20020422Decision Memo.doc

DECISION MEMORANDUM

TO: COMMISSIONER KJELLANDER
COMMISSIONER SMITH
COMMISSIONER HANSEN
JEAN JEWELL
RON LAW
LOU ANN WESTERFIELD
BILL EASTLAKE
RANDY LOBB
DON HOWELL
DAVE SCHUNKE
RICK STERLING
TONYA CLARK
BEV BARKER
GENE FADNESS
WORKING FILE

FROM: SCOTT WOODBURY

DATE: APRIL 22, 2002

RE: CASE NO. GNR-E-02-1
INVESTIGATION – PURPA QFs
PUBLISHED RATE ELIGIBILITY AND CONTRACT LENGTH

On February 5, 2002, the Commission initiated generic docket No. GNR-E-02-1 soliciting comments on the continued reasonableness of current QF project size limitations for published rate eligibility (i.e., 1 MW) and restrictions on contract length (i.e., 5 years) from the PURPA QF community, from interested persons and from those regulated electric utilities (Idaho Power, Avista and PacifiCorp) required to purchase QF power pursuant to Sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA), and the implementing rules and regulations of the Federal Energy Regulatory Commission (FERC).
BACKGROUND
Congress in 1978 as part of the National Energy Act and as part of a package of legislation designed to address the then prevailing nationwide energy crisis passed the Public Utility Regulatory Policies Act (PURPA). Its purpose was to encourage the promotion and development of renewable energy technologies as alternatives to fossil fuels and the construction of new generating facilities by electric utilities. PURPA requires that electric utilities offer to purchase power produced by cogenerators or small power producers that obtain qualifying facility (QF) status.
The rate to be paid for QF power is not to exceed the “incremental costs” to the utility of alternative electric energy. Under the implementing rules and regulations of the Federal Energy Regulatory Commission (FERC), the rate a qualifying facility receives for the sale of its power is generally referred to as the “avoided cost” rate and is to reflect the incremental cost to an electric utility of electric energy or capacity or both, which, but for the purchase from the qualifying facility, such utility would generate itself or purchase from another source. PURPA and related FERC regulations provide that the rates for QF purchases (1) shall be just and reasonable to the electric consumers of the electric utility and in the public interest, and (2) shall not discriminate against qualifying cogenerators or small power producers.
FERC promulgated the general scheme and rules, but left implementation to the regulatory authorities of the individual states. Under FERC rules and regulations, published rates are required only for purchases from qualifying facilities with a designed capacity of 100 kilowatts (kW) or less. Reference 18 C.F.R. § 292.304(c). PURPA, however, does not prohibit the publishing of rates for larger projects. In its discretion, this Commission has set the design capacity limit for published rates at 1 megawatt (MW). A special hearing to establish and approve such rates is required. Rates and contracts for facilities larger than 1 MW are to be individually negotiated. FERC establishes no requirement regarding length of contract.
In comments filed in Idaho Power Company Case No. IPC-E-01-37, the J.R. Simplot Company petitioned the Commission to revisit and review two issues, i.e., (1) the size of QF projects entitled to published avoided cost rates and (2) contract length. Simplot asks that the Commission re-examine the basis for its decisions to limit published rates to QFs smaller than 1 MW in size and set the required contract term at five years.
In Order No. 25884, Case No. IPC-E-93-28, the Commission found that there was a widely held expectation that there would be increasing competition within the electric utility industry. The Commission also found that ratepayers should be indifferent to whether a resource serving them was constructed by a utility or an independent developer. The cost and quality of service provided by either should be the same. Simplot contends that competition in the electric industry in Idaho is very unlikely in the foreseeable future and that such a rationale for limiting the size of QFs to 1 MW for published rates, is no longer compelling or an eventuality. Order No. 25884 pp. 3-4. Simplot also questions whether ratepayers have been held indifferent. Simplot proposes that QF developers up to 10 MW in size should have access to published SAR based avoided cost rates. Simplot also advocates reinstatement of the 20-year contract as necessary for the QF industry to be able to assist the State’s regulated electric utilities in providing the capacity and energy they need.
Simplot requested that the Commission (1) expand entitlement to the Commission’s published avoided cost rates to all QFs that are 10 MW or less in capacity and (2) increase the standard PURPA contract length for all QFs 10 MW or less in capacity from 5 to 20 years, with the QF developer retaining the right to choose the term up to 20 years.
The Commission in its Order No. 28945 in Case No. IPC-E-01-37 found the issues of contract length and size limitation raised by Simplot to be important issues meriting a separate forum or docket for discussion.
The Commission’s February 5 Notice in Case No. GNR-E-02-1 was a Notice of Investigation and Modified Procedure. The deadline for filing written comments was March 15, 2002. The Commission received comments from the following parties:
Avista Corporation Idaho Power Company PacifiCorp Commission Staff Sorenson Engineering Windland, Inc. Intermountain Forest Association (IFA) Vulcan Power Company Representative Bert Stevenson—District 24 EnXco Idaho Rural Council Land and Water Fund of the Rockies Idaho Rivers United Idaho Irrigation Pumpers Association Dairymen’s Association Potlatch Corporation Plummer Forest Products, Inc. J.R. Simplot Company Independent Energy Producers of Idaho Idaho Farm Bureau Empire Lumber Company Black Hills Energy Capital JUB Engineers Water Power LLC Valerie Chisholm Bill Arkoosh Christopher Scott Harriman David A. O’Day
Comments can be generally summarized as follows:
Idaho’s three major electric utilities contend that J.R. Simplot Company and the other QF developers and consultants are over-reacting to what was the “perfect storm” of drought and high wholesale market prices that occurred in 2000-2001. Although the Companies acknowledge that the regional surplus in energy has evaporated and all are involved in acquiring additional resources, they contend that changes to PURPA QF rules and requirements are not necessary or required. Should the Commission be inclined to alter the status quo, the Companies request a full administrative hearing. All other commenting parties recommend raising the size limitations for PURPA QF published rate eligibility from 1 MW to 5, 10, 18 (Windland), 30 (Vulcan), 30-50 (Black Hills) MW and increasing the contract length from 5 to 20 years.

