28583.doc

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

ORDER NO. 28583

On June 29, 2000, the Idaho Power Company (Idaho Power; Company) filed its 2000 Integrated Resource Plan (IRP) with the Idaho Public Utilities Commission. The Company’s filing is pursuant to a biennial requirement established in Commission Order No. 22299, Case No. U-1500-165. 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.
On August 3, 2000, the Commission issued a Notice of Filing in Case No. IPCE0010. The established deadline for filing written comments was August 23, 2000. Timely comments were filed by the Commission Staff. Late comments were filed by the Northwest Energy Coalition and Idaho Rivers United, and Joachin Falkenhagen, one of the Company’s shareholders. On October 10th the Company filed a limited response. The comments can be summarized as follows:
Northwest Energy Coalition and United Rivers United (collectively, the Coalition)
In filed joint comments, it is recommended that the Company commitments set forth in an August 7 letter to Commission Staff be included in the Company’s IRP as an addendum. The Coalition expresses surprise, that at a time when wholesale power prices are at an all-time high and extremely volatile, the Company’s IRP is markedly supply-side oriented (focusing on the need for peak resources) and virtually silent on the potential for demand-side measures, including load management, conservation and energy efficiency. The Coalition recommends that the Company look to revitalizing its conservation programs because of the cost-effective resource they provide to the utility and the economic and environmental benefits they provide to the customers in the Company’s service territory. Targeted conservation, particularly for commercial and industrial customers, the Coalition notes, can help reduce peak demand and should be aggressively pursued by Idaho Power. The Coalition recommends the Company explore aggressive load management and time-of-use rates to ensure system reliability and cost effectiveness. The Coalition supports a tariff rider approach to recovery of DSM capital costs.
The Coalition takes issue with the Company’s apparent discounting of the role distributed renewable generation technologies can play in reducing distribution and transmission constraints as well as meeting strategic load growth demands.
The Coalition recommends that Idaho Power continue to examine the increasing competitiveness of non-hydro renewable resources as wind projects.
The Coalition notes that environmental considerations when selecting priority resources in the IRP seem to be absent or minimal at best (i.e., brief discussion of emission cost adder for natural gas SCCT and CCCT). No environmental assessment is made of non-fossil fuel options or conservation and load management investments. While gas-fired combined cycle combination turbines (CCCT) are the cleanest of the fossil fuel generating technologies, CO2 released by fossil fuel combustion, the Coalition states, is the largest single source contributing to global warming, accounting up to one-half of the total. The Coalition recommends that the IRP explicitly consider CO2 emissions and that the Company include in its evaluation criteria for proposals, a power supply proposal plan for mitigating CO2 emissions. Such a mitigation plan, the Coalition contends, will have added value (economic benefits) to Idaho Power when the Company sells surplus into the market or for off-system sales.
Idaho Power Reply
The Company’s filed reply in this case addresses only the Coalition’s comments. Idaho Power stands by the commitments set forth in its August 7th letter to Staff, but contends that it would be premature to revise its IRP to include the estimated inputs of the various initiatives. The Company believes that its IRP process may provide additional data that would also be of value.
Although the energy product requested in the Company’s Request for Proposals (RFP) is specifically described (250 MW of peaking capability), the Company believes that its RFP process will assist in the evaluation of capacity and energy from smaller undertakings of the nature usually endorsed by the Coalition. Other types of resources, such as future distributed generation and demand-side initiatives, the Company states, could be brought on in smaller increments to compliment the selected RFP resource addition.
Commenting on its anticipated “Green” tariff filing, the Company states that it is seeking a supply source (possibly, wind resources) that will be acceptable to the environmental community.
Idaho Power states that it is not requiring CO2 offsets as part of its RFP evaluation. These offsets, it states, are not a current legal requirement in Idaho. The Company considers mandated CO2 offsets to be a public policy issue best addressed by the Commission in a separate proceeding.
The Company appreciates the Coalition’s comments pertaining to a tariff rider mechanism for DSM recovery, noting that the Coalition has correctly identified a ratemaking obstacle to utility-based DSM programs.
Joachin Falkenhagen
Mr. Falkenhagen, in comments filed with the Commission, notes his interest in wind generation, details the comparative advantages of such a technology, and recommends that wind power be considered as an option.
Commission Staff
Commission Staff in its comments summarizes the Company’s IRP filing, notes that it participated in the IRP development process and recommends that the Commission acknowledge receipt of the Company’s IRP filing.
Staff provided specific input regarding the Company’s hydro relicensing efforts and the potential effects of related protection, mitigation and enhancement (PM&E) measures. Staff notes that the Company fails to assume any reduction in generation from its hydro facilities as a consequence of relicensing.
Staff had expressed concern as to the vulnerability of Idaho Power to conditions outside its own system, constraints that might prove critical in determining the Company’s ability to import or exchange power seasonally. Examining such issue, the Company in its IRP concludes that the most serious transition bottlenecks are within its own system, and not in surrounding transmission sytems.
The Company in an IRP draft, Staff states, had identified purchases from the market as a preferred strategy in meeting deficits in the near term as well as a partial response in meeting deficits into the future. Staff expressed concern regarding the risks of relying on the market, noting the failure of the market to actually deliver power when needed. Staff believed that the Company’s assumption that there would always be ample resources on the market at reasonable prices and that they will be deliverable to Idaho needed to be better supported (e.g., assessment of regional reserve margins; Company response to March 2000 NWPPC report on supply adequacy/reliability; BPA white book analysis). The Company in its IRP does not provide the assessment that Staff was looking for but simply points out that its preferred strategy of acquiring new generation is an effort to decrease its reliance on market resources.
While the Company’s IRP addresses electric transmission constraints, Staff notes that it provides no information comparing the costs of building new transmission capacity to other alternatives.
Staff expresses concern regarding potential constraints that could affect the ability of a gas-fired generator to secure inadequate fuel supply when needed. The IRP does not address this issue. Relevant information may be gleaned from responses to the Company’s RFP.
Also of interest to the Staff, is how the Company would meet load under extremely low water conditions and address related transmission constraints. Responding to this concern, the Company in its IRP 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 region have winter-peaking requirements.
Regarding demand-side management, Staff recommends that the Company explore “non-traditional” programs and measures, e.g.
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.

