as needed to meet system load;
( Initiate a request for proposals (RFP) to establish the cost of acquiring dispatchable energy and capacity beginning in 2004.

Request for Proposals
Idaho Power released an RFP on August 4, 2000. A pre-bidders meeting was held at Idaho Power on August 18, 2000. Proposals are due on September 15, 2000. Idaho Power plans to determine a short list by October 6, and to complete negotiations by December 5, 2000. The Company plans to file a contract for approval with the Commission on December 12, 2000.

STAFF ANALYSIS
Staff met with Idaho Power representatives and discussed issues many times by telephone throughout the Company’s development of its RFP. Consequently, many of the concerns expressed by Staff were addressed during the course of development of the IRP. In any case, Staff did provide written comments to the Company prior to the preparation of the draft. Some of the comments were to improve clarity or simply editorial. Others were more substantive and are summarized below.

Relicensing
Staff recommended that Idaho Power expand its discussion concerning relicensing of the Company's hydro facilities. The Company admits that relicensing, particularly for the T.E. Roach complex (Hells Canyon), will play a major role in determining the future availability of hydro generation, yet the initial draft of its Integrated Resource Plan was based on the assumption that there will be no change in either the cost or operation of those facilities. While Staff acknowledges that it may be too early to know what protection, mitigation and enhancement (PM&E) measures will be required, Staff believed that the effects of possible reductions in generation should be analyzed. Staff understands the Company’s concern about suggesting possible PM&E measures and costs for fear that they will be viewed as representing commitments to which the Company may be held in the future. Staff suggested that the uncertainty could be handled in a manner similar to other types of risk analysis—by assuming a reasonable range of possible operational constraints, and analyzing how these assumptions affect the Company’s plan. Analysis of uncertainty is one of the primary purposes of the IRP process. Relicensing is one of those uncertainties, and one that can potentially have significant impact on the Company’s future.
In response to Staff’s comments, while Idaho Power includes additional discussion of relicensing in its final IRP, the Company fails to assume any reduction in generation from its hydro facilities as a consequence of relicensing.

Vulnerability of Idaho Power to Conditions Outside of Its Own System
In its draft IRP, Staff believed Idaho Power had done an acceptable job of assessing expected conditions within its own generation and transmission system; however, Staff was concerned about the vulnerability of Idaho Power and its customers to conditions outside of its own system. One example of this vulnerability could be transmission. Idaho Power addressed constraints within its own system, but has no real control over constraints in surrounding systems that may be even more critical in determining the Company’s ability to import or exchange power seasonally.
Idaho Power responds to this concern by conducting additional research to confirm that the most serious transmission bottlenecks are within its own system, not in surrounding transmission systems.

Risks of Relying on the Market
Purchases from the market were identified by Idaho Power as the preferred strategy to meet deficits in the near term as well as to partially meet deficits well into the future. Staff pointed out that the recent well-publicized brownouts and blackouts in other parts of the country due to failures of the market to be able to actually deliver power when needed and in the amounts needed have heightened the sensitivity of customers towards reliance on the market. Staff believed that the assumption that there will always be ample resources on the market at reasonable prices and that they will be deliverable to Idaho needed to be better supported. Given the increasing reliance of other utilities on the market, the lack of building of new generation and transmission facilities, and the increasing volume of other marketing transactions, Staff believed more specific attention should have been focused on whether there are limits to market resources. To increase Staff’s and the customers’ comfort level with this strategy, Staff recommended additional analysis of the risks of relying on the market.
More specifically, Staff agreed that reliance on purchases from Northwest markets is a reasonable strategy for meeting near term needs as well as partially meeting needs well into the future. However, Staff believed the risks of reliance on Northwest markets specifically needed to be more fully addressed. The availability of seasonal surplus in the region seemed to be implicit in Idaho Power’s analysis. If Idaho Power intends to rely on market purchases, it should have provided some analysis or evidence to show that enough power will be available when needed and at a reasonable price. Staff felt an assessment of regional reserve margins would have been useful. Staff was also interested in a response from Idaho Power to the Northwest Power Planning Council’s report Northwest Power Supply Adequacy/Reliability Study, Phase 1 Report, March 6, 2000, and to BPA’s most recent White Book analysis. Staff believed that one of the critical questions to be answered is whether Idaho Power believes it is subject to the same power supply risks as identified in these reports, how great those risks are, and how Idaho Power intends to mitigate those risks or to perform in the event risks cannot be completely eliminated.
Idaho Power does not address Staff’s comments specifically, but instead simply points out that its preferred strategy of acquiring new generation is an effort to decrease its reliance on market resources.