Avista Corporation
Avista supports continuation of the 1 MW size limitation for PURPA published avoided cost rates. Units with a generation capacity larger than 1 MW, the utility states, may have a significant impact on the Company’s electrical system. System impacts such as requirements for reserves, system voltage and scheduling, Avista states, can result in major costs to the Company. Raising the threshold for entitlement to published avoided costs to 10 MW, Avista argues, could result in significant additional costs to Avista’s customers. Ten megawatts represents one percent of the Company’s load. Avista maintains that contract terms and conditions for PURPA QFs larger than 1 MW must be evaluated and negotiated individually.
Avista disagrees with the contention that competition has not occurred in Idaho. Avista maintains that the western system, of which Idaho is a part, supports a very robust and competitive wholesale market. New generation, the Company contends, whether owned or purchased, must be competitive with market prices. Wholesale transactions, the Company contends, have increased tremendously in the last few years. This, it states, has resulted from the transparency of wholesale prices and the number of sellers in the market. The market, it states, has supported numerous independent power plants that have been built and operated as merchant plants solely for sale into the wholesale market. For all intents and purposes, Avista states, wholesale electric markets are transparent with respect to price. Almost all generating utilities and project developers, it contends, sell and buy at prices tied to the regional trading hubs. Avista recommends that no requirement be imposed upon utilities to offer contracts of a longer duration than five years, and that contracts of a longer duration be individually negotiated and approved by the Commission. Current power markets, it states, are focused on short-term arrangements. Generally speaking, the Company contends that 20-year purchase contracts are not available and 10-year deals are very difficult to find. Most market transactions, it states, are one month to five years in length. Credit risks to the purchasers and sellers, it contends, are very difficult to manage for power sale arrangements that extend beyond a five-year term.
Although, longer than five-year term arrangements are not precluded in the current market, Avista contends that they require custom negotiation. In current market, it states that options to renew or extend contracts may be more readily obtainable than initial long terms. Avista notes that the WUTC currently only approves published PURPA rates for a period of six months going forward using the wholesale market as a surrogate price. Were the Idaho Commission to require longer than five year contracts on the basis of published avoided cost rates, Avista states that its task in reconciling the requirements of Washington and Idaho would be much more difficult.
Avista submits that a short mandatory timeframe for contracts pursuant to published cost rates better reflects changing market prices and protects Avista’s customers from bearing excess costs associated with mandatory long-term, non-negotiated contracts.
Any change to PURPA rules, Avista contends, should be measured against the impact or the customer (ratepayer). The cost and quality of a resource to Avista’s customers, the utility contends, should be similar whether obtained from Avista, another utility, or a QF developer. The Company does not believe that customers will benefit either from changing the eligibility for published rates or the restrictions on contract length.
Idaho Power Company
Rolling back the clock to pre-1995 solutions, Idaho Power contends, is not the right way to deal with 21st Century conditions. The type of contracts advocated by the QF developers, Idaho Power contends, reduce utility flexibility to respond to changing conditions and transfer the risk of changing market conditions from the developers to Idaho Power and its customers. Idaho Power believes that the best way to ensure that QF resources are added to the Company’s resource portfolio in a manner that is sufficient and fair to all of the Company’s customers is for QF merchant plants to be placed on an equal footing with all other resources to be acquired pursuant to the Integrated Resource Plan (IRP) process. Idaho Power’s customers, the Company contends, have a right to expect that they are not being required to pay higher rates to subsidize a particular industry or group of developers. Any change in PURPA QF policy and requirements, the Company maintains, should be made only after careful consideration and analysis.
Idaho Power maintains a substantial uncertainty still exists in the electric utility industry. If Congress decides that retail competition is the preferred national policy, then Idaho and its utilities, Idaho Power contends, will soon find themselves right back in the retail access arena and the Company may again find itself trying to deal with long-term fixed rate contracts that represent stranded costs. The Commission, Idaho Power contends, must consider, as it did in 1995 and 1996, whether providing a sheltered environment for QF projects by a long-term fixed rate contract, is good public policy. Today’s energy supply environment, Idaho Power maintains, has not returned to pre-1966 status. If nothing else, the Company contends that the determined efforts on the part of the FERC to substitute competition for regulation in the wholesale electric market will continue to instigate profound changes in the electric utility industry and affect the way utilities acquire and manage resources.
Idaho Power contends that QF resources should be acquired like all other resources. QFs, it maintains, should be required to participate in a competitive bidding process with Idaho Power owned generation and non-QF merchant plant developers to fulfill requirements identified in the Company’s IRP process. Acquiring QF resources on the same basis as all other resources in a competitive bidding process, the Company maintains, will ensure that the proper type of resources are added at the times and in the amounts identified in the IRP process. Competitive bidding, the Company maintains, eliminates the problem of “grandfathering” when rates change and obviates the need to conduct separate rate proceedings solely for the purpose of setting avoided rates.
The contracting process that QF developers propose, the Company contends, would inevitably lead to the development of “non-dispatchable” resources. That result, the Company states, is very likely to be inconsistent with least cost resource acquisition principles determined in the 2002 IRP planning process. If acquisition of base-load resources is the Commission’s preferred option regardless of the outcome of the IRP process, then the Company contends that the Commission should require Idaho Power to issue an RFP for a 20 year base-load resource and all developers, utilities, non-utilities and QFs should bid in that RFP.
Market prices, Idaho Power maintains, are a reasonable measure of the costs the Company could avoid acquiring the smaller, non-dispatchable, non-firm resources offered by QF developers. If the Commission decides to adopt the proposal advocated by QF developers, Idaho Power contends that it will be necessary for the Commission to review the posted rates currently in effect to see they still represent an appropriate avoided cost.
PacifiCorp
PacifiCorp maintains that the Commission should not modify the existing 1 MW threshold for published QF avoided cost prices or the standard five year term of QF contracts. The fundamental assumptions about the future of the wholesale electricity market that led the Commission to arrive at the 1 MW threshold and five year contract term, the Company contends, remain equally valid today and in the foreseeable future and reflect an appropriate balance between the Congressional mandate under PURPA to promote the development of cogeneration and small power production while at the same time ensuring that ratepayers do not absorb additional costs associated with that development. Reinstituting a 10 MW threshold for surrogate avoided costs and prices and/or 20 year levelized QF contracts, PacifiCorp contends, may result in a subsidy to the QF industry, at the expense of utility ratepayers and in violation of the policies underlying PURPA. Moving to a 20-year contract term without adequate market based pricing mechanisms, PacifiCorp contends, may force the utilities to make sustained purchases that are priced above their true avoided costs or the prevailing market prices. Raising the threshold for published avoided cost prices to 10 MW, PacifiCorp contends, prevents an individualized analysis of the true avoided costs associated with those projects, and may make Idaho a magnet for above-market QF generation from neighboring jurisdictions where the threshold is 1 MW.
Conversely, PacifiCorp contends that maintaining the current 1 MW threshold and five year contract term does not preclude the development of QF generation resources pursuant to individually negotiated agreements in which the full range of factors (including actual avoided costs, dispatchability, credit worthiness and reliability) may be considered.
To the extent the Commission is inclined to re-implement the 10 MW threshold, 20-year levelized contract terms or both, PacifiCorp recommends that the Commission open the proceeding to include a consideration of the full panoply of interrelated QF issues – such as the appropriate avoided cost methodology, market-based pricing mechanisms, fixed versus variable pricing, credit and collateral issues, levelization of prices and related security issues – that effect the risks assumed by a utility and its customers under long-term QF contracts.
The Commission’s decision in this case, PacifiCorp maintains, should be guided by the principle of ratepayer neutrality. Consistent with that standard, states may not impose avoided cost prices on a utility that exceed the utility’s actual avoided costs. If parties are required by state law or policy to sign contracts that reflect prices for QF sales at wholesale that are in excess of avoided costs, PacifiCorp cites case authority to the effect that those contracts will be considered “void ab initio.”
The Commission’s findings in Order No. 26576 reducing the term of QF contracts from 20 years to 5 years, PacifiCorp maintains, remain largely true today. Open access transmission linking the supply markets throughout the Western System Coordinating Council has been implemented. Thermal technologies continue to improve. Natural gas prices have returned to historical levels and, combined with normal hydro conditions, have resulted in electricity prices that are relatively low throughout the region. There is legislation presently before Congress that would repeal the mandatory purchase obligation under Section 210 of PURPA. Finally, the Company contends that 20 year purchase terms are inconsistent with the shorter purchase terms (5 years or less) currently used by utilities to meet their supply needs.
PacifiCorp cautions confusing wholesale competition with retail competition. Notwithstanding, last year’s price spikes, the recent demise of Enron and the decreased focus on retail deregulation, PacifiCorp maintains that competition at the wholesale level is here to stay.
A significant portion of PacifiCorp’s power purchase needs, the Company contends, are being met by purchases of five years or less. The shrinking of the term of power purchases, it states, is a direct outgrowth of the advent of competitive wholesale markets. Moreover, it states that short-term purchases are consistent with the Company’s need for flexible resource options. The Company notes that it recently conducted a request for proposal (RFP) process to procure needed peaking resources for summers 2002-04. The Company received 52 proposals from 27 different parties and has secured 400 MW of flexible resources at highly competitive prices. These resources, the Company states, are dispatchable entirely at the Company’s option, whereas QF resources are not typically dispatchable. Further, PacifiCorp notes that the suppliers were subjected to stringent, ongoing creditworthiness requirements not typically found in QF contracts. Two of the contracted resources are three-year purchase options for the summer months. The third is a 15 year plant lease with purchase/termination options in the third and sixth years. These resources, PacifiCorp maintains, are representative of the tailored products available in the wholesale market. While forced, long-term purchases of an inflexible supply will certainly benefit the QF industry, PacifiCorp maintains that such purchases are out step with the Company’s supply needs and other market alternatives and are inconsistent with PURPA’s ratepayer neutrality standard.