In an August 7 letter to Staff, the Company commits to investigate a variety of demand-side programs, i.e.,
Issue an RFP by August 4, 2000 seeking resource proposals for 2004.

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 Public 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 pro forma 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.

Because of identified transmission constraints, Staff recommended that the Company more fully explore distributed generation alternatives. Staff notes that the Company has committed to perform a feasibility study investigating distributed generation options.
Staff supports the Company’s proposal to issue an RFP (for 250 MW of new power starting in 2004) and hopes that in addition to new generation, the Company will consider DSM, renewables, distributed generation, load management, and voluntary curtailment as well as other alternatives.
COMMISSION FINDINGS
The Commission has reviewed the filings of record in Case No. IPC-E-00-10 including the Company’s year 2000 Integrated Resource Plan and related comments and reply. We find the Company’s IRP contains the necessary information and is in the appropriate format as directed by the Commission in Order Nos. 22299 and 27064.
We acknowledge the Company’s power supply commitments as set forth in its August 7 letter to Commission Staff and have every confidence that the Company will follow through on its promises. To such end, we note the Company’s green energy tariff filing in Case No. IPC-E-00-18 and its recent Request for Proposals (RFP). It has been pointed out in comments however, that Idaho Power in recent years has reduced or eliminated nearly all of its prior DSM programs. In fairness to the Company, there are other regulated electric companies in the region that have done the same. The touted justification is that utilities must position themselves to be competitive in a restructured electric industry. In place of company specific programs, Idaho Power now participates in the Northwest Energy Efficiency Alliance (NEEA), a regional approach to conservation whose goal is long term market transformation.
It is now early December 2000 and the Northwest region continues to experience record high prices in the wholesale market. Voluntary conservation is encouraged to reduce the extent of rate increases that will follow purchases at those high prices. For the region it is a wake up call. Creative thinking and planning by utilities and customers may serve to reduce reliance on market purchases to the benefit of both customers and stockholders. Idaho Power and its customers are encouraged to take inventory and stock of available demand side management and conservation opportunities so that rate increases can be mitigated.
Although commenting parties have requested changes, we find no reason to require formal amendment to the Company’s Integrated Resource Plan. We accordingly find it reasonable to acknowledge and accept Idaho Power’s year 2000 IRP for filing.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over Idaho Power Company, an electric utility company, pursuant to Title 61 of the Idaho Code and the Commission’s Rules of Procedure, IDAPA 31.01.01.000 et seq.
O R D E R
In consideration of the foregoing and as more particularly described above, IT IS HEREBY ORDERED and the Idaho Public Utilities Commission does hereby acknowledge and accept for filing Idaho Power Company’s year 2000 Integrated Resource Plan.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7) days after any person has petitioned for reconsideration, any other person may cross-petition for reconsideration. See Idaho Code § 61-626.

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
day of December 2000.

DENNIS S. HANSEN, PRESIDENT

MARSHA H. SMITH, COMMISSIONER

PAUL KJELLANDER, COMMISSIONER

ATTEST:

Jean D. Jewell
Commission Secretary

vld/O:IPC-E-00-10_sw
A copy of the August 7 letter was filed by the Company in this case on November 8, 2000. The substance of the letter is set out in our summary of Staff Comments below.

ORDER NO. 28583 1

Office of the Secretary
Service Date
December 18, 2000