Transmission Constraints
Staff was pleased that the Company addressed transmission constraints in its IRP. Staff recognized the uncertainty associated with FERC Orders 888 and 2000, but wanted to see more analysis and discussion of transmission constraints. Staff suggested that perhaps one way to handle analysis of the uncertainty would be to assume a reasonable range of possibilities and see how they affect the decisions Idaho Power might make. For example, under what conditions might it make sense for the Company to increase its transmission capacity? If available transmission capacity was either increased or decreased in the future, how might Idaho Power respond? The IRP seemed to imply that the Company had done some analysis to compare the costs of building additional transmission capacity to the costs of acquiring new generation, but the cost of new transmission was not actually discussed in the document. Staff expressed interest in knowing more about the analysis that had been done.
Idaho Power responded to Staff’s comments by modifying its discussion of transmission constraints, but still does not provide information comparing the costs of building new transmission capacity to other alternatives.

Gas Transportation Constraints
Just as transmission constraints will affect Idaho Power’s ability to import power, gas transportation constraints could affect the ability of the owner of a gas-fired generator to have an adequate fuel supply when needed. The ability to deliver gas to southern Idaho, particularly during the November-December time periods when Idaho Power’s system is deficit, would be of particular concern. Would a SCCT or a CCCT plant operate under either a long term gas supply contract or rely on spot purchases, and in either case, is there enough pipeline capacity available in southern Idaho where the facility would have to be built? Would new pipeline capacity have to be built, and how would this affect the cost of generation? Could insufficient pipeline capacity change Idaho Power’s choice of alternatives? Given that fuel costs are the single biggest expense associated with either SCCT or CCCT generation, it is critical that gas price and availability be carefully scrutinized so that the cost of resources offered under an RFP can be compared to accurately estimated costs of a Company-constructed generating plant.
Idaho Power does not respond to this concern in its IRP, but the Company did discuss this issue with Staff in meetings. The Company believes that gas pipeline capacity is available to support the requirements of new gas-fired generation. Reserve capacity may be available, but the commodity will be priced at market. Proposals received in response to the Company’s RFP will help to confirm whether this is actually the case.

Extremely Low Water Conditions
Low water scenarios have been evaluated in the IRP. While unlikely, even lower water conditions than those examined in the IRP are possible for short periods of time. Idaho Power may be able to import enough power from the Northwest during low water conditions due to the diversity of loads and the unlikely possibility that the same low water conditions would exist in Idaho as in the rest of the region. However, under extremely low water conditions, such as could exist for only one or a few years, Staff was concerned about the transmission constraints to the Northwest. Staff was also concerned that imports from the Southeast would be unavailable during the months when imports would be most needed. The Northwest Power Planning Council’s recent study seems to indicate that there are no opportunities to import power from the Southwest to the Northwest during the months of July and August, and limited ability in other summer months due to transmission constraints. As a result of the seriousness of this condition, Staff believed it would be worthwhile to address how Idaho Power would meet load under extremely low water conditions.
Idaho Power responds to this concern by including additional discussion in its final IRP. The Company states that it is able to reasonably plan to use short-term power purchases to meet temporary water-related generation deficiencies on its own system because the Company has summer peaking requirements while other utilities in the Pacific Northwest region have winter peaking requirements. As a result, the Company’s need for resources tends to occur in months when the demand for power is lower in other parts of the region.