The Commission, need only look at current wholesale market prices, PacifiCorp maintains, for evidence that the competitive wholesale markets are alive and well. During the market price spikes that occurred last year, PacifiCorp states that it experienced a surge in QF proposals for projects seeking to take advantage of high market based prices. Now that market prices have fallen, the Company notes that QFs are advocating for expanded access to published avoided cost prices. A return to 20 year levelized contracts, PacifiCorp contends, increases the risk that utilities will be forced to make sustained above market QF purchases in violation of PURPA’s ratepayer neutrality requirement.
The Commission should not increase the threshold for published QF avoided cost prices to 10 MW, PacifiCorp maintains. Competition, it states, exists in the regional wholesale market. To increase the threshold to 10 MW, the Company contends, could result in artificial subsidy of the QF industry by utility ratepayers. Expansion of eligibility for published prices, PacifiCorp contends, prevents consideration of all relevant supply options in determining avoided costs. Such a shift, it states, appears to conflict with FERC rulings that all relevant supply sources should be considered in determining avoided costs. Published prices, which currently are required to be calculated in accordance with the SAR methodology, PacifiCorp contends, do not permit an individualized evaluation of the actual avoided costs associated with a particular resource. FERC regulations for calculating avoided costs, the Company notes, require consideration of a QFs peak availability, dispatchability, reliability, ability to coordinate outages, usefulness during system emergencies and actual value to the utility’s system. Relatedly, the Company notes that this Commission has previously recognized that it is appropriate to consider the effect of transmission constraints on a utility’s ability to wheel QF generation to meet load in other areas of its system. Significantly, PacifiCorp notes that there are no adjustments provided under the SAR methodology for these factors.
Raising the threshold to 10 MW, PacifiCorp cautions, may create a magnet effect, attracting above market QF generation into Idaho. Wheeling of QF generation, it states, may result in inefficient allocation of scarce transmission resources. If QFs are truly competitive with utilities and other suppliers, PacifiCorp maintains that they should be able to survive in the competitive market, without the artificial shelter provided by the published price.
PacifiCorp also maintains that a 10 MW threshold may be contrary to the development of efficient, appropriately sized QF facilities. The Company’s experience is that a 10 MW threshold encourages QFs to size facilities at just under 10 MW or to construct multiple smaller facilities in order to take advantage of the published avoided cost prices.
If the Commission is inclined to increase the threshold and/or contract term, PacifiCorp contends that the docket should be expanded to consider other related issues. The risks that a utility will be forced to pay above-market prices under long-term agreements, PacifiCorp maintains, can be addressed in part by the implementation of market-based pricing mechanisms. As one option, PacifiCorp contends that the Commission could adopt a 20-year contract term in which the prices are adjusted at five-year intervals, based upon the market price forecast. A second option could involve a “dead band” of a predetermined percentage being placed above and below the contract price. If the actual market price of electricity stays within the dead band, the contract prices would remain unchanged. If the market prices are outside the dead band, the contract prices would automatically be reset to a revised market price forecast, with a new dead band.
Similarly, if the Commission is inclined to revert to a 20-year contract term, PacifiCorp contends that the efficacy of price levelization as a means of incenting QF development should be revisited. Utilities need adequate assurances that QFs will continue to operate during the out of the money years, so that both parties can obtain the benefits of the bargain underlying such contracts. While the Commission’s Order No. 21690 addressed the security concerns associated with levelized pricing, PacifiCorp states that it is unclear whether the existing security provisions are adequate to address the risk that Idaho utilities will face if 20 year, levelized contracts are reinstituted. As the utilities will face increased risks associated with QF non-performance under 20 year contracts, PacifiCorp recommends that the Commission consider requiring express creditworthiness and collateral provisions in such contracts. Alternatively, the Company maintains that these factors could be considered in the calculation of avoided costs.
The Company notes that its suggestions are not intended to be an exhaustive treatment of protections necessary to minimize the risks associated with 20-year contracts or a 10 MW threshold. Rather, they are being provided as examples of the need for the Commission to consider all the interrelated issues involved in QF contracts.
Commission Staff
Staff recommends that the threshold for availability of published rates be increased to 5 MW. Staff believes that published rates are fair and reasonable, and accurately represent the costs of the surrogate avoided resource (SAR) adopted by the Commission. As long as published rates reasonably reflect utilities’ avoided costs, then Staff contends there is little reason to restrict their availability to projects smaller than 1 MW. A threshold set at 5 MW, Staff contends, would permit most projects to receive published rates, thereby reducing administrative complexity while still ensuring a fair rate.
Staff further believes that reduction in administrative complexity is sufficient reason to increase the threshold for published rates to 5 MW even if the minimum contract length is not increased to 20 years. However, if a 5-year contract limit is retained, Staff believes that the methodology for projects larger than the threshold be changed from the current least cost planning methodology to a market-based approach. Market prices for five years into the future, it states, are regularly available, consistently updated, and would be easy to apply.
Staff notes that the Commission’s policy with respect to standard contract length has evolved over the years. From 1980 when PURPA was first implemented in Idaho, through 1987, utilities were obligated to provide QFs with 35-year contracts. The reason for the 35-year maximum contract length was that 35 years was the amortization period allowed for similar utility owned facilities. A contract length that agreed with the projects amortization schedule served to make financing easier, and in effect, helped to encourage QF development. In 1987, the Commission shortened the standard contract length to 20 years reasoning that risk and uncertainty inherent in long range forecasting increases dramatically with time and that a shorter contract term would reduce that risk. Later in 1996, the Commission again re-examined the issue of contract length and shortened the required contract length to five years for projects 1 MW and larger. In 1997, the Commission extended the five-year contract limitation established for large QFs to smaller than 1 MW QFs as well.
Staff notes that a vast majority of QF contracts signed in Idaho since the implementation of PURPA have been for a term of 35 years. Approximately 86% of the contracts have been for a term of 35 years, about 8% have been for 20 years, and only a single contract has been signed for a term of five years. It is undeniable, Staff states, that longer contracts have proven to be an incentive to QF development, and conversely, that very short contract length limitations have proven to be a barrier to development.
In the earlier proceeding in which the Commission reduced required contract lengths from 20 to 5 years (IPC-E-95-9), Staff notes that it advocated maintaining the standard 20-year contract term. Staff contended that it was reasonable to require 20-year contracts for QFs since utilities long-term acquisition planning was still primarily based on the acquisition of long-lived resources under long-term commitments. Staff reasoned that as long as the rates that utilities pay for QF power are based on the utility’s avoidance of planned resources, the utilities should be required to offer 20 year contracts if the planned resources have lives of 20 years or more. Staff believed that although utilities were then relying on short-term market purchases to satisfy their short-term needs, the fact that their respective IRPs called for acquisition of long-term resources could not be overlooked and justified requiring 20-year contract terms for QF projects. Staff continues to believe that its earlier position has merit.
Staff notes that each of the utilities has either recently built new generation, is currently adding new generation, or plans to add new generation in the very near future. Idaho Power, for example, recently completed a 90 MW gas-fired plant at Mountain Home. The utility is also currently seeking Commission approval for a power purchase contract from a 250 MW gas-fired plant to be constructed by Ida-West near Middleton (IPC-E-01-42). The proposed contract for purchases from the plant is for a five year term with options to renew the contract for any one or all of the five successive years. The contract also contains provisions to permit Idaho Power to purchase the plant after the initial five years or alternatively after ten years. The plant itself is expected to have a useful life of 30 years.
Avista, Staff notes, is in the process of completing the 280 MW Coyote Springs II plant. Avista Utilities will own and receive the output of half of the new plant. Avista is also finalizing construction of a small gas-fired plant called Boulder Park. The plant is located in the Spokane area and has a capacity of 25 MW. In addition, Avista is adding a combustion turbine with a capacity of 7 MW at its Kettle Falls plant. Along with the addition of new generation capacity, Avista has signed a market purchase agreement for 125 MW through 2006, and has proposed an additional 100 MW purchase for 2007-2010.
PacifiCorp, Staff notes, is pursuing adding single cycle gas turbines at its Gadsby site in Salt Lake and at West Valley City in Utah to meet near term capacity constraints. The Company is also considering building a fourth coal unit at its Hunter plant in Utah.
While Staff notes that it is certainly true that each of the utilities continues to make substantial purchases from the market under contracts five years or less in length, it is also true that each of the utilities has either already made, or is considering, long-term commitments for new generation. All of the new generation plants being built by the utilities will have useful lives in excess of 20 years. Because the utilities are making long-term commitments, Staff contends that there is no more danger that QF contracts will become stranded costs in the future than the utilities’ own new generating plants.
Staff believes, however, that there are key differences between utility owned plants and QFs that should not be overlooked. While utilities are making long-term commitments to new generating resources, most of those resources are dispatchable peaking or base load facilities with relatively low capital costs and avoidable variable costs. When it is not economical to operate utility owned plants, they can be idled, saving fuel and other variable costs. With QFs on the other hand, utilities must continue to purchase their output regardless of whether cheaper power is available from the market or some other source. Under the current pricing methodology for QFs, the Surrogate Avoided Resource used as the basis for calculating rates is a non-dispatchable combined cycle combustion turbine (CCCT). Therefore, Staff notes that there is no consideration given to whether plants can be dispatched or not. While a 20 year contract for QFs would be more consistent with utility-owned resources, Staff contends that a pricing methodology for QFs that fails to account for dispatchability may produce rates that are too high when compared to utility-owned resources. Staff believes that it may be appropriate to apply some discount to published avoided cost rates for non-dispatchable plants. To do so, however, it states, would require a Commission approved change to the existing methodology. Staff believes that the Commission should revise its rules to return to 20 years as the required minimum length for QF contracts. However, Staff believes that the Commission may wish to consider whether some adjustment to the current avoided cost rate calculation methodology is warranted to discount rates for QFs that cannot be dispatched by the utility. Staff believes that this may be necessary in order to treat QF projects on an equal footing with utility owned plants.

Availability of Published Rates
When PURPA was first implemented in Idaho, Staff notes that published avoided cost rates were made available to projects smaller than 10 MW. For projects larger than 10 MW, contracts were to be individually negotiated. However, even for these larger projects, published rates were still expected to form the starting point for negotiations. The utilities contended that these facilities, because they represented a significant generating resource on each utility’s system, required special operating and scheduling procedures.
Staff notes that approximately half of the QF contracts signed in Idaho since PURPA’s implementation have been for projects smaller than 1 MW. Over 80% of the contracts have been for projects smaller than 5 MW. Only three contracts larger than 10 MW have been signed, each of which is at existing industrial facilities (Potlatch, Simplot’s Pocatello plant, and Boise Cascade’s Emmett sawmill).
Staff believes that the level at which the Commission establishes the threshold for published rates is both a matter of accuracy and administrative convenience. The presumption seems to be that published rates reflect avoided cost rates that are too high, but as long as the rates are restricted to small projects, they are acceptable. The 1 MW or larger methodology was conceived with the assumption that a long-term look at the utility’s resource option was appropriate since QF contracts were also assumed to be 20 years in length. With a contract limit of only five years, Staff contends that the methodology produces results that could be obtained more easily by simply obtaining market quotes for similar products.
While the 1 MW or larger methodology is relatively straightforward conceptually, Staff contends that it is fairly difficult to actually apply. Utilities must use complex, proprietary power supply models that can be perceived as “black boxes.” Rate computations can be very time consuming. To date, no contracts have been signed with rates computed using the methodology.
The under 1 MW methodology, Staff contends, is based on the assumed costs of a combined cycle combustion turbine. Since this is, in fact, the same type of unit some of the utilities are now pursuing, Staff contends that the rates computed using this methodology are nearly the same as the cost utilities are actually incurring to build new generation. There is no evidence at this time to indicate that the rates computed using this methodology do not accurately reflect the costs of a gas-fired CCCT when viewed over a 20 year period.
Sorenson Engineering
Ted Sorenson supports reinstatement of the 20-year contract for avoided cost rates for the QF industry and increasing the eligible project size threshold to 10 MW. Mr. Sorenson has been the design engineer for 19 small hydroelectric projects, almost all for farmers, ranchers or canal companies. Construction of a new hydroelectric plant, he states, is capital intensive and he finds it impossible to amortize a plant over five years.
Windland, Inc.
Windland believes the current qualifying facilities size threshold of 1 MW and restriction of the maximum contract length of five years are no longer reasonable. Windland is in the business of developing commercial wind farms. Such resources, Windland contends, are precisely the type of facility that PURPA legislation was intended to promote. Since PURPA was passed, the cost per kilowatt-hour of wind-generated electricity, Windland contends, has declined by 90%. The primary factor influencing the improved cost effectiveness, it notes, has been a trend toward the use of larger turbines. The Stateline project on the Washington-Oregon border near Hermiston, Oregon, it notes, uses 660-kilowatt turbines. Commercial turbine sales, it states, are today primarily of the 650 – 900 kilowatt class machines, but this class of turbine, it contends, is nearing the end of its market lifecycle and is starting to be displaced by turbines in the 1.3 – 1.8 MW range. The commercial trend to larger turbines plus scale economies in operation and maintenance, siting, permitting, financing and construction, make the development of wind-based 1 MW QFs economically untenable. Similarly, Windland believes the five-year maximum contract duration for QFs is unreasonable and limits QF opportunities to assist in mitigating extreme variability in power costs.
Windland believes that Idaho ratepayers should be protected from unfortunate resource planning decisions such as the strategy that eventually resulted in Idaho Power building an inefficient, high operating cost, non-renewable fuel facility at Mountain Home as a quick response to unexpectedly high market prices for power. Use of a maximum contract length dramatically shorter than the useful life of capital intensive qualifying facilities, the Company states, serves as unreasonable barrier to such QFs being developed. Electric generating facilities built by large utilities and those provided by smaller QFs tend to be long-lived assets. The Commission uses a 20-year amortization period in its non-fossil-fueled model. Windland believes that, consistent with the Commission’s model, the maximum contract duration for PURPA QFs should also be extended to 20 years. Windland believes a reasonable maximum facility size is 13 to 18 MW range. A policy that allows the development of multiple 13-18 MW wind projects, Windland states, would provide a set of ancillary regional benefits. For example, distributed generation frees up transmission capacity, strengthens the grid and reduces losses by putting the generation source near the customer load. Windland requests that the Commission hold public hearings to determine the extent of such ancillary benefits. Windland requests that the Commission establish PURPA QF size limits at 18 MW and extend the maximum contract duration to 20 years.
Intermountain Forest Association (IFA)
IFA notes that the purpose of PURPA was to promote the development of renewable energy technologies as alternatives to use of fossil fuels. The Intermountain Forest Association represents forestland owners and mill operators in the intermountain west. IFA is interested in assisting and crafting public policy that encourages stable energy prices and encourages the use of renewable energy sources.
IFA encourages the Commission to (1) expand entitlement to publish avoided cost rates to all QFs that are 10 MW or less in capacity; (2) increase the standard PURPA contract length for all QFs that are 10 MW or less in capacity from 5 to 20 years, with the QF developer retaining the right to choose the term up to 20 years; and (3) re-examine rates to all QFs to ensure that current avoided cost rates are adequate to stimulate and support new generation facility development.
Vulcan Power Company
Vulcan Power Company is a geothermal base-load power developer. The Company’s power marketing efforts in Idaho over the past five years, it states, have consistently been blocked by self-interested Idaho electric utility opposition to projects of its type. Idaho utilities, it contends, will not buy the power, will not even negotiate on a level playing field basis, and continue to insist on building fossil and other generation which brings major environmental and economic risks of their own to Idaho.
The 1 MW size restriction, Vulcan Power contends, is unduly burdensome and results in higher prices for renewable power than would result from economies of scale of larger projects. Vulcan recommends that the size be increased to at least 30 MW in Idaho with the ability to develop multiple projects of at least 30 MW at or near a given site location and green-power hearings are recommended.
The five-year time length, Vulcan contends, is unduly burdensome and results in higher prices for renewable energy than would result from longer contract terms. Vulcan recommends that such project contract term be extended to at least 12 years and preferably longer. Vulcan contends that hearings are needed to consider how the Commission may best advance the development of a thriving renewable industry in Idaho, diversify the sources of power and reduce reliance on foreign fuel sources which pollute Idaho ecosystems.
Vulcan Power attaches a copy of a recently proposed New Mexico renewable portfolio standard. The Nevada state legislature, it notes, recently passed a 15% renewable portfolio standard. The Commission is an excellent forum for power policy and Vulcan asks that the Commission consider widening the scope of the current evaluation.
Representative John A. “Bert” Stevenson
On behalf of the people of Legislative District 24 (Minidoka and Jerome Counties), and himself, Representative Stevenson recommends that PURPA qualifying facility contracts be increased not to exceed 10 MW, and that the length of the contracts be extended for a period not to exceed 20 years.
EnXco
EnXco is the world’s leading operator of wind turbines, and has U.S. headquarters in California. EnXco states that it has committed significant resources to Idaho, since the summer of 2001, with the objective of developing viable wind energy projects in the state. EnXco has installed “met towers,” to accurately measure wind energy (the first step in wind project development), at Notch Butte Farms (between Jerome and Shoshone, Idaho) and will be installing additional met towers at a number of locations in southern Idaho. EnXco has worked closely with the Idaho Department of Water Resources (Energy Division) to increase awareness of the benefits of wind energy.
Because most QFs are constructed using private funding, EnXco contends that it is essential that they be provided with a reasonable price for the product and that the contract for energy be of sufficient time to support the investment. The current specified contract duration of five years, EnXco contends, is insufficient, and the Commission should consider a more reasonable period of 20 years.
Like many other construction related activities, EnXco notes that QFs benefit from “economy of scale.” The current limit in Idaho of 1 MW is well below the size necessary for cost effective projects – either based on renewable energy technologies or cogeneration. If Idaho adopted the original federal specification of 80 MW, construction of QFs of all technologies, it states, would become feasible in Idaho. EnXco sees the future of wind energy in Idaho as based on a number of modest projects (between 20 and 80 MW) at locations spread across the state. Commercial quality wind resources, it states, is a form a distributed generation which has the potential to improve electrical service in remote rural areas. Homegrown wind and biomass generation projects, it states, offer the opportunity for Idaho farmer and ranchers to secure much needed alternate revenue streams, and for industrial operations to reduce their overall energy costs through cogeneration. Taking advantage of these opportunities is essential, it states, if Idaho’s industry and agriculture is to continue to be competitive. EnXco urges the Commission to conduct hearings on this critical matter.
Idaho Rural Council
The Idaho Rural Council supports the concept of a safe, sustainable, affordable and just energy policy. It believes strongly in energy conservation and the efficient and responsible use of energy resources. The Rural Council is in favor of renewable and distributed energy production and thus believes that longer PURPA contracts in the 15 to 20 year range are essential to encourage investment in renewables, such as wind and solar. While small hydro projects in canal systems make sense, the Rural Council is concerned that damming up the few remaining free flowing waters of Idaho does not make sense either in water quality terms or for protection and enhancement of fisheries. The Rural Council believes that hydro projects should be limited to canal systems or other waters that have neither fish nor recreation issues. To that end, the Rural Council recommends that an environmental assessment (EA) be done for all projects to determine their impacts and allow for public comment and participation.
To better reflect the true nature of the avoided cost and thus protect ratepayers from paying higher prices than necessary, the Rural Council contends that avoided costs should reflect the seasonal fluctuations of these costs. It is important, it states, that wind and solar production projects become a part of the energy mix here in Idaho if we are to have a sustainable energy future. Idaho, it states, has abundant wind and solar resources and along with conservation and efficiency, the state should look to better utilize these resources. The Rural Council urges the Commission to be creative and visionary in its approach so that we can move forward to establishing a safe, stable and sustainable energy future that is environmentally responsible, economically sound, and socially just.