Demand Side Management
Staff pointed out in its comments on the draft IRP that demand side management should not only include “traditional” conservation, but also other programs and measures intended to reduce demand. Some of these “non-traditional” DSM programs and measures could include the following:

Tariff provisions to allow customers to self-generate.
Tariff provisions to encourage load shifting, such as time-of-day rates, on-peak/off-peak rates, and market based rates.
Voluntary curtailment or load reduction, primarily by large commercial and industrial customers. It may make more sense to offer interruptible rates, or to compensate customers for voluntary curtailment than to purchase power during peak load periods. Large customers may choose to shut down, either partially or fully, or install backup generation.

Idaho Power responds to this concern by making specific commitments to investigate a variety of demand–side programs. These commitments are discussed later in these comments.

Distributed Generation
Because of the transmission constraints pointed out in the IRP, Staff believed that distributed generation should have been more fully addressed. Although the draft IRP addressed the use of fuel cells, one possible type of distributed generation, it failed to address other forms of distributed generation. For example, natural gas fueled micro turbines and reciprocating engines are currently being used in some applications in some areas of the country and may hold more immediate promise than fuel cells. Staff requested that the Company compare the cost of other types of distributed generation to the options analyzed in the draft IRP.
Idaho Power responds to this request by adding additional discussion to its final IRP and by committing to perform a feasibility study investigating distributed generation options.

Request for Proposals (RFP)
Because Idaho Power was developing its IRP at the same time it was preparing an RFP, Staff also provided feedback on the Company’s RFP. Staff’s comments were generally related to concerns and insistence that the RFP be broad enough to capture any potential proposals for anything other than new generation plants. Although proposals for new generation may seem most likely, Staff believes the RFP should encourage innovation and creativity. Staff felt that DSM, renewables, distributed generation, load management, voluntary curtailment and various other alternatives should be eligible to bid under the RFP and that should they be bid, that they be fairly compared against new generation as well as against each other. Staff also recommended that the RFP be specific about the factors and the respective weightings that will be used in evaluating the proposals.

IDAHO POWER COMMITMENTS
Idaho Power met with the Commissioners on August 2, 2000 to discuss Idaho Power’s resource acquisition strategies aimed at meeting the Company’s energy needs in the future. During the discussion with Commissioners, Idaho Power committed to take the following actions related to resources:

( Issue an RFP by August 4, 2000 seeking resource proposals for 2004 (done).

( Prepare an analysis of the revenue requirement impact of the most attractive proposal versus a regulated utility-built resource – December 2000.

( File an application with the Commission for either the approval of the contract resulting from the RFP or a certificate of convenience and necessity to have the utility build and ratebase the project – December 2000.

( Perform and present a feasibility study on the near-term application of mobile generators to provide not only additional power and energy but also to provide reinforcement to the delivery system and potentially defer or avoid capacity upgrades to delivery facilities – November 2000.

( Submit time-of-use pricing proposals to better reflect costs to consumers with the next general rate case or sooner.

( Submit and discuss proforma load management tariff/contracts that target acquiring capacity from retail customers at a price reflective of market conditions – November 2000.

( Submit a “green” tariff filing to the Commission within the next 30 days.

STAFF RECOMMENDATIONS
All of Staff’s recommendations, both written and verbal, were addressed by the Company in the preparation of the final draft IRP or, alternatively, in commitments made during a recent meeting with Commissioners and Staff. Staff recommends the Commission acknowledge receipt of the IRP. Moreover, after thoroughly reviewing the Company’s 2000 IRP, Staff believes that the release of the IRP seeking proposals for up to 250 MW of new power starting in 2004 is an appropriate action. Staff recommends that the Commission be kept informed during the proposal evaluation process.

Dated at Boise, Idaho, this day of August 2000.

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Scott Woodbury
Deputy Attorney General
Technical Staff: Rick Sterling

SW:RS:gdk:i:word/umisc/comments/ipce0010.swr

STAFF COMMENTS 1 AUGUST 23, 2000