Land and Water Fund of the Rockies (LAW Fund) and Idaho Rivers United (IRU)
The LAW Fund and IRU while generally supporting economic incentives that encourage private investment in clean renewable forms of energy, are concerned that instatement of expanded eligibility for published avoided cost rates and longer contract lengths may spawn another era of hydropower development in Idaho to the detriment of ratepayers, as well as environment. The Commission should, however, it states, encourage investment in other renewable resources such as anaerobic digesters and wind power in order to diversify the state’s portfolio of generation resources. Although wind provides non-firm power, they state that investment in wind energy will be of great value to ratepayers because the winter months provide the greatest wind resource in Idaho, thus coinciding with the state’s high winter peak demand. Hydropower, on the other hand, they state, generally provides its greatest output during the late spring and early summer months, when Idaho and the Northwest typically enjoy a surplus of electric generation. The incremental costs of such hydropower for utilities – and the margin of value of that power to ratepayers – it contends, is extremely small, or even negative.
The LAW Fund and IRU recommend that the Commission establish PURPA policies which recognize the seasonal variability of Idaho’s generation resources and demand peaks – specifically, the surplus of power we generally enjoy in May and June, and high peak demands of late summer and mid-winter. They contend that a fair approach to achieving recognition for such seasonal variability is through approval and publication of seasonally adjusted avoided cost rates.
With respect to the specific issues at stake in this proceeding, the LAW Fund and IRU request the Commission (1) increase the QF size limitation for published rate eligibility to 5 MW; (2) increase the contract length for power purchases from such projects to 20 years; and (3) require standardized agreements for interconnections of such projects. The LAW Fund and IRU also request that the Commission evaluate a new system for setting avoided cost rates, which would recognize seasonal variability in generation resources and demand in Idaho. The LAW Fund and IRU believe that the Commission should proceed with caution before establishing policies that might force ratepayers to purchase power that they simply do not need, at prices that are higher than utilities’ actual incremental costs.
Idaho Irrigation Pumpers Association (Irrigators)
Increasing the current QF size limitation from 1 to 10 MW and increasing the contract length to 20 years, the Irrigators contend, appear to be reasonable and appropriate measures for the Commission to stimulate new capacity and increase the supply of affordable power.
There are a variety of QF projects that the agricultural community can bring forth to add electrical capacity and to ease the price impact upon all customers. However, the Irrigators contend that these projects do not necessarily fit under the 1 MW eligibility cap that is presently in existence in Idaho regarding QF projects. Additionally, if these larger agricultural QF projects are going to be brought forward, it is contended that they are going to require institutional financing. Such financing, it states, is extremely difficult to obtain for a project that must be amortized over decades and yet can only get a QF contract that is five years in length.
The present size limitation, the Irrigators contend, places an artificial barrier to somewhat larger projects that could be of great value all ratepayers. The Irrigators agree that QF projects must continue to meet appropriate avoided cost tests. The Irrigators advocate that larger resources and longer contract period be permitted for cost effective projects.
Idaho Dairymen’s Association
The Dairymen note that the investor-owned utilities have never liked PURPA. Notwithstanding the utilities’ distaste for the Act, the Dairymen state that it is still the law. Limitation on the size of QFs, they state, negatively impacts design and economic feasibility. However, coupling the size limitation with the five-year contract term limitation virtually destroys any realistic possibilities for QFs to satisfy any reasonable return on investment economic analysis. Not only has the size limitation made project development uneconomic due to economy of scale considerations, but it has also, they contend, artificially restricted innovation.
Potlatch Corporation
Potlatch supports Simplot’s request with one modification. Potlatch notes that the Commission’s QF restrictions have not achieved their stated goals. They have neither encouraged the development of cost effective QFs nor protected utility ratepayers from inordinate price increases. In fact, they have had precisely the opposite effect, it states, by effectively shutting down the industry when continued resource development would have been a welcomed hedge against exorbitant market prices.
The unpredictable nature of hydroelectric conditions, and the recent reliance on natural gas for all new thermal generation, Potlatch contends, virtually ensures that unpredictable price spikes will reoccur at some time. Wholesale prices in the Northwest have always been subject to wide swings in reaction to water supplies, it states, and natural gas prices have been through repeated booms and busts for more than 25 years, with seasonal price variations of 100% or more quite common.
Resuscitation of the Idaho QF industry, Potlatch contends, is a matter of the utmost importance. There is no mystery, it states, about what is required to achieve this goal. The Commission must simply return to the “status quo ante” and require Idaho utilities to offer standard 20-year contracts and published rates to all QFs of whatever size. The demonstrable fact, Potlatch contends, is that the utilities are either unable or unwilling to negotiate with QFs under any other scenario. Potlatch believes this is primarily due to the fact that the opaque and complex proprietary models employed to estimate avoided cost for larger projects are something of a shell game. These models, it states, invariably calculate avoided costs as equivalent to short-term market prices. This means that a potential QF developer receives little or no value for its capacity. The utilities for their part are disinclined to agree to a more realistic price that would reflect long-term capacity values for fear of being criticized for executing an above market contract. Consequently, to the best of Potlatch’s knowledge there have been no new QF contracts of more than 1 MW signed by Idaho utilities since the Orders of the mid-1990s were issued.
Instead, Idaho utilities, Potlatch states, have relied on wholesale markets to meet short-term load growth (with disastrous consequences) and then, when the need for new capacity has become apparent, they have invariably constructed their own plants, directly or through subsidiaries or affiliates, at costs greatly in excess of published QF rates. Idaho Power’s 2002 addition of its 90 MW Mountain Home plant, it contends, is a perfect example of a detrimental impact of this policy on ratepayers. The cost of that plant, under the most favorable conditions, is estimated at $77/MWh, roughly 40% higher than its levelized QF rate of $55/MWh.
We will never know, Potlatch queries, whether the Mountain Home could have been avoided with less expensive PURPA purchases. But, Potlatch contends, we do know that the next plant won’t be avoided by offering only five-year contracts for less than 1 MW projects. The record of prior cases is replete with evidence that QF developers need something on the order of 20 year contracts to finance their projects. Size restrictions also need to be lifted completely, it states, so that developers can take advantage of economies of scale and produce sufficient capacity to avoid the need for new utility plants the size of Mountain Home or larger.
Potlatch urges the Commission to lift the existing size and contract duration restrictions for QF developments for all Idaho utilities. In addition, Potlatch recommends that all QFs should be able to take advantage of published avoided cost rates. Potlatch submits that these remedies can be adopted without evidentiary hearings.
Plummer Forest Products, Inc.
Plummer urges that the threshold for published rate availability be increased to 10 MW and that contracts with a 20-year length be authorized. Plummer is a privately held Idaho corporation formed in 1999 to build and operate a small log sawmill in Plummer, Idaho. An electric cogeneration plant with a rate of capacity of 6 MW is located within the mill and is fueled by the wood waste generated by the mill and by wastes purchased from other sources. The facility is leased by Plummer from the Coeur d’Alene Tribe and has been subleased to Haleywest LLC. Currently the output of the plant is being sold into the regional spot (non-firm or surplus) markets. Revenues from sales, Plummer states, are insufficient to cover variable operating costs. Fixed costs such as depreciation and capital costs are not recovered at all. In the absence of a long-term contract with rates sufficient to cover costs and reduce market volatility, Plummer states it may be compelled to discontinue operation of the cogeneration plant in the near future and layoff employees.
Contrary to the expectations reflected in Commission Order No. 26576, Plummer notes that wholesale market prices for energy reached unprecedented levels never expected in a competitive market for energy, and Idaho utilities are currently acquiring or building long-term generating resources.
The policy of the State of Idaho, Plummer contends, as reflected by activities of the Idaho Legislature, is hostile to competition or industry restructuring. It is now apparent, it states, that competition has not and will not pose a threat to the utilities’ monopoly control of generation and distribution of electricity in Idaho.
The practical effect of the Commission Order Nos. 25884 and 26576, Plummer contends, has been to bring to a halt the development of PURPA resources in Idaho. Recent events, however, compel the conclusion that it is now time to adopt policies that would make the independent power projects economically feasible. Plummer recommends that the Commission consider expanding the scope of the proceeding to consider other related changes. Plummer contends the IRP methodology has proven to be exceedingly cumbersome as it is dependent on multiple computer runs of IRP models, the results of which are largely inscrutable to a third party. Moreover, both Idaho Power Company and Avista, it states, have recently constructed gas turbine generating facilities. There is now, therefore, it states, direct and relatively easily obtainable information about the costs of utility generation that could be avoided by QF purchases. The actual costs of a utility’s own addition of new generating capacity, Plummer contends, is the best evidence of avoided cost.
Although noting that the Commission in recent Order No. 28945 clarified the Commission’s intent in approving two SAR methodologies, one for “fueled” projects and one “non-fueled” projects, Plummer contends that the Commission did not preclude a fresh look at whether the distinction between fueled and non-fueled is sensible today. Finally, Plummer asks for parity of cost recovery for non-utility generation, citing a recent Commission Order modifying Avista’s power cost adjustment methodology. Case No. AVU-E-01-10, Order No. 28775. Whatever cost recovery method is approved for utility owned generation, Plummer contends, should also be afforded non-utility generation.
Changing eligibility for published rates and contract lengths, Plummer contends, are positive straightforward steps that should be taken now in view of the growing uncertainty regarding reliable supplies of energy at reasonable costs.
J.R. Simplot Company and Independent Energy Producers of Idaho (IEPI)
The J.R. Simplot Company and the Independent Energy Producers of Idaho urge the Commission to issue its Order requiring utilities under its jurisdiction to offer standard rate contracts at published avoided cost rates to all QFs up to 10 MW in size and requiring all utilities under its jurisdiction to offer standard rate contracts to QFs of up to 20 years at the QFs option. Tendered with its comments in this case, are previous comments submitted by J.R. Simplot Company in Case No. IPC-E-01-37, the case which precipitated the Commission’s investigation. Those comments can be summarized as follows:
1. QF Size.

As reflected in Simplot’s comments, in Order No. 25884 the Commission limited the availability of published rates to QFs smaller than 1 megawatt in size. As a basis for the change the Commission found that:

There is a widely held expectation that there will be increasing competition within the electric utility industry. In light of that, we believe it is especially important that the QF industry be able to demonstrate that the energy resources it offers are as cost effective as those that a utility could construct. Ratepayers should be indifferent to whether a resource serving them was constructed a utility or an independent developer. The cost and quality of service provided by either should be the same.

Order No. 25884 pp. 3-4. Regardless of one’s view as to the desirability of competition in the electric utility industry, it has decidedly not come to Idaho, Simplot notes, and is very unlikely to do so in the foreseeable future. Such a rationale for limiting the size of QFs to published rates, Simplot contends, is no longer compelling or an eventuality.

Furthermore, the Commission’s admonition that the ratepayer be indifferent to the cost, Simplot contends, has also not come to fruition. Indeed, it states, just the opposite has proven true. Simplot provides a table identifying Company resources brought on line since PURPA was first implemented and their related costs. (Cascade rebuild – 12 MW at 90 mills/kWh; North Valmy Coal – 260 MW at 62.5 mills/kWh; Milner Hydro Retrofit – 59 MW at 62.74 mills/kWh; Swan Falls Hydro Rebuild – 28 MW at 73.05 mills/kWh; Mountain Home Natural Gas Combustion Turbine – 90 MW at 77 mills/kWh and temporary mobile generators at 124 mills/kWh.) Simplot concludes that PURPA projects (60 PURPA contracts – 166 MW of capacity year end 2000 at an average cost of 61 mills/kWh) cost ratepayers less than the Company’s own resources.

The best way to cure this inequity, Simplot contends, is to allow QF developers up to 10 MW in size access to published SAR based avoided cost rates.

In reducing the project size at which a QF is entitled to the published SAR rates, Simplot quotes the Commission as stating:

By lowering the threshold to 1 MW, we are striking a reasonable balance between encouraging the development of independent, alternative energy technologies with the need to protect ratepayers from paying for resources which have not proven their cost effectiveness.

Unfortunately, Simplot contends that the Commission’s decision had the opposite effect. Instead of encouraging development, it discouraged development. Since 1994 (Order No. 25884), the Company, Simplot contends, has signed only two QF contracts.

2. Contract Length.
The other deadly blow dealt the QF industry, Simplot contends, was the reduction of the maximum contract term from 20 years to 5 years. In doing so the Commission concluded first, that competition was coming to the electric utility industry and second, that Idaho Power was only acquiring power to meet its load through “short term (five years or less) purchases.” Like the rationale for reducing QF size, Simplot contends that the rationale for reducing contract length is no longer valid in Idaho. Reference Case No. IPC-E-95-9, Order No. 26576 at p. 3. Only with the reinstatement of the 20-year contract, Simplot contends, will the QF industry be able to assist the State’s regulated electric utilities in providing the capacity and energy they need.

In the comments filed in this case Simplot and IEPI include a review of PURPA and conclude that its purpose was to encourage the development of the QF industry in order to promote national energy security. That too, it states, is the Commission’s role. Implementing rules and regulations that discourage the development of the QF industry, it states, are contrary to law, contrary to good public policy and contrary to good utility planning. Contract length and QF size rules, it states, discourage cogeneration. One need only look at the dearth of any QF development in Idaho since issuance of Order No. 25884, it states, as compelling evidence of the effect of the Commission’s rules. While it is true that the Commission is prohibited from examining or regulating the financial results of operations of QFs, the commentors suggest that it is equally true that the Commission must be instructed as to impact of its Orders on the QF industry in order to determine whether it is fulfilling its duty under federal law to encourage the development of QFs. The Commission, they state, must understand that the restriction on contract length is a barrier to the construction of QF projects. It is a practical impossibility to finance a capital intense project such as a PURPA facility over just five years. Similarly, they state, QF size limitations, pose an artificial barrier to development of a QF industry in Idaho. The 1 MW rule precludes the development of many projects that require larger size generators in order to capture economies of scale for a particular project. It further, they state, fosters waste by not permitting developers to capture the full potential of their project. It makes no economic sense, commentors state, to artificially undersize a cogeneration project in order to comply with an arbitrary ceiling on QF size.
The Commission, Simplot and IEPI state, should not further an obvious double standard, turning a blind eye to the utilities need to construct new generation in Idaho while heeding the utilities misguided assertions that short-term purchases on the “wholesale power markets” will meet its load requirements for the foreseeable future.
The fact is, the commentors state, that there is no longer a “considerable surplus” of electricity in the region. Indeed, they state, utilities are scrambling to build new capacity to meet projected deficits and insulate themselves and their ratepayers from the volatility of the unpredictable and unforgiving market place. The QF industry has a role to play in the resource acquisition portfolios of Idaho utilities. The only artificial shelter being provided, they state, is the 1 MW size and 5-year contract term shelter afforded Idaho utilities. This shelter, it states, allows the utilities to avoid having to acquire some of their resources from the QF industry thereby creating the self-fulfilling prophecy of resource deficit and emergency shortages. It results, they argue, in poor planning and the acquisition of unnecessarily expensive resources such as Idaho Power’s mobile diesel debacle.
Simplot and IEPI also point to ancillary benefits to the utilities of a robust and healthy QF industry. Such benefits, they state, include the superior reliability of QF projects, transmission benefits of added generation at or near load centers, and reliability benefits of multiple diverse generating projects utilizing a variety of fuel mixes. There are also economic benefits to the utilities, they state, when the agricultural and industrial sectors are made more profitable and viable. Simplot and IEPI urge the Commission to require utilities under its jurisdiction to offer standard rate contracts at published avoided cost rates to all QFs up to 10 MW in size; and require all utilities under its jurisdiction to offer standard rate contracts to QFs up to 20 years at the QFs option.
Idaho Farm Bureau
The Idaho Farm Bureau indicates that its members are very interested in developing various forms of distributed generation including anaerobic digestion, small hydro units, wind and possibly biomass and geothermal. All of these forms of generation, it states, are completely renewable and will help to strengthen the existing power grid by firming the grid with a greater diversity of generation as well as distributing generation around the state and closer to load centers. The current PURPA rules in Idaho, it states, are too restrictive and do not allow enough flexibility to effectively implement many of these innovative new solutions.
Farm Bureau also raises an additional concern with respect to the current interconnect process. It has been told that a number of dairymen have applied to Idaho Power under the Company’s current interconnect guidelines for a feasibility study on the possibility of connecting anaerobic digesters to the grid. They were required to pay thousands of dollars upfront only to be told six months later that it would cost them more than $80,000 to connect to the grid for work which should cost considerably less. The Farm Bureau requests that the Commission investigate current interconnect procedures as required by the utilities.
Empire Lumber Company
If Idaho’s utilities had not universally forecasted large surpluses in 2000-2001, Empire states that ratepayers could have avoided significant payments for buy-backs from irrigators and expensive market purchases by acquiring significantly cheaper long-term contracts that were available to come online in the year 2000 timeframe. Opportunities, it states, exist today once again.
While new QF resources may from time to time not be competitive with spot markets, Empire states that QF resources are a bargain when “perfect” storm rates rise to astronomical levels of several thousand dollars a MW hour. The overpayment to QFs in past years, it contends which were the utility objection to purchasing QF resources versus market purchases have been significantly recovered in the 2000-2001 period.
Empire states that it has sought to obtain a long-term contract from any utility which would be the basis of financing a power plant burning wood waste, including responding to several of Avista’s RFPs and making inquiries to other Idaho utilities. To date, it states, no Idaho utility has been willing to purchase, pursuant to a long-term contract, Empire’s output at prices sufficient to build a project and have instead, elected to build and purchase energy in capacity from their captive affiliates.
Without a contractual obligation to offer to purchase under PURPA as implemented by the Commission, Empire states that regulated utilities have generally shown a pronounced unwillingness to purchase QF resources pursuant to long-term contracts.
To build a project, Empire states that it needs a financeable stream of revenue contingent only on actual production of capacity and energy. A 10-year contract, which necessarily amortizes debt over 10 years, requires significantly higher, unrealistic rates when compared to a 20-year contract. Accordingly, Empire states that the contract length for QF resources should be at least 20 years so that the optimum rates for projects can be structured.
As the energy crisis of 2000-2001 demonstrated, Empire states that ratepayers should not have a substantial part of their resources tied to short-term market rates, but rather ratepayers should have a balanced resource portfolio that contains some fixed rate, long-term resources to hedge risks of higher natural gas and market electrical rates. A significant part of the high prices for power in 2000-2001, it states, came from utilities underestimating demand and over reliance on short-term market purchases.
Empire contends that the present Integrated Resource Planning process controlled by regulated utilities has proven to be unreliable forecasting tool and not inclusive of the PURPA resources even in times of need. Given the control utilities have over both the IRP process and discretionary selection of QF resources greater than 1 MW, Empire contends that the present utilities discretionary implementation of PURPA is open to significant self-dealing abuses between utilities and affiliates to control the flow of information and selection of projects. If unregulated utility affiliates wish to sell merchant plant output without ratepayers underwriting the costs through committed purchases, Empire states that QFs should have no qualm with such risk taking. The present day utility control of the planning process and project selection of affiliates, it states, has curiously evolved into a recreation of modern day utility monopolies which PURPA sought to repeal by direct involvement of state public utility commissions to put the project selection process on a level playing field.
With respect to project size, Empire states that no power plant of 1 MW can achieve efficiencies which make development feasible based on existing rates set forth in Order No. 28758 which are based on a large natural gas plant of 230 MW. No utility, it contends, will volunteer to buy any QF project of any size unless the Commission sets the size at which a mandatory offer to purchase must be made. The larger the size, the more efficient and competitive a QF will be, allowing more supply competing with rate base utility projects and favored utility affiliates seeking to build projects. Without firm rules and enforcement for when a utility must offer to purchase, Empire contends that the present non-selection of QF resources will definitely continue. A further problem arises, it states, with utility control of project selection because no QF will seek to develop a project when in Idaho a utility is ultimately perceived as selecting its own project without an impartial Commission evaluation process.
The Commission, Empire contends, needs to have a clear, no nonsense approach to enforcing the mandatory offer to purchase. Adopting a liberalized QF policy without “teeth,” it states, will only serve to resume in short order the “power wars” between the regulated utilities fighting to protect their turf and the independents who seek to provide independent competition.
Empire also addresses rates and rate structures, transmission and annual total utility purchases. Each utility in Idaho, it states, has experienced in the last five years significant growth. Taking each utility’s average five-year growth, it states, could be a logical limit for capping QF and other resources to avoid unnecessary and expensive excess of purchases in one year.
Empire urges the Commission to implement new terms and conditions immediately to encourage QF resources within the existing framework and follow up with extensive hearings as necessary.
Black Hills Energy Capital
Black Hills operates two QFs in Idaho and several others throughout the U.S. The Company contends that project terms should preferably be a minimum of 10 years for combustion turbine based facilities and, because they are more capital intensive to design and construct and 15 years for waste fueled facilities. These contract lengths, it states, allow reasonable debt amortization periods. Lenders, it states, generally do not allow a QFs amortization to extend beyond the firm contract length.
As for project size, Black Hills states that limits should be high enough for economies of scale. It is extremely difficult, it states, to earn a reasonable rate of return on any gas-fired projects less than about 30 MW in size and waste fueled projects less than 15 MW in size citing reasons of labor, original plant construction cost, and heat efficiency. For such reasons, Black Hills, would like to see a minimum project size cap of 30 MW, but it states that 50 MW is the ideal QF size owing to standard turbine sizes, initial cost, efficiency, labor costs, etc., with a term of 10 years for gas-fired projects and a 15 year term for waste fired facilities.
JUB Engineers
JUB provided professional engineering services for over 50 PURPA QF hydroelectric projects. Many of those projects, it states, were built and have been online going on 20 years. They have proven, contrary to misinformation, it states, to be reliable and cost competitive. In southern Idaho, JUB estimates that there is probably up to 80 MW of capacity that is still available on seasonal irrigation canal systems. JUB also cites the interest of dairy owners in producing electricity by utilizing methane gas from anaerobic digesters.
In order to develop such projects, JUB contends that the following is needed:
1. Long-term (20 year) fixed rate contracts for projects up to 10 MW.

2. Avoided cost rates determined over the term of the contract and equal to the life of Idaho Power’s new resources.

3. Standardized contract terms.

4. Standardized interconnection terms and conditions.

5. Avoided cost rates determined using Idaho Power’s actual new plant additions for avoided cost rate calculations.

Water Power LLC
Mr. John Straubhar is president of Water Power LLC, a company that is currently working with American Falls Reservoir District, Twin Falls Canal Company, North Side Canal Company and the Boise Project Board of Control to develop 13 small hydroelectric qualifying facilities, all on seasonal canals that operate typically from April to October. These plants, it states, represents some 15 MW of capacity and 66,287 MWh of production, all of which could be online in three to five years.
The primary hindrance to development of these projects, it states, is a 5-year contract and 1 MW size imitation to the published SAR based avoided cost rates. We need, it states, a contract term of at least 20 years and 10 MW size threshold for published SAR based avoided cost rates. What the QF industry needs, he states, is the following:
Long-term, fixed rate, contracts for projects up to 10 MW.

Avoided cost rates determined over the term of the contract and equal to the life of Idaho Power’s new resources.

Standardized contract terms.

Standardized interconnection terms and conditions.

Avoided cost rates determined using Idaho Power’s actual new plant additions for avoided cost rate calculations.

Contrary to rumor and innuendo, Mr. Straubhar contends that the QF industry is very reliable and competitive.
Valerie K. Chisholm
Ms. Chisholm supports the reestablishment of longer contracts for PURPA projects of renewable energy sources, particularly wind and solar. What we need, she states, are small, local (demand-side) systems that can augment our energy independence and that can be more responsive to our responsibility to ensure a cleaner environment. At the same time, she states, we must all refocus our definition of need and examine our incessant, wasteful consumption.
Bill Arkoosh
Congress, Mr. Arkoosh states, intentionally meant to foster the QF industry under PURPA, by insisting that QFs had a right of first opportunity to provide the marginal unit of power at the marginal rate. Congress extended the marginal cost concept, he states, to added capacity. Although every participant in all this Commission’s QF cases understands and mouths these concepts, Mr. Arkoosh states, we have not implemented them. A five year contract term, he states, prevents realistic commercial financing, thus violating the mandate to provide incentive terms. Anything over 1 MW, he states, imprisons the QF in the pre-PURPA wilderness of seeking terms and rates from the same utility it seeks to displace.
The proof, Mr. Arkoosh states, has resided very much in the pudding. The utilities tell the Commission they do not intend to build, so the marginal cost of the unwanted marginal unit sinks to nearly zero. The QF withers without an offer of a fair price. Suddenly, demand in the area of service magically grows, the utilities approach the Commission for permission to obtain more capacity and power. The approach, Mr. Arkoosh states, seems always in a vacuum, isolated from the question of obtaining the power from QFs, except to note that no QFs are up and running to meet this new and desperate need. And the approach, he contends, always comes in a hurry.
To some of the participants in the QF industry, Mr. Arkoosh states that the solution seems exceedingly simple. We in Idaho should do as Congress intended and give the QFs the right of first opportunity to sell the marginal unit at the marginal cost by providing terms and conditions which assures the public that before the traditional utility be allowed to provide the marginal units of capacity and power, they have offered the opportunity to Idaho’s public. Those terms and conditions would require that a precondition to any acquisition be tied to the realistic, rather than the induced, absence of QF power. In order for the utility to show a realistic absence of QF power, it would be required to show that it had timely offered QFs the opportunity to displace the power or capacity the utility seeks to put online at the same rate the utility seeks upon bankable terms. By marrying the terms and rates offered to QFs to the real world needs for power and financing and only through this marriage, will Idaho, Mr. Arkoosh contends, ever benefit from PURPA. It is ironic, he states, that while trying to evade purchasing power from QFs through hocus planning and the false polemic that avoided cost pricing is a “subsidy” to QFs, the utilities have really upped costs to the ratepayers.
Christopher Scott Harriman
Mr. Harriman is plant manager for two gas turbine cogeneration facilities in southern Idaho. The current rule, he states, makes it virtually impossible for a developer to retrieve a project capital expenditure in the 5-year timeframe. It makes it virtually impossible to receive project financing. If the Commission believes that it is desirable to see new qualifying facilities developed in the State of Idaho, Mr. Harriman states that a return to the old rules are the minimum that should be done.
David A. O’Day
Mr. O’Day is a member of Water Power LLC and was prior project manager of the 9.5 MW Horseshoe Bend Hydroelectric Project. Mr. O’Day urges the Commission to approve the requested change to increase the size of QF projects to at least 10 MW and to extend the term of the power sales agreements to at least 20 years, with the actual term to be determined by offerer.

Commission Decision
The Commission has issued an investigation as to the continued reasonableness of current size limitations for PURPA QF published rate eligibility (i.e., 1 MW) and restrictions on contract length (i.e., 5 years). On the basis of the written comments, is the Commission prepared to change the existing size and contract length restrictions? If not, how does the Commission wish to proceed? Does the Commission find it reasonable to proceed to hearing on the size and contract length issue or on any of the other issues identified by the parties?

Scott D. Woodbury

bls/M:GNRE0201_sw
DECISION MEMORANDUM 1